UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability Corporation
)
)
Docket No. _______
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF
PROPOSED RELIABILITY STANDARDS PRC-029-1 AND PRC-024-4
Lauren A. Perotti
Assistant General Counsel
Alain Rigaud
Associate Counsel
North American Electric Reliability
Corporation
1401 H Street NW, Suite 410
Washington, D.C. 20005
202-400-3000
Lauren.perotti@nerc.net
Alain.rigaud@nerc.net
Counsel for the North American Electric
Reliability Corporation
November 4, 2024
TABLE OF CONTENTS
I.
SUMMARY ............................................................................................................................ 3
II.
NOTICES AND COMMUNICATIONS ................................................................................ 5
III. REGULATORY BACKGROUND ........................................................................................ 6
A.
Regulatory Framework ....................................................................................................... 6
B.
NERC Reliability Standards Development Procedure ....................................................... 7
IV. THE NEED FOR RIDE-THROUGH STANDARDS ADDRESSING INVERTER-BASED
RESOURCES ................................................................................................................................. 7
A. Disturbances on the BPS Indicate that IBRs are Failing to Ride-through as they Should to
Maintain Reliability. ................................................................................................................... 7
B. NERC Efforts to Address Reliability Risks with IBRs failing to Ride-Through System
Disturbances................................................................................................................................ 8
C. Order No. 901 Directs NERC to Develop Reliability Standards to Address Concerns
Related to IBRs at “All Stages of Interconnection, Planning, and Operations” ....................... 10
1.
V.
Order No. 901 Ride-through Directives........................................................................ 12
NERC’s Order No. 901 Work Plan....................................................................................... 14
A.
Project 2020-06 Verifications of Models and Data for Generators .................................. 15
B.
Project 2021-04 Modifications to PRC-002-2 Disturbance Monitoring........................... 16
C.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) ........................... 17
D. Project 2023-02 Analysis and Mitigation of BES Inverter-Based Resource Performance
Issues ......................................................................................................................................... 18
VI. JUSTIFICATION FOR APPROVAL: PROPOSED RELIABILITY STANDARD PRC029-1 ............................................................................................................................................. 19
A.
Proposed Definition of Ride-Through .............................................................................. 23
B.
Title and Purpose .............................................................................................................. 24
C.
Applicability ..................................................................................................................... 24
D.
Requirement R1 ................................................................................................................ 25
E.
Requirement R2 ................................................................................................................ 29
F.
Requirement R3 ................................................................................................................ 33
G.
Requirement R4 ................................................................................................................ 36
H.
Consideration of FERC Order No. 901 Directives ........................................................... 41
1. Paragraph 190 Directing Reliability Standards Addressing IBR Ride-through
Performance .......................................................................................................................... 41
2.
Paragraph 193: Consideration of Voltage Ride-Through Performance Exemptions.... 43
i
TABLE OF CONTENTS
3.
Paragraph 199: Mitigation of Reliability Impacts from Ride-through Exemptions ..... 46
4.
Paragraph 208: Post-Disturbance Ramp Rates Return to Pre-Disturbance Output ...... 47
5. Paragraph 209: Ride-Through Standards Must Address Different Types of Loss of
Synchronism ......................................................................................................................... 47
VII. JUSTIFICATION FOR APPROVAL: PROPOSED RELIABILITY STANDARD PRC024-4 ............................................................................................................................................. 49
A.
Title and Purpose .............................................................................................................. 51
B.
Applicability ..................................................................................................................... 51
C.
Requirements .................................................................................................................... 52
VIII. ENFORCEABILITY OF PROPOSED RELIABILITY STANDARDS .............................. 52
IX. EFFECTIVE DATE OF THE PROPOSED RELIABILITY STANDARDS....................... 52
X.
CONCLUSION ..................................................................................................................... 56
Exhibit A
Exhibit B
Exhibit C
Exhibit D
Exhibit E
Exhibit F
Exhibit G
Exhibit H
Exhibit I
Proposed Reliability Standards
A-1 Proposed Reliability Standard PRC-024-4 – Clean
A-2 Proposed Reliability Standard PRC-024-4 - Redline
A-3 Proposed Reliability Standard PRC-029-1
Implementation Plan
Order No. 672 Criteria
Consideration of Directives
Technical Rationale
E-1 Technical Rationale PRC-024-4
E-2 Technical Rationale PRC-029-1
Analysis of Violation Risk Factors and Violation Severity Levels
F-1 Analysis of Violation Risk Factors and Violation Severity Levels PRC-024-4
F-2 Analysis of Violation Risk Factors and Violation Severity Levels PRC-029-1
Summary of Development History and Complete Record of Development
Summary of Issues and Alternatives Considered Memo
Standard Drafting Team Roster
ii
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability Corporation
)
)
Docket No. _______
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF
PROPOSED RELIABILITY STANDARD(S) PRC-029-1 AND PRC-024-4
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 of the
regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”), 2 the
North American Electric Reliability Corporation (“NERC”) 3 hereby submits for Commission
approval proposed Reliability Standard PRC-029-1 Frequency and Voltage Ride-through
Requirements for Inverter-based Generating Resources, proposed Reliability Standard PRC-0244 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind
Plants, and Synchronous Condensers, and the proposed definition of the term Ride-through for
inclusion in the Glossary of Terms used in NERC Reliability Standards. 4 As discussed herein, the
proposed Reliability Standards would advance the reliability of the Bulk-Power System (“BPS”)
by establishing voltage and frequency ride-through criteria for Generator Owners of InverterBased Resources (“IBR”) to continue to inject current and perform voltage support during a BPS
disturbance and prohibit momentary cessation in the no-trip zone during disturbances.
1
16 U.S.C. § 824o.
18 C.F.R. § 39.5 (2024).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006) [hereinafter ERO Certification
Order].
4
The Glossary of Terms used in NERC Reliability Standards (“NERC Glossary” or “Glossary”) is available
on the NERC website at https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf. Unless
otherwise indicated, all capitalized terms used in this petition shall have the meaning set forth in the NERC Glossary.
2
1
The proposed Reliability Standards are an integral part of NERC’s proposed framework to
address IBR performance issues in a comprehensive and holistic manner. The proposed Reliability
Standards addressed in this filing are responsive to the Commission’s directives in Order No. 901
directing NERC to submit new or revised standards addressing IBR ride-through performance
requirements by November 4, 2024. 5 As discussed in detail below, the proposed Reliability
Standards are part of a set of standards that collectively respond to the Commission’s directives
for requirements addressing IBR ride-through settings, ride-through performance, data recording,
and analysis and mitigation of unexpected IBR performance. This proposed framework consists
of the following standards and definitions:
•
Proposed definition of the term Inverter-Based Resource, for inclusion in the
Glossary of Terms used in NERC Reliability Standards (separately filed,
concurrently with this petition);6
•
Proposed Reliability Standard PRC-028-1 – Disturbance Monitoring and Reporting
Requirements for IBR, with comprehensive disturbance monitoring and reporting
requirements to IBR (separately filed, concurrently with this petition);
•
Proposed Reliability Standard PRC-029-1 – Frequency and Voltage Ride-through
Requirements for IBR, with capability and performance-based requirements for
IBR Ride-through performance; and
•
Proposed Reliability Standard PRC-030-1 – Unexpected Inverter-Based Resource
Event Mitigation, requiring analysis and mitigation of IBR performance issues
(separately filed, concurrently with this petition).
5
Order No. 901, Reliability Standards to Address Inverter-Based Resources, 185 FERC ¶ 61,042 (2023)
[hereinafter Order No. 901].
6
The proposed definition for this term, which is used throughout the proposed Reliability Standards
addressed in the filing, as follows:
Inverter-Based Resource (IBR): A plant/facility consisting of individual devices that are capable of
exporting Real Power through a power electronic interface(s) such as inverter or converter, and that are
operated together as a single resource at a common point of interconnection to the electric system. IBRs
include, but are not limited to, plants/facilities with solar photovoltaic (PV), Type 3 and Type 4 wind, battery
energy storage system (BESS), and fuel cell devices.
2
NERC requests that the Commission approve the proposed Reliability Standards, provided
in Exhibit A hereto, as just, reasonable, not unduly discriminatory or preferential, and in the public
interest. NERC also requests approval of: (1) the associated Implementation Plan (Exhibit B); the
associated Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) (Exhibit F);
and the retirement of currently effective Reliability Standard PRC-024-3.
As required by Section 39.5(a) of the Commission’s regulations, 7 this petition presents the
technical basis and purpose of the proposed Reliability Standards, a summary of the development
history (Exhibit G), and a demonstration that the proposed Reliability Standards meet the criteria
identified by the Commission in Order No. 672 8 (Exhibit C). The NERC Board of Trustees
adopted the proposed Reliability Standards on October 8, 2024.
I.
SUMMARY
Multiple NERC disturbance reports, 9 including those analyzing the Blue Cut Fire10 and
Canyon 2 Fire,11 have demonstrated a risk to the reliability of the BPS when IBRs have failed to
ride-through system disturbances. Across multiple system events, a widespread loss of generating
resources – solar photovoltaic (“solar PV”), wind, synchronous generation, and battery energy
7
18 C.F.R. § 39.5(a).
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, 114 FERC 61,104 at
PP 262, 321-37 (2006) [hereinafter Order No. 672], order on reh’g, Order No. 672-A, 114 FERC 61,328 (2006).
9
See Event Reports involving IBRs entering into momentary cessation or tripping in the aggregate: (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), https://www.nerc.com/pa/rrm/ea/Pages/Major-Event-Reports.aspx.
10
NERC, 1,200 MW Fault Induced Solar Photovoltaic Resource Interruption Disturbance Report, Southern
California 8/16/2016 Event (Blue Cut Fire Disturbance Report) (June 2017),
https://www.nerc.com/pa/rrm/ea/1200_MW_Fault_Induced_Solar_Photovoltaic_Resource_/1200_MW_Fault_Induc
ed_Solar_Photovoltaic_Resource_Interruption_Final.pdf.
11
Joint NERC and WECC Staff Report, 900 MW Fault Induced Solar Photovoltaic Resource Interruption
Disturbance Report (Canyon 2 Fire 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%20Disturbance%20Report.pdf.
8
3
storage systems (“BESS”) – have abnormally tripped, ceased current injection, or reduced power
output with control interactions. BPS-connected generating resources remaining connected during
normal and contingency conditions is a critical component of BPS reliability; the unexpected loss
of widespread generating assets poses a significant risk to BPS reliability. Generator ride-through
is a foundational essential reliability service. Ensuring fault ride-through capability enables
dynamic reactive power support, frequency response, and other services.
For this reason, NERC identified the need for a comprehensive Ride-through Reliability
Standard for IBRs. 12 This need was further reinforced when the Commission issued Order No.
901, directing the development of new or modified Reliability Standards to address risks
associated with IBRs, including new requirements for disturbance monitoring data sharing, IBR
performance requirements, and post-event performance validation.
Proposed Reliability Standard PRC-029-1 would address the important reliability issue of
IBR Ride-through performance through capability and performance-based requirements for IBRs.
Consistent with the relevant Commission directives in Order No. 901, proposed PRC-029-1 would
advance reliability by: (1) establishing a clear understanding of what it means for a generator to
Ride-through a disturbance; (2) establishing voltage and frequency Ride-through criteria for IBRs
to prevent the unnecessary tripping and momentary cessation of current due to phase lock loop
loss of synchronism; and (3) ensuring that post-disturbance ramp rates return to pre-disturbance
levels.
With the development of proposed Reliability Standard PRC-029-1 addressing IBRs, it
became necessary to revise the applicability of currently effective Reliability Standard PRC-0243, which addresses frequency and voltage settings for generating resources. Proposed Reliability
12
See Exhibit G, Complete Record of Development at item 17.
4
Standard PRC-024-4 would revise the applicable facility types to exclude IBRs and to include type
1 and type 2 wind resources and synchronous condensers. NERC determined there is no reliability
need to impose actual disturbance Ride-through requirements on these resources, and that
restrictions for frequency and voltage protection setting ranges would continue to be appropriate.
Together the proposed Reliability Standards would help ensure that applicable BPS connected
resources would Ride-through system disturbances and avoid the negative reliability impacts
associated with unnecessary tripping and momentary cessation.
For these reasons, which are summarized here and stated more fully below, NERC requests
that the Commission approve the proposed Reliability Standards and Ride-through definition,
provided in Exhibit A hereto, as just, reasonable, not unduly discriminatory or preferential, and in
the public interest.
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following: 13
Lauren A. Perotti*
Assistant General Counsel
Alain Rigaud*
Associate Counsel
North American Electric Reliability
Corporation
1401 H Street NW
Suite 410
Washington, D.C. 20005
202-400-3000
Lauren.perotti@nerc.net
Alain.rigaud@nerc.net
Soo Jin Kim*
Vice President, Engineering and Standards
Jamie Calderon*
Director, Standards Development
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560
Soo.jin.kim@nerc.net
Jamie.calderon@nerc.net
13
Persons to be included on the Commission’s service list are indicated with an asterisk. NERC requests
waiver of 18 C.F.R. § 385.203(b) to permit the inclusion of more than two people on the service list.
5
III.
REGULATORY BACKGROUND
A.
Regulatory Framework
By enacting the Energy Policy Act of 2005, 14 Congress entrusted the Commission with the
duties of approving and enforcing rules to ensure the reliability of the BPS, and with the duty of
certifying an ERO that would be charged with developing and enforcing mandatory Reliability
Standards, subject to Commission approval. Section 215(b)(1) of the FPA states that all users,
owners, and operators of the BPS in the United States will be subject to Commission-approved
Reliability Standards. 15 Section 215(d)(5) of the FPA authorizes the Commission to order the ERO
to submit a new or modified Reliability Standard. 16 Section 39.5(a) of the Commission’s
regulations requires the ERO to file for Commission approval each Reliability Standard that the
ERO proposes should become mandatory and enforceable in the United States, and each
modification to a Reliability Standard that the ERO proposes to make effective. 17
The Commission has the regulatory responsibility to approve Reliability Standards that
protect the reliability of the BPS and to ensure that such Reliability Standards are just, reasonable,
not unduly discriminatory or preferential, and in the public interest. Pursuant to Section 215(d)(2)
of the FPA and Section 39.5(c) of the Commission’s regulations, the Commission will give due
weight to the technical expertise of the ERO with respect to the content of a Reliability Standard.18
14
15
16
17
18
16 U.S.C. § 824o.
Id. § 824(b)(1).
Id. § 824o(d)(5).
18 C.F.R. § 39.5(a).
16 U.S.C. § 824o(d)(2); 18 C.F.R. § 39.5(c)(1).
6
B.
NERC Reliability Standards Development Procedure
The proposed Reliability Standards were developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 19 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual. 20 In its ERO
Certification Order, the Commission found that NERC’s proposed rules provide for reasonable
notice and opportunity for public comment, due process, openness, and a balance of interests in
developing Reliability Standards and thus satisfies certain criteria for approving Reliability
Standards. 21 The development process is open to any person or entity with a legitimate interest in
the reliability of the BPS. NERC considers the comments of all stakeholders. Further, a vote of
stakeholders and adoption by the NERC Board of Trustees is required before NERC submits the
Reliability Standard to the Commission for approval.
IV.
THE NEED FOR RIDE-THROUGH STANDARDS ADDRESSING INVERTERBASED RESOURCES
A.
Disturbances on the BPS Indicate that IBRs are Failing to Ride-through as
they Should to Maintain Reliability.
In 2017, following a series of grid disturbances involving IBRs, NERC developed the
Inverter-Based Resources Performance Task Force, or IRPTF. This group undertook a
comprehensive review of all NERC Reliability Standards to determine if there were opportunities
to address gaps or otherwise improve the standards to assure reliability considering the
unprecedented growth of IBRs on the BPS.
19
Order No. 672 at P 334.
The NERC Rules of Procedure, including Appendix 3A, NERC Standard Processes Manual, are available
at http://www.nerc.com/AboutNERC/Pages/Rules-of-Procedure.aspx.
21
ERO Certification Order at P 250.
20
7
In 2019, the IRPTF published a white paper summarizing its work. Among other things,
the IRPTF highlighted issues with the then effective PRC-024 Reliability Standard, PRC-024-2 Generator Frequency and Voltage Protective Relay Settings. 22 In this white paper, the IRPTF
found that misinterpretation of the requirements of Reliability Standard PRC-024-2 led to the
intentional and unnecessary tripping of solar PV resources during the Blue Cut Fire 23 and Canyon
2 Fire 24 disturbances because some entities misinterpreted the area outside of the “No Trip” curve
as a “Must-Trip” requirement instead of as a “May-Trip” zone. The intent of the PRC-024-2
voltage ride-through requirement was to define the minimum and maximum voltage conditions
where generating resources may trip from protective relaying for voltage excursions. The IRPTF
recommended that clarifications to the standard be made so entities would know that being outside
a “No-Trip” zone does not mean the unit must trip, but rather it may trip to protect its equipment.
To address this misinterpretation, NERC initiated Project 2018-04 Modifications to PRC024-2 to address the IRPTF recommendations. Project 2018-04 Modifications to PRC-024-2
developed the currently effective version of the PRC-024 Reliability Standard, PRC-024-3 Frequency and Voltage Protection Settings for Generating Resources in 2019 that the Commission
approved in 2020.25
B.
NERC Efforts to Address Reliability Risks with IBRs failing to RideThrough System Disturbances.
While Reliability Standard PRC-024-3 addressed the misinterpretation identified in the
IRPTF report, events were still occurring following its development where IBRs were failing to
22
NERC IRPTF PRC-024-2 Gaps Whitepaper (Mar. 2020),
https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/NERC
_IRPTF_PRC-024-2_Gaps_Whitepaper_FINAL_CLEAN.pdf [hereinafter “IRPTF White Paper”].
23
Blue Cut Fire Disturbance Report supra note 10.
24
Canyon 2 Fire Disturbance Report, supra note 11.
25
N. Am. Elec. Reliability Corp., Docket No. RD20-7-000 (July 9, 2020). Reliability Standard PRC-024-3
became effective in the United States on October 1, 2022.
8
Ride-through a disturbance. 26 These events made it clear that additional Reliability Standard
requirements were needed to comprehensively address the issue of IBRs failing to Ride-through
system disturbances. Reliability Standard PRC-024-3 is an equipment settings standard focused
solely on voltage and frequency protection, and, in turn, does not address risks associated with
IBR Ride-through capabilities.
In 2022, following its analysis of over 10 disturbances involving widespread loss of IBRs,
NERC revised and repurposed an existing project to modify the PRC-024 standard, Project 202002 Transmission Connected Resources, to address IBR Ride-through performance. The purpose
of Project 2020-02 Modifications to PRC-024 (Generator Ride-Through) was to retire Reliability
Standard PRC-024-3 and replace it with a performance-based Ride-through standard that ensures
generators remain connected to the BPS during system disturbances. The Standard Authorization
Request for the project provided:
Across all events, a widespread loss of generating resources – solar PV, wind,
synchronous generation, and battery energy storage systems (BESS) – have
abnormally tripped, ceased current injection, or reduced power output with control
interactions. Generator ride-through is a foundational essential reliability service.
BPS-connected generating resources remaining connected during normal and
contingency conditions is a critical component of BPS reliability. Ensuring fault
ride-through capability enables dynamic reactive power support, frequency
response, and other services. The unexpected loss of widespread generating assets
poses a significant risk to BPS reliability.27
The Project 2020-02 drafting team determined that Ride-through performance
requirements for IBRs should be addressed by a separate standard from synchronous resources
because of the different natures of synchronous resources and IBRs, including their risks,
performance, and equipment capabilities. During the drafting team’s development of a
performance-based standard for IBRs in proposed Reliability Standard PRC-029-1, the
26
27
Event Reports, supra note 9.
See Exhibit G, Complete Record of Development at item 17.
9
Commission issued Order No. 901, directing the development of Reliability Standards for IBRs,
including Reliability Standards to address IBR ride through performance. Accordingly,
development of proposed Reliability Standard PRC-029-1 was aligned with the Commission’s
directives in Order No. 901 related to performance requirements for registered IBRs, which are
described further below.
C.
Order No. 901 Directs NERC to Develop Reliability Standards to Address
Concerns Related to IBRs at “All Stages of Interconnection, Planning, and
Operations”
On October 19, 2023, the Commission issued Order No. 901, 28 directing the development
of Reliability Standards to address IBRs. In Order 901, and preceding Notice of Proposed
Rulemaking, the Commission cites multiple ERO resources on IBR issues, including reliability
guidelines, white papers, reliability assessments, technical reports, event reports, NERC alerts, and
other resources, as underscoring the need for mandatory Reliability Standards to address reliability
concerns related to IBRs at “all stages of interconnection, planning, and operations.” 29 While the
Commission acknowledged that NERC and industry groups had efforts underway to address the
reliability risks associated with IBRs, the Commission directed NERC to address specific
reliability gaps because the existing Reliability Standards do not adequately address the reliability
risks posed by the increasing numbers of IBRs connecting to the BPS. 30 The Commission directed
NERC to develop new and revised Reliability Standards to address the following four topic areas
28
29
30
See Order No. 901.
Id. at P 25.
Id. at Section III.
10
of IBR issues: (1) data sharing; 31 (2) data and model validation; 32 (3) planning and operational
studies; 33 and (4) performance requirements. 34
Within these four topic areas, the Commission identified the specific reliability issues that
must be addressed. In so doing, the Commission distinguished between IBRs currently registered
with NERC for compliance purposes, or will be in the future based on the approved revisions in
the IBR Registration Approval Order (“registered IBRs”); 35 IBRs that are not registered with
NERC (“unregistered IBRs”) but which need to be modeled for reliability; and IBRs that are
connected to the distribution system, but, in the aggregate, can impact BES reliability (“IBRDERs”). 36 NERC was directed to develop responsive standards and submit them to the
Commission on a three-year, staggered timeframe.
With respect to the implementation of the directed standards modifications, the
Commission stated, “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 rule prior to that date.”37
31
See Order No. 901 at PP 66-109 (discussion of directives related to data sharing requirements).
See id. at PP 110-161 (discussion of directives related to data and model validation requirements).
33
See id. at PP 162-177 (discussion of directives related to planning and operational studies requirements).
34
See id. at PP 178-211 (discussion of directives related to performance requirements).
35
On November 22, 2022, the Commission issued an order directing NERC to undertake actions to expand
the class of IBRs that are required to register with NERC and comply with NERC Reliability Standards.
Registration of Inverter-Based Resources, 181 FERC ¶ 61,124 (2022) [hereinafter IBR Registration Order].
Specifically, the Commission directed NERC to explain how it will identify and register owners and operators of
IBRs that are connected to the Bulk-Power System, but are not required to register with NERC under the Bulk
Electric System definition, that have an aggregate material impact on the reliable operation of the Bulk-Power
System.” Id. at P 1.
The Commission approved NERC’s proposed expansion of the Generator Owner and Generator Operator
registry criteria to encompass additional IBRs in an order issued June 27, 2024. Order Approving Revisions to North
American Electric Reliability Corporation Rules of Procedure and Requiring Compliance Filing, 187 FERC ¶
61,196 (2024) [hereinafter IBR Registration Approval Order].
36
Order No. 901 at P 4 n.14.
37
Order No. 901 at P 226.
32
11
Additionally, the Commission directed NERC to submit an informational filing, within 90
days of the date of the order, detailing a comprehensive standards development plan and
explanation of how NERC would prioritize the development of new or modified Reliability
Standards. 38 This work plan is described in Section V infra.
1. Order No. 901 Ride-through Directives
Citing the NERC disturbance reports and white papers, the Commission directed NERC to
develop new or revised Reliability Standards to require Generator Owners of registered IBRs to
meet ride-through performance requirements. The Commission stated:
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 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, postdisturbance ramp rates, phase lock loop synchronization, and other
known causes of IBR tripping or momentary cessation.39
The Commission recognized that there may be instances where an exemption to the ridethrough requirements may be necessary and directed NERC to consider if such an exemption
would be appropriate in its standard development process as follows:
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
38
39
Order No. 901 at P 222.
Id. at P 190.
12
for certain registered IBRs from voltage ride-through performance
requirements. Any such exemption should be only for voltage ridethrough 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. 40
The Commission also directed that if NERC determined that an exemption was necessary
from Ride-through requirements, to develop standards to mitigate the reliability impacts of said
exemption as follows:
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, we direct NERC to develop new or
modified Reliability Standards to mitigate the reliability impacts to
the Bulk-Power System of such an exemption. 41
The Commission directed NERC to develop post-disturbance ramp rate requirements as
follows:
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 postdisturbance ramp rates for registered IBRs to be unrestricted and not
programmed to artificially interfere with the resource returning to a
pre-disturbance output level in a quick and stable manner after a
Bulk-Power System. 42
The Commission directed NERC to address in its IBR Ride-through standards the different
types of loss synchronism as follows:
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
40
41
42
Id. at P 193.
Id. at P 199.
Id. at P 208.
13
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 predisturbance levels during a disturbance, consistent with the IBR
Interconnection Requirements Guideline and Canyon 2 Fire Event
Report recommendations. 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. 43
V.
NERC’S ORDER NO. 901 WORK PLAN
On January 17, 2024, NERC submitted its Informational Filing that included its Order No.
901 Work Plan.44 NERC detailed how it will leverage the multiple standards development projects
planned or already underway to address IBR-related risks and add new projects as necessary, to
ensure that the reliability issues identified by the Commission in Order No. 901 are addressed
appropriately through the standards development process. The Order No. 901 Work Plan consists
of four key milestones with associated dates for completion, which are consistent with the
Commission’s direction in Order No. 901, to help ensure that the process proceeds in an orderly
and timely manner. These milestones are summarized below:
•
Milestone 1: Submission of Order No. 901 Work Plan (completed: January 17,
2024)
•
Milestone 2: Development and Filing of Reliability Standards to Address
Performance Requirements and Post-Event Performance Validation for Registered
IBRs (completion: November 4, 2024)
•
Milestone 3: Development and Filing of Reliability Standards to Address Data
Sharing and Model Validation for all IBRs (completion: November 4, 2025)
43
Id. at P 209.
Informational Filing of the North American Electric Reliability Corporation Regarding the Development of
Reliability Standards Responsive to Order No. 901, Docket No. RM22-12-000 (Jan. 17, 2024) [hereinafter Order
No. 901 Work Plan].
44
14
Milestone 4: Development and Filing of Reliability Standards to Address Planning
and Operational Studies Requirements for all IBRs (completion: November 4,
2026).
•
Relevant to this filing, NERC initiated the following standards project to meet the goals set
in Milestone 2 of the Order 901 Work Plan:
•
•
•
•
Project No. 2020-06, Verifications of Models and Data for Generators,
Project No. 2021-04, Modifications to PRC-002-2 Disturbance Monitoring,
Project No. 2020-02 Modifications to PRC-024 (Generator Ride-through), and
Project No. 2023-02 Analysis and Mitigation of BES Inverter-Based Resource
Performance Issues
The standards projects associated with Milestone 2 address IBR performance during
disturbances commonly referred to as “Ride-through”. These standards will focus on how to
adequately monitor, analyze, report, and mitigate IBR performance during a disturbance that
occurs in “ride-through” periods.
As relevant to the instant petition and discussed in detail in Section VI(H), proposed
Reliability Standard PRC-029-1 addresses the Commission’s Order No. 901 directives relating to
IBR Ride-through performance, described in the previous section, by requiring that Generator
Owners of IBRs ride through voltage and frequency excursions within the zones defined in the
standard. Proposed Reliability Standard PRC-024-4 proposes to remove IBR from Reliability
Standard PRC-024 to maintain capability-based requirements for synchronous generators,
synchronous condensers, and asynchronous type 1 and type 2 wind generation. A summary of the
Reliability Standards developed to address the Milestone 2 directives is provided below.
A.
Project 2020-06 Verifications of Models and Data for Generators
Addressed in a separate filing filed concurrently with this petition, Project 2020-06
Verifications of Models and Data for Generators proposes to establish a new defined term,
Inverter-Based Resource (“IBR”), for inclusion in the NERC Glossary, as follows:
15
Inverter-Based Resource (IBR): A plant/facility consisting of
individual devices that are capable of exporting Real Power through
a power electronic interface(s) such as an inverter or converter, and
that are operated together as a single resource at a common point of
interconnection to the electric system. Examples include, but are not
limited to, plants/facilities with solar photovoltaic (PV), Type 3 and
Type 4 wind, battery energy storage system (BESS), and fuel cell
devices.
The proposed definition of Inverter-Based Resource (“IBR”) would establish a consistent
understanding of the meaning of the term across all NERC Reliability Standards going forward.
This term is used throughout the Order No. 901 Work Plan Milestone 2 Reliability Standards
discussed below.
B.
Project 2021-04 Modifications to PRC-002-2 Disturbance Monitoring
Addressed in a separate filing filed concurrently with this petition, Project 2021-04
Modifications to PRC-002-2 Disturbance Monitoring 45 proposes to establish a new Reliability
Standard PRC-028-1, Disturbance Monitoring and Reporting Requirements for IBRs, to create
new capability-based requirements disturbance monitoring and reporting for IBRs. The purpose of
proposed Reliability Standard PRC-028-1 would be “[t]o have adequate data available from
Inverter-Based Resources to evaluate Inverter-Based Resource ride-through performance during
system disturbances and to provide data for Inverter-Based Resource model validation.” The data
collected under proposed Reliability Standard PRC-028-1 would be used to inform other
Reliability Standards for Milestone 2, 3, and 4 as actual IBR performance is a core component of
Order No. 901.
45
Project 2021-4 Modifications to PRC-002 – Phase II, https://www.nerc.com/pa/Stand/Pages/Project-202104-Modifications-to-PRC-002-2.aspx
Project 2021-04 Modifications to PRC-002 – Phase II,
https://www.nerc.com/pa/Stand/Pages/Project-2021-04-Modifications-to-PRC-0022.aspxhttps://www.nerc.com/pa/Stand/Pages/Project-2021-04-Modifications-to-PRC-002-2.aspx.
16
Proposed Reliability Standard PRC-028-1, Requirement R4, provides that Generator
Owners would have continuous dynamic disturbance recording data and storage to determine the
electrical quantities for each main power transformer(s) it owns. This data collected under PRC028-1 would be used to inform the analysis conducted under PRC-030-1 following an IBR
performance issue. The data collected under PRC-028-1 will be essential for assessing ongoing
ride-through performance for the purposes of modeling under Milestone 3. In addition, Project
2021-04 Modifications to PRC-002-2 Disturbance Monitoring proposes to remove IBR as
applicable facilities from PRC-002, as the framework of that standard remains sufficient for
synchronous resources.
C.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Project 2020-02, Modifications to PRC-024, 46 proposes to establish a new Reliability
Standard PRC-029-1, Frequency and Voltage Ride-through Requirements for Inverter-based
Resources, to create capability-based and performance-based requirements for IBR ride-through
performance. As discussed in detail herein, Proposed Reliability Standard PRC-029-1 would
“ensure that IBRs Ride-through to support the BPS during and after defined frequency and voltage
excursions.”
Proposed Reliability Standard PRC-029-1 would establish ride-through performance
criteria and focus on the evaluation and documentation of ride-through capability. The proposed
PRC-029-1 is generally an event-based standard though it is also required to provide evidence of
46
Project 2020-02 Modifications to PRC-024 (Generator Ride-through),
https://www.nerc.com/pa/Stand/Pages/Project_2020-02_Transmission-connected_Resources.aspx Project 2020-02
Modifications to PRC-024 (Generator Ride-through), https://www.nerc.com/pa/Stand/Pages/Project_202002_Transmission-connected_Resources.aspxhttps://www.nerc.com/pa/Stand/Pages/Project_2020-02_Transmissionconnected_Resources.aspx.
17
the capability to ride-through future grid disturbances by means such as dynamic models and
simulation results.
In addition, Project 2020-02, Modifications to PRC-024, proposes to remove IBR from
Reliability Standard PRC-024 to maintain capability-based requirements for synchronous
generators, synchronous condensers, and asynchronous type 1 and type 2 wind generation.
D.
Project 2023-02 Analysis and Mitigation of BES Inverter-Based Resource
Performance Issues
Addressed in a separate filing filed concurrently with this petition, Project 2023-03,
Analysis and Mitigation of BES Inverter-Based Resource Performance Issues, 47 proposes to
establish new Reliability Standard PRC-030-1 to create new risk-based requirements for IBR
Generator Owners related to IBR Performance. Proposed Reliability Standard PRC-030-1 would
require Generator Owners to identify any complete facility loss of output, or changes in Real Power
output that are at least 20 MW and at least 10% of the plant’s gross nameplate rating, occurring
within a four second period. 48 Generator Owners would then be required to analyze their IBR
facility performance during the event, for the purpose of determining the root cause(s) of change(s)
in Real Power output; documenting the facility’s ride-through performance including Reactive
Power response during the event; assessing any performance issues identified and if corrective
actions are needed; and determining the applicability of the root cause(s) to the Generator Owner’s
other IBR facilities. As discussed below, the data from proposed Reliability Standard PRC-028-1
47
Project 2023-02 Analysis and Mitigation of BES Inverter-Based Resource Performance Issues,
https://www.nerc.com/pa/Stand/Pages/Project-2023-02-Performance-of-IBRs.aspx.
48
Changes in Real Power for the following are excluded: changes associated with intermittent primary energy
source availability, created by changes such as variation in wind speed and solar irradiance; resource dispatch,
resource ramping, planned outages, or planned resource testing; a Transmission or collection system loss that, by
configuration, disconnects the Inverter-Based Resource generator; or Real Power reduction due solely to a
Protection System Misoperations being analyzed and corrected under PRC-004 Reliability Standard.
18
and the ride-through criteria established in proposed Reliability Standard PRC-029-1 would inform
the analysis of ride-through performance in PRC-030-1.
Upon request, the analysis results would be provided to the requesting associated
Reliability Coordinator, Balancing Authority, or Transmission Operator. If performance issues and
a need for corrective actions are identified in the analysis, the Generator Owner would develop
and communicate to the associated Reliability Coordinator, Balancing Authority, and
Transmission Operator either a Corrective Action Plan for the identified IBR, including other
applicable facilities owned by the Generator Owner, or a technical justification that addresses why
corrective actions would not be taken. The Corrective Action Plan would then be implemented
with any changes communicated to the associated Reliability Coordinator.
Collectively, the proposed Reliability Standards would enhance the reliability of the BPS
by addressing critical IBR reliability issues in accordance with Milestone 2 of NERC’s Order No.
901 Work Plan.
VI.
JUSTIFICATION FOR APPROVAL: PROPOSED RELIABILITY STANDARD
PRC-029-1
Proposed Reliability Standard PRC-029-1 addresses a gap in the currently effective
Reliability Standards related to IBR ride-through performance during system disturbances. BPS
connected generating resources remaining connected during normal and contingency conditions is
a critical component of BPS reliability. Ensuring fault ride-through capability enables dynamic
Reactive Power support, frequency response, and other services. Multiple NERC disturbance
reports involving IBRs have shown that the unexpected and widespread loss of generating assets
poses a significant risk to BPS reliability. Proposed Reliability Standard PRC-029-1 would address
this issue and advance the reliability of the BPS by establishing frequency and voltage Ride-
19
through performance criteria for IBRs to prevent unnecessary tripping or momentary cessation of
current injection.
The currently effective Reliability Standards related to disturbance monitoring and
generator performance during system disturbances were developed with a focus on synchronous
generation resources. This focus was appropriate as it reflected the generation mix that comprised
the BPS at the time they were originally developed. 49 As the resource mix is transforming to
include an increasing amount of IBRs, 50 a different approach that takes into consideration the
technical and operational characteristics of IBRs is needed to ensure reliability going forward.
While IBRs can produce Real and Reactive Power like synchronous generators, IBRs do
not react to disturbances on the BPS in the same way. Traditional synchronous resources that are
not connected to a fault will automatically ride through 51 a disturbance because they are
synchronized (i.e., connected at identical speeds) to the electric power system and physically
linked to support the system voltage or frequency during voltage or frequency fluctuations by
continuing to produce Real and Reactive Power due to their inherent inertia.
In contrast, IBRs are not directly synchronized to the electric power system and must be
programmed to support the electric power system and to ride-through a disturbance. The
operational characteristics of IBRs coupled with their equipment settings may cause them to reduce
49
PRC-024-3 and PRC-002 are the standards for ride-through and disturbance monitoring, respectively.
See e.g., 2020 Long Term Reliability Assessment Report at 9 (Dec. 2020),
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2
020.pdf (2020 LTRA Report); 2021 Long Term Reliability Assessment Report at 29 (Dec. 2021).
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2021.pdf. (NERC projects
IBR nameplate capacity additions of approximately 504 GW of solar and 360 GW of wind (i.e., a total nameplate
capacity of 864 GW) and cumulative retirements of approximately 60 GW of nuclear, coal, natural gas, and biomass
to the Bulk-Power System over the next decade.)
51
See Standardization of Generator Interconnection Agreements & Procs., Order No. 2003, 104 FERC ¶
61,103, at P 562 n.88, (2003). (defining ride through as “a Generating Facility staying connected to and
synchronized with the Transmission System during system disturbances within a range of over- and underfrequency[/voltage] conditions, in accordance with Good Utility Practice.”).
50
20
power output, whether by tripping offline 52 or ceasing to inject current without tripping offline
(known as momentary cessation), 53 individually or in the aggregate in response to a single fault on
a transmission or sub-transmission system. Thus, the 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 an interconnection. This is of particular concern because
currently many simulations inaccurately predict that IBRs will maintain Real Power output and
provide voltage and frequency support consistent with the purpose of Reliability Standard PRC024-3.
Unless 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 BPS and make up an increasing proportion of the
resource mix. As evaluated in past NERC reports and white papers, a controller and protection
setting standard has been insufficient at ensuring actual IBR performance during voltage and
frequency disturbances, contributing to a growing reliability issue.
For these reasons, the Project 2020-02 drafting team determined that Ride-through
performance requirements for IBRs should be addressed by a separate standard from synchronous
resources that account for the characteristics of IBRs, including their risks, performance, and
equipment capabilities, as demonstrated in several recent events exhibiting significant IBR ride-
52
Tripping offline is a mode of operation during which part of or the entire IBR disconnects from the BulkPower System and therefore cannot supply Real and Reactive Power.
53
NERC, Reliability Guideline BPS-Connected Inverter-Based Resource Performance at p. 11 (Sept. 2018)
(IBR Performance Guideline) (Momentary cessation is a mode of operation during which the inverter remains
electrically connected to the Bulk-Power System, but the inverter does not inject current during low or high voltage
conditions outside the continuous operating range. As a result, there is no current injection from the inverter and
therefore no active or reactive current (and no active or reactive power))
https://www.nerc.com/comm/RSTC_Reliability_Guidelines/Inverter-Based_Resource_Performance_Guideline.pdf.
21
through deficiencies. 54 As result, the drafting team developed a new standard, PRC-029-1, to
address the Ride-through performance of IBRs, and that PRC-024-4 would be revised to only be
applicable to synchronous generators, type 1 and 2 wind plants, and synchronous condensers.
Proposed Reliability Standard PRC-029-1 addresses the reliability issues identified in
multiple NERC events reports and Order No. 901 by preventing unnecessary tripping or
momentary cessation of current due to phase lock loop loss of synchronism or other causes and
ensuring post-disturbance ramp rates return to pre-disturbance levels. Where the need for an
exemption exists, due to hardware limitations on legacy equipment, proposed Reliability Standard
PRC-029-1 ensures that it is documented, communicated to all relevant entities, accepted by the
Compliance Enforcement Authority, and that the entity operates to whatever its capability is to
mitigate potential reliability impacts. In so doing, proposed Reliability Standard PRC-029-1
addresses the Commission’s directives to address IBR ride-through issues in Order No. 901.
NERC developed the proposed Reliability Standard using NERC’s standards development
process. This process included multiple public comment and ballot periods. Notably, the NERC
Board of Trustees initiated the use of Section 321 of the NERC Rules of Procedure at its August
15, 2024 meeting for this project in order to meet the Commission’s timeline set forth in Order
No. 901 directives. Section 321 allows the NERC Board of Trustees to take special actions when
a ballot pool has failed to approve a proposed Reliability Standard that contains a provision to
adequately address a specific matter identified in a directive. Under this special authority, the
NERC Board of Trustees directed the NERC Standards Committee to work with NERC Staff to
convene a technical conference to gather input from industry to address the outstanding issues and
revise PRC-029-1. The technical conference took place on September 4-5, 2024, and it focused on
54
Event Reports supra note 9.
22
unresolved issues raised by stakeholders during the PRC-029-1 comment periods. Proposed
Reliability Standard PRC-029-1 was revised based on the input from the technical conference and
received the required weighted segment approval of the ballot body during its last ballot period
from September 24 through October 4, 2024. The NERC Board of Trustees adopted the proposed
Reliability Standards on October 8, 2024. A full summary of development is included in Exhibit
G.
In this section, NERC provides an overview of the proposed Reliability Standard, with a
summary of the supporting rationale, and demonstrates how proposed Reliability Standard PRC029-1 is consistent with and addresses the directives in paragraphs 190, 193, 199, 208 and 209 of
Order No. 901, listed above in Section IV(C)(1).
Additional information may be found in the Consideration of Directives included as
Exhibit D, Summary of Issues and Alternatives Considered Memo included as Exhibit H,
Technical Rationale for Proposed Reliability Standard PRC-029-1, included as Exhibit E-2 to this
petition, as well as the Complete Record of Development, included as Exhibit G.
A.
Proposed Definition of Ride-Through
Proposed Reliability Standard PRC-029-1 uses the term “Ride-through”, which NERC
proposes to include in the NERC Glossary. The proposed definition is:
Ride-through: The plant/facility remains connected and continues to operate through
voltage or frequency system disturbances.
Under the NERC Standard Processes Manual, definitions themselves may not include
statements of performance requirements. The addition of the term Ride-through within the NERC
Glossary would establish a consistent understanding of the meaning of the term across all NERC
Reliability Standards going forward and clarify what is expected for a plant or facility to Ridethrough a disturbance. The specific performance requirements and measures to demonstrate Ride23
through are to be found within the Requirements and Attachments of proposed Reliability Standard
PRC-029-1. This term is used in proposed Reliability Standard PRC-030-1 as well. References to
“Ride-through criteria” in proposed Reliability Standard PRC-030-1 allow for those additional
analytics to include further evaluations with PRC-029-1 Ride-through performance requirements
as appropriate, while preventing duplication of those performance requirements in different
Reliability Standards.
B.
Title and Purpose
The title of proposed Reliability Standard PRC-029-1 is Frequency and Voltage Ridethrough Requirements for Inverter-based Resources. The purpose of proposed Reliability Standard
PRC-029-1 is: “To ensure that IBRs Ride-through to support the Bulk Power System (BPS) during
and after defined frequency and voltage excursions.”
C.
Applicability
Proposed Reliability Standard PRC-029-1 is applicable to Generator Owners that own: (1)
BES IBRs; and (2) non-BES IBRs that either have or contribute to an aggregate nameplate capacity
of greater than or equal to 20 MVA, connected through a system designed primarily for delivering
such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
The proposed standard includes as applicable entities those Generator Owners that own
IBRs meeting the Bulk Electric System definition criteria, which have traditionally been subject
to registration for compliance with NERC Reliability Standards. It also includes those Generator
Owners that own the non-BES IBRs that NERC will register in accordance with revisions to its
24
Rules of Procedure approved by the Commission in 2024. 55 As such, the applicability of proposed
Reliability Standard PRC-029-1 is consistent with paragraph 190 of Order No. 901, in which the
Commission directed NERC to develop Reliability Standards that require registered IBRs to ridethrough frequency and voltage system disturbances, continue to inject current and perform
frequency support during a BPS disturbance, and prohibit momentary cessation in the no-trip zone
during disturbances, and 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.
D.
Requirement R1
Proposed Reliability Standard PRC-029-1 Requirement R1 establishes requirements that
all applicable IBRs will Ride-through grid voltage disturbances consistent with the “must Ridethrough zone” and operation regions specified in Attachment 1. Proposed Requirement R1 would
provide as follows:
R1.
Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements, in accordance with the “must Ridethrough1 zone” as specified in Attachment 1, except in the following conditions:
[Violation Risk Factor: High] [Time Horizon: Operations Assessment]
•
The IBR needed to electrically disconnect in order to clear a fault;
•
The voltage at the high-side of the main power transformer2 went outside an
accepted hardware limitation, in accordance with Requirement R4;
55
See IBR Registration Approval Order, supra note 38 Presently, the NERC Glossary defines the Generator
Owner as the “Entity that owns and maintains generating Facility(ies)”, with the term “Facility” defined as “A set of
electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt
compensator, transformer, etc.).” NERC has initiated a separate, high priority project, Project 2024-01 Rules of
Procedure Definitions Alignment (Generator Owner and Generator Operator), to align the definitions of Generator
Owner and Generator Operator in the Glossary with the recently approved versions of those terms as used in the
NERC Rules of Procedure. The first phase of this project is scheduled for completion in early 2025. Additional
information on this project is available at https://www.nerc.com/pa/Stand/Pages/Project-2024-01-Rules-ofProcedure-Definitions-Alignment_GO-and-GOP.aspx.
25
•
The instantaneous positive sequence voltage phase angle change is more than 25
electrical degrees at the high-side of the main power transformer and is initiated
by a non-fault switching event on the transmission system3; or
•
The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than 2
seconds.
[1] Includes no tripping associated with phase lock loop loss of synchronism.
[2] For the purpose of this standard, the main power transformer is the power transformer that steps up voltage
from the collection system voltage to the nominal transmission/interconnecting system voltage for IBRs. In
case of IBR connecting via a dedicated Voltage Source Converter High Voltage Direct Current (VSCHVDC), the main power transformer is the main power transformer on the receiving end.
[3] Current blocking mode may be used for non-fault initiated phase jumps greater than 25 degrees in order
to prevent tripping.
Under Requirement R1, Generator Owners of IBRs must be able to demonstrate Ridethrough performance by not tripping or entering momentary cessation and must continue to
exchange current and remain electrically connected, consistent with the magnitude and duration
performance criteria in Attachment 1 of proposed PRC-029-1. Momentary cessation is when an
inverter is temporarily current blocking while still remaining connected. Requirement R1 restricts
momentary cessation to only two system conditions: 1) non-fault line switching caused voltage
phase angle jumps in excess of 25 degrees that could result in tripping unless the inverter goes into
current blocking, and 2) while voltage at the plant-system interface is less than 0.10 per unit during
which time it may be difficult or impractical to maintain current exchange.
The drafting team determined that the terminology for “must Ride-through zones” and
“operation regions” should be consistent with those terms as used within IEEE 2800-2022. 56 The
“must Ride-through zones” are defined in terms of voltage and frequency magnitude and time
duration. Usage of the term “must Ride-through zone,” compared to the term “No trip zone,” was
56
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 BulkPower System).
26
also determined to prevent industry from inaccurately interpreting everything outside to be a “must
trip zone”. While tripping of IBR plants is permitted outside of the defined “must Ride-through
zones,” protection and controllers should be set in accordance with the actual capability of the
IBR. Additionally, the drafting team determined that the voltage thresholds of each operation
region should be based on measurements taken on the high-side of the main power transformer,
which is also consistent with IEEE 2800-2022. BESS units also must comply with Requirement
R1 in all operating modes including charging, discharging, and idle (energized, but not charging
or discharging). A BESS in idle mode must be capable of responding to system voltage and
frequency excursions as it does in charging or discharging modes.
These Ride-through zones were established based on the drafting team’s experience with
voltage and frequency excursions in planning and operating criteria disturbances, underfrequency
load shedding stages, reasonable and practical limits of IBR voltage and frequency tolerances, and
Reliability Standard PRC-024-3 voltage and frequency relay setting graphs. These include
adequate margins against worst-case conditions that could be brought about during system
disturbances. During the development of proposed Reliability Standard PRC-029-1, the drafting
team proposed more stringent (i.e., more broad) criteria than those used in IEEE 2800-2022 due
to the anticipated decrease in System inertia caused by the continual changing resource mix.
Considering comments from industry received throughout the standard development process and
discussion during the technical conference convened under Section 321 of the NERC Rules of
Procedure, the frequency must Ride-through zones were changed to be more similar to IEEE 28002022 Ride-through zones. The frequency Ride-through zones are more robust than the currently
effective in PRC-024-3 and require demonstration of performance. The proposed frequency Ride-
27
through criteria is sufficient to address the recommendations identified in current NERC event
reports and assessments.
Phase lock loop loss of synchronism poses a significant risk to reliability by causing IBRs
to unexpectedly trip offline. When a grid disturbance occurs, such as a close-in fault or a relatively
large switching event, the grid voltage may experience a rapid phase angle shift. In such cases, the
phase angle displacement can be large enough to pose challenges for the phase lock loop to track
the terminal voltage, cause control instability within the inverter, such as the inner current control
loop or the DC link control loop, and even lead to tripping of the inverter due to the malfunction
of the controls. Since phase angle jumps are common occurrences on the BPS, the proposed
standard requires the IBR to be designed and operated to Ride-through a minimum phase angle
jump of 25 electrical degrees. This is a typical value and aligns with the requirement in IEEE 28002022. Some IBR equipment has phase lock loop loss of synchronism protection, referring to a
protective function that operates when the phase angle displacement exceeds a threshold for a
predetermined period of time (on the order of a couple of milliseconds). Historically, this
protection has been used by some inverter manufacturers, especially for inverters in distribution
systems. For the IBR connected to the BPS, this protection function should be disabled. If it is
enabled, the phase angle jump protection setting should be configured such that the IBR shall only
trip to prevent equipment damage. Tripping due to phase lock loop loss of synchronism is
specifically not permitted within voltage and frequency must Ride-through zones.
The proposed Reliability Standard provides for the following exceptions to Attachment 1
performance criteria: 1) an IBR needs to trip to clear a fault; 2) voltage at the high-side of the main
power transformer goes outside an accepted and a documented hardware equipment limitation
established in accordance with Requirement R4; 3) instantaneous positive sequence voltage phase
28
angle jumps more than 25 electrical degrees at the high-side of the main power transformer
initiated by a non-fault switching events occur on the transmission system; or 4) volts per Hz
(V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for longer than 45
seconds or exceed 1.18 per unit for longer than 2 seconds. These exemptions are considered
reasonable limits to ensure system stability during a voltage phase angle while protecting the
hardware from incurring damage.
E.
Requirement R2
Proposed Reliability Standard PRC-029-1 Requirement R2 establishes voltage Ridethrough performance criteria during system disturbances for all applicable IBRs. Acceptable
performance criteria depend on the operation region that an IBR is presently in or when in
transition from one operation region to another operation region. Proposed Requirement R2 would
provide as follows:
R2. Each Generator Owner shall ensure the design and operation is such that the voltage
performance for each IBR adheres to the following during a voltage excursion, unless a
documented hardware limitation exists in accordance with Requirement R4. [Violation
Risk Factor: High] [Time Horizon: Operations Assessment]
2.1. While the voltage at the high-side of the main power transformer remains within
the continuous operation region as specified in Attachment 1, each IBR shall:
2.1.1. Continue to deliver the pre-disturbance level of Real Power or available
Real Power4, whichever is less.5
2.1.2. Continue to deliver Reactive Power up to its Reactive Power limit and
according to its controller settings.
2.1.3. Prioritize Real Power or Reactive Power when the voltage is less than 0.95
per unit, the voltage is within the continuous operating region, and the IBR
cannot deliver both Real Power and Reactive Power due to a current limit
or Reactive Power limit, unless otherwise specified through other
mechanisms by an associated Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator.
2.2. While voltage at the high-side of the main power transformer is within the
mandatory operation region as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support, on
29
the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under6:
•
Reactive Power priority by default; or
•
Real Power priority if required through other mechanisms by an associated
Transmission Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator.
2.3. While voltage at the high-side of the main power transformer is within the
permissive operation region, as specified in Attachment 1, each IBR may operate
in current blocking mode if necessary to avoid tripping. Otherwise, each IBR shall
follow the requirements for the mandatory operation region in Requirement R2.2.
2.3.1. If an IBR enters current blocking mode, it shall restart current exchange in
less than or equal to five cycles of positive sequence voltage returning to a
continuous operation region or mandatory operation region.
2.4. Each IBR shall not itself cause voltage at the high-side of the main power
transformer to exceed the applicable high voltage thresholds and time durations in
its response as voltage recovers from the mandatory or permissive operation
regions to the continuous operation region.
2.5. Each IBR shall restore Real Power output to the pre-disturbance or available
level7 (whichever is lesser) within 1.0 second when the voltage at the high-side of
the main power transformer returns from the mandatory operation region or
permissive operation region (including operating in current blocking mode) to the
continuous operation region, as specified in Attachment 1, unless an associated
Transmission Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator requires a lower post-disturbance Real Power level
requirement or requires a different post-disturbance Real Power restoration time
through other mechanisms.8
[4] “Available Real Power" refers to changes of facility Real Power output attributed to factors such as
weather patterns, change of wind, and change in irradiance, but not changes of facility Real Power attributed
to IBR tripping in whole or part.
[5] Except if this would occur during a frequency excursion. The Real Power response should recover in
accordance with the primary frequency controller.
[6] In either case and if required, the magnitude of Real Power and reactive current shall be as specified by
the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
[7] “Available Real Power" refers to changes of facility Real Power output attributed to factors such as
weather patterns, change of wind, and change in irradiance, but not changes of facility Real Power attributed
to IBR tripping in whole or part.
[8] Except if this would occur during a frequency excursion. The Real Power response should recover in
accordance with the primary frequency controller.
Under Requirement R2, a Generator Owner must adhere to the specific performance
criteria that is needed to assure consistent IBR performance within each operation region in
30
Attachment 1 and when in transition between regions. A default post-disturbance ramp rate of 1.0
second is specified unless a faster or slower rate is specified by the Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator to accommodate specific system
post-disturbance recovery needs. Any Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator specified ramp rate becomes the standard requirement.
Requirement R2 Part 2.1 would ensure that when the voltage at the high-side of the main
power transformer (“MPT”) recovers to the continuous operation region from either the mandatory
operation region or the permissive operation region, an IBR delivers the pre-disturbance level of
Real Power or available Real Power, whichever is less. “Available Real Power” allows for changes
of facility Real Power output attributed to factors such as weather patterns, change of wind, and
change in irradiance, but not changes attributed to IBR tripping in whole or part. This requires an
IBR to exit the “High Voltage Ride Through (“HVRT”)” or “Low Voltage Ridge Through
(“LVRT”)” modes properly such that it does not cause reduction in the Real Power when the highside of MPT voltage recovers to within the continuous operation region. When the voltage at the
high-side of the MPT is greater than 0.90 per-unit and less than 0.95 per-unit, IBRs are expected
to exit the LVRT mode and come back to “normal operating mode”. If an IBR has a default total
current limit of 1.0 per-unit, the apparent power production of an IBR will be limited below 1.0
per-unit (e.g., the per-unit value of IBR terminal voltage). In such case, the IBR needs to configure
a preference setting, either to maintain pre-disturbance Real Power or maximize the Reactive
Power to further help with voltage recovery, or according to requirements specified by the
Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
Requirement R2 Part 2.2 would ensure that when the voltage at the high-side of the MPT
is within the mandatory operation region, IBRs inject or absorb reactive current proportional to
31
the level of terminal voltage deviations they measure. For each IBR, the Generator Owner shall
follow Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission
Operator specified certain magnitude of Reactive Power response to voltage changes, if available.
By default, reactive current prioritization shall be configured unless Transmission Planner,
Planning Coordinator, Reliability Coordinator, or Transmission Operator requires Real Power
priority.
Requirement R2 Part 2.3 would ensure that when the voltage at the high-side of the MPT
is within the permissive operation region, IBRs continue to Ride-through, though they are briefly
allowed to enter the current block mode if necessary to avoid tripping off from the grid. In
developing this provision, the drafting team took into consideration the physical operational
capability of the power electronics devices under such low voltage conditions. The IBR shall
restart current exchange in less than or equal to five cycles of positive sequence voltage returning
to the continuous operation region or mandatory operation region. If the interconnecting entity has
performance requirements that are more stringent than the standard, the Generator Owner should
follow the requirements set by the interconnecting entity.
Requirement R2 Part 2.4 would ensure that, when a fault is cleared on the transmission
system, the voltage regulators of connected IBRs must adjust the reactive current injection to
restore the transmission system voltage to the pre-disturbance voltage as defined by the automatic
voltage regulator (“AVR”) setpoint. It was considered that tuning of the AVR requires a balance
between multiple competing physical factors, e.g., rise time, overshoot, and transient stability.
However, it is anticipated that IBR controls will be tuned to allow for a stable post-disturbance
voltage recovery without causing excessive overshoot or undershoot of the setpoint. When such
overshoots do occur, they must not exceed the magnitudes and durations specified in the applicable
32
table given in Attachment 1. Furthermore, the proposed standard anticipates that control system
tuning to prevent such over/under voltages will focus on the speed at which the controller responds
to setpoint changes rather than on the magnitude of the reactive current response. For example,
reductions in k-factor to prevent over/under voltages should only be considered as a last resort.
Requirement R2 Part 2.5 would ensure that the IBR returns to effective pre-disturbance
operation unless otherwise specified or needed by the Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator. The voltage recovery within 1
second from a disturbance is consistent with IEEE-2800 and there was no technical basis to deviate
from that time duration. Ensuring that IBRs can return to pre-disturbance operation is vital to
reliability. Post-disturbance injection should be coordinated by Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator because injecting current at predisturbance levels during the recovery from a disturbance may overcorrect in some localized areas
that is not always practical or desirable for reliability.
F.
Requirement R3
Proposed Reliability Standard PRC-029-1 Requirement R3 establishes Ride-through
requirements for all applicable IBRs during frequency excursion events. Proposed Requirement
R3 would provide as follows:
R3. Each Generator Owner shall ensure the design and operation is such that each IBR meets
or exceeds Ride-through requirements during a frequency excursion event whereby the
System frequency remains within the “must Ride-through zone” according to
Attachment 2 and the absolute rate of change of frequency (RoCoF)9 magnitude is less
than or equal to 5 Hz/second, unless a documented hardware limitation exists in
accordance with Requirement R4. [Violation Risk Factor: High] [Time Horizon:
Operations Assessment]
[9] Rate of change of frequency (RoCoF) is calculated as the average rate of change for multiple calculated
system frequencies for a time period of greater than or equal to 0.1 second. RoCoF is not calculated during
the fault occurrence and clearance.
33
Under proposed Requirement R3, IBRs would be required to remain electrically connected
and continue to exchange current during a frequency excursion event in which the frequency
remains within the must Ride-through zone according to Attachment 2 and while the absolute rate
of change of frequency (“RoCoF”) magnitude is less than or equal to 5 Hz/second. Some IBR
controllers are sensitive to RoCoF, particularly auxiliary equipment that are essential for IBR
performance, during a frequency excursion event.
Under Requirement R3, IBRs would be allowed to trip for an absolute RoCoF exceeding
5Hz/sec within the must Ride-through zone of Attachment 2 to maintain the stability of the IBR
or prevent equipment damage. Failure to Ride-through due to RoCoF exceeding 5Hz/sec shall only
be allowed during a generator/load imbalance event that causes the frequency to deviate from
nominal. Additionally, IBR frequency protection settings should only be set to protect the IBR
from damage caused by operation at off-nominal frequency. The IBR Generator Owner must
ensure that the IBR frequency protection does not prevent an IBR from being able to Ride-through
in accordance with Requirement R3.
Analysis of the Blue Cut Fire event 57 found that a significant amount of solar PV resources
incorrectly determined a frequency deviation that triggered protection systems, causing those IBR
to trip. These IBR controllers were not set to calculate frequency over a window of time and
averaged to verify controller measurements. Under
Requirement
R3,
frequency must
be
calculated as the average rate of change over multiple calculated system frequencies for some time
greater than or equal to 0.1 seconds to minimize this kind of misoperation tripping of IBRs on the
RoCoF setting. The RoCoF calculation is not applicable during the occurrence and clearance of a
fault (i.e., protection should not trip due to any perceived RoCoF during the entire disturbance and
57
Supra note 10.
34
recovery period), and the IBR should not trip at the onset of a fault, during a fault, or at fault
clearance due to the ROCOF calculation, i.e., this controller setting should be disabled during
faults. The RoCoF calculation should begin after fault clearance and is only applicable for
generation/load imbalance disturbances such as a system separation, an island condition, or the
loss of a large load or generator.
Requirement R3 additionally requires IBR Ride-through when the calculated RoCoF is
equal to or less than 5 Hz/s. This magnitude and threshold criteria is consistent with IEEE 28002022 and determined to be necessary to address anticipated increases of deviations from nominal
grid frequency. Nominal grid frequency reflects a balance of system generation and load. A system
event that causes a generation/load imbalance will cause system frequency to deviate from
nominal. The system may experience an over-frequency event (in the case of more generation than
load) or an under-frequency event (in the case of less generation than load). System inertia resists
deviation from nominal frequency, giving system operators additional time to rebalance generation
and load. System inertia is dependent on the amount of rotating mass connected to the system (i.e.,
synchronous generators or motors). The larger the system inertia, the slower the system frequency
will deviate from the nominal value and the lower the grid RoCoF, giving more time to try to
rebalance generation and load. As the grid continues to experience a shift towards generation that
does not have rotating mass, planners and operators must account for increasing system frequency
deviations from nominal values.
A reduction in system inertia is an inevitable consequence of a power system transitioning
toward more IBR and less synchronous generators; however, the utilization of IBR-specific control
features (i.e., advanced control modes and grid forming technologies) can provide additional
stability benefits to help mitigate the loss of inertia. As discussed in the previous paragraph, less
35
system inertia means the frequency will deviate from the nominal value more quickly during a
generation/load imbalance event and will expose the system to a higher RoCoF.
To avoid the risk of widespread tripping, proposed Reliability Standard PRC-029-1
Attachment 2 provides a wider frequency Ride-through band than presently exists in Reliability
Standard PRC-024-3 Attachment 2. This is consistent with IEEE 2800-2022, which contains
frequency Ride-through times and thresholds are more stringent (i.e. wider) than those presently
in Reliability Standard PRC-024-3 and contain continuous operation ranges that exceed the
frequency excursions observed during major BPS disturbances. Additionally, detailed feedback
from original equipment manufacturers (“OEM”) provides insight that they are already designing
IBR equipment that conforms with the criteria in IEEE 2800-2022. Aligning the frequency Ridethrough criteria in proposed Reliability Standard PRC-029-1 with those in IEEE 2800-2022
provides a meaningful benefit to reliability while also minimizing cost and timeline implications
as OEM are already designing conforming equipment.
G.
Requirement R4
Proposed Reliability Standard PRC-029-1 Requirement R4 allows for IBRs that are already
existing and in operation at the time proposed PRC-029-1 goes into effect (“legacy IBRs”) to
obtain an exemption to the voltage and frequency Ride-through requirements if hardware
replacements would be necessary to comply with Requirements R1 through Requirement R3.
Proposed Requirement R4 would provide as follows:
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of
PRC-029-1, has known hardware limitations that prevent the IBR from meeting Ridethrough criteria as detailed in Requirements R1-R3, and requires an exemption from
specific Ride-through criteria shall:10 [Violation Risk Factor: Lower] [Time Horizon:
Long-term Planning]
36
4.1. Document information supporting the identified hardware limitation no later than
12 months following the effective date of PRC-029-1. This documentation shall
include:
4.1.1. Identifying information of the IBR (name and facility number);
4.1.2. Which aspects of Ride-through requirements that the IBR would be unable
to meet and the capability of the hardware due to the limitation;
4.1.3. Identification of the specific piece(s) of hardware causing the limitation;
4.1.4. Technical documentation verifying the limitation is due to hardware that
would need to be physically replaced to meet all Ride-through criteria, and
that the limitation cannot be remedied by software updates or setting
changes; and
4.1.5. Information regarding any plans to remedy the hardware limitation (such
as an estimated date).
4.2. Provide a copy of the information detailed in Requirement R4.1, except for any
material considered by the original equipment manufacturer to be proprietary
information, to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the Compliance
Enforcement Authority (CEA) no later than 12 months following the effective
date of PRC-029-1.11
4.2.1. Provide any response for additional information requested by the
associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA to the
requestor within 90 days of the request.
4.2.2. Provide a copy of the acceptance of a hardware limitation by the CEA to
the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s) within 90 days
of receiving the acceptance. 11
4.3. Each Generator Owner with a previously accepted limitation that replaces the
hardware causing the limitation shall document and communicate such a
hardware change to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s) within 90
days of the hardware change.
4.3.1. When existing hardware causing the limitation is replaced, the exemption
for that Ride-through criteria no longer applies.
Under Requirement R4, Generator Owners owning legacy IBRs would be allowed
exemptions from the voltage or frequency Ride-through performance criteria in Requirements R1R3 if such limitations are documented and communicated to the Planning Coordinator,
Transmission Planner, Reliability Coordinator, and Transmission Operator of the respective
37
footprints in which the IBR is located. The Planning Coordinator, Transmission Planner,
Reliability Coordinator, and Transmission Operator would then need to take the voltage or
frequency Ride-through limitations into account in planning and operations.
The drafting team determined that an exemption to the Ride-through performance criteria
was necessary for legacy IBRs because of the hardware limitations associated with those facilities.
Specifically, it was determined that the anticipated difficulty of Generator Owners having to
wholesale retrofit and redesign legacy facilities currently in operation would be unreasonable and
unduly burdensome, and it could lead to undesirable impacts on reliability. Entities would be
required to take units offline to retrofit or risk noncompliance and could choose to retire the units
instead of retrofit based on economic considerations. A proposed IBR Ride-through standard
having no exemptions could result in a resource capacity deficiency due to these retired units and
thus lead to a substantial negative impact to reliability of the BPS.
A Generator Owner may seek an exemption from both the voltage and frequency Ridethrough criteria. In Order No. 901 the Commission only directed NERC to consider if an
exemption from the voltage Ride-through criteria was necessary. After reviewing stakeholder
feedback on the draft standard, the drafting team concluded that an exemption to the frequency
Ride-through criteria would also be necessary and appropriate. During the technical conference
convened under Section 321, the Standards Committee and NERC Staff included a panel
discussion on frequency exemptions. Panelists discussed various challenges related to legacy IBR,
such as difficulties obtaining more detailed information on equipment capabilities; specifically for
manufacturers who are no longer in business and for IBR that are no longer supported by the
manufacturer. Other concerns raised included the possibility that manufacturers would not be
38
willing to provide design or hardware limitation documentation should they identify the
information to be proprietary information. 58
Following the technical conference, NERC staff and the Standards Committee determined
that a frequency exemption to the Ride-through criteria was necessary, in addition to the voltage
exemption contemplated in Order No. 901, because of hardware-based capability limitations due
to manufacture design for a significant amount of installed IBRs. Without a frequency exemption,
these legacy IBRs may be required to go offline to refit to comply with proposed Reliability
Standard PRC-029-1. It was determined that a potential disconnection of a large amount of
installed IBR capacity overwhelmingly indicated a reliability need to allow for a documented and
limited set of exemptions for IBR from voltage and frequency ride-through criteria. In light of this
reliability concern, Requirement R4 of proposed Reliability Standard PRC-029-1 allows for a
documented, and limited, set of exemptions for IBR from frequency Ride-through criteria. This
exemption process is discussed below.
Under Requirement R4 Part 4.1, the IBR Generator Owner must document the need for an
exemption. The documentation must identify the hardware that prevents the IBR from meeting
Ride-through criteria, describe the aspect(s) of the Ride-through criteria that cannot be met, and
provide information regarding what the IBR is capable of despite the limitation. Any exemptions
due to hardware limitations must not be construed as complete exemptions from the applicable
Ride-through criteria in Attachment 1. Exemptions must be specific and limited to the voltage or
frequency band(s) and associated duration(s) that cannot be satisfied or as to the number of
cumulative voltage deviations within a ten-second time period that the equipment can Ride-
58
See Exhibit G Complete Record of Development at item 14, Day 2 Recording and Transcript of the
Standards Committee & NERC Ride-through Technical Conference; Project 2020-02 Modifications to PRC-024
(Generator Ride-through) Related Files; posted September 18, 2024.
39
through if its less than four deviations within any ten-second time period. For this reason, when
describing the hardware limitations, the Generator Owner must identify the specific equipment
and explain the characteristic(s) of that equipment that prevent Ride-through.
Under Requirement R4 Part 4.2, this Generator Owner must submit such information to
the Transmission Planner, Planning Coordinator, Reliability Coordinator, Transmission Operator,
and Compliance Enforcement Authority. Further, the IBR must perform in accordance with the
capability of the plant, accounting for the limitation, for those criteria identified in the
documentation for exemption.
Under Requirement R4 Part 4.2.1, the Generator Owner is required to supply further
information on the need for and the nature of the exemption if requested by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, Transmission Operator, or Compliance
Enforcement Authority.
Under Requirement R4 Part 4.2.2, the Compliance Enforcement Authority must accept that
all aspects of the documentation specified in proposed Requirement R4 have been provided by the
Generator Owner before an exemption can granted. This would ensure that NERC has visibility
into each hardware exemption that is granted and that they have been accurately limited to the
particular limitation of the hardware. NERC would work with the Regional Entities to develop a
framework for evaluating any exemption submissions in a fair and consistent manner across the
ERO Enterprise. NERC would also monitor the use of this process and the disposition of requests
as the proposed standard is implemented. To the extent NERC determines any further action would
be prudent, it would be dependent on the volume and nature of the hardware limitations being
submitted for Compliance Enforcement Authority acceptance. NERC will consult with
Commission staff as it performs this oversight activity.
40
Under Requirement R4 Part 4.3, if the hardware causing the limitation is replaced and the
limitation is removed, then the exemption no longer applies. The IBR Generator Owner must
communicate to the Planning Coordinator, Transmission Planner, Reliability Coordinator, and
Transmission Operator of the hardware and change to anticipated performance within 90 days of
the hardware replacement. This is to ensure that all IBRs capable of fully complying with the Ridethrough criteria in Requirements R1-R3 do so as soon as possible.
H.
Consideration of FERC Order No. 901 Directives
Proposed Reliability Standard PRC-029-1 is responsive to the Commission’s performance
directives in paragraphs 190, 193, 199, 208 and 209 of Order No. 901, described above in Section
IV(C)1. The Commission directed NERC to develop performance-based Reliability Standards that
require IBRs to Ride-through system disturbances and require post-disturbance ramp rates to
return to pre-disturbance levels. The Commission further directed NERC to determine if an
exemption from Ride-through criteria is necessary and, if so, that it is only for a limited and
documented set of existing IBRs, and that NERC develop new or modified Reliability Standards
to mitigate the reliability impact of any such exemptions. The following discussion summarizes
how proposed Reliability Standard PRC-029-1 addresses these directives, as further discussed in
the Consideration of Directives included as Exhibit D hereto.
1. Paragraph 190 Directing Reliability Standards Addressing IBR Ride-through
Performance
In paragraph 190 of Order No. 901, the Commission issued several directives for NERC
related to Reliability Standards for IBRs to Ride-though system disturbances. Each of these are
addressed in turn below.
First, the Commission directed NERC to require that registered IBRs “ride through
frequency and voltage system disturbances and that permit IBR tripping only to protect the IBR
41
equipment in scenarios similar to when synchronous generation resources use tripping as
protection from internal faults.” 59 To address the reliability concerns for the voltage component of
this directive, proposed Reliability Standard PRC-029-1 Requirement R1 would require registered
Generator Owners of IBRs to both design and operate their IBR plants to Ride-through voltage
excursions within “must Ride-through zones” according to how these zones are defined in the
standard. Proposed Reliability Standard PRC-029-1 Requirement R3 would require the same
design and operation Ride-through requirements for Ride-through frequency excursions. The must
Ride-through zones used within the requirements and Attachments are defined in terms of voltage
and frequency magnitudes and time durations. Tripping of IBR plants is permitted only outside of
the defined must Ride-through zones.
Second, in paragraph 190, the Commission directed NERC to require that registered IBRs
“continue to inject current and perform frequency support during a Bulk-Power System
disturbance.” 60 NERC addresses this directive in proposed Reliability Standard PRC-029-1
Requirements R1-R3. These requirements would require IBRs to Ride-through system
disturbances. The proposed Ride-through definition states that IBR facilities must remain
connected and continue to fulfill their established control and regulation functions (which
generally involve exchange of current) to qualify as riding through system disturbances. Support
of frequency is predicated on, and to a large degree achieved by being able to Ride-through system
disturbances.
Third, in paragraph 190, the Commission directed NERC to develop requirements that
“prohibit momentary cessation in the no-trip zone during disturbances.”61 Proposed Reliability
59
60
61
Order No. 901 P 190.
Id.
Id.
42
Standard PRC-029-1 addresses this directive in Requirement R1, which would require IBRs to
meet or exceed Ride-through requirements in Attachment 1. As discussed above, these Ridethrough requirements would restrict the use of momentary cessation to the following two system
conditions: 1) non-fault line switching caused voltage phase angle jumps in excess of 25 degrees
that could result in tripping unless the inverter goes into current blocking; and 2) voltage at the
plant-system interface that is less than 0.10 per unit during which time it may be difficult or
impractical to maintain current exchange.
Lastly, in paragraph 190, the Commission directed NERC to require that registered IBRs
have “performance requirements, including requirements addressing frequency and voltage Ridethrough, post-disturbance ramp rates, phase lock loop synchronization, and other known causes of
IBR tripping or momentary cessation.”62 Proposed Reliability Standard PRC-029-1 addresses this
directive in Requirement R1. As noted above, Requirement R1 establishes IBR frequency and
voltage Ride-through requirements. The proposed requirement also specifies a default postdisturbance ramp rate of 1.0 second unless a faster or slower rate is specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator to
accommodate specific system post-disturbance recovery needs. Additionally, tripping due to phase
lock loop loss of synchronism is specifically not permitted within voltage and frequency must
Ride-through zones.
2. Paragraph 193: Consideration of Voltage Ride-Through Performance
Exemptions
In paragraphs 193 and 199 of Order No. 901, the Commission directed NERC to consider
whether the proposed new or revised Reliability Standard should contain exemptions to the Ride-
62
Id.
43
through performance requirements for those legacy IBRs that are currently in operation and unable
to meet the requirements.
First, in paragraph 193 of Order No. 901, the Commission directed NERC 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.” 63
As discussed more fully above, NERC has determined that a limited and documented exemption
for certain registered IBRs from voltage or frequency Ride-through performance requirements
would be appropriate. Thus, proposed Reliability Standard PRC-029-1 Requirement R4
establishes a process by which entities may obtain an exemption from the voltage or frequency
Ride-through criteria of PRC-029-1 Requirement R1 or Requirement R3 for IBR plants/facilities
that are in service at the effective date of the standard. Although Order No. 901 was silent regarding
the need for NERC to consider frequency Ride-through exemptions, NERC determined that
frequency exemptions were needed to address significant OEM design capability limits regarding
frequency thresholds. More information on why a frequency exemption was determined to be
necessary can be found in the discussion of Requirement R4, above, and in the Summary of Issues
and Alternatives Considered Memo included as Exhibit H.
In all cases, the IBR Generator Owner must document the need for an exemption, and the
documentation must explain what hardware prevents the IBR from meeting Ride-through criteria,
which aspect(s) of the Ride-through criteria that cannot be met, and information regarding what
the IBR is capable of despite the limitation. The Generator Owner must then submit this
information to the Transmission Planner, Planning Coordinator, Reliability Coordinator,
Transmission Operator, and Compliance Enforcement Authority. Further, the IBR must perform
63
Id. at P 193.
44
in accordance with the capability of the plant, accounting for the limitation, for those criteria
identified in the documentation for exemption. The Compliance Enforcement Authority checks
that all aspects of the documentation specified in Requirement R4 have been provided by the
Generator Owner, and the Generator Owner is required to supply further information on the need
for and the nature of the exemption if requested by the Transmission Planner, Planning
Coordinator, Reliability Coordinator, Transmission Operator, or Compliance Enforcement
Authority. The implementation plan provides a 12-month time window for exemption requests to
be submitted following the enforcement date. Following the 12-month window, further exemption
requests will not be accepted or could be considered an admission of non-compliance.
Second, in paragraph 193 the Commission directs 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…” 64 The exemption provision in Requirement R4 addresses this directive by
providing that exemptions are available only for IBR plants/facilities that are in service at the
effective date as noted above. The exemption provision also stipulates that once the plant/facility
hardware causing the limitation is replaced, the exemption no longer applies.
Lastly, in paragraph 193 the Commission directed NERC “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.”65 The exemption
provision in Requirement R4 addresses this directive as it requires an IBR Generator Owner to
64
65
Id.
Id.
45
supply its exemption request documentation to its Transmission Planner, Planning Coordinator,
Reliability Coordinator, and Transmission Operator within the 12-month window following the
effective date as noted above.
3. Paragraph 199: Mitigation of Reliability Impacts from Ride-through
Exemptions
In paragraph 199 of Order No. 901, the Commission directed NERC to mitigate the
reliability impacts to the Bulk-Power System of any exemptions from Ride-through
requirements. 66 The reliability impacts of voltage or frequency must Ride-through exemptions are
mitigated by existing NERC Reliability Standards addressing the responsibilities of Transmission
Planners, Planning Coordinators, Reliability Coordinators, and Transmission Operators. 67 These
entities routinely conduct evaluations of potential impacts to the grid for a variety of different
operating conditions, scenarios, and time windows. These entities have the obligation to require
Corrective Action Plans be developed in accordance with the requirements of those other standards
when such adverse system conditions exceeding acceptable thresholds are identified in the studies
required by those other standards. Additionally, under Milestone 4 of the Order No. 901 Work
Plan, NERC will develop Reliability Standards that will specifically require evaluations that
include accurately-modeled performance capabilities of IBR, inclusive of any documented Ridethrough criteria exemption accepted through the process detailed in proposed Reliability PRC029-1 Requirement R4, and that evaluate for reliability impacts on the BPS.
66
Id. at P 199.
See e.g. Reliability Standards; IRO-002-7 - Reliability Coordination - Monitoring and Analysis; IRO-0083 – Reliability Coordinator Operational Analyses and Real-time Assessments; TOP-002-4 — Operations Planning;
TPL-001-5.1 — Transmission System Planning Performance Requirements
67
46
4. Paragraph 208: Post-Disturbance Ramp Rates Return to Pre-Disturbance
Output
In paragraph 208 of Order No. 901, the Commission directed NERC to “develop and
submit to the Commission for approval new or modified Reliability Standards that require postdisturbance ramp rates for registered IBRs to be unrestricted and not programmed to artificially
interfere with the resource returning to a pre-disturbance output level in a quick and stable manner
after a Bulk-Power System disturbance event.” 68 Proposed Reliability Standard PRC-029-1
addresses this directive in Requirement R2. As noted above, Requirement R2 is responsive to this
directive because it has a default post-disturbance ramp rate of 1.0 second specified unless a faster
or slower rate is specified by the Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator to accommodate specific system post-disturbance recovery
needs. Any Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission
Operator specified ramp rate criteria becomes the standard required criteria for this aspect of Ridethrough performance.
5. Paragraph 209: Ride-Through Standards Must Address Different Types of
Loss of Synchronism
Paragraph 209 of Order No. 901 contains several directives for NERC regarding IBRs
ability to Ride-Through different types of loss of synchronism. Each of these are addressed in turn.
First, the Commission directed NERC to require that registered IBRs “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.” 69 Proposed
Reliability Standard PRC-029-1 addresses this directive in Requirement R1. As noted above, under
Requirement R1, phase lock loop loss of synchronism is not allowed as a cause of tripping while
68
69
Order No. 901 at P 208.
Id. at P 209.
47
voltage remains within the must Ride-through zone unless there are phase jumps more than 25
degrees caused by non-fault switching events. A footnote under Requirement R1 also specifically
states that phase lock loop loss of synchronism as not a permissible condition for tripping while
voltage remains within the must Ride-through zone.
Second, the Commission directed NERC to require that registered IBRs “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.” 70 Proposed Reliability Standard PRC-029-1 addresses this
directive in Requirements R1 and R2. As noted above, Requirement R1 specifically does not
permit tripping due to phase lock loop loss of synchronism within voltage and frequency must
Ride-through zones. Requirement R2 specifies that IBRs are required to have Real and Reactive
Power performance during voltage disturbances. Additionally, Requirement R2 requires IBRs to
return to pre-disturbance power injection. Requirement R2 Part R2.1.1 includes a provision to
return to “Available Active Power" to allow for “changes of facility Real Power output attributed
to factors such as weather patterns, change of wind, and change in irradiance.” However, “changes
of facility Real Power attributed to IBR tripping in whole or part” are not permitted under
Requirement R2 Part R2.1.1. The reason for this is to ensure clarity regarding allowable changes
due to changes in the IBR fuel source rather than due to any tripping of the IBR, in whole or in
part.
70
Id.
48
Lastly, the Commission directed NERC “to consider whether there are conditions that may
limit generators to maintain synchronism.” 71 NERC determined that IBRs are non-synchronous
but can exhibit forms of instability other than loss of synchronism. System stability is a shared
responsibility of Transmission Planners, Planning Coordinators, Reliability Coordinators, and
Transmission Operators. IBR generation levels may need to be restricted by these entities to
maintain System stability or to mitigate known System constraints to a localized area.
VII.
JUSTIFICATION FOR APPROVAL: PROPOSED RELIABILITY STANDARD
PRC-024-4
Proposed Reliability Standard PRC-024-4 contains revisions that would enable the
standard to be retained as a protection-based standard with applicability to only synchronous
generators, synchronous condensers, and type 1 and type 2 wind units. Proposed Reliability
Standard PRC-024-4 would continue to address frequency and voltage protection setting ranges
for synchronous units as they do not require performance-based requirements to Ride-through
disturbances. Additionally, consistent with the proposed definition of IBR developed under Project
2020-06, type 1 and 2 wind units are not considered IBRs. These wind turbine types operate as
asynchronous generating resources and do not have modern controllers capable of riding through
system events.
The revised standard applicability of proposed Reliability Standard PRC-024-4 is
supported by the different natures of synchronous and IBR generation resources, including their
risks, performance, and equipment capabilities. As described above, NERC’s Project 2020-02,
Modifications to PRC-024, was initiated by NERC in response to several event reports where
widespread loss of IBRs abnormally tripped, ceased current injection, or reduced power output
71
Id.
49
with control interactions. For the reasons described below, there is no need to impose actual
disturbance Ride-through requirements on synchronous units but only to include restrictions for
frequency and voltage protection setting ranges as maintained in PRC-024-4.
The behavior of rotating synchronous generators during faults and other disturbances on
the transmission system is well established and understood in comparison to IBR generation. The
disturbance Ride-through vulnerabilities of synchronous generators are pole slipping instability
and undervoltage dropout of critical plant auxiliary equipment, leading to tripping of a generator.
NERC determined that these issues did not need to be addressed in Project 2020-02, as pole
slipping (or loss of synchronism) can be managed by Real Power dispatch constraints or stability
System Operating Limits. Auxiliary equipment has not posed a Ride-through risk.
Over-frequency protection, under-frequency protection, over-voltage protection, and
under-voltage protection may or may not be applied to synchronous generating units. If applied,
settings should be coordinated between the needs of generating unit protection and the no-trip
zones within PRC-024-4 attachments. Coordination of generating unit capabilities, voltage
regulating controls, and protection is addressed within Reliability Standard PRC-019-2. Excitation
and governing controls affect synchronous generator Ride-through behavior to some degree but
because of progressive improvement, standardization, and level of maturity of these controls, they
are rarely a cause of unnecessary tripping during disturbances. In addition, there are other existing
NERC standards to prevent unnecessary tripping of the generators during a system disturbance
such as PRC-025-2 - Generator Relay Loadability and PRC-026-2 - Relay Performance During
Stable Power Swings.
50
NERC developed the proposed Reliability Standard using NERC’s standards development
process. This process included multiple public comment and ballot periods. The NERC Board of
Trustees adopted proposed Reliability Standard PRC-024-4 on October 8, 2024.
In this section, NERC provides an overview of the proposed Reliability Standard, with a
summary of the supporting rationale. Additional information may be found in the Technical
Rationale for Proposed Reliability Standard PRC-024-4, included as Exhibit E-1 to this
petition, as well as the Complete Record of Development, included as Exhibit G.
A.
Title and Purpose
The title of proposed Reliability Standard PRC-024-4 is – Frequency and Voltage
Protection Settings for Synchronous Generators, Type 1 and 2 Wind Plants, and Synchronous
Condensers. The purpose is to ensure that protection of synchronous generators, type 1 and type 2
wind resources, and synchronous condensers do not cause tripping during defined frequency and
voltage excursions in support of the BPS.
B.
Applicability
Proposed Reliability Standard PRC-024-4 is still applicable to Generator Owners and
Transmission Owners, as well as Planning Coordinators which are applicable entities only in the
Quebec Interconnection. The functional entity responsible for setting frequency, voltage, and volts
per hertz protection for synchronous generators, type 1 and 2 wind plants, and synchronous
condensers is either the Generator Owner or Transmission Owner. Modifications are proposed in
PRC-024-4 to expand functional entity applicability to include “Transmission Owners that apply
protection” because of the inclusion of synchronous condenser applicability in section 4.2.2.
The Applicable Facilities in subparts in Section 4.1.1 were modified to restrict PRC-024-4
to synchronous generators and type 1 and 2 wind plants. Section 4.2.2 was added to include
synchronous condensers and associated equipment.
51
C.
Requirements
Proposed Reliability Standard PRC-024-4 modifies Requirements R1, R2, R3, and R4 to
include the Transmission Owner as a functional entity applicable to each requirement due to the
addition of synchronous condensers in the applicable facilities. Additionally, modifications were
made to Requirements R1, R2, R3, and R4 to include language that relates to type 1 and 2 wind
plants and synchronous condensers and to remove language that relates to IBR functionality since
IBRs are addressed in proposed Reliability Standard PRC-029-1.
VIII. ENFORCEABILITY OF PROPOSED RELIABILITY STANDARDS
The proposed Reliability Standards include measures that support each requirement by
clearly identifying what is required and how the ERO will enforce the requirement. These
measures help ensure that the requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party. 72 Additionally, the proposed Reliability
Standards include VRFs and VSLs. The VRFs and VSLs provide guidance on the way that NERC
will enforce the requirements of the proposed Reliability Standards. The VRFs and VSLs for the
proposed Reliability Standards comport with NERC and Commission guidelines related to their
assignment. Exhibit F provides a detailed review of the VRFs and VSLs, and the analysis of how
the VRFs and VSLs were determined using these guidelines.
IX.
EFFECTIVE DATE OF THE PROPOSED RELIABILITY STANDARDS
NERC respectfully requests that the Commission approve the proposed Reliability
Standards to become effective as set forth in the proposed Implementation Plan, provided in
Exhibit B hereto. The proposed Implementation Plan provides that the proposed Reliability
Standards PRC-024-4 and PRC-029-1 shall become effective on the first day of the first calendar
72
Order No. 672 at P 327.
52
quarter that is twelve calendar months after the effective date of the Commission’s order approving
the proposed Reliability Standard. Currently effective Reliability Standard PRC-024-3 would be
retired immediately prior to the effective date of proposed Reliability Standard PRC-024-4. The
Implementation Plan for proposed PRC-029-1 provides phased-in compliance dates for both
capability and performance-based elements of Requirements R1, R2, and R3 for BES IBRs and
non-BES IBRs.
For BES IBRs, the implementation timeframe for capability-based elements is as follows.
Generator Owners shall comply with the portion of Requirements R1, R2, and R3 relating to the
design of their BES IBRs to meet the requirements by the effective date of the standard.
Additionally, the implementation timeframe for the exemption process in Requirement R4 is the
effective date of the standard.
For non-BES IBRs, the implementation timeframe for capability-based elements is as
follows. Generator Owners shall comply with the portion of Requirements R1, R2, and R3 relating
to the design of their applicable non-BES IBRs until the later of: (1) January 1, 2027; or (2) the
effective date of the standard. Additionally, the implementation timeframe for the exemption
process in Requirement R4 is the later of: (1) January 1, 2027; or (2) the effective date of the
standard.
For all IBRs, the implementation timeframe performance-based elements is as follows.
Generator Owners shall not be required to comply with the portion of Requirements R1, R2, and
R3 relating to the operation of IBRs to meet the requirements until the entity has established the
required disturbance monitoring equipment capabilities for those IBRs in accordance with the
53
implementation plan for proposed Reliability Standard PRC-028-1. 73 Under that plan, Generator
Owners will follow a phased-in compliance timeline with requirements to establish disturbance
monitoring capabilities fully implemented by January 1, 2030.
This Implementation Plan recognizes the need for this phased in compliance timeline so
entities can establish disturbance monitoring capabilities before having to comply with the
performance-based elements of proposed Reliability Standard PRC-029-1. Further, Generator
Owners and Generator Operators owning or operating BPS connected IBRs that do not meet
NERC’s current definition of BES will be registered no later than May 2026 in accordance with
the IBR Registration proceeding in FERC Docket No. RR24-2. To ensure an orderly registration
and compliance process for these entities, as well as fairness and consistency in the standard’s
application among similar asset types, the proposed Implementation Plan provides additional time
for both new and existing registered entities to come into compliance with new IBR Ride-through
requirements for their applicable IBRs not meeting the BES definition. In so doing, this
Implementation Plan advances an orderly process for new registrants while allowing existing
73
The proposed implementation plan for proposed Reliability Standards PRC-028-1 and PRC-002-5 provides
that the proposed standards would become effective the first calendar quarter following regulatory approval.
Implementation of PRC-028-1 would then follow a phased-in compliance timeline, ending by 2030. The relevant dates
under that plan are as follows:
BES IBRs: Generator Owners shall comply with requirements to establish disturbance monitoring data
recording capabilities for 50% of their existing BES IBRs (i.e. in commercial operation on or before the effective date)
within three calendar years of the effective date of PRC-029-1, and 100% of their BES IBRs by January 1, 2030. If a
Generator Owner has only one such BES IBR, it shall comply within three calendar years. For new BES IBRs,
Generator Owners shall comply within 15 calendar months following the effective date of the standard or by the
commercial operation date, whichever is later.
Non-BES IBRs: Generator Owners shall comply with requirements to establish disturbance monitoring data
recording capabilities for 100% of those non-BES IBRs in commercial operation prior to May 15, 2026 by no later
than January 1, 2030. Generator Owners shall comply with for their new non-BES IBRs within 15 calendar months
following the effective date of the standard or by the commercial operation date, whichever is later.
Additional information is available in Section VIII and Exhibit B to NERC’s Petition for Approval of
Proposed Disturbance Monitoring Reliability Standards PRC-028-1 and PRC-002-5 (Nov. 4, 2024).
54
entities to focus their immediate efforts on their assets posing the highest risk to the reliable
operation of the BPS.
Consistent with Order No. 672, the proposed implementation plan balances the urgency in
the need to implement new requirements for IBR Ride-through performance, a need which is
demonstrated in multiple NERC event reports and highlighted in Order No. 901, while providing
a reasonable amount of time for those who must comply to develop the necessary procedures,
software, facilities, staffing, or other relevant capability.74 The proposed implementation plan is
also consistent with the Commission’s directive in Order No. 901 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 rule prior to that date.”75
74
75
Order No. 672 at P 333.
Order No. 901 at P 226.
55
X.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve:
•
proposed Reliability Standards PRC-024-4 and PRC-029-1, and associated elements
included in Exhibit A, effective as proposed herein;
•
the proposed Implementation Plan included in Exhibit B; and
•
the retirement of Reliability Standard PRC-024-3 effective as proposed herein.
Respectfully submitted,
/s/ Alain Rigaud
Lauren A. Perotti
Assistant General Counsel
Alain Rigaud
Associate Counsel
North American Electric Reliability Corporation
1401 H Street NW, Suite 410
Washington, D.C. 20005
202-400-3000
Lauren.perotti@nerc.net
Alain.rigaud@nerc.net
Counsel for the North American Electric Reliability Corporation
Date: November 4, 2024
56
Exhibit A
Proposed Reliability Standards
RELIABILITY | RESILIENCE | SECURITY
Exhibit A-1
PRC-024-4 Clean
RELIABILITY | RESILIENCE | SECURITY
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 3 of PRC-024-4 is posted for final ballot. Non-substantive corrections were identified
during the last additional ballot. This draft includes those corrections.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process Manual
December 13, 2023
25-day formal comment period with initial ballot
March 27 - April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
Anticipated Actions
Date
Final ballot
September 25 –
September 30, 2024
Board Adoption
October 8, 2024
Final Draft of PRC-024-4
September 2024
Page 1 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Final Draft of PRC-024-4
September 2024
Page 2 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
A. Introduction
1.
Title:
Frequency and Voltage Protection Settings for Synchronous Generators,
Type 1 and Type 2 Wind Resources, and Synchronous Condensers
2.
Number:
PRC-024-4
3.
Purpose:
To assure that protection of synchronous generators, type 1 and type 2
wind resources, and synchronous condensers do not cause tripping
during defined frequency and voltage excursions in support of the Bulk
Power System (BPS).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Generator Owners that apply protection listed in Sections 4.2.1 or 4.2.2.
4.1.2. Transmission Owners that apply protection listed in Section 4.2.2.
4.1.3. Transmission Owners (in the Quebec Interconnection only) that own a
BES generator step-up (GSU) transformer or main power transformer
(MPT) 1 and apply protection listed in Section 4.2.1.
4.1.4. Planning Coordinators (in the Quebec Interconnection only)
4.2. Facilities 2:
4.2.1 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the generating resource(s); or (ii)
provide signals to the generating resource(s) to trip; and are applied to
the following:
4.2.1.1
Bulk Electric System (BES) synchronous generators.
4.2.1.2
BES GSU transformer(s) for synchronous generators.
4.2.1.3
High-side of the synchronous generator-connected unit
auxiliary transformer 3 (UAT) installed on BES generating
resource(s).
4.2.1.4
Individual dispersed power producing type 1 or type 2 wind
resource(s) identified in the BES Definition, Inclusion I4.
For the purpose of this standard, the MPT is the power transformer that steps up voltage from multiple small synchronous
generators (e.g. multiple small hydro generators connecting to a common bus) or from a type 1 or type 2 wind resource
collector station to transmission voltage .
2 It is not required to install or activate the protections described in Facilities Section 4.2.
3 These transformers are variously referred to as station power UAT, or station service transformer(s) used to provide overall
auxiliary power to the synchronous generators. This UAT is the transformer connected on the generator bus between the low
side of the GSU and the generator terminal.
1
Final Draft of PRC-024-4
September 2024
Page 3 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
4.2.1.5
Elements that are designed primarily for the delivery of
capacity from multiple synchronous generators connecting to
a common bus or individual dispersed power producing type 1
or type 2 wind resources identified in the BES Definition,
Inclusion I4, to the point where those resources aggregate to
greater than 75 MVA.
4.2.1.6
MPT of multiple synchronous generators connecting to a
common bus or MPT of individual dispersed power producing
type 1 or type 2 wind resources as identified in the BES
Definition, Inclusion I4.
4.2.2 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip transmission connected synchronous
condensers; or (ii) provide signals to trip transmission connected
synchronous condenser and are applied to the following:
4.2.2.1
BES synchronous condensers
4.2.2.2
BES step-up transformer(s) for synchronous condensers.
4.2.2.3
High-side of the synchronous condenser-connected unit
auxiliary transformer (UAT).
4.2.3 Exemptions: Protection on all auxiliary equipment within the
synchronous generator, type 1 or type 2 wind resource, or synchronous
condenser Facility.
5.
Effective Date: See Implementation Plan for PRC-024-4
Final Draft of PRC-024-4
September 2024
Page 4 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
B. Requirements and Measures
R1.
Each Generator Owner and Transmission Owner shall set applicable frequency
protection 4 in accordance with PRC-024-4 Attachment 1 such that the applicable
protection does not cause the Facility to which it is applied to trip within the “no trip
zone” during a frequency excursion with the following exceptions: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•
Applicable frequency protection may be set to trip within a portion of the “no
trip zone” for documented and communicated regulatory or equipment
limitations in accordance with Requirement R3.
M1. Each Generator Owner and Transmission Owner shall have evidence that the
applicable frequency protection has been set in accordance with Requirement R1,
such as dated setting sheets, calibration sheets, calculations, or other documentation.
R2.
Each Generator Owner and Transmission Owner shall set applicable voltage
protection 5 in accordance with PRC-024-4 Attachment 2, such that the applicable
protection does not cause the Facility to which it is applied to trip within the “no trip
zone” during a voltage excursion at the high-side of the GSU or MPT, subject to the
following exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
•
If the Transmission Planner allows less stringent voltage protection settings than
those required to meet PRC-024-4 Attachment 2, then the Generator Owner or
Transmission Owner may set its protection within the voltage recovery
characteristics of a location-specific Transmission Planner’s study.
•
Applicable voltage protection may be set to trip during a voltage excursion
within a portion of the “no trip zone” for documented and communicated
regulatory or equipment limitations in accordance with Requirement R3.
M2. Each Generator Owner and Transmission Owner shall have evidence that applicable
voltage protection has been set in accordance with Requirement R2, such as dated
setting sheets, voltage-time boundaries, calibration sheets, coordination plots,
dynamic simulation studies, calculations, or other documentation.
R3.
Each Generator Owner and Transmission Owner shall document each known
regulatory or equipment limitation 6 that prevents its Facility, with applicable
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. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to trip the same Facilities.
5 Ibid.
6 Excludes limitations caused by the setting capability of the frequency, voltage, and volts per hertz protective relays applied to
the synchronous generator(s), type 1 and type 2 wind resource(s), and synchronous condenser(s). This does not exclude
limitations originating in the equipment protected by the relay(s).
4
Final Draft of PRC-024-4
September 2024
Page 5 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
3.1. The Generator Owner and Transmission Owner shall communicate the
documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and
Transmission Planner within 30 calendar days of any of the following:
•
Identification of a regulatory or equipment limitation.
•
Repair of the equipment causing the limitation that removes the limitation.
•
Replacement of the equipment causing the limitation with equipment that
removes the limitation.
•
Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life-time frequency excursion allowance.
M3. Each Generator Owner and Transmission Owner shall have evidence that it has
documented and communicated any known regulatory or equipment limitations that
resulted in an exception to Requirements R1 or R2 in accordance with Requirement
R3, such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
R4.
Each Generator Owner and Transmission Owner shall provide its applicable protection
settings associated with Requirements R1 and R2 to the Planning Coordinator or
Transmission Planner that models the associated Facility within 60 calendar days of
receipt of a written request for the data and within 60 calendar days of any change to
those previously requested settings unless directed by the requesting Planning
Coordinator or Transmission Planner that the reporting of protection setting changes
is not required. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M4. Each Generator Owner and Transmission Owner shall have evidence that it
communicated applicable protection settings in accordance with Requirement R4,
such as dated emails, correspondence or other evidence and copies of any requests it
has received for that information.
Final Draft of PRC-024-4
September 2024
Page 6 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
The Generator Owner and Transmission Owner shall keep data or evidence
of Requirements R1 through R4 for five years or until the next audit,
whichever is longer.
•
If a Generator Owner or Transmission Owner is found non-compliant, the
Generator Owner or Transmission Owner shall keep information related to
the non-compliance until mitigation is complete and approved for the time
period specified above, whichever is longer.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Final Draft of PRC-024-4
September 2024
Page 7 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
R1.
N/A
N/A
N/A
R2.
N/A
N/A
N/A
R3.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 30 calendar days but less
than or equal to 60 calendar
days of identifying the
limitation.
Final Draft of PRC-024-4
September 2024
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 60 calendar days but less
than or equal to 90 calendar
days of identifying the
limitation.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 90 calendar days but less
than or equal to 120 calendar
days of identifying the
limitation.
Severe VSL
The Generator Owner or
Transmission Owner failed to
set its applicable frequency
protection so that it does not
trip according to Requirement
R1.
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does not
trip according to Requirement
R2.
The Generator Owner or
Transmission Owner failed to
document any known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar
Page 8 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
days of identifying the
limitation.
R4.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 60 calendar days but less
than or equal to 90 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 90 calendar days but less
than or equal to 120 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 120 calendar days but less
than or equal to 150 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner failed to
provide its protection settings
within 150 calendar days of any
change to those settings.
OR
OR
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
60 calendar days but less than
or equal to 90 calendar days of
a written request.
The Generator Owner or
Transmission Owner provided
protection settings more than
90 calendar days but less than
or equal to 120 calendar days
of a written request.
The Generator Owner or
Transmission Owner or
provided protection settings
more than 120 calendar days
but less than or equal to 150
calendar days of a written
request.
The Generator Owner or
Transmission Owner failed to
provide protection settings
within 150 calendar days of a
written request.
Final Draft of PRC-024-4
September 2024
OR
Page 9 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
D. Regional Variances
D.A.
Variance for the Quebec Interconnection
This Variance replaces Requirement R2 of the continent-wide standard in its entirety
and adds a new requirement, Requirement D.A.5., applicable to Planning
Coordinators in the Quebec Interconnection.
This Variance replaces continent-wide Requirement R2 in its entirety with the
following:
D.A.2.
Each Generator Owner and Transmission Owner shall set applicable
voltage protection 7 in accordance with PRC-024 Attachment 2A, such
that the applicable protection does not cause the Facility to which it is
applied to trip within the “no trip zone” during a voltage excursion at the
high-side of the GSU or MPT, subject to the following exceptions:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
•
For newly designated strategic power plants, applicable protections
must comply with the high voltage durations for such plants within 48
calendar months of the notification made pursuant to Requirement
D.A.5. During this transition period, voltage protections must at least
comply with the high voltage durations for “all power plants”.
•
Applicable voltage protection may be set to trip during a voltage
excursion within a portion of the “no trip zone” of PRC-024
Attachment 2A for documented and communicated regulatory or
equipment limitations in accordance with Requirement R3.
•
If the Transmission Planner allows less stringent voltage protection
settings than those required to meet PRC-024 Attachment 2A, then
the Generator Owner or Transmission Owner may set its protection
within the voltage recovery characteristics of a location-specific
Transmission Planner’s study.
M.D.A.2. Each Generator Owner and Transmission Owner shall have evidence that
applicable voltage protection has been set in accordance with
Requirement R2, such as dated setting sheets, voltage-time boundaries,
calibration sheets, coordination plots, dynamic simulation studies,
calculations, or other documentation.
This Variance adds the following Requirement:
D.A.5
Each Planning Coordinator shall designate, at least once every five
calendar years, the strategic power plants that must comply with
Attachment 2A and notify, within 30 calendar days of its designation,
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to trip the same Facilities.
7
Final Draft of PRC-024-4
September 2024
Page 10 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
each Generator Owner or Transmission Owner that owns facilities 8 in the
strategic power plants. [Violation Risk Factor: Medium] [Time Horizon:
Long-term planning]
M.D.A.5
Each Planning Coordinator shall have evidence that it designated, at least
once every five calendar years, strategic power plants in accordance with
Requirement D.A.5, Part 5 and shall have dated evidence that each
Generator Owner or Transmission Owner has been notified in accordance
with Requirement D.A.5, part 5.2. Evidence may include, but is not
limited to letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
Facilities in the strategic power plants include facilities with synchronous generator(s) from the generator up to and including
the MPT or GSU.
8
Final Draft of PRC-024-4
September 2024
Page 11 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
This Variance adds a VSL for D.A.5 and modifies the VSL for R2 as follows:
R#
D.A.2.
Violation Severity Levels
Lower
VSL
N/A
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Generator Owner or Transmission
Owner failed to set its applicable
voltage protection so that it does not
trip in accordance with Requirement
D.A.2.
OR
D.A.5.
N/A
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or Transmission
Owner that owns facilities in the
strategic power plants between 31
days and 45 days after its designation.
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or Transmission
Owner that owns facilities in the
strategic power plants between 46
days and 60 days after its designation.
The Generator Owner or Transmission
Owner set its applicable voltage
protection in accordance with
Requirement D.A.2 but, for strategic
power plants, failed to do so within 48
months of notification.
The Planning Coordinator failed to
designate, at least once every five
years, the strategic power plants that
must comply with Attachment 2A.
OR
The Planning Coordinator failed to
notify, each Generator Owner or
Transmission Owner that owns
facilities in the strategic power plants
or notified them more than 60 days
after its designation.
E.Associated Documents
Implementation Plan
Final Draft of PRC-024-4
September 2024
Page 12 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Version History
Version
Date
Action
Change Tracking
1
May 9, 2013
Adopted by the NERC Board of
Trustees
1
March 20, 2014
FERC Order issued approving PRC024-1. (Order becomes effective on
7/1/16.)
2
February 12, 2015
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2014-01:
Applicability revised to
clarify application of
requirements to BES
dispersed power
producing resources
2
May 29, 2015
FERC Letter Order in Docket No.
RD15-3-000 approving PRC-024-2
Modifications to adjust
the applicability to
owners of dispersed
generation resources.
3
February 6, 2020
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2018-04
3
July 9, 2020
FERC Letter Order approved PRC0243. Docket No. RD20-7-000
3
July 17, 2020
Effective Date
10/1/2022
4
August 2, 2024
Revisions made by the 2020-02
Drafting Team
Revision accounts for
changes with PRC-029-1
as part of Milestone 2 of
NERC’s work plan to
address FERC Order No.
901.
Final Draft of PRC-024-4
September 2024
Page 13 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 1
(Frequency No Trip Boundaries by Interconnection 9)
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1: Eastern Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 1: Frequency Boundary Data Points - Eastern Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥60.5
Instantaneous 10
10(90.935-1.45713*f)
≤57.8
≤59.5
Instantaneous11
10(1.7373*f-100.116)
<60.5
Continuous operation
> 59.5
Continuous operation
The figures do not visually represent the “no trip zone” boundaries before 0.1 seconds and after 10,000 seconds. The
Frequency Boundary Data Points Table defines the entirety of the “no trip zone” boundaries.
10 Frequency is calculated over a window of time. While the frequency boundaries include the option to trip instantaneously for
frequencies outside the specified range, this calculation should occur over a time window. Typical window/filtering lengths are
three to six cycles (50 – 100 milliseconds). Instantaneous trip settings based on instantaneously calculated frequency
measurement is not permissible.
9
Final Draft of PRC-024-4
September 2024
Page 14 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
63
Frequency (Hz)
62
61
60
59
No Trip Zone*
58
57
56
0.1
1
10
100
1000
10000
Time (Sec)
Figure 2: Western Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 2: Frequency Boundary Data Points – Western Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.7
≥61.6
≥60.6
<60.6
Instantaneous11
30
180
Continuous operation
≤57.0
≤57.3
≤57.8
≤58.4
≤59.4
Instantaneous11
0.75
7.5
30
180
>59.4
Continuous operation
Final Draft of PRC-024-4
September 2024
Page 15 of 22
Frequency (Hz)
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
67
66
65
64
63
62
61
60
59
58
57
56
55
No Trip Zone*
0.1
1
10
100
1000
10000
Time (Sec)
Figure 3: Quebec Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 3: Frequency Boundary Data Points – Quebec Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (Sec)
>66.0
≥63.0
Instantaneous11
5
<55.5
≤56.5
Instantaneous11
0.35
≥61.5
90
≤57.0
2
≥60.6
660
≤57.5
10
<60.6
Continuous operation
≤58.5
90
≤59.4
660
>59.4
Continuous operation
Final Draft of PRC-024-4
September 2024
Page 16 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 4: ERCOT Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 4: Frequency Boundary Data Points – ERCOT Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥61.6
≥60.6
<60.6
Instantaneous11
30
540
Continuous operation
≤57.5
≤58.0
≤58.4
≤59.4
Instantaneous11
2
30
540
>59.4
Continuous operation
Final Draft of PRC-024-4
September 2024
Page 17 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
PRC-024 — Attachment 2
Voltage (per unit)8
(Voltage No-Trip Boundaries – Eastern, Western, and ERCOT Interconnections)
1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
The Voltage No Trip Zone ends at 4
seconds for applicability to PRC-024
No Trip Zone*
0
0.5
1
1.5
2
2.5
Time (sec)
High Voltage Duration
3
3.5
4
Low Voltage Duration
Figure 5: Voltage No-Trip Boundaries – Eastern, Western, and ERCOT
Interconnections
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 5: Voltage Boundary Data Points
High Voltage Duration
Low Voltage Duration
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
≥1.200
≥1.175
≥1.15
≥1.10
<1.10
0.00
0.20
0.50
1.00
4.00
<0.45
<0.65
<0.75
<0.90
≥ 0.90
0.15
0.30
2.00
3.00
4.00
Final Draft of PRC-024-4
September 2024
Page 18 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 2: Voltage Boundary Clarifications – Eastern, Western,
and ERCOT Interconnections
Boundary Details:
1. Unless otherwise specified by the Transmission Planner, the per unit voltage base for
these boundaries is the nominal transmission system voltage (e.g., 100 kV, 115 kV, 138
kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the boundaries assume RMS fundamental frequency phase-to-ground or
phase-to-phase per unit voltage.
5. For applicability to PRC-024, the “no trip zone” ends at 4 seconds.
Evaluating Protection Settings:
The voltage values in the Attachment 2 voltage boundaries are voltages at the high-side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high-side of the transformer with a low side below 100kV and a high-side 100kV or above.
When evaluating protection settings, consider the voltage differences between where the
protection is measuring voltage and the high-side of the GSU/MPT. A steady state calculation or
dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the synchronous generator,
type 1 or 2 wind resources, or synchronous condenser under study.
b. All installed wind resource reactive support (e.g., static VAR compensators, synchronous
condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals or
the collector station and the high-side of the GSU/MPT.
d. For dynamic simulations, the synchronous generator or condenser automatic voltage
regulator is in automatic voltage control mode with associated limiters in service.
Final Draft of PRC-024-4
September 2024
Page 19 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
PRC-024— Attachment 2A
(Voltage No-Trip Boundaries – Quebec Interconnection)
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
0 0.1
0.033
0.15
2.5
0.5
1
2
3
4
5
30
300
Time (sec)
Low Voltage/High Voltage Duration – Synchronous Generators and Condensers
High Voltage Duration - Strategic Power Plants
Figure 6: Voltage No-Trip Boundaries – Quebec Interconnection
* The area outside the “No Trip Zone” is not a “Must Trip Zone.”
Final Draft of PRC-024-4
September 2024
Page 20 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Table 6: High Voltage Boundary Data Points – Quebec Interconnection
High Voltage Duration for all
Synchronous Generators and
Condensers
High Voltage Duration for strategic
Power Plants
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
-->1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
--0.033
0.10
2.00
30
300
continuous
>1.50
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
0.033
0.10
2.50
5.00
30
300
continuous
Table 7: Low Voltage Boundary Data Points – Quebec Interconnection
Low Voltage Duration for all
Synchronous Generators and
Condensers
Final Draft of PRC-024-4
September 2024
Voltage (per unit)
Minimum Time (sec)
<0.25
<0.75
<0.85
<0.90
≥0.90
0.15
1.00
2.00
30
continuous
Page 21 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 2A: Voltage Boundary Clarifications – Quebec
Interconnection
Boundary Details:
1. The per unit voltage base for these boundaries is the nominal operating voltage (e.g.,
120 kV, 161 kV, 230 kV, 315 kV, 735 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the Quebec Interconnection boundaries assume positive-sequence values.
Evaluating Protection Settings:
The voltage values in the Attachment 2A voltage boundaries are voltages at the high-side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high-side of the transformer that connects to the interconnecting voltage. When evaluating
protection settings, consider the voltage differences between where the protection is
measuring voltage and the high-side of the GSU/MPT. A steady state calculation or dynamic
simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high-side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Final Draft of PRC-024-4
September 2024
Page 22 of 22
Exhibit A-2
PRC-024-4 Redline
RELIABILITY | RESILIENCE | SECURITY
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 3 of PRC-024-4 is posted for final ballot. Non-substantive corrections were identified during
the last additional ballot. This draft includes those corrections.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process Manual
December 13, 2023
25-day formal comment period with initial ballot
March 27 - April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
Anticipated Actions
Date
Final ballot
September 25 –
September 30, 2024
Board Adoption
October 8, 2024
Page 1 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Page 2 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
A. Introduction
1.
Title:
Frequency and Voltage Protection Settings for Synchronous
Generatorsing, Type 1 and Type 2 Wind Resources, and Synchronous Condensers
2.
Number:
PRC-024-43
3.
Purpose:
To assureset that protection of such that synchronous generatorsing, type 1
and type 2 wind resource(s), and synchronous condensers do not cause
tripping remain connected during defined frequency and voltage
excursions in support of the Bulk Electric Power System (BPES).
4.
Applicability:
4.1. Functional Entities:
4.1.1 Generator Owners that apply protection listed in Section 4.2.1 or 4.2.2.
4.1.2 Transmission Owners that apply protection listed in Section 4.2.2.
4.1.24.1.3
Transmission Owners (in the Quebec Interconnection only) that own
a BES generator step-up (GSU) transformer or main power transformer
(MPT) 1 and apply protection listed in Section 4.2.1.
4.1.34.1.4
Planning Coordinators (in the Quebec Interconnection only)
4.2. Facilities 2:
4.2.1 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the generating resource(s); or (ii)
provide signals to the generating resource(s) to either trip or cease injecting
current; and are applied to the following:
4.2.1.1 Bulk Electric (BES) synchronous generatorsing resource(s).
4.2.1.2 BES GSU transformer(s) for synchronous generators.
4.2.1.3 High -side of the synchronous generator-connected unit auxiliary
transformer 3 (UAT) installed on BES generating resource(s).
4.2.1.4 Individual dispersed power producing type 1 or type 2 wind
resource(s) identified in the BES Definition, Inclusion I4.
For the purpose of this standard, the MPT is the power transformer that steps up voltage from the collection system
voltage to the nominal transmission/interconnecting system voltage for dispersed power producing resources.
1
2
It is not required to install or activate the protections described in Facilities Section 4.2.
These transformers are variably referred to as station power UAT, or station service transformer(s) used to provide
overall auxiliary power to the generating resource(s). This UAT is the transformer connected on the generator bus
between the low side of the GSU and the generator terminal.
3
Page 3 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
4.2.1.5 Elements that are designed primarily for the delivery of capacity
from multiple synchronous generators connecting to a common
bus orthe individual dispersed power producing type 1 or type 2
wind resources identified in the BES Definition, Inclusion I4, to the
point where those resources aggregate to greater than 75 MVA.
4.2.1.6 MPT 4 of multiple synchronous generators connecting to a
common bus or MPT of individual dispersed power producting
type 1 or type 2 wind resource(s) as identified in the BES
Definition, Inclusion I4.
4.2.2 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip transmission connected synchronous
condensers; or (ii) provide signals to trip transmission connected
synchronous condenser and are applied to the following:
5.
4.2.2.1
BES synchronous condensers
4.2.2.2
BES step-up transformer(s) for synchronous condensers.
4.2.2.3
High-side of the synchronous condenser-connected unit auxiliary
transformer (UAT).
4.2.24.2.3
Exemptions: Protection on all auxiliary equipment within the
synchronous generatoring, type 1 or type 2 wind resource, or synchronous
condenser Facility.
Effective Date: See the Implementation Plan for PRC-024-43.
For the purpose of this standard, the MPT is the power transformer that steps up voltage from the collection system
voltage to the nominal transmission/interconnecting system voltage for dispersed power producing resources
4
Page 4 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
B. Requirements and Measures
R1.
Each Generator Owner and Transmission Owner shall set its applicable frequency
protection 5 in accordance with PRC-024-4 Attachment 1 such that the applicable
protection does not cause the generating resourceFacility to which it is applied to trip or
cease injecting current within the “no trip zone” during a frequency excursion with the
following exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
•
Applicable frequency protection may be set to trip or cease injecting current within
a portion of the “no trip zone” for documented and communicated regulatory or
equipment limitations in accordance with Requirement R3.
M1. Each Generator Owner and Transmission Owner shall have evidence that the applicable
frequency protection has been set in accordance with Requirement R1, such as dated
setting sheets, calibration sheets, calculations, or other documentation.
R2.
Each Generator Owner and Transmission Owner shall set its applicable voltage
protection 65 in accordance with PRC-024-4 Attachment 2, such that the applicable
protection does not cause the generating resourceFacility to which it is applied to trip or
cease injecting current within the “no trip zone” during a voltage excursion at the
high- side of the GSU or MPT, subject to the following exceptions: [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning]
•
If the Transmission Planner allows less stringent voltage protection settings than
those required to meet PRC-024-4 Attachment 2, then the Generator Owner may
set its protection within the voltage recovery characteristics of a location-specific
Transmission Planner’s study.
•
Applicable voltage protection may be set to trip or cease injecting current during a
voltage excursion within a portion of the “no trip zone” for documented and
communicated regulatory or equipment limitations in accordance with
Requirement R3.
M2. Each Generator Owner and Transmission Owner shall have evidence that applicable
voltage protection has been set in accordance with Requirement R2, such as dated
setting sheets, voltage-time boundaries, calibration sheets, coordination plots, dynamic
simulation studies, calculations, or other documentation.
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated
control systems) that respond to electrical signals and: (i) directly trip the synchronous generatorsing, type 1 or type 2
wind resource(s), or synchronous condenser(s); or (ii) provide signals to the generating resource(s) to either trip or
cease injecting currentthe same Facilties.
5
6
Ibid
Page 5 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
R3.
Each Generator Owner and Transmission Owner shall document each known regulatory
or equipment limitation 7 that prevents an applicable generating resource(s)its Facility,
with applicable 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. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
3.1. The Generator Owner and Transmission Owner shall communicate the
documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and
Transmission Planner within 30 calendar days of any of the following:
•
Identification of a regulatory or equipment limitation.
•
Repair of the equipment causing the limitation that removes the limitation.
•
Replacement of the equipment causing the limitation with equipment that
removes the limitation.
•
Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life-time frequency excursion allowance.
M3. Each Generator Owner and Transmission Owner shall have evidence that it has
documented and communicated any known regulatory or equipment limitations that
resulted in an exception to Requirements R1 or R2 in accordance with Requirement R3,
such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
R4.
Each Generator Owner and Transmission Owner shall provide its applicable protection
settings associated with Requirements R1 and R2 to the Planning Coordinator or
Transmission Planner that models the associated Facility generating resource(s) within
60 calendar days of receipt of a written request for the data and within 60 calendar days
of any change to those previously requested settings unless directed by the requesting
Planning Coordinator or Transmission Planner that the reporting of protection setting
changes is not required. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
M4. Each Generator Owner and Transmission Owner shall have evidence that it
communicated applicable protection settings in accordance with Requirement R4, such
as dated e-mails, correspondence or other evidence and copies of any requests it has
received for that information.
Excludes limitations caused by the setting capability of the frequency, voltage, and volts per hertz protective relays
applied to the synchronous for the generatorsing, type 1 or type 2 wind resource(s), and synchronous condenser(s).
This does not exclude limitations originating in the equipment protected by the relay. This also does not exclude
limitations of frequency, voltage, and volts per hertz protection embedded in control systems.
7
Page 6 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means
NERC or the Regional Entity, or any entity as otherwise designated by an Applicable
Governmental Authority, in their respective roles of monitoring and/or enforcing
compliance with mandatory and enforceable Reliability Standards in their
respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the period
of time an entity is required to retain specific evidence to demonstrate compliance.
For instances where the evidence retention period specified below is shorter than
the time since the last audit, the Compliance Enforcement Authority may ask an
entity to provide other evidence to show that it was compliant for the full-time
period since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
•
The Generator Owner and Transmission Owner shall keep data or evidence
Requirement R1 through R4; for five3 years or until the next audit,
whichever is longer.
•
If a Generator Owner or Transmission Owner is found non-compliant, the
Generator Owner or Transmission Owner shall keep information related to
the non-compliance until mitigation is complete and approved for the time
period specified above, whichever is longer.
1.3. Compliance Monitoring and Assessment Program: As defined in the NERC Rules of
Procedure, “Compliance Monitoring and Enforcement Program” refers to the
identification of the processes that will be used to evaluate data or information for
the purpose of assessing performance or outcomes with the associated Reliability
Standard.
Page 7 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and Type 2 Wind Resources, and
Synchronous Condensers
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed
to set its applicable
frequency protection so
that it does not trip or
cease injecting current
according to Requirement
R1.
R2.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed
to set its applicable voltage
protection so that it does
not trip or cease injecting
current according to
Requirement R2.
R3.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
The Generator Owner or
Transmission Owner
documented the known
non-protection system
equipment limitation that
prevented it from meeting
the criteria in Requirement
R1 or R2 and
communicated the
documented limitation to
The Generator Owner
or Transmission Owner
documented the known
non-protection system
equipment limitation
that prevented it from
meeting the criteria in
Requirement R1 or R2
and communicated the
documented limitation
The Generator Owner or
Transmission Owner failed
to document any known
non-protection system
equipment limitation that
prevented it from meeting
the criteria in Requirement
R1 or R2.
Page 8 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and Type 2 Wind Resources, and
Synchronous Condensers
Violation Severity Levels
R#
R4.
Lower VSL
Moderate VSL
Transmission Planner more
than 30 calendar days but less
than or equal to 60 calendar
days of identifying the
limitation.
its Planning Coordinator
and Transmission Planner
more than 60 calendar
days but less than or equal
to 90 calendar days of
identifying the limitation.
to its Planning
Coordinator and
Transmission Planner
more than 90 calendar
days but less than or
equal to 120 calendar
days of identifying the
limitation.
OR
The Generator Owner or
Transmission Owner provided
its protection settings more
than 60 calendar days but less
than or equal to 90 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner
provided its protection
settings more than 90
calendar days but less than
or equal to 120 calendar
days of any change to
those settings.
The Generator Owner
or Transmission Owner
provided its protection
settings more than 120
calendar days but less
than or equal to 150
calendar days of any
change to those
settings.
The Generator Owner or
Transmission Owner failed
to provide its protection
settings within 150 calendar
days of any change to those
settings.
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
60 calendar days but less than
or equal to 90 calendar days of
a written request.
OR
The Generator Owner or
Transmission Owner
provided protection
settings more than 90
calendar days but less than
High VSL
OR
The Generator Owner
or Transmission Owner
provided protection
settings more than 120
calendar days but less
than or equal to 150
Severe VSL
The Generator Owner or
Transmission Owner failed
to communicate the
documented limitation to
its Planning Coordinator
and Transmission Planner
within 120 calendar days of
identifying the limitation.
OR
The Generator Owner or
Transmission Owner failed
to provide protection
settings within 150 calendar
days of a written request.
Page 9 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and Type 2 Wind Resources, and
Synchronous Condensers
Violation Severity Levels
R#
Lower VSL
Moderate VSL
or equal to 120 calendar
days of a written request.
High VSL
Severe VSL
calendar days of a
written request.
Page 10 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
D. Regional Variances
D.A.
Variance for the Quebec Interconnection
This Variance extends the applicability of Requirements R1, R3, and R4 to
Transmission Owners in the Quebec Interconnection that own a BES GSU or MPT
and apply protection listed in Section 4.2.1, Facilities. This Variance also replaces
Requirement R2 of the continent-wide standard in its entirety and adds a new
requirement, Requirement D.A.5., applicable to Planning Coordinators in the
Quebec Interconnection.
In Requirements R1, R3, and R4, all references to “Generator Owner” are replaced
with “Generator Owner and Transmission Owner.”
This Variance replaces continent-wide Requirement R2 in its entirety with the
following:
D.A.2.
Each Generator Owner and Transmission Owner shall set its applicable
voltage protection 85 in accordance with PRC-024 Attachment 2Aa, such
that the applicable protection does not cause the generating
resourceFacility to which it is applied to trip within the “no trip zone” or
cease injecting current during a voltage excursion within the “no trip
zone” at the high- side of the GSU or MPT, subject to the following
exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
•
For newly designated strategic power plants, applicable protections
must comply with the high voltage durations for such plants within 48
calendar months of the notification made pursuant to Requirement
D.A.5. During this transition period, voltage protections must at least
comply with the high voltage durations for “all power plants”.
•
Applicable voltage protection may The generating resource(s) are
permitted to be set to trip or to cease injecting current during a
voltage excursion within a portion of bounded by the “no trip zone”
of PRC-024 Attachment 2Aa for documented and communicated
regulatory or equipment limitations in accordance with Requirement
R3.
•
If the Transmission Planner allows less stringent voltage protection
settings than those required to meet PRC-024 Attachment 2Aa, then
the Generator Owner or Transmission Owner may set its protection
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated
control systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type
2 wind resource(s), or synchronous condenser(s); or (ii) provide signals to trip the same Facilities.
8
Page 11 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
within the voltage recovery characteristics of a location-specific
Transmission Planner’s study.
•
Inverter-based resources voltage protection settings may be set to
cease injecting current momentarily during a voltage excursion at the
high side of the MPT, bounded by the “no trip zone” of PRC-024
Attachment 2a, under the following conditions:
o After a minimum delay of 0.022 s, when the positive-sequence
voltage exceeds 1.25 per unit (p.u.) Normal operation must
resume once the voltage drops back below 1.25 p.u at the high
side of the MPT.
o After a minimum delay of 0.022 s, when the phase-to-ground
root mean square (RMS) voltages exceeds 1.4 p.u., as measured
at generator terminals, on one or multiple phases. Normal
operation must resume once the positive-sequence voltage
drops back below the 1.25 p.u. at the high side of the MPT.
M.D.A.2. Each Generator Owner and Transmission Owner shall have evidence that
applicable voltage protection has been set in accordance with
Requirement R2, such as dated setting sheets, voltage-time boundaries,
calibration sheets, coordination plots, dynamic simulation studies,
calculations, or other documentation.
This Variance adds the following Requirement:
D.A.5
Each Planning Coordinator shall designate, at least once every five
calendar years, the strategic power plants that must comply with
Attachment 2Aa and notify, within 30 calendar days of its designation,
each Generator Owner or Transmission Owner that owns facilities 9 in the
strategic power plants. [Violation Risk Factor: Medium] [Time Horizon:
Long-term planning]
M.D.A.5
Each Planning Coordinator shall have evidence that it designated, at least
once every five calendar years, strategic power plants in accordance with
Requirement D.A.5, Part 5 and shall have dated evidence that each
Generator Owner or Transmission Owner has been notified in accordance
with Requirement D.A.5, part 5.2. Evidence may include, but is not
limited to: letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
Facilities in the strategic power plants include facilities with synchronous generator(s) from the generator up to
and including the MPT or GSU.
9
Page 12 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2 Wind and Synchronous Condensers
Resources
Violation Severity Levels
This Variance adds a VSL for D.A.5 and modifies the VSL for R2 as follows:
Violation Severity Levels
R#
Lower
VSL
Moderate VSL
High VSL
Severe VSL
D.A.2.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does not
trip or cease injecting current in
accordance with Requirement
D.A.2.
OR
D.A.5.
N/A
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or
Transmission Owner that owns
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or
Transmission Owner that owns
The Generator Owner or
Transmission Owner set its
applicable voltage protection in
accordance with Requirement
D.A.2 but, for strategic power
plants, failed to do so within 48
months of notification.
The Planning Coordinator failed
to designate, at least once
every five years, the strategic
power plants that must comply
with Attachment 2Aa.
Page 13 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2 Wind and Synchronous Condensers
Resources
Violation Severity Levels
R#
Lower
VSL
Moderate VSL
High VSL
Severe VSL
facilities in the strategic power plants facilities in the strategic power plants
between 31 days and 45 days after its between 46 days and 60 days after its OR
designation.
designation.
The Planning Coordinator failed
to notify, each Generator
Owner or Transmission Owner
that owns facilities in the
strategic power plants or
notified them more than 60
days after the its designation.
E. Associated Documents
Implementation Plan
Page 14 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
E.A.
Associated Documents
Implementation Plan
Page 15 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Version History
Version
Date
Action
Change Tracking
1
May 9, 2013
Adopted by the NERC Board of
Trustees
1
March 20, 2014
FERC Order issued approving PRC024-1. (Order becomes effective
on 7/1/16.)
2
February 12, 2015
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2014-01:
Applicability revised to
clarify application of
requirements to BES
dispersed power
producing resources
2
May 29, 2015
FERC Letter Order in Docket No.
RD15-3-000 approving PRC-024-2
Modifications to adjust
the applicability to
owners of dispersed
generation resources.
3
February 6, 2020
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2018-04
3
July 9, 2020
FERC Letter Order approved PRC024-3. Docket No. RD20-7-000
3
July 17,2020
October 1, 2022
Effective Date
4
August 2, 2024
Revisions made by the 2020-02
Drafting Team
Revision accounts for
changes with PRC-029-1
as part of Milestone 2 of
NERC’s work plan to
address FERC Order No.
901.
Page 16 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Attachment 1
(Frequency No Trip Boundaries by Interconnection 10)
Eastern Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1: Eastern Interconnection Boundaries
Figure 1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 1: Frequency Boundary Data Points - Eastern Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
Instantaneous11
≤57.8
Instantaneous11
≥60.5
10(90.935-1.45713*f)
≤59.5
10(1.7373*f-100.116)
The figures do not visually represent the “no trip zone” boundaries before 0.1 seconds and after 10,000 seconds. The
Frequency Boundary Data Points Table defines the entirety of the “no trip zone” boundaries.
10
Frequency is calculated over a window of time. While the frequency boundaries include the option to trip instantaneously for
frequencies outside the specified range, this calculation should occur over a time window. Typical window/filtering lengths are
three to six cycles (50 – 100 milliseconds). Instantaneous trip settings based on instantaneously calculated frequency
measurement is not permissible.
11
Page 17 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
<60.5
Continuous operation
> 59.5
Continuous operation
Table 1
Western Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
56
0.1
1
10
100
1000
10000
Time (Sec)
Figure 2: Western Interconnection Boundaries
Figure 2
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 2: Frequency Boundary Data Points – Western Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.7
Instantaneous11
≤57.0
Instantaneous11
≥61.6
30
≤57.3
0.75
≥60.6
180
≤57.8
7.5
<60.6
Continuous operation
≤58.4
30
≤59.4
180
>59.4
Continuous operation
Table 2
Page 18 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Frequency (Hz)
Quebec Interconnection Boundaries
67
66
65
64
63
62
61
60
59
58
57
56
55
No Trip Zone*
0.1
1
10
100
1000
10000
Time (Sec)
Figure 3: Quebec Interconnection Boundaries
Figure 3
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 3: Frequency Boundary Data Points – Quebec Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (Sec)
>66.0
Instantaneous11
<55.5
Instantaneous11
≥63.0
5
≤56.5
0.35
≥61.5
90
≤57.0
2
≥60.6
660
≤57.5
10
<60.6
Continuous operation
≤58.5
90
≤59.4
660
>59.4
Continuous operation
Table 3
Page 19 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
ERCOT Interconnection Boundaries
63
Frequency (Hz)
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 4: ERCOT Interconnection Boundaries
Figure 4
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 4: Frequency Boundary Data Points – ERCOT Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
Instantaneous11
≤57.5
Instantaneous11
≥61.6
30
≤58.0
2
≥60.6
540
≤58.4
30
<60.6
Continuous
operation
≤59.4
540
>59.4
Continuous operation
Table 4
Page 20 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
PRC-024 — Attachment 2
Voltage (per unit)10
(Voltage No-Trip Boundaries – Eastern, Western, and ERCOT Interconnections)
1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
The Voltage No Trip Zone ends at 4
seconds for applicability to PRC-024
No Trip Zone*
0
0.5
1
1.5
2
2.5
Time (sec)
High Voltage Duration
3
3.5
4
Low Voltage Duration
Figure 5: Voltage No-Trip Boundaries – Eastern, Western, and ERCOT
Interconnections
12Figure
1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 5: Voltage Boundary Data Points
High Voltage Duration
Low Voltage Duration
Voltage (pu)
Minimum Time (sec)
Voltage (pu)
Minimum Time (sec)
≥1.200
≥1.175
≥1.15
≥1.10
<1.10
0.00
0.20
0.50
1.00
4.00
<0.45
<0.65
<0.75
<0.90
≥ 0.90
0.15
0.30
2.00
3.00
4.00
Voltage at the high-side of the GSU or MPT.
10
Page 21 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Table 1
Page 22 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Attachment 2: Voltage Boundary Clarifications – Eastern,
Western, and ERCOT Interconnections
Boundary Details:
1. Unless otherwise specified by the Transmission Planner, the per unit voltage base for
these boundaries is the nominal transmission system voltage (e.g., 100 kV, 115 kV, 138
kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the boundaries assume RMS fundamental frequency phase-to-ground or
phase-to-phase per unit voltage.
5. For applicability to PRC-024, the “no trip zone” ends at 4 seconds.
Evaluating Protection Settings:
The voltage values in the Attachment 2 voltage boundaries are voltages at the high side of the
GSU/MPT. For generating resources with multiple stages of step up to reach interconnecting
voltage, this is the high side of the transformer with a low side below 100kV and a high side
100kV or above. When evaluating protection settings, consider the voltage differences between
where the protection is measuring voltage and the high side of the GSU/MPT. A steady state
calculation or dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the synchronous generator,
type 1 or 2 wind resources, or synchronous condenser unit under study.
b. All installed wind resource generating plant reactive support (e.g., static VAR
compensators, synchronous condensers, capacitors) equipment is available and
operating normally.
c. Account for the actual tap settings of transformers between the generator terminals or
the collector station and the high side of the GSU/MPT.
d. For dynamic simulations, the synchronous generator or condenser automatic voltage
regulator is in automatic voltage control mode with associated limiters in service.
Page 23 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
PRC-024— Attachment 2a
(Voltage No-Trip Boundaries – Quebec Interconnection)
May cease current injection momentarily
under specified conditions
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
0 0.1
0.033
0.15
2.5
0.5
1
2
3
4
5
30
300
Time (sec)
Low Voltage/High Voltage Duration - All Power Plants
Low Voltage Duration – Inverter-Based Resources
High Voltage Duration - Strategic Power Plants
Figure 6: Voltage No-Trip Boundaries – Quebec Interconnection
Figure 1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Page 24 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind, and Synchronous Condensers Resources
V Table 6: High Voltage Boundary Data Points – Quebec Interconnection
High Voltage Duration for all Power
Plants
High Voltage Duration for strategic
Power Plants
Voltage (pu)
Minimum Time (sec)
Voltage (pu)
Minimum Time (sec)
-->1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
--0.033
0.10
2.00
30
300
continuous
>1.50
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
0.033
0.10
2.50
5.00
30
300
continuous
Table 1
Table 7: Low Voltage Boundary Data Points – Quebec Interconnection
Low Voltage Duration for all Power
Plants
Low Voltage Duration for InverterBased Resources
Voltage (pu)
Minimum Time (sec)
Voltage (pu)
Minimum Time (sec)
<0.25
<0.75
<0.85
<0.90
≥0.90
0.15
1.00
2.00
30
continuous
<0.25
<0.75
<0.85
<0.90
≥0.90
3.4*V(pu)+0.15
1.00
2.00
30
continuous
Table 2
Page 25 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind, and Synchronous Condensers Resources
Attachment 2Aa: Voltage Boundary Clarifications – Quebec
Interconnection
Boundary Details:
1. The per unit voltage base for these boundaries is the nominal operating voltage (e.g., 120
kV, 161 kV, 230 kV, 315 kV, 735 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60 Hertz
or the magnitude of the high voltage boundary can be adjusted in proportion to deviations
of frequency below 60 Hertz.
4. Voltages in the Quebec Interconnection boundaries assume positive-sequence values.
Evaluating Protection Settings:
The voltage values in the Attachment 2a voltage boundaries are voltages at the high side of the
GSU/MPT. For generating resources with multiple stages of step up to reach interconnecting
voltage, this is the high side of the transformer that connects to the interconnecting voltage.
When evaluating protection settings, consider the voltage differences between where the
protection is measuring voltage and the high side of the GSU/MPT. A steady state calculation or
dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators, synchronous
condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals and
the high side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Page 26 of 26
Exhibit A-3
PRC-029-1
RELIABILITY | RESILIENCE | SECURITY
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Final Draft of PRC-029-1 is posted for a formal comment and additional ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
25-day formal comment period and initial ballot
March 27 – April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
15-day formal comment period and additional ballot
July 22 – August 12, 2024
14-day formal comment period and additional ballot
September 17 –
September 30, 2024
Final Ballot
None Required
Board adoption
October 8, 2024
Final Draft of PRC-029-1
October 2024
Page 1 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Ride-through: The plant/facility remains connected and continues to operate through voltage
or frequency system disturbances.
Final Draft of PRC-029-1
October 2024
Page 2 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
A. Introduction
1. Title:
Frequency and Voltage Ride-through Requirements for Inverter-based
Resources
2. Number:
PRC-029-1
3. Purpose:
To ensure that IBRs Ride-through to support the Bulk Power System (BPS)
during and after defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.2
Facilities:
4.2.1. Bulk Electric System (BES) IBRs
4.2.2. Non-BES IBRs that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system
designed primarily for delivering such capacity to a common point of
connection at a voltage greater than or equal to 60 kV.
Effective Date: See Implementation Plan for Project 2020-02 – PRC-029-1
Standard-only Definition: None
Final Draft of PRC-029-1
October 2024
Page 3 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
B. Requirements and Measures
R1.
Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements, in accordance with the “must Ridethrough 1 zone” as specified in Attachment 1, except in the following conditions:
[Violation Risk Factor: High] [Time Horizon: Operations Assessment]
•
The IBR needed to electrically disconnect in order to clear a fault;
•
The voltage at the high-side of the main power transformer 2 went outside an
accepted hardware limitation, in accordance with Requirement R4;
•
The instantaneous positive sequence voltage phase angle change is more than
25 electrical degrees at the high-side of the main power transformer and is
initiated by a non-fault switching event on the transmission system 3; or
•
The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than
2 seconds.
M1. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R1. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner shall
retain evidence of actual disturbance monitoring (i.e., sequence of event recorder,
dynamic disturbance recorder, and fault recorder) to demonstrate that the operation
of each IBR did adhere to Ride-through requirements, as specified in Requirement R1.
If the Generator Owner choose to utilize Ride-through exemptions that occur within
the “must Ride-through zone” and are caused by non-fault initiated phase jumps of
greater than 25 electrical degrees, then each Generator Owner shall also retain
evidence of actual disturbance monitoring (i.e., sequence of event recorder, dynamic
disturbance recorder, and fault recorder) data to demonstrate that the IBR failed to
Ride-through during a phase jump of greater than or equal to 25 electrical degrees, and
documentation from their Transmission Planner, Reliability Coordinator, Planning
Coordinator, or Transmission Operator that a non-fault initiated switching event
occurred.
R2. Each Generator Owner shall ensure the design and operation is such that the voltage
performance for each IBR adheres to the following during a voltage excursion, unless a
documented hardware limitation exists in accordance with Requirement R4. [Violation
Risk Factor: High] [Time Horizon: Operations Assessment]
2.1.
While the voltage at the high-side of the main power transformer remains within
the continuous operation region as specified in Attachment 1, each IBR shall:
Includes no tripping associated with phase lock loop loss of synchronism.
For the purpose of this standard, the main power transformer is the power transformer that steps up voltage from the
collection system voltage to the nominal transmission/interconnecting system voltage for IBRs. In case of IBR connecting via a
dedicated Voltage Source Converter High Voltage Direct Current (VSC-HVDC), the main power transformer is the main power
transformer on the receiving end.
3 Current blocking mode may be used for non-fault initiated phase jumps greater than 25 degrees in order to prevent tripping.
1
2
Final Draft of PRC-029-1
October 2024
Page 4 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
2.1.1 Continue to deliver the pre-disturbance level of Real Power or available
Real Power 4, whichever is less. 5
2.1.2 Continue to deliver Reactive Rower up to its Reactive Power limit and
according to its controller settings.
2.1.3 Prioritize Real Power or Reactive Power when the voltage is less than
0.95 per unit, the voltage is within the continuous operating region, and
the IBR cannot deliver both Real Power and Reactive Power due to a
current limit or Reactive Power limit, unless otherwise specified through
other mechanisms by an associated Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator.
2.2.
2.3.
While voltage at the high-side of the main power transformer is within the
mandatory operation region as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support, on
the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under 6:
•
Reactive Power priority by default; or
•
Real Power priority if required through other mechanisms by an associated
Transmission Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator.
While voltage at the high-side of the main power transformer is within the
permissive operation region, as specified in Attachment 1, each IBR may operate
in current blocking mode if necessary to avoid tripping. Otherwise, each IBR shall
follow the requirements for the mandatory operation region in Requirement
R2.2.
2.3.1 If an IBR enters current blocking mode, it shall restart current exchange
in less than or equal to five cycles of positive sequence voltage returning
to a continuous operation region or mandatory operation region.
2.4.
Each IBR shall not itself cause voltage at the high-side of the main power
transformer to exceed the applicable high voltage thresholds and time durations
in its response as voltage recovers from the mandatory or permissive operation
regions to the continuous operation region.
2.5.
Each IBR shall restore Real Power output to the pre-disturbance or available
level 7 (whichever is lesser) within 1.0 second when the voltage at the high-side
of the main power transformer returns from the mandatory operation region or
“Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
5 Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
6 In either case and if required, the magnitude of Real Power and reactive current shall be as specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
7 “Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
4
Final Draft of PRC-029-1
October 2024
Page 5 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
permissive operation region (including operating in current blocking mode) to
the continuous operation region, as specified in Attachment 1, unless an
associated Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator requires a lower post-disturbance Real Power level
requirement or requires a different post-disturbance Real Power restoration
time through other mechanisms. 8
M2. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to requirements, as specified in Requirement R2. Examples of evidence may
include, but are not limited to dynamic simulations, studies, plant protection settings,
and control settings design evaluation. Each Generator Owner shall also retain evidence
of actual disturbance monitoring (i.e., sequence of event recorder, dynamic disturbance
recorder, and fault recorder) data to demonstrate that the operation of each IBR did
adhere to performance requirements, as specified in Requirement R2, during each
voltage excursion measured at the high-side of the main power transformer. Regarding
R2.1.3, R2.2, and R2.5, the Generator Owner shall retain evidence of receiving such
performance requirements, (e.g., email exchange, contract information) if the
Transmission Planner, Transmission Operator, Reliability Coordinator, or Planning
Coordinator has required the Generator Owner through other mechanisms to follow
performance requirements other than those in Requirement R2 (e.g., ramp rates,
Reactive Power prioritization).
R3. Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements during a frequency excursion event
whereby the System frequency remains within the “must Ride-through zone” according
to Attachment 2 and the absolute rate of change of frequency (RoCoF) 9 magnitude is
less than or equal to 5 Hz/second, unless a documented hardware limitation exists in
accordance with Requirement R4. [Violation Risk Factor: High] [Time Horizon:
Operations Assessment]
M3. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R3. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner shall
also retain evidence of actual disturbance monitoring (i.e., sequence of event recorder,
dynamic disturbance recorder, and fault recorder) data to demonstrate the operation
of each IBR did adhere to Ride-through requirements, as specified in Requirement R3,
during each frequency excursion event measured at the high-side of the main power
transformer.
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of PRC029-1, has known hardware limitations that prevent the IBR from meeting Ride-through
criteria as detailed in Requirements R1-R3, and requires an exemption from specific
Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
9 Rate of change of frequency (RoCoF) is calculated as the average rate of change for multiple calculated system frequencies for
a time period of greater than or equal to 0.1 second. RoCoF is not calculated during the fault occurrence and clearance.
8
Final Draft of PRC-029-1
October 2024
Page 6 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Ride-through criteria shall: 10 [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
4.1.
Document information supporting the identified hardware limitation no later
than 12 months following the effective date of PRC-029-1. This documentation
shall include:
4.1.1 Identifying information of the IBR (name and facility number);
4.1.2 Which aspects of Ride-through requirements that the IBR would be
unable to meet and the capability of the hardware due to the limitation;
4.1.3 Identification of the specific piece(s) of hardware causing the limitation;
4.1.4 Technical documentation verifying the limitation is due to hardware that
would need to be physically replaced to meet all Ride-through criteria,
and that the limitation cannot be remedied by software updates or
setting changes; and
4.1.5 Information regarding any plans to remedy the hardware limitation (such
as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1, except for any
material considered by the original equipment manufacturer to be proprietary
information, to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the Compliance
Enforcement Authority (CEA) no later than 12 months following the effective
date of PRC-029-1. 11
4.2.1 Provide any response for additional information requested by the
associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA to the
requestor within 90 days of the request.
4.2.2 Provide a copy of the acceptance of a hardware limitation by the CEA to
the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s) within 90 days
of receiving the acceptance. 12
4.3.
Each Generator Owner with a previously accepted limitation that replaces the
hardware causing the limitation shall document and communicate such a
hardware change to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s) within 90
days of the hardware change.
10 The exemption requests for a non-US Registered Entity should be implemented in a manner that is consistent with, or under
the direction of, the applicable governmental authority or its agency in the non-US jurisdiction.
11 To the extent the original equipment manufacturer considers any material to be proprietary, the Generator Owner is
required to share this proprietary material only with the CEA.
12 Acceptance by the CEA is verification that the information provided includes all information listed in Requirement R4.1.
Final Draft of PRC-029-1
October 2024
Page 7 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
4.3.1 When existing hardware causing the limitation is replaced, the
exemption for that Ride-through criteria no longer applies.
M4. Each Generator Owner submitting for an exemption for an IBR that is in-service by the
effective date of PRC-029-1, shall have evidence of submission to the CEA consistent
with the information listed in Requirement R4.1. Each Generator Owner shall have
evidence of communicated copies of each submission in accordance with Requirement
R4.2 and to the associated entities described in Requirement R4.2. Acceptable types of
evidence for submittals include, but are not limited to, meeting minutes, agreements,
copies of procedures or protocols in effect, or email correspondence. Acceptable types
of evidence for a hardware limitation may include, but is not limited to damage curves
provided by the original equipment manufacturer. Each Generator Owner that receives
a request for additional information under Requirement R4.2.1 shall have evidence of
providing that information within 90 days. Each Generator Owner that replaces
hardware at an IBR that is directly associated with an accepted exemption and that
hardware is the cause for the limitation, shall have evidence of communicating the
hardware change to the associated entities described in Requirement R4.3 within 90
days of the hardware replacement.
Final Draft of PRC-029-1
October 2024
Page 8 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means
NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring and/or
enforcing compliance with mandatory and enforceable Reliability Standards in
their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below is
shorter than the time since the last audit, the Compliance Enforcement Authority
may ask an entity to provide other evidence to show that it was compliant for the
full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
•
Each Generator Owner shall retain evidence with Requirements R1, R2, and
R3 in this standard for 36 calendar months or the date of the last audit,
whichever is greater.
•
Each Generator Owner shall retain evidence with Requirement R4 in this
standard for five calendar years or the date of the last audit, whichever is
greater.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC Rules
of Procedure, “Compliance Monitoring and Enforcement Program” refers to the
identification of the processes that will be used to evaluate data or information
for the purpose of assessing performance or outcomes with the associated
Reliability Standard.
Final Draft of PRC-029-1
October 2024
Page 9 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to
Ride-through in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to Ride-through
requirements in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
R2.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to adhere
to performance requirements
during voltage excursions, as
specified in Requirement R2,
unless a documented
hardware limitation exists in
accordance with Requirement
R4.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to performance
requirements during voltage
excursions, as specified in
Requirement R2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
R3.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to
Ride-through in accordance
with Attachment 2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to Ride-through
requirements in accordance
with Attachment 2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
Final Draft of PRC-029-1
October 2024
Page 10 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
R#
R4.
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 12 months, but less than
or equal to 15 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 15 months, but less than
or equal to 18 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 18 months, but less than
or equal to 24 months after
the effective date of
Requirement R4.
The Generator Owner failed to
document complete
information for IBR identified
with known hardware
limitations that prevent the
IBR from meeting Ridethrough criteria as detailed in
Requirements R1, R2, or R3.
OR
OR
OR
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
90 days but less than or equal
to 120 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
120 days, but less than or
equal to 150 days after
receiving a request for
additional information by an
entity listed in Requirement
R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
150 days but less than or equal
to 180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
provide a copy to the
applicable entities as detailed
in Requirement R4.2 within 24
months after the effective
date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
90 days but less than or equal
to 120 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
Final Draft of PRC-029-1
October 2024
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
120 days but less than or equal
to 150 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
150 days but less than or equal
to 180 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
OR
The Generator Owner failed to
respond to the applicable
Page 11 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
R#
Lower VSL
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), Reliability
Coordinator(s), and CEA more
than 90 calendar days but less
than or equal to 120 calendar
days after the change to the
hardware.
Moderate VSL
OR
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 120 calendar days but
less than or equal to 150
calendar days after the change
to the hardware.
High VSL
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 150 calendar days but
less than or equal to 180
calendar days after the change
to the hardware.
Severe VSL
entities as detailed in
Requirement R4.2.2 more than
180 days after receiving the
acceptance of a hardware
limitation by the CEA.
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s),Reliability
Coordinator(s), and CEA more
than 180 days after the change
to the hardware.
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
Final Draft of PRC-029-1
October 2024
Page 12 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Version History
Version
Date
1
10/8/24
Draft 4 approved by the NERC Board of
Trustees
1
10/16/24
Draft4_Errata approved by the Standards
Committee
Final Draft of PRC-029-1
October 2024
Action
Change
Tracking
Page 13 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-through Requirements for AC-Connected Wind IBR
13
Voltage
(per unit) 14
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 15
N/A
≥ 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
3.00
< 0.70
Mandatory Operation Region
2.50
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.16
< 0.10
Permissive Operation Region
0.16
Table 2: Voltage Ride-through Requirements for All Other IBR
Voltage
(per unit) 16
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 17
N/A
> 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
6.00
< 0.70
Mandatory Operation Region
3.00
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.32
< 0.10
Permissive Operation Region
0.32
Type 3 and type 4 wind resources directly connected to the AC Transmission System.
Refer to bullet #4 below.
15 These conditions are referred to as the “may Ride-through zone”.
16 Refer to bullet #4 below.
17 These conditions are referred to as the “may Ride-through zone”.
13
14
Final Draft of PRC-029-1
October 2024
Page 14 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
1. Table 1 applies to type 3 and type 4 wind IBR or hybrid IBR that include wind, unless
connected via a dedicated Voltage Source Converter - High Voltage Direct Current
(VSC-HVDC) transmission facility.
2. Table 2 applies to all other IBR types not covered in Table 1; including, but not
limited to, the following facilities:
a. IBR, regardless of their energy resource, interconnecting via a dedicated VSCHVDC transmission facility.
b. Other IBR or hybrid IBR consisting of photovoltaic (PV) and BESS.
3. The applicable voltage for VSC-HVDC system with a dedicated connection to an IBR
is on the AC side of the transformer(s) that is (are) used to connect the VSC-HVDC
system to the interconnected transmission system.
4. The voltage base for per unit calculation is the nominal phase-to-ground or
phase-to-phase transmission system voltage unless otherwise defined by the
Planning Coordinator, Transmission Planner, or Transmission Owner.
5. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase-to-neutral or phase-to-phase fundamental root mean square (RMS) voltage at
the high-side of the main power transformer.
6. Tables 1 and 2 are only applicable when the frequency is within the “must
Ride-through zone” as specified in Figure 1 of Attachment 2.
7. At any given voltage value, each IBR shall Ride-through unless the time duration at
that voltage has exceeded the specified minimum Ride-through time duration. If the
voltage is continuously varying over time, it is necessary to add the duration within
each band of Tables 1 and 2 over any 10 second time period.
8. The specified duration of the mandatory operation regions and the permissive
operation regions in Tables 1 and 2 is cumulative over one or more disturbances
within any 10 second time period.
9. The IBR may trip for more than four deviations of the applicable voltage at the highside of the main power transformer outside of the continuous operation region
within any 10 second time period.
10. Instantaneous trip settings based on instantaneously calculated voltage
measurements with less than filtering lengths of one cycle (16.6 millisecond) are not
permissible.
11. The “must Ride-through zone” is the combined area of the mandatory operating
regions, the continuous operating regions, and the permissive operating region. All
area outside of these operating regions is referred to as the “may Ride-through
zone”.
Final Draft of PRC-029-1
October 2024
Page 15 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 2: Frequency Ride-Through Criteria
Table 3: Frequency Ride-through Capability Requirements
System Frequency (Hz)
Minimum Ride-Through
Time (sec)
> 61.8
May trip
> 61.2
299
≤ 61.2 and ≥ 58.8
Continuous
< 58.8
299
< 57.0
May trip
1. Frequency measurements are taken at the high-side of the main power transformer.
2. Frequency is measured over a period of time (typically 3-6 cycles) to calculate system
frequency at the high-side of the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency value, each IBR shall Ride-through unless the time duration at
that frequency has exceeded the specified minimum ride-through time duration.
5. The specified durations of Table 3 are cumulative over one or more disturbances within
a 10-minute time period.
Final Draft of PRC-029-1
October 2024
Page 16 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
63
May Ride-through Zone
62
Frequency (Hz)
61
Must Ride-through Zone
60
59
58
May Ride-through Zone
57
56
0
100
200
300
299
400
500
600
700
800
900
∞
1000
Time (seconds)
Figure 1: PRC-029 Frequency Ride-through Requirements
Final Draft of PRC-029-1
October 2024
Page 17 of 17
Exhibit B
Implementation Plan
RELIABILITY | RESILIENCE | SECURITY
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Reliability Standards PRC-024-4 and PRC-029-1
Applicable Standard(s)
•
PRC-024-4 – Frequency and Voltage Protection Settings for Synchronous Generators, Type 1
and Type 2 Wind Resources, and Synchronous Condensers
•
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based
Generating Resources
Requested Retirement(s)
•
PRC-024-3 Frequency and Voltage Protection Settings for Generating Resources
Prerequisite Standard(s)
•
None
Applicable Entities
•
See subject Reliability Standards.
New Terms in the NERC Glossary of Terms
This section includes all newly defined, revised, or retired terms used or eliminated in the NERC
Reliability Standard. New or revised definitions listed below become approved when the proposed
standard is approved. When the standard becomes effective, these defined terms will be removed
from the individual standard and added to the Glossary.
Proposed New Definition(s):
Ride-through: The plant/facility remains connected and continues to operate through voltage or
frequency system disturbances.
Background
The purpose of Project 2020-02 is to modify Reliability Standard PRC-024-3 or replace it with a
performance-based Ride-through standard that ensures generators remain connected to the
Bulk Power System (BPS) during system disturbances. Specifically, the project focuses on using
disturbance monitoring data to substantiate inverter-based resource (IBR) ride-through performance
during grid disturbances. The project also ensures associated generators that fail to Ride-through
system events are addressed with a corrective action plan (if possible) and reported to necessary
entities for situational awareness.
RELIABILITY | RESILIENCE | SECURITY
The purpose for this project is based on the culmination of multiple analyses conducted by the ERO
Enterprise regarding widespread IBR tripping events. Furthermore, the NERC Inverter-Based Resource
Performance Subcommittee 1 has developed comprehensive recommendations for improved
performance of IBRs, including the recommendation to develop comprehensive ride-through
requirements.
In October 2023, FERC issued Order No. 901 2 which directs the development of new or modified
Reliability Standards that include new requirements for disturbance monitoring, data sharing, postevent performance validation, and correction of IBR performance. In January 2024, NERC submitted a
filing to FERC outlining a comprehensive work plan to address the directives within Order No. 901. 3
Within the work plan, NERC identified three active Standards Development projects that would need to
be filed for regulatory approval with FERC by November 4, 2024. These projects include 2020-02
Modifications to PRC-024 (Generator Ride-through) 4, 2021-04 Modifications to PRC-002-2 5, and 202302 Analysis and Mitigation of BES Inverter-based Resource Performance Issues 6.
Project 2020-02
Proposed Reliability Standard PRC-029-1 is a new Reliability Standard that includes Ride-through
requirements and performance requirements for IBRs. The scope of this project was adjusted to align
with associated regulatory directives from FERC Order No. 901 and the scope of the other projects
related to “Milestone 2” of the NERC work plan. The components of this project’s Standard
Authorization Request (SAR) that related to the inclusions of new data recording requirements are
covered in Project 2021-04 and the proposed new PRC-028-1 Reliability Standard. Components of this
project’s SAR that relate to analytics and corrective actions plans are covered in Project 2023-02 and the
proposed new PRC-030-1 Reliability Standard.
PRC-029-1 includes requirements for Generator Owner IBR to continue to inject current and perform
voltage support during a BPS disturbance. The standard also specifically requires Generator Owner IBR
to prohibit momentary cessation in the no-trip zone during disturbances.
PRC-024-4 includes modifications to revise applicable facility types to remove IBR, retain type 1 and
type 2 wind, and to include synchronous condensers.
See documents at the NERC IRPS website: https://www.nerc.com/comm/RSTC/Pages/IRPS.aspx and the previous Inverter-Based
Resource Performance Working Group website https://www.nerc.com/comm/RSTC/Pages/IRPWG.aspx
2 See FERC Order 901, Docket No. RM22-12-000; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=202310193157&optimized=false; October 19, 2023
3 See INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF
RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%2
0901%20Work%20Plan_packaged%20-%20public%20label.pdf; January 17, 2024
4 See NERC Standards Development Project page for Project 2002-02; https://www.nerc.com/pa/Stand/Pages/Project_202002_Transmission-connected_Resources.aspx
5 See NERC Standards Development Project page for Project 2021-04; https://www.nerc.com/pa/Stand/Pages/Project-2021-04Modifications-to-PRC-002-2.aspx
6 See NERC Standards Development Project page for Project 2023-02; https://www.nerc.com/pa/Stand/Pages/Project-2023-02Performance-of-IBRs.aspx
1
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | October 2024
2
General Considerations
This implementation plan recognizes the urgent need for Reliability Standards to address IBR ride
through performance, as demonstrated by multiple event reports of the last decade, while providing a
reasonable period of time for entities to develop the necessary procedures and change their protection
and control settings to meet the new requirements. The ERO Enterprise acknowledges that there are
IBRs currently in operation and unable to meet voltage Ride-through requirements due to their inability
to modify their coordinated protection and control settings. Consistent with FERC Order No. 901, a
limited and documented exemption process for those IBR is appropriate and included within this
Implementation Plan. Other NERC Standards Development projects will be pursued to address ongoing
identification and mitigation of any potential reliability impacts to the BPS for such exemptions.
This implementation plan also recognizes that certain requirements (Requirements R1, R2, and R3) call
for entities to “ensure the design and operation” of their IBR units meets certain criteria. Design
elements may be implemented more expeditiously than operation requirements; the latter of which
will require entities to show compliance through use of actual disturbance monitoring data. Therefore,
this implementation plan provides staggered timeframes by which entities shall first ensure the design
of their IBR units meets the criteria (12 months following regulatory approval). Subsequent compliance
with the “operation” elements of these requirements shall become due as entities install disturbance
monitoring equipment on each applicable IBR in accordance with the implementation plan for proposed
Reliability Standard PRC-028-1 Disturbance Monitoring and Reporting Requirements for Inverter-based
Resources.
The ERO Enterprise acknowledges that Generator Owners and Generator Operators owning or
operating Bulk Power System connected IBRs that do not meet NERC’s current definition of Bulk Electric
System (“BES”) will be registered no later than May 2026 in accordance with the IBR Registration
proceeding in FERC Docket No. RR24-2. To ensure an orderly registration and compliance process for
these entities, as well as fairness and consistency in the standard’s application among similar asset
types, this implementation plan provides additional time for both new and existing registered entities to
come into compliance with Reliability Standard PRC-029-1’s requirements for their applicable IBRs not
meeting the BES definition. In so doing, this implementation plan advances an orderly process for new
registrants while allowing existing entities to focus their immediate efforts on their assets posing the
highest risk to the reliable operation of the Bulk Power System.
Effective Date and Phased-in Compliance Dates
The effective dates for the proposed Reliability Standards are provided below. Where the standard
drafting team identified the need for a longer implementation period for compliance with a particular
section of a proposed Reliability Standard (i.e., an entire Requirement or a portion thereof), the
additional time for compliance with that section is specified below. The phased-in compliance dates for
those particular sections represent the date that entities must begin to comply with that particular
section of the Reliability Standard, even where the Reliability Standard goes into effect at an earlier
date.
PRC-024-4
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | October 2024
3
Where approval by an applicable governmental authority is required, Reliability Standard PRC-024-4
shall become effective on the first day of the first calendar quarter that is twelve months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC024-4 shall become effective on the first day of the first calendar quarter that is twelve months after the
date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1 and definition of Ride-through
Where approval by an applicable governmental authority is required, Reliability Standard PRC-029-1
and the definition of Ride-through shall become effective on the first day of the first calendar quarter
that is twelve months after the effective date of the applicable governmental authority’s order
approving the standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC029-1 and the definition of Ride-through shall become effective on the first day of the first calendar
quarter that is twelve months after the date the standard is adopted by the NERC Board of Trustees, or
as otherwise provided for in that jurisdiction.
PRC-029-1 Phased-in Compliance Dates
Requirements R1, R2, and R3
Capability-Based Elements
Bulk Electric System IBRs
Entities shall comply with the portion of Requirements R1, R2, and R3 relating to the design of their
BES IBRs to meet the requirements by the effective date of the standard.
Applicable Non-BES IBRs 7
Entities shall not be required to comply with Requirements R1, R2, and R3 relating to the design of
their applicable non-BES IBRs until the later of: (1) January 1, 2027; or (2) the effective date of the
standard.
Performance-Based Elements (all applicable IBRs)
Entities shall not be required to comply with the portion of Requirements R1, R2, and R3 relating to
the operation of IBRs to meet the requirements until the entity has established the required
The standard defines such as IBRs as “Non-BES Inverter-Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.”
7
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | October 2024
4
disturbance monitoring equipment capabilities for those IBRs in accordance with the
implementation plan for Reliability Standard PRC-028-1.
Requirement R4
Bulk Electric System IBRs
Entities shall comply with Requirement R4 for their BES IBRs by the effective date of the standard.
Applicable Non-BES IBRs
Entities shall not be required to comply with Requirement R4 or their non-BES IBRs until the later of:
(1) January 1, 2027; or (2) the effective date of the standard.
Retirement Date
PRC-024-3
Reliability Standard PRC-024-3 shall be retired immediately prior to the effective date of Reliability
Standards PRC-024-4 and PRC-029-1 in the particular jurisdiction in which the revised standard is
becoming effective.
Equipment Limitations and Process for Requirement R4
Consistent with FERC Order No. 901, a limited and documented exemption for some legacy IBR with
certain documented equipment limitations are acceptable. Per the Order, these IBRs are
“…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.” 8
To ensure compliance with Requirement R4 and alignment with FERC Order No. 901, only those IBR that
are in operation as of the effective date of PRC-029-1 may be considered for potential exemption.
Further, only those IBR that are unable to meet ride-through requirements due to their inability to
modify their coordinated protection and control settings may be considered for potential exemption.
8
Order No. 901 at p. 193.
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | October 2024
5
Exhibit C
Order No. 672 Criteria
RELIABILITY | RESILIENCE | SECURITY
EXHIBIT C
Order No. 672 Criteria
In Order No. 672, 1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria.
1.
Proposed Reliability Standards must be designed to achieve a specified reliability goal
and must contain a technically sound means to achieve that goal. 2
The Proposed Reliability Standards PRC-029-1 - Frequency and Voltage Ride-through
Requirements for Inverter-based Resources and Proposed Reliability Standard PRC-024-4 –
Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind
Plants, and Synchronous Condensers would advance the reliability of the Bulk-Power System
(“BPS”) by ensuring applicable BPS connected resources would Ride-through system disturbances
and avoid the negative reliability impacts associated with unnecessary tripping and momentary
cessation.
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, 114 FERC ¶ 61,104,
order on reh’g, Order No. 672-A, 114 FERC ¶ 61,328 (2006) [hereinafter Order No. 672].
2
See Order No. 672, supra note 1, at P 321 (“The proposed Reliability Standard must address a reliability
concern that falls within the requirements of section 215 of the FPA. That is, it must provide for the reliable operation
of Bulk-Power System facilities. It may not extend beyond reliable operation of such facilities or apply to other
facilities. Such facilities include all those necessary for operating an interconnected electric energy transmission
network, or any portion of that network, including control systems. The proposed Reliability Standard may apply to
any design of planned additions or modifications of such facilities that is necessary to provide for reliable operation.
It may also apply to Cybersecurity protection.”).
See Order No. 672, supra note 1, at P 324 (“The proposed Reliability Standard must be designed to achieve
a specified reliability goal and must contain a technically sound means to achieve this goal. Although any person may
propose a topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard
should be developed initially by persons within the electric power industry and community with a high level of
technical expertise and be based on sound technical and engineering criteria. It should be based on actual data and
lessons learned from past operating incidents, where appropriate. The process for ERO approval of a proposed
Reliability Standard should be fair and open to all interested persons.”).
Proposed Reliability Standards PRC-029-1 would require Generator Owners of InverterBased Resources (“IBR”) to Ride-through voltage and frequency system disturbances with
capability and performance-based requirements. Specifically, Reliability Standard PRC-029-1
would include requirements for Generator Owners to: (1) be able to properly Ride-through system
disturbances; (2) comply with applicable voltage and frequency Ride-through criteria to prevent
the unnecessary tripping and momentary cessation of current due to phase lock loop loss of
synchronism; and (3) ensure that post-disturbance ramp rates return to pre-disturbance levels.
Proposed Reliability Standard PRC-024-4 contains revisions to apply only to synchronous
generators, synchronous condensers, and type 1 and type 2 wind units. Proposed Reliability
Standard PRC-024-4 would continue to address frequency and voltage protection setting ranges,
but for synchronous units, type 1 and type 2 wind, and synchronous condensers only as IBRs are
now being addressed in proposed PRC-029-1. The revised standard applicability is supported by
the different natures of synchronous and IBR generation resources, including their risks,
performance, and equipment capabilities. Synchronous units do not require performance-based
requirements to Ride-through disturbances and type 1 and 2 wind units operate as asynchronous
generating resources and do not have modern controllers capable of riding through system events.
Ensuring fault ride-through capability enables dynamic reactive power support, frequency
response, and other services. The unexpected loss of widespread IBRs failing to Ride-through
poses a significant risk to BPS reliability and is well documented in multiple disturbance reports
and highlighted in Order No. 901.
2.
Proposed Reliability Standards must be applicable only to users, owners, and
operators of the bulk power system, and must be clear and unambiguous as to what
2
is required and who is required to comply. 3
The proposed Reliability Standards are clear and unambiguous as to what is required and
who is required to comply, in accordance with Order No. 672. Proposed Reliability Standard PRC029-1 would apply to Generator Owners owning IBRs that either meet the NERC Bulk Electric
System definition or Non-BES Inverter-Based Resources that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system
designed primarily for delivering such capacity to a common point of connection at a voltage
greater than or equal to 60 kV.
Proposed Reliability Standard PRC-024-4 would apply to synchronous generators,
synchronous condensers, and type 1 and type 2 wind units.
The proposed Reliability Standards clearly articulate the actions that applicable entities
must take to comply with the standards.
3.
A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 4
The Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for the
proposed Reliability Standard comport with NERC and Commission guidelines related to their
assignment, as discussed further in Exhibit F. The assignment of the severity level for each VSL
is consistent with the corresponding requirement, and the VSLs should ensure uniformity and
consistency in the determination of penalties. The VSLs do not use any ambiguous terminology,
thereby supporting uniformity and consistency in the determination of similar penalties for similar
3
See Order No. 672, supra note 1, at P 322 (“The proposed Reliability Standard may impose a requirement on
any user, owner, or operator of such facilities, but not on others.”).
See Order No. 672, supra note 1, at P 325 (“The proposed Reliability Standard should be clear and
unambiguous regarding what is required and who is required to comply. Users, owners, and operators of the BulkPower System must know what they are required to do to maintain reliability.”).
4
See Order No. 672, supra note 1, at P 326 (“The possible consequences, including range of possible penalties,
for violating a proposed Reliability Standard should be clear and understandable by those who must comply.”).
3
violations. For these reasons, the proposed Reliability Standards include clear and understandable
consequences in accordance with Order No. 672.
4.
A proposed Reliability Standard must identify clear and objective criteria or
measures for compliance, so that it can be enforced in a consistent and nonpreferential manner. 5
The proposed Reliability Standards contain measures that support each requirement by
clearly identifying what is required and how the requirement will be enforced. These measures
help provide clarity regarding how the requirements would be enforced and help ensure that the
requirements would be enforced in a clear, consistent, and non-preferential manner and without
prejudice to any party.
5.
Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently, but do not necessarily have to reflect “best practices” without regard to
implementation cost or historical regional infrastructure design. 6
The proposed Reliability Standards achieve their reliability goals effectively and efficiently
in accordance with Order No. 672. Proposed Reliability Standard PRC-029-1 would provide robust
and technically justified requirements for Generator Owners of IBRs to Ride-through system
disturbances and return post-disturbance ramp rates to pre-disturbance levels. Proposed Reliability
Standard PRC-029-1 focuses on addressing the important reliability issue of IBR ride-through
performance through capability and performance-based requirements for IBRs.
In drafting proposed Reliability Standard PRC-029-1, the drafting team determined that it
was necessary to include provisions allowing an exemptions from the Ride-through performance
criteria for legacy IBRs because of the hardware limitations associated with those facilities.
5
See Order No. 672, supra note 1, at P 327 (“There should be a clear criterion or measure of whether an entity
is in compliance with a proposed Reliability Standard. It should contain or be accompanied by an objective measure
of compliance so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential
manner.”).
6
See Order No. 672, supra note 1, at P 328 (“The proposed Reliability Standard does not necessarily have to
reflect the optimal method, or ‘best practice,’ for achieving its reliability goal without regard to implementation cost
or historical regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.”).
4
Specifically, it was determined that the anticipated difficulty of Generator Owners having to
wholesale retrofit and redesign legacy facilities currently in operation to meet the requirements of
the proposed standard would be unreasonable and unduly burdensome, and it could lead to
undesirable impacts on reliability. This exemption is limited to legacy units and only for those
criteria for which the hardware limitation exists.
Proposed Reliability Standard PRC-024-4, which is only minimally revised for
applicability, would continue to achieve its reliability goals effectively and efficiently for the
facilities to which it applies.
6.
Proposed Reliability Standards cannot be “lowest common denominator,” i.e., cannot
reflect a compromise that does not adequately protect Bulk-Power System reliability.
Proposed Reliability Standards can consider costs to implement for smaller entities,
but not at consequences of less than excellence in operating system reliability. 7
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. In accordance with the Commission’s direction in Order No. 901, proposed Reliability
Standard PRC-029-1 reflects a measured and reasoned consideration of the need for IBRs to Ridethrough system disturbances, balanced against the implementation burden on entities. Proposed
Reliability Standard PRC-029-1 would advance the reliability of the BPS by establishing
frequency and voltage Ride-through performance criteria for IBRs to prevent unnecessary tripping
or momentary cessation of current injection. Proposed Reliability Standard PRC-024-4 is only
minimally revised to limit its applicability for frequency and voltage protection setting ranges to
synchronous units, type 1 and type 2 wind units, and synchronous condensers.
7
See Order No. 672, supra note 1, at P 329 (“The proposed Reliability Standard must not simply reflect a
compromise in the ERO’s Reliability Standard development process based on the least effective North American
practice—the so-called ‘lowest common denominator’—if such practice does not adequately protect Bulk-Power
System reliability. Although the Commission will give due weight to the technical expertise of the ERO, we will not
hesitate to remand a proposed Reliability Standard if we are convinced it is not adequate to protect reliability.”).
See Order No. 672, supra note 1, at P 330 (“A proposed Reliability Standard may take into account the size
of the entity that must comply with the Reliability Standard and the cost to those entities of implementing the proposed
5
7.
Proposed Reliability Standards must be designed to apply throughout North America
to the maximum extent achievable with a single Reliability Standard while not
favoring one geographic area or regional model. It should take into account regional
variations in the organization and corporate structures of transmission owners and
operators, variations in generation fuel type and ownership patterns, and regional
variations in market design if these affect the proposed Reliability Standard. 8
The proposed Reliability Standards would apply consistently throughout North America
and would not favor one geographic area or regional model. While the penetration of IBRs may
vary by region, proposed Reliability Standard PRC-029-1 would apply to all IBRs due to the
reliability risk associated with IBRs failing to Ride-through system disturbances when they are
expected to perform. Proposed Reliability Standard PRC-024-4 would continue to apply across
North America without favoring any one geographic area or regional model.
Reliability Standard. However, the ERO should not propose a ‘lowest common denominator’ Reliability Standard that
would achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.”).
8
See Order No. 672, supra note 1, at P 331 (“A proposed Reliability Standard should be designed to apply
throughout the interconnected North American Bulk-Power System, to the maximum extent this is achievable with a
single Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.”).
6
8.
Proposed Reliability Standards should cause no undue negative effect on competition
or restriction of the grid beyond any restriction necessary for reliability. 9
The proposed Reliability Standards would have no undue negative effect on competition
and would not unreasonably restrict the available transmission capacity or limit the use of the BPS
in a preferential manner. The reliability need for performance-based requirements for IBRs to
Ride-through system disturbances (proposed PRC-029-1) is well documented in multiple
disturbance reports and highlighted in Order No. 901. The revised applicability reflected in
proposed Reliability Standard PRC-024-4 is supported by the different natures of synchronous and
IBR generation resources, including their risks, performance, and equipment capabilities.
9.
The implementation time for the proposed Reliability Standards is reasonable. 10
The implementation plan for the proposed Reliability Standards is just and reasonable and
appropriately balances the urgency in the need to implement the standards against the
reasonableness of the time allowed for those who must comply to develop necessary procedures
or other relevant capability. The proposed implementation plan provides that the proposed
Reliability Standards PRC-024-4 and PRC-029-1 shall become effective on the first day of the
first calendar quarter that is twelve (12) calendar months after the effective date of the
Commission’s order approving the proposed Reliability Standards. Currently effective Reliability
9
See Order No. 672, supra note 1, at P 332 (“As directed by section 215 of the FPA, the Commission itself
will give special attention to the effect of a proposed Reliability Standard on competition. The ERO should attempt to
develop a proposed Reliability Standard that has no undue negative effect on competition. Among other possible
considerations, a proposed Reliability Standard should not unreasonably restrict available transmission capability on
the Bulk-Power System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power
System in an unduly preferential manner. It should not create an undue advantage for one competitor over another.”).
10
See Order No. 672, supra note 1, 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 to develop the necessary procedures, software, facilities, staffing or other relevant
capability.”).
7
Standard PRC-024-3 would be retired immediately prior to the effective date of proposed
Reliability Standard PRC-024-4.
The Implementation Plan for proposed PRC-029-1 provides phased-in compliance dates
for both capability and performance-based elements of Requirements R1, R2, and R3 for BES
IBRs and non-BES IBRs.
For BES IBRs, the implementation timeframe for capability-based elements is as follows.
Generator Owners shall comply with the portion of Requirements R1, R2, and R3 relating to the
design of their BES IBRs to meet the requirements by the effective date of the standard.
Additionally, the implementation timeframe for the exemption process in Requirement R4 is the
effective date of the standard.
For non-BES IBRs, the implementation timeframe for capability-based elements is as
follows. Generator Owners shall comply with the portion of Requirements R1, R2, and R3 relating
to the design of their applicable non-BES IBRs until the later of: (1) January 1, 2027; or (2) the
effective date of the standard. Additionally, the implementation timeframe for the exemption
process in Requirement R4 is the later of: (1) January 1, 2027; or (2) the effective date of the
standard.
For all IBRs, the implementation timeframe for performance-based elements is as follows.
Generator Owners shall not be required to comply with the portion of Requirements R1, R2, and
R3 relating to the operation of IBRs to meet the requirements until the entity has established the
required disturbance monitoring equipment capabilities for those IBRs in accordance with the
implementation plan for proposed Reliability Standard PRC-028-1. 11 Under that plan, Generator
11
The proposed implementation plan for proposed Reliability Standards PRC-028-1 and PRC-002-5 provides
that the proposed standards would become effective the first calendar quarter following regulatory approval.
8
Owners will follow a phased-in compliance timeline with requirements to establish disturbance
monitoring capabilities fully implemented by January 1, 2030.
This Implementation Plan recognizes the need for this phased in compliance timeline so
entities can establish disturbance monitoring capabilities before having to comply with the
performance-based elements of proposed Reliability Standard PRC-029-1. Further, Generator
Owners and Generator Operators owning or operating BPS connected IBRs that do not meet
NERC’s current definition of BES will be registered no later than May 2026 in accordance with
the IBR Registration proceeding in FERC Docket No. RR24-2. To ensure an orderly registration
and compliance process for these entities, as well as fairness and consistency in the standard’s
application among similar asset types, the proposed Implementation Plan provides additional time
for both new and existing registered entities to come into compliance with new IBR Ride-through
requirements for their applicable IBRs not meeting the BES definition. In so doing, this
Implementation Plan advances an orderly process for new registrants while allowing existing
entities to focus their immediate efforts on their assets posing the highest risk to the reliable
operation of the BPS.
Implementation of PRC-028-1 would then follow a phased-in compliance timeline, ending by 2030. The relevant dates
under that plan are as follows:
BES IBRs: Generator Owners shall comply with requirements to establish disturbance monitoring data
recording capabilities for 50% of their existing BES IBRs (i.e. in commercial operation on or before the effective date)
within three calendar years of the effective date of PRC-029-1, and 100% of their BES IBRs by January 1, 2030. If a
Generator Owner has only one such BES IBR, it shall comply within three calendar years. For new BES IBRs,
Generator Owners shall comply within 15 calendar months following the effective date of the standard or by the
commercial operation date, whichever is later.
Non-BES IBRs: Generator Owners shall comply with requirements to establish disturbance monitoring data
recording capabilities for 100% of those non-BES IBRs in commercial operation prior to May 15, 2026 by no later
than January 1, 2030. Generator Owners shall comply with for their new non-BES IBRs within 15 calendar months
following the effective date of the standard or by the commercial operation date, whichever is later.
Additional information is available in Section VIII and Exhibit B to NERC’s Petition for Approval of
Proposed Disturbance Monitoring Reliability Standards PRC-028-1 and PRC-002-5 (Nov. 4, 2024).
9
This phased in implementation plan is consistent with Order No. 672 and complies with
FERC’s directive in Order No. 901 that NERC “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 rule prior to [2030].” 12
10.
The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 13
The proposed Reliability Standards were developed in accordance with NERC’s
Commission-approved processes for developing and approving Reliability Standards. Exhibit G
includes a summary of the Reliability Standards development proceedings, and details the
processes followed to develop the proposed Reliability Standards. These processes included,
among other things, comment periods, pre-ballot review periods, and balloting periods.
Additionally, all meetings of the standard drafting team were properly noticed and open to the
public.
11.
NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards. 14
NERC has identified no competing public interests regarding the request for approval of
this proposed Reliability Standards. No comments were received that indicated that the proposed
Reliability Standards conflict with other vital public interests.
12
226.
Reliability Standards to Address Inverter-Based Resources, Order No 901, 185 FERC ¶ 61,042 (2023) at P
13
See Order No. 672, supra note 1, at P 334 (“Further, in considering whether a proposed Reliability Standard
meets the legal standard of review, we will entertain comments about whether the ERO implemented its Commissionapproved Reliability Standard development process for the development of the particular proposed Reliability
Standard in a proper manner, especially whether the process was open and fair. However, we caution that we will not
be sympathetic to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s
Reliability Standard development process if it is conducted in good faith in accordance with the procedures approved
by the Commission.”).
14
See Order No. 672, supra note 1, at P 335 (“Finally, we understand that at times development of a proposed
Reliability Standard may require that a particular reliability goal must be balanced against other vital public interests,
such as environmental, social and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.”).
10
12.
Proposed Reliability Standards must consider any other appropriate factors. 15
No other negative factors relevant to whether the proposed Reliability Standards are just
and reasonable were identified.
15
See Order No. 672, supra note 1, at P 323 (“In considering whether a proposed Reliability Standard is just
and reasonable, we will consider the following general factors, as well as other factors that are appropriate for the
particular Reliability Standard proposed.”).
11
Exhibit D
Consideration of Directives
RELIABILITY | RESILIENCE | SECURITY
Standards Development Consideration of Directives from
FERC Order 901
Background
The Federal Energy Regulatory Commission (FERC) issued Order No. 901 on October 19, 2023, which includes directives on new or modified NERC Reliability
Standard projects. Order No. 901 addresses a wide spectrum of reliability risks to the grid from the application of inverter-based resources (IBR); including
both utility scale and behind the-meter or distributed energy resources. Within the Order, are four milestones that include sets of directives to NERC. The
first milestone was achieved on January 17, 2024 as NERC filed its initial work plan to address all aspects of Order No. 901 throughout the next three years. 1
The filed work plan includes extensive detail on Standards Development approach and next steps to accomplish the suite of directives addressing IBR. The
work plan was intended to be an initial roadmap to guide development for each of the Reliability Standards Projects identified as a 901-related project.
This document includes specifics for how each directive assigned to Project 2020-02 Modifications to PRC-024 (Generator Ride-through) drafting team have
been addressed.
Resources
FERC Order No. 901 – Final Rule Reliability Standards to Address Inverter-Based Resources
NERC Mapping Document for FERC Order 901 Directives to Standards Development Projects, Draft SARs, and Pending SARs
1
INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901; 01/17/2024;
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%20901%20Work%20Plan_packaged%20%20public%20label.pdf
RELIABILITY | RESILIENCE | SECURITY
Index
Paragraph
Milestone
of Order
49
190
2
50
190
2
Directive Subpart Summary
“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 support
during a Bulk-Power System
disturbance.”
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
The new standard PRC-029-1 will require registered generator
owners of IBRs to both design and operate their IBR plants to ride
through voltage and frequency excursions within “must ridethrough zones” according to how these zones are defined in the
standard. The must ride-through zones are defined in terms of
voltage and frequency magnitude and time duration. Tripping of
IBR plants is permitted only outside of the defined must ridethrough zones. The voltage and frequency must ride-through
zones are based on IEEE 2800-2022 no-trip zones and are
established in view of experience with voltage and frequency
excursions in planning and operating criteria disturbances, underfrequency load shedding stages, reasonable and practical limits of
IBR voltage and frequency tolerances, PRC-024-3 voltage and
frequency relay setting graphs, and include adequate margins
against worst-case conditions that could be brought about during
system disturbances.
In association with the new PRC-029 standard, a definition of the
term ride-through is proposed for addition to the NERC Glossary of
Terms that essentially states that IBR facilities must remain
connected and continue to fulfill their established control and
regulation functions (which generally involve exchange of current)
in order to qualify as riding through system disturbances. Support
of frequency is predicated on, and to a large degree achieved by
the riding through of system disturbances.
Frequency regulation (or governing) is presently not a continentwide necessity and not a requirement on individual generating
2
Index
Paragraph
Milestone
of Order
51
190
2
52
190
2
53
193
2
Directive Subpart Summary
“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, postdisturbance ramp rates, phase
lock loop synchronization, and
other known causes of IBR
tripping or momentary
cessation.”
“Therefore, we direct NERC
through its standard
development process to
determine whether the new
or modified Reliability
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
plants/facilities in NERC standards. RTO/ISO requirements may
apply.
Momentary cessation, understood as inverter temporary current
blocking while still remaining connected, is restricted to only two
system conditions: 1) non-fault line switching caused voltage
phase angle jumps in excess of 25 degrees that could result in
tripping unless the inverter goes into current blocking, and 2)
while voltage at the plant-system interface is less than 0.10 per
unit during which time it may be difficult or impractical to
maintain current exchange.
IBR frequency and voltage ride through requirements are
established in the new PRC-029 standard as noted above. A
default post-disturbance ramp rate of 1.0 second is specified
unless a faster or slower rate is specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator to accommodate specific system postdisturbance recovery needs. Any Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator
specified ramp rate becomes the standard requirement. Tripping
due to phase lock loop loss of synchronism is specifically not
permitted within voltage and frequency must ride through zones.
Exemption from the voltage must ride-through zone requirement
of PRC-029-1 is permitted for IBR plants/facilities that are in
service at the enforcement date of the standard. The IBR
Generator Owner must document the need for an exemption and
the documentation must explain what hardware prevents the IBR
3
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
Standards should provide for a
limited and documented
exemption for certain
registered IBRs from voltage
ride through performance
requirements.”
54
193
2
“Further, we direct NERC to
ensure that any such
exemption would be
applicable for only existing
equipment that is unable to
meet voltage ride-through
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
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
from meeting the requirement and must be specific as to what
aspect of the voltage must ride-through zone cannot be met. The
Compliance Enforcement Authority checks that all aspects of the
documentation specified in the standard have been provided by
the GO and the GO is required to supply further information on
the need for and the nature of the exemption if requested by the
Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator. The implementation plan
provides a 12-month time window for exemption requests to be
submitted following the enforcement date. Following the 12month window, further exemption requests will either not be
accepted or could be considered an admission of non-compliance.
The exemption provision of PRC-029-1 is available only for IBR
plants/facilities that are in service at the enforcement date as
noted above. The exemption provision also stipulates that once
the plant/facility hardware causing the inability to comply with the
voltage must ride-through requirement is replaced, the exemption
is withdrawn (“no longer applies”).
4
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
through, phase lock loop,
ramp rates, etc.).”
55
193
2
“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).”
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
The exemption provision of PRC-029-1 requires an IBR Generator
Owner to supply its exemption request documentation to its
Transmission Planner, Planning Coordinator, Reliability
Coordinator, and Transmission Operator within the 12-month
window following the enforcement date as noted above.
5
Index
Paragraph
Milestone
of Order
56
199
2
57
208
2
Directive Subpart Summary
“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, we
direct NERC to develop new or
modified Reliability Standards
to mitigate the reliability
impacts to the Bulk-Power
System of such an
exemption.”
“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
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
Mitigation of the reliability impacts of voltage must ride-through
exemptions are existing NERC standard responsibilities of
Transmission Planners, Planning Coordinators, Reliability
Coordinators, and Transmission Operators under TPL, IRO, TOP,
and other standards. These entities may need to restrict the
operation of exempted IBRs where and when their tripping may
result in detrimental reliability impacts.
As indicated above, a default post-disturbance ramp rate of 1.0
second is specified unless a faster or slower rate is specified by the
Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator to accommodate specific
system post-disturbance recovery needs. Any Transmission
Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator specified ramp rate becomes the standard
requirement.
6
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
programmed to artificially
interfere with the resource
returning to a pre-disturbance
output level in a quick and
stable manner after a BulkPower System.”
59
209
2
60
209
2
“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-
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Description of How This Directive has Been Addressed
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Phase lock loop loss of synchronism is not allowed as a cause of
tripping while voltage remains within the must ride-through zone
unless there are phase jumps more than 25 degrees caused by
non-fault switching events. A footnote under R1 also specifically
states that phase lock loop loss of synchronism as not a
permissible condition for tripping while voltage remains within the
must ride-through zone.
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
As indicated above, tripping due to phase lock loop loss of
synchronism is specifically not permitted within voltage and
frequency must ride-through zones. The requirement to return to
pre-disturbance power also includes a provision for return to
“available active power" to allow for “changes of facility
active power output attributed to factors such as weather
patterns, change of wind, and change in irradiance,” but
“changes of facility active power attributed to IBR tripping in
7
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
Power System at predisturbance levels during a
disturbance, consistent with
the IBR Interconnection
Requirements Guideline and
Canyon 2 Fire Event Report
recommendations.”
61
209
2
63A
226
2
“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.”
“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
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Description of How This Directive has Been Addressed
whole or part” are not permitted. Injecting current at predisturbance levels during a disturbance is not always
practical or desirable. PRC-029-1 R2 specifies IBR required
active and reactive power performance during voltage
disturbances.
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
IBRs are non-synchronous but can exhibit forms of instability other
than loss of synchronism. System stability is a shared responsibility
of Transmission Planners, Planning Coordinators, Reliability
Coordinators, and Transmission Operators. IBR generation levels
may need to be restricted by these entities to maintain system
stability including IBR stability.
Each of the
identified
Reliability
Standards Projects
in Milestone 2 will
include
implementation
plans that assure
The PRC-029-1 implementation is a staggered implementation
beginning twelve months following governmental approval with
enforcement of all provisions within the twelve months following
approval except as necessary to coordinate with the PRC-028-1
implementation plan that extends to 2030.
8
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
sequentially stagger the
effective and enforceable
dates to ensure an orderly
industry transition for
complying with the IBR
directives in this final rule
prior to that date.”
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
all new or
modified
Reliability
Standards are
effective and
enforceable
before 2030.
Description of How This Directive has Been Addressed
9
Exhibit E
Technical Rationale
RELIABILITY | RESILIENCE | SECURITY
Exhibit E-1
Technical Rationale
PRC-024-4
RELIABILITY | RESILIENCE | SECURITY
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-024-4 – Frequency and Voltage Protection Settings for Synchronous
Generators, Type 1 and 2 Wind Plants, and Synchronous Condensers
General Rationale
The drafting team proposes to modify PRC-024-3 to retain the Reliability Standard as a protection-based
standard with applicability to only synchronous generators, synchronous condensers, and type 1 and 2
wind plants. This proposal is a consequence of both the different natures of synchronous and inverterbased generation resources and several recent events exhibiting significant IBR ride-through deficiencies.
The behavior of rotating synchronous generators during faults and other disturbances on the transmission
system is well established and understood in comparison to IBR generation. The disturbance ride-through
vulnerabilities of synchronous generators are pole slipping instability and undervoltage dropout of critical
plant auxiliary equipment, leading to tripping of a generator. Pole slipping (or loss of synchronism) can be
managed by active power dispatch constraints or stability System Operating Limits, and is outside the
scope of Project 2020-02. Undervoltage dropout of critical auxiliary equipment is also outside the scope of
Project 2020-02 because of complexities associated with auxiliary systems and how such equipment
behaves under low voltage conditions. The Project 2020-02 Standard Authorization Request (SAR) notes
that auxiliary equipment has not posed a ride-through risk and the SAR specifically excludes modifications
in PRC-024-3 for auxiliary equipment.
Over-frequency protection, under-frequency protection, over-voltage protection, and under-voltage
protection may or may not be applied to synchronous generating units. If applied, settings should be
coordinated between the needs of generating unit protection and the no-trip zones within PRC-024-4
attachments. Coordination of generating unit capabilities, voltage regulating controls, and protection is
addressed within PRC-019-2. Excitation and governing controls affect synchronous generator ride-through
behavior to some degree but because of progressive improvement, standardization, and level of maturity
of these controls, they are rarely a cause of unnecessary tripping during disturbances. In addition, there
are other existing NERC standards to prevent unnecessary tripping of the generators during a system
disturbance such as PRC-025-2 “Generator Relay Loadability” and PRC-026-2 “Relay Performance During
Stable Power Swings”. For these reasons, there is no need to impose actual disturbance ride-through
requirements on synchronous units but only to include restrictions for frequency and voltage protection
setting ranges as maintained in PRC-024-4.
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for setting frequency, voltage, and volts per hertz protection for
synchronous generators, type 1 and 2 wind plants, and synchronous condensers is either the Generator
Owner (GO) or Transmission Owner (TO). Planning Coordinators (PC) are retained as applicable entities
only in the Quebec Interconnection. Modifications are proposed in PRC-024-4 to expand functional entity
RELIABILITY | RESILIENCE | SECURITY
applicability to include “Transmission Owners that apply protection” because of the inclusion of
synchronous condenser applicability in section 4.2.2.
Facilities (4.2)
Applicability Facilities subparts in Section 4.1.1 were modified to restrict PRC-024-4 to synchronous
generators and type 1 and 2 wind plants. Section 4.2.2 was added to cover synchronous condensers and
associated equipment.
Rationale for Requirements R1 through R4
Modifications were made to Requirements R1, R2, R3, and R4 to include the Transmission Owner as a
functional entity applicable to each requirement because of the addition of synchronous condensers.
Modifications were made to Requirements R1, R2, R3, and R4 to include language for type 1 and 2 wind
plants and synchronous condensers and to remove language that relates to inverter-based resource (IBR)
functionality since IBRs will be addressed in a new standard PRC-029-1.
Technical Rationale for Reliability Standard PRC-024-4
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
2
Exhibit E-2
Technical Rationale
PRC-029-1
RELIABILITY | RESILIENCE | SECURITY
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1 – Frequency and Voltage Ride-through Requirements for
Inverter-based Generating Resources
General Rationale
The drafting team has created a new Reliability Standard (PRC-029-1) to address inverter-based resource
(IBR) disturbance Ride-through performance criteria. This proposal is a consequence of both the different
natures of synchronous and inverter-based generation resources and several recent events exhibiting
significant IBR Ride-through deficiencies1. The proposed PRC-029-1 aligns with certain Ride-through
requirements of IEEE Std 2800™, IEEE Standard for Interconnection and Interoperability of Inverter-Based
Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems, primarily for
frequency Ride-through, and is structured to follow language from FERC Order No. 901, which states that
“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
The lack of standardization of IBR performance and the software-based nature of the technologies has
created reliability challenges associated with the interconnection of IBR facilities to the power grid. The
nature of the fast switching of power electronics of IBR generation, IBR’s software-based nature, and the
electronic interface to the transmission system is such that disturbance Ride-through behavior is largely
determined by manufacturer-specific equipment and controls system designs. These controls may be
programmed, but also have more restrictive limits on current, both in magnitude and duration. IBR
responses to grid disturbances are highly controlled and managed by using fast switching of power
electronics devices dependent upon manufacturer specific control system design software that can be
programmed in many ways and with various and concurrent Ride-through performance objectives. Rather
than attempting to restrict the myriad of control approaches, protections, and settings, it is more
straightforward to require Ride-through during defined frequency and voltage excursions.
In contrast to synchronous generation, the need for IBR Ride-through requirements has been heightened
by recent events during which IBRs have not met PRC-024-3 frequency and voltage Ride-through
expectations, often due to controls and protection only indirectly associated with the system voltage and
frequency excursions. In addition to Ride-through, there is the question of what IBRs should be doing as
they Ride-through. IBR responses to system disturbances can be beneficial or detrimental to both their
own Ride-through and system reliability, often depending on adjustable control settings. Thus, it is
essential to set expectations on performance during Ride-through as well as Ride-through capability.
Event Reports (nerc.com)
P 195, FERC Order No. 901; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019-3157&optimized=false; October 17,
2023
1
2
RELIABILITY | RESILIENCE | SECURITY
A further reason for proposing a separate IBR standard is that the inertial and short circuit contributions
from IBR are significantly different than synchronous machines. The drafting team thinks that IBRs should
Ride through voltage and frequency excursions up to their maximum capability, while using expanded
voltage and frequency Ride-through criteria to drive those enhancements. These differences between
synchronous machines and IBR contribute to the differences in the frequency and voltage tables and
graphs between the PRC-024-4 and PRC-029-1 standards.
The proposed PRC-029-1 must be understood generally as an event-based standard though it is also
required to provide evidence of the ability to Ride-through disturbance events by means of dynamic
models and simulation results. Compliance with PRC-029-1 is determined chiefly, though not exclusively,
from IBR Ride-through performance during transmission system events in the field. An IBR becomes
noncompliant with PRC-029-1 when an event in the field occurs that shows that one or more
requirements were not satisfied. This intent is clarified by Operations Assessment as the Time Horizon
designation of requirements R1-R3.
FERC Order No. 901 Directives
PRC-029-1 is proposed in consideration of directives from FERC Order No. 901 that were assigned to the
Project 2020-02 drafting team. The following directives were assigned to this drafting team for inclusion in
this standards project (paragraph numbers of the FERC Order are included for reference):
•
Paragraph 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.”
•
Paragraph 190: “The new or modified Reliability Standards must require registered IBRs to
continue to inject current and perform frequency support during a Bulk-Power System
disturbance.”
•
Paragraph 190: “Any new or modified Reliability Standard must also require registered IBR
generator owners and operators to prohibit momentary cessation in the must Ride-through zone
during disturbances.”
•
Paragraph 190: “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.”
•
Paragraph 193: “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.”
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
2
•
Paragraph 193: “Further, we direct NERC to ensure that any such exemption would be applicable
for only existing equipment that is unable to meet voltage Ride-through 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.).”
•
Paragraph 193: “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).”
•
Paragraph 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, we direct NERC to
develop new or modified Reliability Standards to mitigate the reliability impacts to the Bulk-Power
System of such an exemption.”
•
Paragraph 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 pre-disturbance output level
in a quick and stable manner after a Bulk-Power System.”
•
Paragraph 209: “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 predisturbance levels during a disturbance, consistent with the IBR Interconnection Requirements
Guideline and Canyon 2 Fire Event Report recommendations.”
•
Paragraph 209: “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.”
•
Paragraph 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.”
•
Paragraph 226: “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 rule prior to
that date.” (pertains to multiple projects)
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
3
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for assuring acceptable Ride-through performance of IBR is the
Generator Owner.
Facilities (4.2)
Applicability Facilities include only IBR that also meet NERC registration criteria. Language used within
PRC-029-1 applicability only refers to IBR as a whole plant/facility. Consistent with FERC Order No. 901,
IBR performance is based on the overall IBR plant and disturbance monitoring equipment requirements
established under the proposed PRC-028-1. Requirements within PRC-029-1 do not apply to individual
inverter units or measurements taken at individual inverter unit terminals.
Rationale for Requirement R1
The objective of Requirement R1 is to ensure that all applicable IBRs will Ride-through grid voltage
disturbances consistent with the must Ride-through zone and operation regions specified in Attachment
1. IBRs must be able to demonstrate Ride-through performance, that they remain electrically connected,
i.e., shall not trip, and continue to exchange current, i.e., shall not enter momentary cessation.
The drafting team determined that the definition of “must Ride-through zones” and “operation regions”
should be consistent with those terms as used within IEEE 2800-2022. Additionally, the team determined
that the voltage thresholds of each operation region should be based on measurements taken on the
high-side of the main power transformer in PRC-029-1, also consistent with IEEE 2800-2022.
Battery Energy Storage Systems (BESS) units also must comply with Requirement R1 in all operating
modes including charging, discharging, and idle (energized, but not charging or discharging). A BESS in idle
mode must be capable of responding to system voltage and frequency excursions as it does in charging or
discharging modes.
Exceptions to Attachment 1 performance criteria are allowable when 1) an IBR needs to trip to clear a
fault, 2) voltage at the high-side of the main power transformer goes outside an accepted and a
documented hardware equipment limitation established in accordance with Requirement R4, 3)
instantaneous positive sequence voltage phase angle jumps more than 25 electrical degrees at the highside of the main power transformer initiated by a non-fault switching events occur on the transmission
system, or 4) volts per Hz (V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for
longer than 45 seconds or exceed 1.18 per unit for longer than 2 seconds.
When a grid disturbance occurs, such as a close-in fault or a relatively large switching event, the grid
voltage may experience a rapid phase angle shift. In such cases, the phase displacement Δθ can be large
enough to pose challenges for the phase lock loop (PLL) to track the terminal voltage, cause control
instability within the inverter, such as the inner current control loop or the DC link control loop, and even
lead to tripping of the inverter due to the malfunction of the controls.
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
4
Since phase angle jumps are common occurrences on the BPS, this standard requires the IBR to be
designed and operated to Ride-through a minimum phase angle jump of 25 electrical degrees. This is a
typical value and aligns with the requirement in IEEE 2800-2022.
Some IBR equipment has PLL loss of synchronism protection, referring to a protective function that
operates when the angle displacement Δθ exceeds a threshold for a predetermined period of time (on the
order of a couple of milliseconds). Historically, this protection has been used by some inverter
manufacturers, especially for inverters in distribution systems. For the IBR connected to the BPS, this
protection function should be disabled. If it is enabled, the phase angle jump protection setting should be
configured such that the IBR shall only trip to prevent equipment damage.
Rationale for Requirement R2
In addition to having minimum voltage Ride-through capability specified in Requirement R1, all applicable
IBRs are also required to adhere to certain voltage Ride-through performance criteria during system
disturbances. Acceptable performance criteria depend on the operation region that an IBR is presently in
or when in transition from one operation region to another operation region. Requirement R2 includes
specific performance criteria and is needed to assure consistent IBR performance within and each
operation region in Attachment 1 and when in transition between regions.
R ationale for R equirem ent R2.1
This subpart of Requirement R2 ensures that when the voltage at the high-side of the main power
transformer (MPT) recovers to the continuous operation region from either the mandatory operation
region or the permissive operation region, an IBR delivers the pre-disturbance level of Real Power or
available Real Power, whichever is less. Available Real Power allows for changes of facility Real Power
output attributed to factors such as weather patterns, change of wind, and change in irradiance, but not
changes attributed to IBR tripping in whole or part. This requires an IBR to exit the “High Voltage Ride
Through (HVRT)” or “Low Voltage Ridge Through (LVRT)” modes properly such that it does not cause
reduction in the Real Power when the high-side of MPT voltage recovers to within the continuous
operation region.
When the voltage at the high-side of the MPT is greater than 0.90 per-unit and less than 0.95 per-unit,
IBRs are expected to exit the LVRT mode and come back to “normal operating mode”. If an IBR has a
default total current limit of 1.0 per-unit, the apparent power production of an IBR will be limited below
1.0 per-unit (e.g., the per-unit value of IBR terminal voltage). In such case, the IBR needs to configure a
preference setting, either to maintain pre-disturbance Real Power or maximize the Reactive Power in
order to further help with voltage recovery, or according to requirements specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
R ationale for R equirem ent R2.2
This subpart of Requirement R2 ensures that when the voltage at the high-side of the MPT is within the
mandatory operation region, IBRs inject or absorb reactive current proportional to the level of terminal
voltage deviations they measure. IBRs shall follow Transmission Planner, Planning Coordinator, Reliability
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
5
Coordinator, or Transmission Operator specified certain magnitude of Reactive Power response to voltage
changes, if available.
By default, reactive current prioritization shall be configured unless Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator requires Real Power priority.
R ationale for R equirem ent R2.3
This subpart of Requirement R2 ensures that when the voltage at the high-side of the MPT is within the
permissive operation region, IBRs continue to Ride-through, though they are briefly allowed to enter the
current block mode if necessary to avoid tripping off from the grid. The drafting team takes into
consideration the physical operational capability of the power electronics devices under such low voltage
conditions. However, the IBR facility shall restart current exchange in less than or equal to five cycles of
positive sequence voltage returning to the continuous operation region or mandatory operation region. If
the interconnecting entity has performance requirements that are more stringent than the standard, the
Generator Owner should follow the requirements set by the interconnecting entity.
R ationale for R equirem ent R2.4
This subpart of Requirement R2 ensures when a fault is cleared on the transmission system, the voltage
regulators of connected IBRs must adjust the reactive current injection to restore the transmission system
voltage to the pre-disturbance voltage as defined by the automatic voltage regulator (AVR) setpoint. The
drafting team acknowledges that tuning of the AVR requires a balance between multiple competing
physical factors, e.g., rise time, overshoot, and transient stability. However, it is anticipated that IBR
controls will be tuned to allow for a stable post-disturbance voltage recovery without causing excessive
overshoot or undershoot of the setpoint. When such overshoots do occur, they must not exceed the
magnitude and duration of the applicable table given in Attachment 1. Furthermore, this standard
anticipates that control system tuning to prevent such over/under voltages will focus on the speed at
which the controller responds to setpoint changes rather than on the magnitude of the reactive current
response. For example, reductions in k-factor to prevent over/under voltages should only be considered
as a last resort.
R ationale for R equirem ent R2.5
This subpart of Requirement R2 ensures that the IBR returns to effective pre-disturbance operation unless
otherwise specified or needed by the Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator.
Rationale for Requirement R3
The objective of Requirement R3 is to ensure that IBRs Ride-through frequency excursion events with
magnitude and time durations as defined in Attachment 2.
Grid frequency reflects the balance of system generation and load. A system event that causes a
generation/load imbalance will cause system frequency to deviate from nominal. The system may
experience an over-frequency event (in the case of more generation than load) or an under-frequency
event (in the case of less generation than load). Inertia resists the deviation from nominal frequency,
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
6
giving the operators additional time to rebalance generation and load. With the current resource mix,
system inertia is dependent on the amount of rotating mass connected to the system (i.e., synchronous
generators or motors). The larger the system inertia, the slower the system frequency will deviate from
the nominal value and the lower the grid Rate Of Change Of Frequency (ROCOF), giving more time to try to
rebalance generation and load.
A reduction in system inertia is an inevitable consequence of a power system transiting toward more IBR
and less synchronous generators, however the utilization of IBR-specific control features (i.e., advanced
control modes and Grid Forming technologies) can provide additional stability benefits to help mitigate
the loss of inertia. As discussed in the previous paragraph, less system inertia means the frequency will
deviate from the nominal value more quickly during a generation/load imbalance event and will expose
the system to a higher ROCOF. A wider frequency Ride-through capability for IBR may be required to
avoid the risk of widespread tripping.
When considering an expansion of Ride-through capability, it is important to balance the expansion with
the feasibility of producing and installing equipment that can meet the newly proposed criteria. Failure to
adequately consider this could result in resource adequacy deficiencies if expanded criteria lead to
widespread non-compliance of legacy IBR due to hardware limitations. Further, for newly interconnecting
IBR, expanded Ride-through criteria often result in significant design changes that have production time
and cost implications. If proposed Ride-through criteria are too stringent and result in costly design
changes, those costs could result in a slowing of IBR penetration on the BPS.
For the reasons above, it is imperative that newly created Ride-through criteria are reasonable for both
BPS reliability and for the IBR equipment. To date, NERC has analyzed numerous major events including
both winter storms Uri and Elliot. No IBR tripped offline for frequency threshold criteria (because the
system frequency caused a trip due to exceeding equipment frequency limits) and all frequency-related
tripping observed were due to mis-parameterization or the use of instantaneous measurements in
protection schemes. Additionally, the deviations in frequency observed during the events listed above did
not exceed the PRC-024 criteria. It should be noted that winter storm Uri did produce a frequency
excursion extremely close to, and even touching, the criteria in PRC-024.
With no “benchmark events” to inform criteria expansions, studies could be used to assess future BPS
needs. These studies would need a detailed list of scenarios, including different IBR penetrations and load
levels, and are dependent on the ability to accurately model current and future IBR technologies,
including GFM functions. NERC has issued two level 2 alerts related to IBR, one on IBR performance and
the second on modeling. These alerts seek to obtain data from IBR while also giving recommendations to
mitigate the observed systemic modeling and performance deficiencies of IBR. Given these observed
deficiencies and the lack of recently conducted detailed system-wide studies, there is insufficient studybased evidence to inform widely expanded Ride-through criteria.
It is clear however that the performance of the BPS during disturbance will change as the IBR penetration
increases. How this performance will change can be predicted with detailed studies, but an incremental
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
7
approach to expanding Ride-through criteria adds additional stability margin while modeling deficiencies
are addressed and detailed studies are conducted.
The frequency Ride-through times and thresholds in IEEE 2800-2022 are more stringent (wider) than
those presently in PRC-024-3 and contain continuous operation ranges that exceed the frequency
excursions observed during major BPS disturbances. Detailed feedback from original equipment
manufacturers (OEM) provides insight that they are already designing IBR equipment that conforms with
the criteria in IEEE 2800-2022. For this reason, the frequency Ride-through criteria in the PRC-029
standard are in alignment with those criteria in IEEE 2800-2022, which provides an expansion of Ridethrough criteria compared to PRC-024 while also minimizing cost and timeline implications as OEM are
already designing conforming equipment.
Requirement R3 does not prescribe specific frequency protection settings for IBR equipment. IBR
frequency protection settings should only be set to protect the IBR from damage caused by operation at
off-nominal frequency. An IBR owner must ensure that the IBR frequency protection does not prevent an
IBR from meeting the R3 Ride-through requirement.
This standard requires that IBRs remain electrically connected and continue to exchange current during a
frequency excursion event in which the frequency remains within the must Ride-through zone according
to Attachment 3 and while the absolute ROCOF magnitude is less than or equal to 5 Hz/second. Some IBR
controllers and their ability to remain electrically connected and continue to exchange current with the
grid are sensitive to ROCOF, particularly auxiliary equipment that are essential for IBR performance,
during a frequency excursion event. If needed to maintain the stability of the IBR or prevent equipment
damage, the R3 requirement allows the IBR to trip for an absolute ROCOF exceeding 5Hz/sec within the
must Ride-through zone of Attachment 2. Failure to Ride-through due to ROCOF exceeding 5Hz/sec shall
only be allowed during a generator/load imbalance event that causes the frequency to deviate from
nominal.
To minimize the misoperation tripping of the IBR on the ROCOF setting, the rate of change of frequency
(ROCOF) must be calculated as the average rate of change over multiple calculated system frequencies for
some time greater than or equal to 0.1 seconds. The ROCOF calculation is not applicable during the fault
occurrence and clearance (i.e., protection should not trip due to any perceived ROCOF during the entire
disturbance and recovery period) and should not operate at the onset of a fault, during a fault, or at fault
clearance, i.e., it should be disabled during faults. The IBR shall Ride-through any system disturbance
while the voltage at the high-side of the main power transformer remains within the must Ride-through
zones as specified in Attachment 1. The ROCOF measurement should begin after fault clearance and is
only applicable for generation/load imbalance disturbances such as a system separation, an island
condition, or the loss of a large load or generator.
Rationale for Requirement R4
The objective of Requirement R4 is to ensure legacy IBR (IBR existing as of the enforcement date of PRC029-1) are able to obtain an exemption to the voltage and frequency Ride-through requirements if
hardware replacements or other costly upgrades would be necessary to comply with Requirements R1
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
8
through Requirement R3. This provision allows such exemptions as long as such limitations are
documented and communicated to the Planning Coordinator, Transmission Planner, Reliability
Coordinator, and Transmission Operator of the respective footprints in which the IBR project is located.
The Planning Coordinator, Transmission Planner, Reliability Coordinator, and Transmission Operator will
then need to take the voltage Ride-through limitations into account in planning and operations.
Limitations must not be construed as complete exemptions from the applicable tables, but must be
specific as to which voltage or frequency band(s) and associated duration(s) cannot be satisfied or specific
as to the number of cumulative voltage deviations within a ten-second time period that the equipment
can Ride-through if less than four. Limitation descriptions should identify the specific equipment and
explain the characteristic(s) of that equipment that prevent Ride-through. If any equipment limitation is
removed or otherwise corrected, it is likewise necessary to communicate to the Planning Coordinator,
Transmission Planner, Reliability Coordinator, and Transmission Operator of this.
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
9
Exhibit F
Analysis of Violation Risk Factors and Violation Severity Levels
RELIABILITY | RESILIENCE | SECURITY
Exhibit F-1
Analysis of Violation Risk Factors and Violation Severity
Levels PRC-024-4
RELIABILITY | RESILIENCE | SECURITY
Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-024-4
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC-024-4. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to BulkPower System instability, separation, or a cascading sequence of
failures, or could place the Bulk-Power System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to BulkPower System instability, separation, or a cascading sequence of failures, or could place the Bulk-Power System at
an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk-Power System, or the ability to effectively
monitor and control the Bulk-Power System. However, violation of a medium risk requirement is unlikely to lead to Bulk- Power System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the BulkPower
System, or the ability to effectively monitor, control, or restore the BulkPower System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Power System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk-Power System, or the ability to effectively monitor and control the Bulk-Power System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk-Power
System, or the ability to effectively monitor, control, or restore the Bulk-Power System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
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Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
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3
NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of the
intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
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The VRF did not change from the previously FERC approved PRC-024-3 Reliability Standard.
VSLs for PRC-024-4, Requirement R1
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to set its
applicable frequency protection so
that it does not trip according to
Requirement R1.
VSL Justifications for PRC-024-4, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
consequence of lowering the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-024-4, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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7
The VRF did not change from the previously FERC approved PRC-024-3 Reliability Standard.
VSLs for PRC-024-4, Requirement R2
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to set its
applicable voltage protection so that
it does not trip according to
Requirement R2.
VSL Justifications for PRC-024-4, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
consequence of lowering the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
8
VSL Justifications for PRC-024-4, Requirement R2
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
9
The VRF did not change from the previously FERC approved PRC-024-3 Reliability Standard.
VSLs for PRC-024-4, Requirement R3
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner documented
the known non-protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 30
calendar days but less than or
equal to 60 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner documented
the known non-protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 60
calendar days but less than or
equal to 90 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner documented
the known non-protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 90
calendar days but less than or
equal to 120 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner failed to
document any known nonprotection system equipment
limitation that prevented it from
meeting the criteria in Requirement
R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar days of
identifying the limitation.
VSL Justifications for PRC-024-4, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
consequence of lowering the level of compliance.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
10
VSL Justifications for PRC-024-4, Requirement R3
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
11
The VRF did not change from the previously FERC approved PRC-024-3 Reliability Standard.
VSLs for PRC-024-4, Requirement R4
Lower
Moderate
High
The Generator Owner or
Transmission Owner provided its
protection settings more than 60
calendar days but less than or
equal to 90 calendar days of any
change to those settings.
The Generator Owner or
Transmission Owner provided its
protection settings more than 90
calendar days but less than or
equal to 120 calendar days of any
change to those settings.
The Generator Owner or
Transmission Owner provided its
protection settings more than 120
calendar days but less than or
equal to 150 calendar days of any
change to those settings.
OR
OR
OR
The Generator Owner or
Transmission Owner provided
protection settings more than 60
calendar days but less than or
equal to 90 calendar days of a
written request.
The Generator Owner or
Transmission Owner provided
protection settings more than 90
calendar days but less than or
equal to 120 calendar days of a
written request.
The Generator Owner or
Transmission Owner or provided
protection settings more than 120
calendar days but less than or
equal to 150 calendar days of a
written request.
Severe
The Generator Owner or
Transmission Owner failed to
provide its protection settings within
150 calendar days of any change to
those settings.
OR
The Generator Owner or
Transmission Owner failed to
provide protection settings within
150 calendar days of a written
request.
VSL Justifications for PRC-024-4, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
consequence of lowering the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
12
VSL Justifications for PRC-024-4, Requirement R4
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
13
Exhibit F-2
Analysis of Violation Risk Factors and Violation Severity
Levels PRC-029-1
RELIABILITY | RESILIENCE | SECURITY
Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1
This document provides the drafting team’s (DT’s) justification for assignment of violation risk factors (VRFs) and violation severity levels
(VSLs) for each requirement in PRC-029-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in the
Electric Reliability Organizations (ERO) Sanction Guidelines. The DT applied the following NERC criteria and FERC Guidelines when developing
the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Power System (BPS) instability, separation, or a cascading sequence
of failures, or could place the BPS at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning time
frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to BPS instability, separation, or a cascading sequence of failures, or could place the BPS at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the BPS, or the ability to effectively monitor and
control the BPS. However, violation of a medium risk requirement is unlikely to lead to BPS instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or restore
the BPS. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by
the preparations, to lead to BPS instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the BPS, or the ability to effectively monitor and control the BPS; or, a requirement that is administrative in nature and a
requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by
the preparations, be expected to adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or
restore the BPS.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the BPS. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the BPS:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
2
Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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3
NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the
requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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4
Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for PRC-029-1, Requirement R1
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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VSLs for PRC-029-1, Requirement R1
Lower
Moderate
N/A
The Generator Owner failed to
ensure the design capability of
each applicable IBR to Ride-through
in accordance with Attachment 1,
except for those conditions
identified in Requirement R1.
High
N/A
Severe
The Generator Owner failed to
ensure each applicable IBR adhered
to Ride-through requirements in
accordance with Attachment 1,
except for those conditions
identified in Requirement R1.
VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
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VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
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VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
Definitions of VRFs
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R2
Lower
The Generator Owner failed to
ensure the design capability of
each applicable IBR to adhere to
performance requirements during
voltage excursions, as specified in
Requirement R2, unless a
documented hardware limitation
exists in accordance with
Requirement R4.
Moderate
N/A
High
N/A
Severe
The Generator Owner failed to
ensure each applicable IBR adhered
to performance requirements
during voltage excursions, as
specified in Requirement R2, unless
a documented hardware limitation
exists in accordance with
Requirement R4.
VSL Justifications for PRC-029-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
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VSL Justifications for PRC-029-1, Requirement R2
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
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VRF Justifications for PRC-029-1, Requirement R3
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is appropriate that if violated, it would be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R3
Lower
Moderate
The Generator Owner IBR to
N/A
ensure the design capability of
each applicable IBR to Ride-through
in accordance with Attachment 2,
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
High
N/A
Severe
The Generator Owner IBR to
ensure each applicable IBR adhered
to Ride-through requirements in
accordance with Attachment 2,
10
unless a documented hardware
limitation exists in accordance with
Requirement R4.
unless a documented hardware
limitation exists in accordance with
Requirement R4.
VSL Justifications for PRC-029-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
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VSL Justifications for PRC-029-1, Requirement R3
Number of Violations
VRF Justifications for PRC-029-1, Requirement R4
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R4
Lower
The Generator Owner provided a
copy to the applicable entities as
detailed in Requirement R4.2 more
than 12 months but less than or
equal to 15 months after the
effective date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 90 days but less than or
equal to 120 days after receiving a
request for additional information
by an entity listed in Requirement
R4.2.1.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 90 days but less than or
equal to 120 days after receiving
the acceptance of a hardware
limitation by the CEA.
OR
The Generator Owner with a
previously communicated
hardware limitation that replaces
Moderate
High
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 120 days but less than
or equal to 150 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 150 days but less than
or equal to 180 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
OR
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 120 days but less than
or equal to 150 days after receiving
the acceptance of a hardware
limitation by the CEA.
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 150 days but less than
or equal to 180 days after receiving
the acceptance of a hardware
limitation by the CEA.
OR
OR
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
120 calendar days but less than or
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
150 calendar days but less than or
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
Severe
The Generator Owner failed to
document complete information
for IBR identified with known
hardware limitations that prevent
the IBR from meeting Ride-through
criteria as detailed in Requirements
R1 or R2.
OR
The Generator Owner failed to
provide a copy to the applicable
entities as detailed in Requirement
R4.2 within 24 months after the
effective date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 180 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 180 days after receiving
the acceptance of a hardware
limitation by the CEA.
13
VSLs for PRC-029-1, Requirement R4
Lower
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),
Reliability Coordinator(s), and CEA
more than 90 calendar days but
less than or equal to 120 calendar
days after the change to the
hardware.
Moderate
equal to 150 calendar days after
the change to the hardware.
High
equal to 180 calendar days after
the change to the hardware.
Severe
OR
The Generator Owner failed to
document complete information
for IBR identified with known
hardware limitations that prevent
the IBR from meeting Ride-through
criteria as detailed in Requirements
R1 or R2.
VSL Justifications for PRC-029-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
14
VSL Justifications for PRC-029-1, Requirement R4
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
15
Exhibit G
Summary of Development and Complete Record of Development
RELIABILITY | RESILIENCE | SECURITY
Summary of Development History
The following is a summary of the development record for proposed Reliability Standards
PRC-024-4 and PRC-029-1. Project 2020-02 was originally initiated in 2020 to revise the PRC024 standard, as well as several other standards, to include all types of dynamic reactive sources
and DC transmission systems used to provide Essential Reliability Services to the Bulk Electric
System. The scope of Project 2020-02 was adjusted in 2022 to address ride-through performance
for generating resources.
I.
Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give “due
weight” to the technical expertise of the ERO. 1 The technical expertise of the ERO is derived from
the standard drafting team (“SDT”) selected to lead each project in accordance with Section 4.3 of
the NERC Standard Processes Manual.2 For this project, the SDT consisted of industry experts,
all with a diverse set of experiences. A roster of the Project 2020-02 SDT members is included in
Exhibit H.
II.
Standard Development History
A. Project Initiation
In 2020, NERC initiated Project 2020-02 Transmission Connected Resources to address a
Standards Authorization Request (“SAR”) submitted by the NERC System Analysis and Modeling
Subcommittee (“SAMS”) proposing to modify Reliability Standards MOD-025-2, MOD-026-1,
MOD-027-1, PRC-019-2 and PRC-024-3. The SAMS developed a white paper to support this
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. § 824(d)(2).
The NERC Standard Processes Manual is available at
https://www.nerc.com/FilingsOrders/us/RuleOfProcedureDL/SPM_Clean_Mar2019.pdf.
2
1
project, addressing deficiencies of reactive power support from nonsynchronous generating
resources and transmission-connected dynamic reactive sources. 3
B. Standard Authorization Request Development
On March 18, 2020, the Standards Committee accepted the SAMS SAR and authorized
posting the SAR for a 30-day informal comment period and the solicitation of SAR drafting team
members.4 The informal comment period and the nomination period for a SAR drafting team was
extended and was open from March 30, 2020 through May 13, 2020.
C. Supplemental Drafting Team Nominations
Supplemental drafting team nominations were held from April 28, 2021 through May 17,
2021 and from November 19, 2021 – December 20, 2021. 5 The Standards Committee appointed
the SAR drafting team on September 23, 2021. 6 Additional SAR drafting team members were
appointed on February 16, 2022. 7 Since the original SAR had overlapping Reliability Standards
with other projects, the Standards Committee determined that the Project 2020-02 drafting team
would focus on revisions to PRC-024 and definitions in the Glossary of Terms used in NERC
Reliability Standards.
3
See NERC Standards Committee March 18, 2020 Agenda Package, Item 6,
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC%20Agenda%20Package_March20
20.pdf.
4
NERC, Meeting Minutes – Standards Committee Meeting (March 18, 2020),
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC_March_Meeting_Minutes_Approv
ed_April_22_2020.pdf.
5
See Exhibit G, Complete Record of Development, at items 10,12.
6
NERC, Meeting Minutes – Standards Committee Meeting (Sept. 23, 2021),
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC%20September%20Minutes%20%20Approved%20October%2020,%202021.pdf.
7
NERC, Meeting Minutes – Standards Committee Meeting (Feb. 16, 2022),
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC_February_Meeting_Minutes_Appr
oved_April_20_2022.pdf.
2
D. Acceptance of Revised SAMS SAR
On April 20, 2022, the Standards Committee accepted the revised SAMS SAR, authorized
drafting revisions to the Reliability Standards identified in the SAR, and appointed the Project
2020-02 SAR drafting team as the standard drafting team.
E. Standard Authorization Request Development (Generator Ride-Through)
On April 28, 2022, NERC Staff submitted a Standard Authorization Request seeking to
retire Reliability Standard PRC-024-3 and replace it with a performance-based ride-through
standard that ensures generators remain connected to the Bulk-Power System during system
disturbances. The project name for Project 2020-02 was then was changed to Project 2020-02
Modifications to PRC-024 (Generator Ride-Through). On May 18, 2022, the Standards Committee
accepted the Modifications to PRC-024 Ride-through SAR and authorized posting of the SAR for
a 45-day formal comment period from May 31, 2022 – July 14, 2022. The Standards Committee
also authorized the solicitation of supplemental SDT members.8
F. Standard Authorization Request Development (Revised)
On April 19, 2023, the Standards Committee accepted the Modifications to PRC-024 Ridethrough SAR as revised by the drafting team, authorized drafting revisions to the Reliability
Standards identified in the SAR, and appointed the Project 2020-02 SAR drafting team as the
Project 2020-02 standards drafting team. 9
8
NERC, Meeting Minutes – Standards Committee Meeting (May 18, 2022),
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC%20May%20Meeting%20Minutes
%20-%20Approved%20June%2015,%202022.pdf.
9
NERC, Meeting Minutes – Standards Committee Meeting (Apr. 19, 2023),
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/April%20Meeting%20Minutes%20%20Aprove%20May%2017,%202023.pdf.
3
G. Issuance of Federal Energy Regulatory Commission Order No. 901
On October 19, 2023, the Commission issued Order No. 901 10 directing NERC to develop
new or modified Reliability Standards addressing reliability concerns related to IBRs.
Accordingly, proposed Reliability Standards PRC-029-1 and PRC-024-4, related to performance
requirements for registered IBRs, were aligned with associated regulatory directives from Order
No. 901.
H. Standards Committee Authorizes Procedural Waiver
On December 13, 2023, the Standards Committee authorized a waiver of Sections 4.7, 4.9
and 4.12 of the Standard Processes Manual to reduce the initial formal comment and ballot period
for Project 2020-02 from 45 days to as little as 25 days, with ballot pools formed in the first 10
days and initial ballot and non-binding poll of VRFs and VSLs conducted during the last 10 days
of the comment period, additional formal comment and ballot period(s) reduced from 45 days to
as little as 15 days, with ballot(s) conducted during the last days of the comment period, and final
ballot reduced from 10 days to 5 calendar days. 11
I. First Posting – Comment Period, Initial Ballot, and Non-binding Poll
On March 20, 2024, The Standards Committee authorized initial posting of proposed
Reliability Standards PRC-024-4 and PRC-029-1, the associated Implementation Plan and other
associated documents for a 25-day formal comment period from March 27, 2024 through April
22, 2024, with a parallel initial ballot and non-binding poll on the Violation Risk Factors (“VSFs”)
and Violation Severity Levels (“VSLs”) held during the last 10 days of the comment period from
10
11
Reliability Standards to Address Inverter-Based Resources, Order No. 901, 185 FERC ¶ 61,042 (2023).
Exhibit G, Complete Record of Development at item 24.
4
April 12, 2024 through April 22, 2024.12 The initial ballot and non-binding poll results for the
proposed Reliability Standards are as follows:
•
Proposed Reliability Standard PRC-024-4 received 61.73 percent approval,
reaching quorum at 91.51 percent of the ballot pool. The non-binding poll for the
associated VRFs and VSLs received 76.51 percent supportive opinions, reaching
quorum at 83.07 percent of the ballot pool. 13
•
Proposed Reliability Standard PRC-029-1 received 25.37 percent approval,
reaching quorum at 91.01 percent of the ballot pool. The non-binding poll for the
associated VRFs and VSLs received 25.15 percent supportive opinions, reaching
quorum at 88.45 percent of the ballot pool. 14
•
The Implementation Plan received 37.5 percent approval, reaching quorum at 91.14
percent of the ballot pool. 15
There were 79 sets of responses, including comments from approximately 180 different
individuals and approximately 111 companies, representing all 10 industry segments. 16
J. Second Posting - Comment Period, Initial Ballot, and Non-binding Poll
Proposed Reliability Standards PRC-024-4 and PRC-029-1, the associated Implementation
Plan and other associated documents were posted for a 20-day formal comment period from June
18, 2024 through July 8, 2024, with a parallel additional ballot and non-binding poll held during
12
13
14
15
16
Id. at items 34, 38.
Id. at items 39, 42.
Id. at items 40, 43.
Id. at item 41.
Id. at item 36.
5
the last 10 days of the comment period from June 28, 2024 through July 8, 2024. 17 The additional
ballot and non-binding poll results for the proposed Reliability Standards are as follows:
•
Proposed Reliability Standard PRC-024-4 received 82.7 percent approval, reaching
quorum at 85.98 percent of the ballot pool. The non-binding poll for the associated
VRFs and VSLs received 76.51 percent supportive opinions, reaching quorum at 83.07
percent of the ballot pool. 18
•
Proposed Reliability Standard PRC-029-1 received 35.45 percent approval, reaching
quorum at 85.39 percent of the ballot pool. The non-binding poll for the associated
VRFs and VSLs received 29.03 percent supportive opinions, reaching quorum at 82.47
percent of the ballot pool. 19
•
The Implementation Plan received 48.59 percent approval, reaching quorum at 85.98
percent of the ballot pool. 20
There were 63 sets of responses, including comments from approximately 138 different
individuals and approximately 91 companies, representing 7 industry segments. 21
K. Third Posting - Comment Period, Initial Ballot, and Non-binding Poll
Proposed Reliability Standard PRC-029-1, the associated Implementation Plan and other
associated documents were posted for a 20-day formal comment period from July 22, 2024 through
August 12, 2024, with a parallel additional ballot and non-binding poll held during the last 10 days
17
18
19
20
21
Id. at items 56, 60.
Id. at items 61, 64.
Id. at items 62, 65.
Id. at item 63.
Id. at item 58.
6
of the comment period from August 2, 2024 through August 12, 2024. 22 The additional ballot and
non-binding poll results for the proposed Reliability Standards are as follows:
•
Proposed Reliability Standard PRC-029-1 received 52.89 percent approval, reaching
quorum at 89.51 percent of the ballot pool. The non-binding poll for the associated
VRFs and VSLs received 42.58 percent supportive opinions, reaching quorum at 88.05
percent of the ballot pool. 23
•
The Implementation Plan received 60.04 percent approval, reaching quorum at 89.3
percent of the ballot pool. 24
There were 70 sets of responses, including comments from approximately 159 different
individuals and approximately 112 companies representing all 10 industry segments. 25
L. Proceedings under Section 321 of NERC Rules of Procedure
Following the failure of the third ballot for proposed Reliability Standard PRC-029-1, the
NERC Board of Trustees took action at its August 15, 2024 meeting to invoke its special authority
under Section 321 of the NERC Rules of Procedure. 26 Finding that the ballot body for draft
Reliability Standard PRC-024-1 has not approved a proposed Reliability Standard that contains
provisions to adequately address specific matters identified in directives issued by the Commission
in Order No. 901, the Board directed the Standards Committee to work with NERC Staff to carry
out the following instructions, in accordance with NERC Rules of Procedure Section 321.2:
•
Convene a public technical conference to discuss the issues surrounding the FERC
directives, including whether or not the proposed Reliability Standard PRC-029-1
(and, to the extent necessary, any conforming changes in proposed Reliability
22
Id. at items 76, 80.
Id. at items 81, 83.
24
Id. at item 82.
25
Id. at item 78.
26
NERC, Board of Trustees Meeting Minutes (Aug. 15, 2024),
https://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/Minutes%20%20BOT%20Open%20-August%2015%202024.pdf.
23
7
Standard PRC-024-4) being developed through Project 2020-02 Modifications to
PRC-024 (Generator Ride-through) is just, reasonable, not unduly discriminatory
or preferential, in the public interest, helpful to reliability, practical, technically
sound, technically feasible, and cost-justified;
•
Prepare a memorandum discussing the issues, an analysis of the alternatives
considered, and other appropriate matters;
•
Use the input from the technical conference to revise the proposed Reliability
Standard(s), as appropriate; and
•
Re-ballot the proposed Reliability Standard(s) one additional time, with such
adjustments are necessary to meet the 45-day deadline provided in NERC Rules of
Procedure Rule 321.2.1.
The Standards Committee, working with NERC Staff, convened a technical conference
which took place from September 4-5, 2024. This technical conference focused on unresolved
issues raised by stakeholders during the comment periods for earlier drafts of proposed Reliability
Standard PRC-029-1. 27 Following the technical conference, representatives from the Standards
Committee worked with NERC Staff to revise proposed Reliability Standard PRC-029-1 using
input from the technical conference and prepare a memorandum discussing the issues, an analysis
of the alternatives considered, and other appropriate matters.
M. Fourth Posting - Comment Period, Initial Ballot, and Non-binding Poll for PRC029-1
Proposed Reliability Standard PRC-029-1, the associated Implementation Plan and other
associated documents were posted for a 13-day formal comment period originally scheduled to
run from September 13, 2024 through September 30, 2024, with a parallel additional ballot and
non-binding poll to be held from September 24, 2024 through September 30, 2024. To allow
stakeholders additional time to review the Standards Committee/NERC Staff memorandum, the
27
Id. at items 112, 113, 114.
8
ballot period was extended through October 4, 2024. 28 The additional ballot and non-binding poll
results for the proposed Reliability Standard are as follows:
•
Proposed Reliability Standard PRC-029-1 received 77.88 percent approval, reaching
quorum at 89.51 percent of the ballot pool. The non-binding poll for the associated
VRFs and VSLs received 73.6 percent supportive opinions, reaching quorum at 86.85
percent of the ballot pool. 29
•
The Implementation Plan received 77.89 percent approval, reaching quorum at 88.56
percent of the ballot pool. 30
N. Final Ballot for PRC-024-4
Proposed Reliability Standard PRC-024-4 was posted for a 5-day final ballot period from
September 25, 2024 through September 30, 2024. The final ballot for proposed Reliability
Standard PRC-024-4 reached quorum at 90.77 percent of the ballot pool, receiving support from
86.41 percent of the voters. The ballot for the Implementation Plan, conducted during the fourth
posting for PRC-029-1, reached quorum at 88.56 percent of the ballot pool, receiving support from
77.89 percent of the voters. 31
O. Board of Trustees Adoption
The NERC Board of Trustees adopted proposed Reliability Standards PRC-024-4 and
PRC-029-1 on October 8, 2024. 32
28
Id. at item 97.
Exhibit G, Complete Record of Development at items 98, 100.
30
Id. at item 99.
31
Id. at item 107.
32
NERC, Board of Trustees Agenda Package Feb., 2024, Agenda Item 2b. (Project 2020-2 Modifications to
PRC-24 (Generator Ride-through)),
https://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/Board%20of%20Trustees%20
Open%20Meeting%20Agenda%20Package%20October%208%202024%20Attendees.pdf. In approving proposed
Reliability Standard PRC-029-1, the NERC Board of Trustees determined that good cause existed to extend the
ballot period past the 45 days prescribed in Section 321.2.1, from September 30, 2024 to October 4, 2024.
29
9
P. October 16, 2024 Errata
On October 16, 2024, the Standards Committee approved correcting three errata in
proposed Reliability Standard PRC-029-1: one non-substantive error in PRC-029-1 and two nonsubstantive errors in the implementation plan. 33
33
NERC, Standards Committee Agenda Package Oct. 16, Agenda Item 3,
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC_Meeting_Agenda_PackageOctober_16_2024_lp.pdf.
10
Complete Record of Development
11
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Related Files
Status
The final ballot for PRC-024-4 - Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous Condensers, concluded at 8 p.m. Eastern, Monday, September 30, 2024.
The re-ballot ballot for PRC-029-1-4 - Frequency and Voltage Ride-through Requirements for Inverter-Based Resources, concluded at 8 p.m. Eastern, Friday, October 4, 2024. Per Rule 321 of the Rules of Procedure, there will be no final
ballot.
Background
The Standards Committee accepted the revised SAR and authorized drafting revisions to the Reliability Standards identified in the SAR on April 19, 2023. The objective of the SAR is to modify PRC-024-3 or replace the standard with a performance-based ride-through
standard that ensures generators remain connected to the BPS during system disturbances. Specifically, the SAR focuses on using disturbance monitoring data to substantiate IBR ride-through performance during grid disturbances. The SAR also ensures associated
generators that fail to ride-through system events are addressed with a corrective action plan (if possible).
FERC Order 901 requires that IBR-related performance requirements for ride-through are completed and filed with FERC by November 4, 2024. This drafting team will address the IBR-related PRC-029 first and modify PRC-024 to only apply towards synchronous
machines. Following the approval of PRC-029, the drafting team will consider additional modifications to PRC-024 to assure performance-based requirements for synchronous machines are adequately addressed per the SAR.
Standard(s) Affected – PRC-024
Purpose/Industry Need
From a risk-based perspective, the goal of the standard is to mitigate the ongoing and systemic performance issues identified across multiple Interconnections and across many disturbances analyzed by NERC and the Regions. Ongoing NERC reports and findings from
NERC alerts have continued to substantiate that IBR are failing to ride-through in accordance with expectations and multiple NERC guidelines. These issues have been identified in IBRs as well as synchronous generators, with many causes of tripping entirely
unrelated to voltage and frequency protection settings as dictated by the currently effective version of PRC-024.
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ft
Actions
Dates
Results
Consideration of
Comments
Errata for Draft 4
PRC-029-1
(108) Clean| (109) Redline
Implementation Plan
(110) Clean | (111) Redline
The Standards Committee approved
on October 16, 2024
Ballot Results
Final Ballot
09/25/24 - 09/30/24
(106) Info
Vote
Ballot Results
09/24/24 - 10/04/24
(extended to allow for review of
NERC/ Standards CommitteeMemo)
(98) PRC-029-1
(99) Implementation Plan
See Addendum items 112 - 114 for Materials from the September 2024 Technical
Conference Convened Under Section 321 of the NERC Rules of Procedure
Comment Period
09/17/24 - 09/30/24
Submit Comments
Draft 3
PRC-029-1
(66) Clean| (67) Redline to Last Posted
Additional Ballots and Non-binding Poll
Implementation Plan
(68) Clean | (69) Redline to Last Posted
(80) Info
Supporting Materials
(79) Ballot Open Reminder
Ballot Results
08/02/24 - 08/12/24
(81) PRC-029-1
(82) Implementation Plan
Vote
(70) Unofficial Comment Form (Word)
PRC-029-1 Technical Rationale
(71) Clean | (72) Redline to Last Posted
PRC-029-1 VRF/VSL Justifications
(73) Clean | (74) Redline to Last Posted
Comment Period
(76) Info
Submit Comments
07/22/24 - 08/12/24
(78) Consideration of Comments
(75) Consideration of Directives from FERC Order 901
Ballot Results
Draft 2
PRC-024-4
(44) Clean | (45) Redline
PRC-029-1
(46) Clean | (47) Redline
(48) Implementation Plan
(61) PRC-024-4
06/28/24 - 07/08/24
(62) PRC-029-1
(63) Implementation Plan
Non-binding Poll Results
(64) PRC-024-4
Technical Rationales
PRC-029-1
(51) Clean | (52) Redline
VRF/VSL Justifications
PRC-029-1
(54) Clean | (55) Redline
Draft 1
PRC-024-4
(25) Clean | (26) Redline
(27) PRC-029-1
Comment Period
(56) Info
Submit Comments
06/18/24 - 07/08/24
(38) Info
04/12/24 - 04/22/24
Vote
(42) PRC-024-4
(30) PRC-024-4
(33) PRC-029-1
(40) PRC-029-1
Non-binding Poll Results
Technical Rationales
(31) PRC-029-1
(39) PRC-024-4
(41) Implementation Plan
Supporting Materials
(29) Unofficial Comment Form
(Word)
VRF/VSL Justifications
Ballot Results
Initial Ballots and Non-binding Polls
(37) Ballot Open Reminder
Join Ballot Pools
03/27/24 - 04/05/24
Comment Period
(34) Info
03/27/24 - 04/22/24
Submit Comments
(24)Waiver
(17) PRC-024 Standard Authorization
Request
Supporting Materials
(18) Unofficial Comment Form (Word)
The Standards Committee approved
the waiver on December 13, 2023
The Standards Committee accepted the
SAR on April 19, 2023
Comment Period
(19) Info
05/31/22 - 07/14/22
Submit Comments
Nomination Period
(16) Info
05/31/22 - 07/14/22
Submit Nominations
Standard Authorization Request
(13) Clean | (14) Redline
The Standards Committee accepted the
SAR on April 20, 2022
Nomination Period
(12) Info
11/19/21 - 12/20/21
Submit Nominations
Nomination Period
04/28/21 - 05/17/21
Submit Nominations
(3) Standard Authorization Request
Supporting Materials
(4) Unofficial Comment Form (Word)
(5) Transmission-connected Dynamic Reactive Resources White Paper
Comment Period
(6) Info
03/30/20 - 05/13/20(Extended)
(Updated)
Submit Comments
Drafting Team Nominations
Supporting Materials
(1) Unofficial Nomination Form (Word)
Nomination Period
(2) Info
(Updated)
Submit Nominations
03/30/20 - 05/13/20(Extended)
(7) Comments Received
Additional Materials from the September 2024 Technical Conference
Convened under Section 321 of the NERC Rules of Procedure
Standards Committee & NERC Generator Ride-through (PRC-029-1) Technical Conference
(112) Agenda, Panelist Bios, Presentations
Day 1 Recording | (113) Transcript
Day 2 Recording | (114) Transcript
Unofficial Nomination Form
Project 2020-02 Transmission-connected Resources
Standard Authorization Request Drafting Team
Do not use this form for submitting nominations. Use the electronic form to submit nominations for
Project 2020-02 Transmission-connected Resources Standard Authorization Request (SAR) drafting team
members by 8 p.m. Eastern, Wednesday, May 13, 2020. This unofficial version is provided to assist
nominees in compiling the information necessary to submit the electronic form.
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Chris Larson (via email), or at 404-446-9708.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
Previous drafting or review team experience is beneficial, but not required. A brief description of the
desired qualifications, expected commitment, and other pertinent information is included below.
Background
The problem of increasing amounts of reactive power being supplied by nonsynchronous sources was
identified in NERC’s 2017 Long-term Reliability Assessment. In response to the concern, the Planning
Committee (PC) assigned the System Analysis and Modeling Subcommittee (SAMS) to study the issue. The
SAMS developed the Applicability of Transmission-Connected Reactive Devices white paper, which was
approved by the PC at its December 10-11, 2019 meeting. The PC Executive Committee reviewed the draft
SAR from SAMS at its January meeting and subsequently approved the SAR by email vote ending on
February 11, 2020. The SAR concerning Transmission-Connected Resources (TCR) aims to modify NERC
Reliability Standards MOD-025, MOD-026, MOD-027, PRC-019 and PRC-024 to comprehensively include
all types of dynamic reactive resources (including static var systems and FACTS) and DC transmission
systems used to provide Essential Reliability Services (ERS) in the Bulk Electric System (BES).
Dynamic reactive resources used to provide ERS in the BES include generation resources (rotating
machine and inverter-based) as well as transmission connected dynamic reactive resources (powerelectronics based). Existing Reliability Standards for verifying the capability, modeling and performance of
dynamic reactive resources are only applicable to Facilities comprising generation resources. Augmenting
the applicability of these standards to include (nongeneration) transmission-connected reactive
resources, both rotating machine (i.e. synchronous condenser) and power-electronics based, will enhance
the BES reliability by ensuring that the capability, models and performance are verified and validated for
all varieties of dynamic reactive resources utilized in providing ERS in the BES.
RELIABILITY | RESILIENCE | SECURITY
Standard(s) affected: MOD-025, MOD-026, MOD-027, PRC-019 and PRC-024
Drafting Team activities include participation in technical conferences, stakeholder communications
and outreach events, periodic drafting team meetings and conference calls. Approximately one faceto-face meeting per quarter can be expected (on average three full working days each meeting) with
conference calls scheduled as needed to meet the agreed-upon timeline the drafting team sets forth.
NERC is seeking individuals who possess experience in the following areas:
•
Developing and verifying dynamic models used in long-term planning assessments, specifically
for transmission-connected reactive resources*
•
Modeling and studying transmission-connected reactive devices during interconnection
studies or long-term planning assessments
•
Performing equipment capability testing for transmission-connected reactive devices and
rotating machines
•
Understanding the large disturbance behavior of transmission-connected reactive devices,
particularly the power electronic controls that govern the performance of these devices during
abnormal grid conditions
* Transmission-connected reactive resources generally refers to FACTS (Flexible AC Transmission
System) devices such as Static Var Compensators (SVCs) and Static Synchronous Compensator
(STATCOMs) as well as other power-electronic devices that fall in this category such as HVDC circuits
and synchronous condensers.
Name:
Organization:
Address:
Telephone:
Email:
Please briefly describe your experience and qualifications to serve on the requested SAR Drafting
Team (Bio):
If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
Unofficial Nomination Form | Project 2020-02 Transmission-connected Resources
Standard Authorization Request Drafting Team | March-May 2020
2
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Acknowledgement that the nominee has read and understands both the NERC Participant Conduct
Policy and the Standard Drafting Team Scope documents, available on NERC Standards Resources.
Yes, the nominee has read and understands these documents.
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
MRO
NPCC
RF
SERC
Texas RE
WECC
NA – Not Applicable
Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Unofficial Nomination Form | Project 2020-02 Transmission-connected Resources
Standard Authorization Request Drafting Team | March-May 2020
3
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator
Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner
Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
Name:
Telephone:
Organization:
Email:
Name:
Telephone:
Organization:
Email:
Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
1
Name:
Telephone:
Title:
Email:
These functions are defined in the NERC Functional Model, which is available on the NERC web site.
Unofficial Nomination Form | Project 2020-02 Transmission-connected Resources
Standard Authorization Request Drafting Team | March-May 2020
4
UPDATED
Standards Announcement
Project 2020-02 Transmission-connected Dynamic Reactive Resources
Nomination Period Now Open through May 13, 2020
Now Available
Nominations are being sought for Project 2020-02 Transmission-connected Dynamic Reactive
Resources drafting team members. The due date has been extended, and is now open through 8 p.m.
Eastern, Wednesday, May 13, 2020.
Use the electronic form to submit a nomination. Contact Wendy Muller regarding issues using the
electronic form. An unofficial Word version of the nomination form is posted on the Standard
Drafting Team Vacancies page and the project page.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls. Previous drafting team experience is beneficial
but not required.
See the project page (linked above) and nomination form for additional information.
Next Steps
The Standards Committee is expected to appoint members to the drafting team in May 2020. Nominees
will be notified shortly after they have been appointed.
For information on the Standards Development Process, refer to the Standard Processes Manual.
Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from the
"Service" drop-down menu and specify “Project 2020-02 Transmission-connected Resources observer list” in
the Description Box. For more information or assistance, contact Senior Standards Developer, Chris Larson
(via email) or at 404-446-9708.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
RELIABILITY | RESILIENCE | SECURITY
Standard Authorization Request (SAR)
Complete and please email this form, with
Complete
and please
email this form, with
attachment(s)
to: sarcomm@nerc.net
attachment(s) to: sarcomm@nerc.net
SAR Title:
The North American Electric Reliability Corporation (NERC)
welcomes suggestions to improve the reliability of the bulk
power system through improved Reliability Standards.
Requested information
Revise the Applicable Facilities of MOD-025, MOD-026, MOD-027, PRC019 and PRC-024 Standards to comprehensively include all types of
dynamic reactive resources (including static var systems and FACTS) and
DC transmission systems used to provide Essential Reliability Services in
the Bulk Electric System.
February 24, 2020
Date Submitted:
SAR Requester
Name:
Hari Singh – Chair, System Analysis & Modeling Subcommittee (SAMS)
Organization: Xcel Energy
Telephone:
303-571-7095
Email:
hari.singh@xcelenergy.com
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
Dynamic reactive resources used to provide Essential Reliability Services (ERS) in the BES include
generation resources (rotating machine and inverter-based) as well as transmission connected dynamic
reactive resources (power-electronics based). Existing reliability standards for verifying the capability,
modeling and performance of dynamic reactive resources are only applicable to Facilities comprising
generation resources. Augmenting the applicability of these standards to include (non-generation)
transmission-connected reactive resources – both rotating machine (i.e. synchronous condenser) and
power-electronics based – will enhance the BES reliability by ensuring that the capability, models and
performance is verified and validated for all varieties of dynamic reactive resources utilized in providing
ERS in the BES.
RELIABILITY | RESILIENCE | SECURITY
Requested information
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
Augment the “Applicability – Facilities” and “Applicability-Functional Entities” sections in MOD-025,
MOD-026, MOD-027, PRC-019 and PRC-024 reliability standards to address (non-generation)
transmission-connected dynamic reactive resources – both rotating machine (i.e. synchronous
condenser) and power-electronics based. Also modify Requirements (including applicable attachments)
as needed to ensure they continue to address the additional Facilities. As needed, also define new
Glossary Terms for all or some of the transmission-connected dynamic reactive devices noted in the
SAMS white-paper “Transmission Connected Dynamic Reactive Resources – Assessment of Applicability
in Reliability Standards”.
Project Scope (Define the parameters of the proposed project):
Revise the “Applicability – Facilities” section, “Applicability – Functional Entities” section, and
Requirements (including applicable attachments) as needed in MOD-025, MOD-026, MOD-027, PRC-019
and PRC-024 reliability standards to comprehensively address all varieties of transmission-connected
dynamic reactive resources that are utilized in providing ERS in the BES.
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
The “Applicability – Facilities” and “Applicability-Functional Entities” sections in MOD-025, MOD-026,
MOD-027, PRC-019 and PRC-024 reliability standards will be revised to address (non-generation)
transmission-connected dynamic reactive resources based on the recommendations summarized in
Table 1 of the SAMS white-paper “Transmission Connected Dynamic Reactive Resources – Assessment
of Applicability in Reliability Standards”. The white-paper also provides the technical justifications for
the recommended revisions and the associated reliability benefits. Also modify Requirements (including
applicable attachments) as needed to ensure they continue to address the additional Facilities. As
needed, also define new Glossary Terms for all or some of the transmission-connected dynamic reactive
devices noted as items 1.a – 1.j in the Additional Considerations section of the SAMS white-paper.
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
Unknown
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
Power-electronics based transmission-connected reactive resources – also known as FACTS (Flexible AC
Transmission System) devices – such as: Static Var Compensator (SVC), Static Synchronous Compensator
(STATCOM), HVDC Links (LCC or VSC).
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please attach pertinent
information to this form before submittal to NERC.
1
Standard Authorization Request (SAR)
2
Requested information
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Transmission Owners in addition to the existing Functional Entities
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
“Transmission Connected Dynamic Reactive Resources – Assessment of Applicability in Reliability
Standards” white-paper approved by SAMS members.
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
PRC-019 SAR requested by SPCS and PRC-024 SAR requested by IRPTF
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
No viable alternatives were found by SAMS.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted to obtain
industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.
2
Standard Authorization Request (SAR)
3
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.
Enter
(yes/no)
Yes
Yes
Yes
Yes
Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
e.g. NPCC
For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC
Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document
Version History
Version
Date
Owner
Change Tracking
1
June 3, 2013
1
August 29, 2014
Standards Information Staff
Updated template
2
January 18, 2017
Standards Information Staff
Revised
2
June 28, 2017
Standards Information Staff
Updated template
Standard Authorization Request (SAR)
Revised
4
Unofficial Comment Form
Project 2020-02 Transmission-connected Resources
Standard Authorization Request
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System to
submit comments on the Project 2020-02 Transmission-connected Resources Standard Authorization
Request by 8 p.m. Eastern, Wednesday, May 13, 2020.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Chris Larson (via email), or at 404-446-9708.
Background
The potential risk of increasing amounts of reactive power being supplied by nonsynchronous sources was
identified in NERC’s 2017 Long-term Reliability Assessment. In response to the concern, the Planning
Committee (PC) assigned the System Analysis and Modeling Subcommittee (SAMS) to study the issue. The
SAMS developed the Applicability of Transmission-Connected Reactive Devices white paper, which was
approved by the PC at its December 10-11, 2019 meeting. The PC Executive Committee reviewed the draft
SAR from SAMS at its January meeting and subsequently approved the SAR by email vote ending on
February 11, 2020. The SAR concerning Transmission-Connected Resources (TCR) aims to modify NERC
Reliability Standards MOD-025, MOD-026, MOD-027, PRC-019 and PRC-024 to comprehensively include
all types of dynamic reactive resources (including static var systems and FACTS) and DC transmission
systems used to provide Essential Reliability Services (ERS) in the Bulk Electric System (BES).
Dynamic reactive resources used to provide ERS in the BES include generation resources (rotating
machine and inverter-based) as well as transmission connected dynamic reactive resources (powerelectronics based). Existing Reliability Standards for verifying the capability, modeling and performance of
dynamic reactive resources are only applicable to Facilities comprising generation resources. Augmenting
the applicability of these standards to include (nongeneration) transmission-connected reactive
resources, both rotating machine (i.e. synchronous condenser) and power-electronics based, will enhance
the BES reliability by ensuring that the capability, models and performance are verified and validated for
all varieties of dynamic reactive resources utilized in providing ERS in the BES.
RELIABILITY | RESILIENCE | SECURITY
Questions
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree
but have comments or suggestions for the project scope please provide your recommendation and
explanation.
Yes
No
Comments:
2. Provide any additional comments for the SAR drafting team to consider, if desired.
Comments:
Unofficial Comment Form | Project 2020-02 Transmission-connected Resources
Standard Authorization Request | March-May 2020
2
Transmission Connected Dynamic Reactive
Resources and HVDC Equipment – Assessment
of Applicability in Reliability Standards
NERC SAMS White Paper
February 2019
Background
The bulk power system (BPS) in North America continues to experience a change in generating resources,
technologies, and transmission system devices used to provide essential reliability services (ERS) such as
voltage control, frequency control, and ramping/balancing capability. In particular, the BPS is experiencing
a rapid change in generation resource mix, with an increasing installation base of inverter-based generation
resources and accompanying retirements of synchronous generation resources. Additionally, generation is
increasingly being located farther from load centers than it was in the past. These factors are contributing
to an increased reliance on non-generation transmission-connected dynamic reactive resources – both
rotating machine (i.e. synchronous condenser) and power-electronics based – to provide ERS in the BPS.
Synchronous condensers are being used to provide dynamic reactive power and transient voltage support,
as well as synchronous inertia and fault current contribution in weak grid conditions. Static var
compensators (SVCs) and static compensators (STATCOMs) are increasingly being used to provide dynamic
reactive power and transient voltage support.
Many relevant NERC Reliability Standards are not applicable to these types of transmission-connected
dynamic reactive resources. It is now clear that an increasing number of these reactive resources are being
used to provide the same ERS as generation resources to ensure reliability of the BPS. In many cases, these
types of dynamic reactive resources are critical to BPS reliability because they are used to increase power
transfer capability, mitigate system instability, provide grid resilience for physical and cyber attacks, and
provide safety nets for severe contingencies. In this respect, ensuring their electrical capability, verification
of performance, and ability to ride through grid events is no less important than for traditional generators.
The NERC Planning Committee and the NERC System Analysis and Modeling Subcommittee (SAMS)
expressed concerns that the existing NERC Reliability Standards may not clearly address non-generation
transmission-connected dynamic reactive resources. In response to these concerns, SAMS has developed
this white paper that comprises an assessment of the applicability of relevant NERC Reliability Standards to
such dynamic reactive resources and provides recommendations to address any identified reliability gap.
In particular, SAMS focused on the following NERC Reliability Standards:
• MOD-025-2: Verification and Data Reporting of Generator Real and Reactive Power Capability and
Synchronous Condenser Reactive Power Capability
• MOD-026-1: Verification of Models and Data for Generator Excitation Control System or Plant
Volt/Var Control Functions
RELIABILITY | RESILIENCE | SECURITY
•
•
•
•
MOD-027-1: Verification of Models and Data for Turbine/Governor and Load Control or Active
Power/Frequency Control Functions
MOD-032-1: Data for Power System Modeling and Analysis
PRC-019-2: Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and
Protection
PRC-024-2: Generator Frequency and Voltage Protective Relay Settings
Results from this assessment and recommendations for moving forward are provided in this white paper.
Applicability Assessment
SAMS reviewed relevant NERC Reliability Standards related to the model verification, capability testing,
disturbance ride through, and protection coordination aspects of generation resources to evaluate if the
transmission-connected dynamic reactive resources are included within the applicability sections of these
standards. The goal was to determine the reliability need/justification for including transmission-connected
dynamic reactive resources as applicable Facilities within the Applicability section of these standards.
Recommended Applicability
Table 1 shows the applicability of relevant NERC Reliability Standards to dynamic reactive resources –
including both generation resources and non-generation transmission connected reactive resources. The
cells with green bold font show the existing applicability and the cells with red bold italicized font show the
recommended applicability based on this SAMS assessment .
For the assessed non-generation reactive resources (refer to Appendix A for their descriptions), each cell
includes either a Yes or N/A as the recommendation for its inclusion as Facilities in the Applicability section
of the relevant Reliability Standard. The technical basis and justification for the recommended applicability
is provided in the following sub-sections.
Table 1: Applicability of Relevant NERC Reliability Standards to Dynamic Reactive Resources
Synchronous Generator
Inverter-Based 1 Generator
Synchronous Condenser
SVC
STATCOM
LCC HVDC
VSC HVDC
MOD-025
Yes
Yes
Yes
Yes
Yes
N/A
Yes
MOD-026
Yes
Yes
Yes
Yes
Yes
N/A
Yes
MOD-027
Yes
Yes
N/A
N/A
N/A
Yes
Yes
MOD-032
Yes
Yes
Yes
Yes
Yes
Yes
Yes
PRC-019
Yes
Yes
Yes
Yes
Yes
Yes
Yes
PRC-024
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Existing applicability
SAMS recommendation
1
Nonsynchronous generating resource
Transmission-Connected Dynamic Reactive Resources – Standards Applicability – NERC SAMS White Paper
| PC Approved December 2019
2
Technical Basis for Applicability
The sub-sections below describe the technical basis and justification for applicability of the relevant NERC
Reliability Standard to each type of transmission-connected dynamic reactive resource listed in Table 1.
M OD-025
The purpose of MOD-025 is to ensure that accurate information on generator gross and net Real and
Reactive Power capability and synchronous condenser Reactive Power capability is available for planning
models used to assess Bulk Electric System (BES) reliability. The technical justification for applicability of
MOD-025 recommended in Table 1 is described below:
•
•
•
•
SVC: A SVC serves many of the same purposes as a synchronous condenser, particularly the injection
or absorption of dynamic reactive power to support steady-state and transient voltage conditions.
Similar to a synchronous condenser, an SVC has a current injection capability that translates to a
reactive power capability based on terminal voltage. For this reason, a power electronics resource
like a SVC connected to the BPS should be a Facility to which MOD-025 is applicable for reactive
power capability verification.
STATCOM: A SVC and STATCOM are very similar in terms of being power electronic resources
connected to the BPS that provide steady-state and dynamic voltage support. The STATCOM and
SVC differ in their reactive capability, particularly under off-nominal voltage conditions. Their
controls are also different based on the types of equipment technologies used in the different
devices. Again, the power electronics have a current injection capability that translates to reactive
power capability based on voltage. For this reason, STATCOM should be a Facility to which MOD025 is applicable for reactive power capability verification.
LCC HVDC: A LCC HVDC circuit is predominantly used to transfer large amounts of active power
across long distances (as well as other applications such as underground cables, etc.). LCC HVDC
technology inherently consumes very large quantities of reactive power at the converters. AC filters
located at the converter terminals to mitigate harmonics also provide reactive power and offset its
consumption from the grid. However, ac filters are comprised of static shunt reactive devices with
known reactive capability ratings that do not need verification. LCC HVDC does not have
independent control of active and reactive power because there is no voltage source within the
converters. For these reasons, LCC HVDC should not be a Facility to which MOD-025 is applicable for
reactive power capability verification.
VSC HVDC: VSC HVDC is different than LCC HVDC in that it has independent control of active and
reactive power because of the independent voltage source within the converters. Therefore, these
elements are able to operate in automatic voltage control, controlling their terminal voltage (or
some other compensated voltage) to support scheduled voltages on the BPS. Therefore, VSC HVDC
should be a Facility to which MOD-025 is applicable for reactive power capability verification.
M OD-026
The purpose of MOD-026 is to verify that the generator excitation control system or plant volt/var
control function model (including the power system stabilizer model and the impedance compensator
model) and the model parameters used in dynamic simulations accurately represent the generator
excitation control system or plant volt/var control function behavior when assessing Bulk Electric System
Transmission-Connected Dynamic Reactive Resources – Standards Applicability – NERC SAMS White Paper
| PC Approved December 2019
3
(BES) reliability. The technical justification for applicability of MOD-026 recommended in Table 1 is
described below:
•
•
•
•
•
Synchronous Condenser: A synchronous condenser is a synchronous machine without a prime
mover (freely rotating shaft) and therefore delivers/absorbs reactive power to the BPS based on its
excitation. In essence, a synchronous condenser exhibits the same dynamic behavior as a
synchronous generator from the perspectives of MOD-026. A synchronous condenser should be
required to provide verified dynamic models as described in MOD-026.
SVC: SVCs provide dynamic reactive power to the BPS to support grid voltage, voltage stability, and
power transfers. These devices include elements and controls that can respond very quickly to grid
conditions (during and after faults, for example). There are no (or minimal) moving parts in these
devices, and the majority of the response is determined based on the settings programmed into the
controls. It is important that these control settings are verified, and the dynamic response of the
model matches reality. For these reasons, SVCs should be required to provide verified dynamic
models as per the intent of MOD-026.
STATCOM: STATCOMs use different technology than SVCs, but they also provide dynamic reactive
power to the BPS and their response is determined based on the settings programmed into the
controls. Therefore, similar to SVCs, STATCOMs should be required to provide verified dynamic
models as per the intent of MOD-026.
LCC HVDC: For the same reasons listed in MOD-025, LCC HVDC should not be a Facility to which
MOD-026 is applicable.
VSC HVDC: Similar to SVCs and STATCOMs, VSC HVDC Facilities also provide dynamic reactive power
to the BPS and their response is determined based on the settings programmed into the controls.
Therefore, VSC HVDC should be required to provide verified dynamic models as per the intent of
MOD-026.
M OD-027
The purpose of MOD-027 is to verify that the turbine/governor and load control or active power/frequency
control model and the model parameters, used in dynamic simulations that assess Bulk Electric System
(BES) reliability, accurately represent generator unit real power response to system frequency variations.
The technical justification for applicability of MOD-027 recommended in Table 1 is described below:
•
•
•
•
Synchronous Condenser: A synchronous conderser is a dynamic reactive power resource and does
not have the capability to provide active power to the BPS. It does not include a turbine-governor
or active power-frequency control system. Therefore, MOD-027 is not applicable..
SVC: It does not include a turbine-governor or active power-frequency control system. Therefore,
SVC should not be a Facility to which MOD-027 is applicable.
STATCOM: A STATCOM is a dynamic reactive power resource and does not have the capability to
provide active power to the BPS. It does not include a turbine-governor or active power-frequency
control system. Therefore, STATCOM should not be a Facility to which MOD-027 is applicable.
LCC HVDC: Although LCC HVDC is not a dynamic reactive power resource, it has the capability to
provide active power/frequency control to the BPS. Since its active power/frequency control system
Transmission-Connected Dynamic Reactive Resources – Standards Applicability – NERC SAMS White Paper
| PC Approved December 2019
4
•
response is determined based on the settings programmed into the controls, it should be required
to provide verified dynamic models as per the intent of MOD-027.
VSC HVDC: A VSC HVDC is a dynamic reactive power resource and also has the capability to provide
active power/frequency control to the BPS. Since its active power/frequency control system
response is determined based on the settings programmed into the controls, it should be required
to provide verified dynamic models as per the intent of MOD-027.
M OD-032
MOD-032 has sufficiently comprehensive applicability to include transmission-connected dynamic reactive
resources for the purposes of obtaining their modeling data. Therefore, SAMS does not recommend any
changes to the applicability of MOD-032.
PR C-019
The purpose of PRC-019 is to verify coordination of generating unit Facility or synchronous condenser
voltage regulating controls, limit functions, equipment capabilities and Protection System settings. The
technical justification for applicability of PRC-019 recommended in Table 1 is described below:
•
•
•
•
•
Synchronous Condenser: A synchronous condenser is protected with a number of protective
functions and limiters, similar to a synchronous generator. If not properly coordinated, the limiters
and protection elements could potentially limit the output or trip the machine below its rated
capability. Therefore, PRC-019 should be applicable to synchronous condensers.
SVC: Analogous to the synchronous machines, SVCs have voltage regulating controls, limiters, and
protection functions. If not properly coordinated, the limiters and protection elements could
potentially limit the output or trip the SVC below its rated capability. Therefore, PRC-019 should be
applicable to SVCs.
STATCOM: Analogous to the SVCs, STATCOMs have active and reactive voltage regulating controls,
limiters, and protection functions. If not properly coordinated, the limiters and protection elements
could potentially limit the output or trip the STATCOM below its rated capability. Therefore, PRC019 should be applicable to STATCOMs.
LCC HVDC: LCC HVDC does not have independent control of active and reactive power because there
is no voltage source within the converters. To the extent that LCC HVDC has voltage regulating
controls, limiters, and protection functions, they, they could potentially limit the LCC HVDC output
below its rated capability if not properly coordinated. PRC-019 should be applicable to LCC HVDC
due to its control and protection equipment abilities.
VSC HVDC: VSC HVDC does have independent control of active and reactive power because they
use voltage source converters. Analogous to the SVCs and STATCOMs, the VSC HVDC has voltage
regulating controls, limiters, and protection functions. If not properly coordinated, the limiters and
protection elements could potentially limit the VSC HVDC output below its rated capability. PRC-019
should be applicable to VSC HVDC due to its control and protection equipment abilities.
PR C-024
In the “Evaluating Protective Relay Settings” section of PRC-024 --Attachement 2 Item #2 states that the GO
must “Evaluate voltage protective relay settings assuming that additional installed generating plant reactive
Transmission-Connected Dynamic Reactive Resources – Standards Applicability – NERC SAMS White Paper
| PC Approved December 2019
5
support equipment (such as static VAR compensators, synchronous condensers, or capacitors) is available
and operating normally.” However,this evaluation focuses on reactive power devices within the generating
plant and does not include similar reactive power devices that are transmission connected.
The purpose of PRC-024 is to ensure Generator Owners set their generator protective relays such that
generating units remain connected during defined frequency and voltage excursions. The technical
justification for applicability of PRC-024 recommended in Table 1 is described below:
•
•
•
•
•
Synchronous Condenser: Synchronous condensers, like synchronous generators, have frequency
and voltage protective relays whose settings should not be within the ride through characteristics
of PRC-024. Undervoltage and overvoltage protection, overspeed protection, etc., are all applied to
a synchronous condenser since it is inherently a rotating electric machine without a prime mover.
The synchronous condenser is expected to ride through grid voltage and frequency excursion events
to provide dynamic voltage support and provide system inertia for stabilizing wide-area system
frequency. Therefore, PRC-024 should be applicable to synchronous condensers.
SVC: SVCs provide dynamic reactive power support during and immediately after a grid disturbance
during the transient timeframes. In this respect, its purpose and functionalty is very similar to that
of synchronous condensers (and synchronous generators). The SVC would be expected to ride
through grid voltage and frequency excursion events to provide dynamic voltage supportsupport
herefore, PRC-024 should be applicable to SVCs.
STATCOM: STATCOMs provide dynamic reactive power support during and immediately after a grid
disturbance during the transient timeframes. In this respect, its purpose and functionalty is very
similar to that of synchronous condensers and SVCs. The STATCOM would be expected to ride
through grid voltage and frequency excursion events to provide dynamic voltage support. PRC-024
should be applicable to STATCOM.
LCC HVDC: The LCC HVDC would be expected to ride through grid voltage and frequency excursion
events to provide continuity of service (i.e. maintaining MW output). Therefore, PRC-024 should
not be applicable to LCC HVDC.
VSC HVDC: VSC HVDC provide dynamic reactive power support during and immediately after a grid
disturbance during the transient timeframes. In this respect, its purpose and functionalty is very
similar to that of SVCs and STATCOMs. The VSC HVDC would be expected to ride through grid voltage
and frequency excursion events to provide dynamic voltage support. Therefore, PRC-024 should be
applicable to VSC HVDC.
Transmission-Connected Dynamic Reactive Resources – Standards Applicability – NERC SAMS White Paper
| PC Approved December 2019
6
Other Considerations
The following additional considerations were noted during the assessment. While not necessarily directly
related to the assessment of applicability of elements to relevant NERC Standards, SAMS believes these
additional topics are important and should be addressed.
1. Definitions for the following terms should be reviewed for potential additions and/or revisions in the
NERC Glossary of Terms include, but are not limited to, the following:
a. Generator (or Generating Facility)
b. Generating Unit Capability 2
c. Dynamic Reactive Power
d. Synchronous Condenser
e. Static Var Compensator (SVC)
f. Static Synchronous Compensator (STATCOM)
g. High Voltage DC (HVDC)
h. Line Commutated Converter (LCC) HVDC
i. Voltage Source Converter (VSC) HVDC
j. Flexible AC Transmission Systems (FACTS)
2. NERC SAMS and the NERC Power Plant Modeling and Verification Task Force (PPMVTF) have both
identified a significant inconsistency between the intent of MOD-025-2 to “ensure that accurate
information on generator…capability 3 is available for planning models used to assess Bulk Electric
System (BES) reliability” and the actual results obtained during testing. MOD-025-2 does not require the
full (maximum achievable) reactive capability of the resource to be reached via test. This is warranted
because the testing conditions likely will limit the resource from reaching its full (maximum achievable)
reactive capability before other limits are reached such as system voltage, generator terminal voltage,
or auxiliary bus voltage limits. While this is reasonable for testing, the standard does not require
calculations to be performed to prove that the resource could reach its full (maximum achievable)
reactive capability under more favorable operating conditions (i.e. when that full reactive capability is
needed for maintaining voltage schedule). Therefore, there is a significant misconception in the industry
that the testing results should be used as the same data submitted for MOD-032-1 for capability of the
machine. This misconception is likely leading to incorrect data being supplied for the purposes of MOD032-1 and is driven by the requirements in MOD-025-2.
2
3
This is a defined term; however, the definition is not sufficiently reflective of the term.
and synchronous condenser reactive power capability
Transmission-Connected Dynamic Reactive Resources – Standards Applicability – NERC SAMS White Paper
| PC Approved December 2019
7
UPDATED
Standards Announcement
Project 2020-02 Transmission-connected Dynamic Reactive Resources
Standard Authorization Request
Informal Comment Period Now Open through May 13, 2020
Now Available
The informal comment period for Project 2020-02 Transmission-connected Resources Standard
Authorization Request has been extended and is now open through 8 p.m. Eastern, Wednesday, May 13,
2020.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. Contact Wendy Muller
regarding issues with the SBS. An unofficial Word version of the comment form is posted on the project
page.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m.
Eastern) for problems regarding accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours for
NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging into
their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The drafting team will review all responses received during the comment period and determine the next
steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from the
"Service" drop-down menu and specify “Project 2020-02 Transmission-connected Resources observer list”
in the Description Box. For more information or assistance, contact Senior Standards Developer, Chris
Larson (via email) or at 404-446-9708.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
RELIABILITY | RESILIENCE | SECURITY
Standards Announcement | Project 2019-01 Modifications to TPL-007-3
TPL-007-4 | July-August, 2019
2
Comment Report
Project Name:
2020-02 Transmission-connected Resources | Standard Authorization Request
Comment Period Start Date:
3/30/2020
Comment Period End Date:
5/13/2020
Associated Ballots:
There were 39 sets of responses, including comments from approximately 118 different people from approximately 100 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
Questions
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree but have comments or suggestions for
the project scope please provide your recommendation and explanation.
2. Provide any additional comments for the SAR drafting team to consider, if desired.
Organization
Name
Name
DTE Energy - Adrian
Detroit Edison Raducea
Company
MRO
Segment(s)
Region
3,4,5
Dana Klem 1,2,3,4,5,6
Group Name
Group
Member Name
DTE Energy - Karie Barczak
DTE Electric
MRO
MRO NSRF
Group
Group
Member
Member
Organization Segment(s)
Group
Member
Region
DTE Energy - 3
Detroit Edison
Company
RF
Daniel Herring DTE Energy - 4
Detroit Edison
Company
RF
Adrian
Raducea
DTE Energy - 5
Detroit Edison
RF
Joseph
DePoorter
Madison Gas 3,4,5,6
& Electric
MRO
Larry Heckert
Alliant Energy 4
MRO
Michael
Brytowski
Great River
Energy
MRO
Jodi Jensen
Western Area 1,6
Power
Administration
MRO
Andy Crooks
SaskPower
Corporation
1
MRO
Bryan Sherrow Kansas City
1
Board of
Public Utilities
MRO
Bobbi Welch
Omaha Public 1,3,5,6
Power District
MRO
Jeremy Voll
Basin Electric 1
Power
Cooperative
MRO
Bobbi Welch
Midcontinent
ISO
MRO
1,3,5,6
2
Douglas Webb Kansas City
1,3,5,6
Power & Light
MRO
Fred Meyer
Algonquin
Power Co.
1
MRO
John Chang
Manitoba
Hydro
1,3,6
MRO
James Williams Southwest
Power Pool,
Inc.
2
MRO
Jamie Monette Minnesota
Power /
ALLETE
1
MRO
Jamison
Cawley
Nebraska
Public Power
1,3,5
Sing Tay
Oklahoma
1,3,5,6
Gas & Electric
MRO
Terry Harbour
MidAmerican
Energy
MRO
1,3
Troy Brumfield American
1
Transmission
Company
Westar
Energy
Douglas
Webb
ACES Power Jodirah
Marketing
Green
Duke Energy Kim
Thomas
1,3,5,6
1,3,4,5,6
1,3,5,6
MRO,SPP RE
MRO
Westar-KCPL Doug Webb
Westar
1,3,5,6
MRO
Doug Webb
KCP&L
1,3,5,6
MRO
Hoosier
Energy Rural
Electric
Cooperative,
Inc.
1
SERC
Kevin Lyons
Central Iowa
Power
Cooperative
1
MRO
Bill Hutchison
Southern
1
Illinois Power
Cooperative
SERC
Amber Skillern East Kentucky 1
Power
Cooperative
SERC
Ben Engelby
Arizona
1
Electric Power
Cooperative,
Inc.
WECC
Steven Myers
North Carolina 3,4,5
EMC
SERC
Meredith
Dempsey
Brazos
Electric
Cooperative
1,5
Texas RE
Ryan Strom
Buckeye
Power, Inc.
5
RF
Calvin
Wheatley
Wabash
Valley Power
Association
1
RF
Kylee Kropp
Sunflower
1
Electric Power
Corporation
MRO
Laura Lee
Duke Energy
1
SERC
Dale Goodwine Duke Energy
5
SERC
MRO,NA - Not
ACES
Bob Solomon
Applicable,RF,SERC,Texas Standard
RE,WECC
Collaborations
FRCC,RF,SERC
MRO
Duke Energy
Northern
California
Power
Agency
Marty
Hostler
Southern
Pamela
Company Hunter
Southern
Company
Services, Inc.
Eversource
Energy
NPCC
3,4,5,6
1,3,5,6
NCPA
SERC
Quintin Lee 1,3
Ruida Shu
1,2,3,4,5,6,7,8,9,10 NPCC
Southern
Company
Eversource
Group
NPCC
Regional
Standards
Committee
Greg Cecil
Duke Energy
Michael
Whitney
Northern
3
California
Power Agency
WECC
Scott
Tomashefsky
Northern
4
California
Power Agency
WECC
Dennis
Sismaet
Northern
6
California
Power Agency
WECC
Marty
Northern
California
Power Agen
5
WECC
Matt Carden
Southern
1
Company Southern
Company
Services, Inc.
SERC
Joel
Dembowski
Southern
Company Alabama
Power
Company
3
SERC
William D.
Shultz
Southern
Company
Generation
5
SERC
Ron Carlsen
Southern
Company Southern
Company
Generation
6
SERC
Sharon
Flannery
Eversource
Energy
3
NPCC
Quintin Lee
Eversource
Energy
1
NPCC
Guy V. Zito
Northeast
Power
Coordinating
Council
10
NPCC
Randy
MacDonald
New
Brunswick
Power
2
NPCC
Glen Smith
Entergy
Services
4
NPCC
7
NPCC
Alan Adamson New York
State
6
RF
Reliability
Council
David Burke
Orange &
Rockland
Utilities
3
NPCC
Michele
Tondalo
UI
1
NPCC
Helen Lainis
IESO
2
NPCC
John Pearson
ISO-NE
2
NPCC
David Kiguel
Independent
7
NPCC
Paul
Malozewski
Hydro One
3
Networks, Inc.
NPCC
Nick Kowalczyk Orange and
Rockland
1
NPCC
Joel Charlebois AESI Acumen
Engineered
Solutions
International
Inc.
5
NPCC
Mike Cooke
Ontario Power 4
Generation,
Inc.
NPCC
Salvatore
Spagnolo
New York
Power
Authority
1
NPCC
Shivaz Chopra New York
Power
Authority
5
NPCC
Deidre Altobell Con Ed Consolidated
Edison
4
NPCC
Dermot Smyth Con Ed 1
Consolidated
Edison Co. of
New York
NPCC
Peter Yost
Con Ed 3
Consolidated
Edison Co. of
New York
NPCC
Cristhian
Godoy
Con Ed 6
Consolidated
Edison Co. of
New York
NPCC
Nicolas
Turcotte
Hydro1
Qu?bec
TransEnergie
NPCC
Chantal Mazza Hydro Quebec 2
NPCC
Sean Bodkin
Dominion Dominion
Resources,
Inc.
6
NPCC
Nurul Abser
NB Power
Corporation
1
NPCC
Randy
MacDonald
NB Power
Corporation
2
NPCC
Jim Grant
NY-ISO
2
NPCC
Quintin Lee
Eversource
Energy
1
NPCC
Silvia Parada
Mitchell
NextEra
Energy, LLC
4
NPCC
Michael
Ridolfino
Central
Hudson Gas
and Electric
1
NPCC
Vijay Puran
NYSPS
6
NPCC
ALAN
ADAMSON
New York
State
Reliability
Council
10
NPCC
John Hasting
National Grid
USA
1
NPCC
Michael Jones National Grid
USA
1
NPCC
PSEG - Public 1
Service
Electric and
Gas Co.
NPCC
Sean Cavote
Brian Robinson Utility
Services
5
NPCC
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree but have comments or suggestions for
the project scope please provide your recommendation and explanation.
Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
No
Answer
Document Name
Comment
These comments represent the MRO NSRF membership as a whole but would not preclude members from submitting individual comments”.
The NSRF agrees with the intent of the SAR but please see our main objection in question 2, a definition of Essential Reliable Service is required.
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Response
Richard Jackson - U.S. Bureau of Reclamation - 1,5
No
Answer
Document Name
Comment
To minimize churn among standard versions, Reclamation recommends the SAR drafting team coordinate changes with other existing drafting teams
for related standards; specifically, MOD-032, Project 2017-07, and the Standards Efficiency Review Phase 2.
Likes
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0
Response
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer
No
Document Name
Comment
ATC generally agrees with the proposed scope and purpose of the SAR. However, the SAR should be modified to more clearly identify the BES nature
of the equipment that is in scope and whether it qualifies as “transmission connected.” The term “transmission connected” is ambiguous since many
regions have different definitions for what is considered transmission. The SAR should be clarified to address this ambiguity.
Additionally, “transmission connected” does not indicate if the dynamic reactive resource itself must be classified as BES, in accordance with NERC’s
definition, to be within the SAR’s scope or if the dynamic reactive resource must simply be connected to an existing BES element to be within the SAR’s
scope. ATC believes that non-BES devices should not fall within the scope of the standards affected (MOD-025, MOD-026, MOD-027, PRC-019, and
PRC-024) such that a device connected to distribution facilities or other non-BES facilities (e.g. DERs or 69 kV bus) would not fall within the scope of
the SAR.
ATC believes the scope of the SAR should only focus on BES dynamic reactive resources similar in nature to the existing BES definition and scope of
the existing standards.
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Response
Thomas Foltz - AEP - 3,5
Answer
No
Document Name
Comment
AEP objects to the SAR’s scope as currently proposed and find it to be far too open-ended, as typified by the inclusion of “all varieties of transmissionconnected dynamic reactive resources that are utilized in providing ERS in the BES.” While we acknowledge that new technologies in this regard
continue to emerge, more specificity is needed within the SAR to enable industry to provide meaningful feedback.
The final paragraph on page 7 of the Whitepaper expresses concern regarding an apparent “significant inconsistency” between the intent of MOD025-2 to “ensure that accurate information on generator…capability is available for planning models used to assess Bulk Electric System (BES)
reliability” and the actual results obtained during testing. The authors of the White Paper believe that misconceptions regarding generator maximum
achievable reactive capability may be causing the provision of incorrect data for the purposes of MOD-032-1, driven by the requirements of MOD-025.
The SAR would presumably require more robust testing on transmission-connected dynamic reactive resources, and it must be understood and
acknowledged by the SDT that such testing would differ greatly from that of the generation resources currently in scope. We have provided feedback
below regarding how we believe such testing impacts the standards that are in scope for this project.
MOD-026: While initial testing is reasonable, it is not realistic to perform any ongoing dynamic testing of FACTS devices after they are installed on the
system. FACTS devices are dynamically tested on a RTDS simulator in the lab before field commissioning, and against the actual system during field
commissioning. Results of these tests are used to validate the models provided. It is not expected that dynamic response would change on an inverter
based system after initial design, thereby making subsequent tests irrelevant.
MOD-027: This standard does not apply to FACTS voltage control equipment, though it could apply to HVDC tie equipment. Frequency response and
power flow contingency settings are an optional characteristic available in most manufacturers’ control systems and is not be utilized by all entities.
These power flow and frequency response capabilities are tested as part of the factory testing before the unit is commissioned to insure that the
capability performs correctly. No further verification is needed on HVDC equipment unless the frequency response capability is turned on and put into
production.
PRC-019: Initial factory testing is sufficient, and no ongoing field testing is necessary. Factory coordination of protection elements and controls is a
basic part of the design of a FACTS device. When possible, FACTS devices are tested to the full range of operation during commissioning, otherwise
such testing is always performed on the RTDS during factory testing. Test results are then compiled and made available to show compliance with
specifications. If changes are made in the field, then coordination studies would be required to update the documentation.
PRC-024: Once again, initial factory testing is sufficient, and no ongoing field testing is necessary. Protective relays are coordinated with the operation
of the FACTS device during the design phase. The FACTS control system is operated against the RTDS model of the system during factory testing to
insure that all specified transient phenomena are properly handled by the device. Many tests are run at varying voltages and frequencies to prove
that the device is robust and meets standards. Test results are compiled and made available to show compliance with specifications. If changes are
made in the field then coordination studies would be required to update the documentation.
Mod-025: The testing of a FACTS reactive resource may potentially (though obviously unintentionally) introduce risk to the system to which it is
connected. Operating the system outside reasonable parameters is not acceptable for the purposes of testing. Testing of a FACTS reactive resource
will be limited due to the constraints of the system at the time the testing is performed. It is quite possible that full output may not be obtained in
either the capacitive or inductive direction (or both). Testing cannot require the disruption of the power system in the vicinity of the FACTS device, nor
can it put that system at any risk due to the testing. The reason for the termination of the test at any output level should be documented in the test
results with no further requirements due for further testing. As mentioned in the last paragraph of the white paper, an early termination of a test due
to system constraints at the time of the test should not be construed to mean that the unit will always be limited to that maximum output. Any
resulting limitation of the FACTS device in planning models would need to be determined after analysis of the cause of the limitation in the test
results.
In summary, while AEP agrees (at least in part) with what the SAR seeks to achieve, we do not see a true reliability-driven need for standards on these
suggested devices, certainly not to the extent as for independent generators. The existence and usage of these additional devices, by their very
nature, requires their owners to perform reliability studies, calculations, and take other necessary measures to verify both their proper operation and
modeling. As a result, we do not believe that adding obligations for these devices would perceptibly enhance the reliability of the BES, and would
primarily be administrative in nature. We do not believe a “reliability parity” exists between the newly-suggested devices and those already within the
scope of these standards, and do not believe that the standards should be revised to include these additional devices. However, if the SDT does
indeed pursue such changes, we believe the SDT should revise the SAR to address the following a) pursue device-specific obligations for the newlyproposed non-generation devices, b) ensure that Violation Severity Levels for any new obligations are less than those associated with the existing
obligation for Facilities comprising generation resources and c) ensure that the periodicity associated with the obligations on the additional devices
are less burdensome as well.
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Response
Andy Fuhrman - Minnkota Power Cooperative Inc. - 1 - MRO
Answer
Document Name
Comment
No
MPC supports comments from the MRO NERC Standards Review Forum (NSRF).
Likes
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Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
No
Answer
Document Name
Comment
ACES has three main concerns with the proposed SAR:
1. The definition of Essential Reliability Services (ERS) is not consistent amongst the SAR, the White Paper, and other previous resources.
•
•
•
The SAR states the following: Dynamic reactive resources used to provide Essential Reliability Services (ERS) in the BES include generation
resources (rotating machine and inverter-based) as well as transmission connected dynamic reactive resources (power-electronics based).
The SAMS White Paper states the following: ... essential reliability services (ERS) such as voltage control, frequency control, and
ramping/balancing capability.
The Essential Reliability Services “Tutorial” form 2014 explains Essential Reliability Services as an integral part of reliable operations to assure
the protection of equipment and are the elemental “reliability building blocks” provided by generation. That includes voltage support and
frequency support.
Therefore, use of “ERS” requires a NERC-approved definition to avoid any inconsistencies.
2- The Assessment of Applicability in Reliability Standards White Paper that has been supplied as a basis for this SAR is in a draft form. The
submission of this SAR should be deferred until the final White Paper is published.
3- The SAR states that the Cost Impact Assessment is unknown. Cost Impacts are an important aspect to be studied. Company budget cycles are
requested to be measured as a consideration in the time-extension decisions.
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Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1,3,5,6
Answer
Document Name
Comment
No
AZPS proposes the scope be modified to include “BES” connected dynamic reactive devices instead of “transmission” connected reactive devices as
not all devices connected at the transmission level are applicable to the BES. In addition, there are cases where devices connected at 69kV may be
considered BES.
AZPS does not agree with all of the conclusions in the February 2019 NERC SAMS White Paper. For example, on Page 2, Table 1: Applicability of
Relevant NERC Reliability Standards to Dynamic Reactive Resources, APS does not agree with the conclusion that LCC HVDC is applicable to MOD027 or that VSC HVDC is applicable to MOD-025, MOD-026 or MOD-027. The intent of MOD-026 is to verify excitation system model and the intent of
MOD-027 is to verify turbine generator model. Application of these standards to HVDC will not be appropriate. If the intent is to verify HVDC dynamic
models as used in powerflow and stability studies, AZPS asserts that there should be a separate SAR for that requirement.
On Page 7, Other Considerations, Item 2 of the NERC SAMS White Paper additional complications of MOD-025 are discussed.
“NERC SAMS and the NERC Power Plant Modeling and Verification Task Force (PPMVTF) have both identified a significant inconsistency
between the intent of MOD-025-2 to “ensure that accurate information on generator and synchronous condenser reactive power capability is available
for planning models used to assess Bulk Electric System (BES) reliability” and the actual results obtained during testing. MOD-025-2 does not require
the full (maximum achievable) reactive capability of the resource to be reached via test. This is warranted because the testing conditions likely will limit
the resource from reaching its full (maximum achievable) reactive capability before other limits are reached such as system voltage, generator terminal
voltage, or auxiliary bus voltage limits. While this is reasonable for testing, the standard does not require calculations to be performed to prove that the
resource could reach its full (maximum achievable) reactive capability under more favorable operating conditions (i.e. when that full reactive capability is
needed for maintaining voltage schedule). Therefore, there is a significant misconception in the industry that the testing results should be used as the
same data submitted for MOD-032-1 for capability of the machine. This misconception is likely leading to incorrect data being supplied for the purposes
of MOD-032-1 and is driven by the requirements in MOD-025-2.”
AZPS asserts that it is not prudent to modify MOD-025 to include new devices when there are other issues that need to be addressed.
AZPS further notes that there is a discrepancy in the NERC SAMS White Paper as follows: On Page 2, Table 1 indicates that LCC HVDC is
recommended to be applicable to PRC-024 but on Page 6, the Technical Basis for Applicability in the White Paper indicates that it should NOT be
applicable to PRC-024. AZPS recommends the table should be corrected to have a N/A value.
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Response
Glenn Barry - Los Angeles Department of Water and Power - 1,3,5,6
Answer
No
Document Name
Comment
The added benefit to reliability might not be significant to justify the inclusion of these transmission-connected resources. Reliability for these resources
is currently addressed by Standards such as PRC-004, which requires Misoperations to be analyzed and reported and the development of Corrective
Action Plans to remediate issues. In addition, the protection and control systems found in these transmission-connected reactive resources are not
easily modified and typically are proprietary, requiring assistance from the manufacturer to change settings and test certain systems. Modifying existing
protection and control systems affects warranty and is not recommended. Therefore, there is no need to retest/compare when no modifications are
being made to the system. With the loss of a FACTS device, the Power System should not completely fall apart. There may be issues with voltage
stability for short periods of time, such as power flow, but the system should not collapse.
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Marty Hostler - Northern California Power Agency - 3,4,5,6, Group Name NCPA
No
Answer
Document Name
Comment
NO, NCPA does not support this SAR as written.
NCPA feels the SAR needs to clearly state that GO/GOPs will not be subject to any changes to MOD-025, 26, 27 and PRC 19 and 24 Standards due to
this Project 2020-02. If the SAR drafting team disagrees please state exactly why members are willing to imply it doesn’t impact GO/GOPs but are
unwilling to back it up by excluding GO/GOP from the SAR and future subject standards new/modified requirement(s).
As written the SAR seems straight forward. For instance it mentions (non-generation) transmission connected reactive resources, which looks like it
excludes GO/GOPs. But from our experience with FERC, NERC, and WECC, unless the SAR or the Standard specifically states it is not applicable to
GO/GOPs we are going to have to annually provide documentation/evidence proving that we don’t own/operate transmission connected resources and
compile evidence, or null evidence letters, annually proving compliance or non-applicability of the standard. This is simply another cost and time burden
on NCPA, our investors, members, and customers, with zero reliability benefit.
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Response
Stephen Stafford - Georgia Transmission Corporation - 1 - SERC
No
Answer
Document Name
Comment
It does not appear that the SAMS seriously considered a Reliability Guideline to address the issues identified in the White Paper. GTC believes that a
Reliability Guideline would be a better initial step to address the needs identified in the White Paper without adding the administrative burden/cost of
record keeping and documentation for audit purposes; therefore, GTC does not believe that a SAR is necessary at this time.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
No
Answer
Document Name
Comment
Dynamic reactive power resources have nothing to do with frequency control, which is a direct consequence of the balance of real power balances
between generation and load. We believe that the inclusion of MOD-027 in the list of standards in the SAR is out of order.
PRC-019 already applies to TO-owned synchronous condensers. PRC-019 was originally deemed necessary due to miscoordination of the protection
elements embedded in automatic voltage regulating system with the process control limiters which may exist in the controls. Does this miscoordination
exist in the additional "all varieties of dynamic reactive resources" scope proposed? In other words, for the additional scoped elements, are the tripping
elements tripping before the limiting elements limit? The driving source of need and the impetus for increasing the scope of the PRC-019 applicability is
not justified in the SAR.
The detailed description does not provide sufficient detail as to the proposed extent of the modifications to existing requirements, nor does it provide
insight into possible function of new requirements. It is suggested that this detail be added to direct a standard drafting team towards the specific
concern to be addressed.
MOD-025 already applies to TO-owned synchronous condensers. Proportionately, are there substantial numbers of additional transmission connected
reactive power resources that, if modelled, would significantly enhance the validity of a planning model? The driving source of need and the impetus for
increasing the scope of the MOD-025 applicability is not justified in the SAR. Additionally, the operational limitations observed during the first 5 years of
the MOD-025 testing which yielded test results that did not prove the actual reactive capabilities of the machines under test raise valid questions
regarding its value - what is to say that expanding the applicability to additional equipment will yield valuable information on reactive capabilities?
The MVA applicability thresholds for MOD-026 were chosen so that approximately 80% of the connected generation in each interconnection would be
drawn into the scope of the applicability. Are there sufficient quantities of other transmission connected reactive power resources whose inclusion in the
applicability would significantly impact and enhance the validity of planning models?
It is suggested that the Project Scope statement be modified to limit the applicable resources to those specifically identified by the SAMs white
paper. Including a statement such as “all variety of transmission connected dynamic resources is unbounded and could create confusion as to what
resources are applicable.
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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
Yes
Document Name
Comment
PacifiCorp supports the proposed Standards Authorization Request to revise the “Applicability – Facilities” and “Applicability-Functional Entities”
sections in the MOD-025, MOD-026, MOD-027, PRC-019 and PRC-024 reliability standards to include (non-generation) transmission-connected
dynamic reactive resources. PacifiCorp also would like to submit a comment for the team members to consider that for MOD-025, testing the full range
of large non-generation transmission-connected dynamic reactive devices may not be possible under normal operating conditions. Data from actual
disturbances may need to be used to verify the reactive capability of these devices including high speed switching of any associated switched shunt
capacitors and/or reactors that are incorporate to extend the range of the dynamic reactive device.
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0
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0
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Laura Nelson - IDACORP - Idaho Power Company - 1
Yes
Answer
Document Name
Comment
Idaho Power (IPCO) supports the proposed modifications listed in the SAR for NERC Project 2020-02.
Impact to Idaho Power with regard to including synchronous condensers as applicable resources for MOD-026 is anticipated to be minimal. IPCO has
performed dynamic system model validation for IPCO-owned synchronous condensers under the WECC Model Validation and Testing Policy. IPCO has
PMU and DFR monitoring equipment installed on the IPCO-owned synchronous condensers; thus, model validation for MOD-026 can potentially be
performed using disturbance recording data since all the machines have already under gone baseline testing.
Anticipated impact for the addition of synchronous condensers as applicable resources for PRC-024 is minimal to IPCO.
IPCO supports inclusion of the non-generation dynamic reactive resources listed in Table 1 of the NERC SAMS White Paper.
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John Pearson - ISO New England, Inc. - 2 - NPCC
Answer
Document Name
Comment
Yes
With increasing installations of transmission-connected dynamic reactive resources, it is necessary to obtain accurate models of equipment as actually
installed and configured to plan and operate the BES.
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0
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0
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Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Yes
Answer
Document Name
Comment
None.
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0
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0
Response
Adrian Raducea - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Yes
Answer
Document Name
Comment
Accurate models are required for all transmission connected resources.
Likes
1
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DTE Energy - Detroit Edison Company, 3, Barczak Karie
0
Response
Spencer Tacke - Modesto Irrigation District - 3,4,6
Answer
Document Name
Comment
Yes
1.
As far as adding other reactive or real power source model verification requirements to the NERC MOD Standards, I am OK with that. But I
would like to add an expansion of the scope of the existing requirements to include generating resources with less than a 75 MVA rating, and connected
at less than 100 KV, per the explanation below.
1.
Based on WECC’s experience since the Aug. 10, 1996 WSCC (now WECC) System Wide Outage, I would like to suggest that as part of this
SAR, we include the expansion of the scope of those generating resources that need to have their dynamic models verified via MOD-026 & MOD-027,
to include those single generating units 10 MVA or larger (or an aggregate facility rating of 20 MVA or larger), and connected at 60 kV and above.
The detailed analysis of the Aug. 10, 1996 WSCC System Wide Outage demonstrated the real significance that the smaller generators have in their
impact to the transient stability of the WECC Interconnected System. During that Outage, it wasn’t until the smaller U.S. Army Corps of Engineers
McNary Hydroelectric Generators (each of the 13 units were smaller than 75 MVA) in the Pacific Northwest ran into excitation limits and tripped off-line
causing a further and critical voltage sag, that the voltage oscillations on the 500 kV system started, and which eventually led to the complete voltage
collapse and blackout of a major portion of the Pacific and Pacific Northwest System. Their excitation systems were modeled incorrectly at the time,
and that is why the initial simulation analysis did not predict the actual response of the Interconnected System that occurred (see Transactions on
Power Systems, Vol. 14, No. 3, August 1996; “Model Validation for the August 10, 1996 WSCC System Outage”). For this reason, WSCC (WECC)
invoked the mandatory Generating Testing and Model Validation Policy, requiring testing of all generators connected at 60 kV and above, and rated at
10 MVA and above (or an aggregate facility rating of 20 MVA or larger). The effectiveness of this Policy was demonstrated by the analysis of
subsequent system wide disturbances that demonstrated good matches between the simulated responses and the actual systems response during the
disturbances (see “Generating Unit Model Validation: WECC Lessons and Moving Forward” ; 2009 IEEE Power and Energy Society Meeting, Calgary,
AB, Canada, July 26-July 30, 2009). This definitely demonstrated the effectiveness of having accurate generator models for all generators 10 MVA and
larger (or an aggregate facility rating of 20 MVA or larger), and connected at 60 kV and above.
In addition, a final and nearly exact match did not occur for the 1996 Outage simulations until the load of the WECC Interconnected System (typically
placed on 69 kV and below modeled busses) was more accurately modeled by introducing a 20% induction motor load, along with the traditional static
load previously modeled. This fact also demonstrated the extreme importance the lower voltage connected models have on the overall system
response of the WECC high voltage (i.e., greater than or equal to 100 kV) Interconnected System.
And in recent years with the very large influx of renewable generation (many thousands of MWs) in California being added to the WECC System at the
lower levels of 20 MVA and connected at 69 kV and below, it is even more incumbent on us to include in model testing and validation, these smaller
size generating units.
Thank you.
Sincerely,
Spencer Tacke
Senior Electrical Engineer
Modesto Irrigation District
1231 11th Street, Modesto, CA 95354
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Response
Robert Blackney - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Yes
Answer
Document Name
Comment
Please see comments submitted by Edison Electric Institute.
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0
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0
Response
Robert Ganley - Long Island Power Authority - 1
Yes
Answer
Document Name
Comment
It is recommended that the drafting team consider working with industry vendors of transmission connected nonsynchronous sources (i.e. FACTS,
HVDC) to ensure that the standard requirements can be benchmarked with actual and realistic resource testing capabilities and modeling capabilities.
As mentioned in the White Paper, controls for nonsynchronous sources are different based on the types of equipment technologies used in the different
devices.
In terms of dynamic simulation modeling of nonsynchronous sources (i.e. FACTS, HVDC), it is expected that such dynamic models would be developed
by and provided by the device vendor. It is encouraged that the applicable standards promote the development of, and use of, standardized “off the
shelf” dynamic simulation software models.
It is likely that many Transmission Owners (TOs) rely on the services of the nonsynchronous resource (i.e. FACTS, HVDC) vendor for capability testing,
protection coordination and model verification – due to the specialized nature of these resources. The proposed standards development envisioned by
this SAR would likely increase a TO’s reliance on support services from their nonsynchronous resource vendors, with a corresponding increase in costs.
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0
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Douglas Webb - Westar Energy - 1,3,5,6 - MRO, Group Name Westar-KCPL
Answer
Document Name
Comment
Yes
Westar Energy and Kansas City Power & Light, Evergy companies, incorporate by reference and support the Edison Electric Institute (EEI) response to
Question 1.
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0
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0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Yes
Answer
Document Name
Comment
EEI supports the proposed changes contained in the Project 2020-02 SAR. The SAR, which is supported by a comprehensive white paper developed
by the System Analysis and Modeling Subcommittee (SAMS), identifies a gap in the existing body of Reliability Standards that has been created by the
changing resource mix and changes in technology and transmission connected devices that are needed to support BES reliability. EEI agrees with
SAMS that both rotating machines and power-electronics based resources that are capable of supporting Essential Reliability Services (ERS) should do
so in a consistent manner.
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0
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0
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Daniel Gacek - Exelon - 1,3,5,6
Yes
Answer
Document Name
Comment
Exelon agrees with the proposed scope as described in the SAR and concurs with the comment submitted by EEI.
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0
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0
Response
Quintin Lee - Eversource Energy - 1,3, Group Name Eversource Group
Answer
Document Name
Yes
Comment
The applicability of NERC standards to battery energy storage resources should be considered as some large projects are in development now. The
applicability of the NERC standards needs to be noted for both storing and releasing energy.
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0
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0
Response
David Jendras - Ameren - Ameren Services - 1,3,6
Yes
Answer
Document Name
Comment
Ameren agrees with and supports EEI comments.
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0
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0
Response
Bruce Reimer - Manitoba Hydro - 1,3,5,6
Yes
Answer
Document Name
Comment
I agree with the recommendation. Dynamic reactive resources, including generation resources such as rotating machinery as well as transmission
connected dynamic reactive resources, both in the form of rotating machinery such as synchronous condensers, and power-electronics based devices
such as SVC’s and STATCOMS, affect the transmission voltages, power transfer levels and hence the reliability of the power system due to their ability
to generate and absorb Mvars dynamically and in the steady state. In many cases the MVA rating of these devices can be larger than single generating
units. As such the accurate representation and capability testing of such devices will contribute to the overall reliability of the BES.
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0
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0
Ruida Shu - NPCC - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC Regional Standards Committee
Yes
Answer
Document Name
Comment
Please consider revising the proposed scope to only include the transmission-connected dynamic reactive resources that are referenced in the SAMs
white paper. This suggested revision would align with the detailed description of the SAR.
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0
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0
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Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Yes
Answer
Document Name
Comment
BPA believes this is a timely and much needed effort to ensure transmission-connected reactive resources have validated dynamic models, and
appropriate system performance.
The Western Interconnection is undergoing significant transformation with its generation mix. Many of the large coal-fired and nuclear power plants
have retired or are scheduled to retire. These generators are replaced with renewable plants, which are usually smaller in size. Current 75 MW
threshold represented 80% of generating capacity in the Western Interconnection in 2007. However, with the retirement of large synchronous
generators and addition of smaller renewable plants, the threshold is now lower.
As such, BPA requests the drafting team to revisit the applicability threshold in MOD-026/27 Reliability Standards for the Western Interconnection as
additional scope to this SAR.
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0
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Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
Yes
ERCOT generally supports the concept described in the SAR. Regarding PRC-024 only, ERCOT agrees that the standard should be revised to prohibit
tripping of GO-owned reactive devices outside certain defined parameters, as suggested by the SAMS whitepaper, but does not agree that the standard
should be revised to prohibit tripping of TO-owned reactive devices. This is because, to the extent tripping of such devices outside of PRC-024’s
defined parameters can foreseeably cause a reliability issue, that issue should be identified in a TP’s or PC’s annual Planning Assessment and resolved
through a Corrective Action Plan (CAP). To the extent the tripping of a TO-owned reactive device does not result in a violation of planning criteria, then
requiring the TO to prevent the tripping of that device in conformance with the settings of PRC-024 would not be necessary or cost-effective.
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Jennie Wike - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6 - WECC
Yes
Answer
Document Name
Comment
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0
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0
Response
Leonard Kula - Independent Electricity System Operator - 2
Yes
Answer
Document Name
Comment
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0
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0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Document Name
Comment
Yes
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0
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0
Response
Anthony Jablonski - ReliabilityFirst - 10
Yes
Answer
Document Name
Comment
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0
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0
Response
Carl Pineault - Hydro-Qu?bec Production - 1,5
Yes
Answer
Document Name
Comment
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0
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0
Response
Colleen Campbell - AES - Indianapolis Power and Light Co. - 3
Yes
Answer
Document Name
Comment
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0
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0
Response
Maryanne Darling-Reich - Black Hills Corporation - Black Hills Power - 1,3,5,6 - MRO,WECC
Yes
Answer
Document Name
Comment
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0
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0
Response
Teresa Cantwell - Lower Colorado River Authority - 1,5
Yes
Answer
Document Name
Comment
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0
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0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Yes
Answer
Document Name
Comment
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0
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0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2
Answer
Document Name
Comment
MISO supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
MISO supports the intent of the SAR to augment the applicability of existing reliability standards for verifying the capability, modeling and performance
of dynamic reactive resources to include (non-generation) transmission-connected reactive resources; however, as written the scope of the SAR relies
on the definition of Essential Reliability Services (ERS) and the definition of ERS is unclear.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE appreciates the SAR drafting team’s efforts in addressing reliability and issues we have seen as a contributing cause to past events (e.g.
STATCOM tripping off during voltage excursion during July 2015 event). Texas RE noticed, however, that the scope of the SAR focuses on
“transmission-connected resources”, but does not clearly address how these reactive devices will be addressed when owned by the Generator Owner
(GO). This is especially pertinent for dispersed power producing resources where synchronous condensers, SVCs, and STATCOMs are frequently
located behind the GSU and used to supplement the Reactive Power output of the individual generating units.
For example, Footnote 4 of PRC-024-2 states “For voltage protective relays associated with dispersed power producing resources identified through
Inclusion I4 of the Bulk Electric System definition, this requirement applies to voltage protective relays applied on the individual generating unit of the
dispersed power producing resources, as well as voltage protective relays applied on equipment from the individual generating unit of the dispersed
power producing resource up to the point of interconnection.” Since the language in this footnote only addresses generating units, a synchronous
condenser, SVC, or STATCOM owned by the GO is not applicable to the currently effective version of the Standard. Texas RE recommends clarifying
the SAR to ensure the modifications to applicability include GO dynamic reactive devices.
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0
2. Provide any additional comments for the SAR drafting team to consider, if desired.
Ruida Shu - NPCC - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC Regional Standards Committee
Answer
Document Name
Comment
The SAR drafting team should consider an implementation plan specifically for BES dynamic reactive resources initial MOD/PRC testing and reporting.
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0
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0
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
The industry need section of the SAR needs is confusing in listing the GO-owned rotating-machine and inverter-based generating facilities that are
already subject to the MOD and PRC standards listed in the SAR title. It is suggested that the need be focused only on the missing elements in the
focus of the concern of this SAR. It is unclear what the term non-generation means.
It is suggested that the detailed description section of the SAR provide only details of what is being proposed to be changed in the list of standard. The
basis and justification references pointing to the SAMS white paper, in our opinion, do not belong in the detailed description section of what is being
proposed. More specificity is suggested: e.g."modify the applicability sections to include…, modify requirements, if needed, to address these additional
facility types…, modify/create new requirements to achieve specific objectives…, add glossary terms, if needed …".
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0
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0
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Bruce Reimer - Manitoba Hydro - 1,3,5,6
Answer
Document Name
Comment
1.
MH believes that it is important to verify voltage and frequency ride through capability of LCC HVDC links. Given these links are large, loss of the
links can be impactive to reliability – especially frequency support. Therefore, PRC-024 should be applicable to LCC links.
While the SAR is clearly focused on “reactive power resources” they’re missing an important contribution of LCC HVDC to frequency stability. The
scope of the SAR should clearly address both voltage and frequency.
On page 6 of the NERC SAMS White paper it says the following for PRC-024:
“The LCC HVDC would be expected to ride through grid voltage and frequency excursion events to provide continuity of service (i.e. maintaining MW
output). Therefore, PRC-024 should not be applicable to LCC HVDC”.
This statement contradicts with the SAMS recommendation in Table-1 to include LCC HVDC in PRC-024. NERC should revise this White Paper to
ensure that PRC-024 is applicable to LCC HVDC.
2.
MH believes MOD-25 should be applicable to LCC HVDC as well. From model verification point of view, it is important to know the behavior
(MW/MVAr) over the range of operation at the inverter bus.
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
As more utilities begin to use PV plants as dynamic reactive power sources at night when real power is zero, it is increasingly important that this unique
mode of operation is considered as the subject reliability standards are revised. In particular, MOD-025 should have provisions for reactive power
capability at zero power for inverter-based resources that are capable of such operation.
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0
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0
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David Jendras - Ameren - Ameren Services - 1,3,6
Answer
Document Name
Comment
Ameren agrees with and supports EEI comments.
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0
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0
Response
Quintin Lee - Eversource Energy - 1,3, Group Name Eversource Group
Answer
Document Name
Comment
Additionally the NERC standards applicability to all energy storage (compressed air, flywheel, gravitational, etc.) methodologies should be
considered. The applicability of the NERC standards needs to be noted for both storing and releasing energy.
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0
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
There appears to be a typo on page 6 where the SAR states: “Therefore, PRC-024 should not be applicable to LCC HVDC.” Table 1 of the document
indicates the SAMS recommendation is for PRC-024 to be applicable to LCC HVDC, and the statement on page 6 that “The LCC HVDC would be
expected to ride through grid voltage and frequency excursion events to provide continuity of service” indicates the intent of the SAR is for PRC-024 to
be applicable to LCC HVDC.
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0
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0
Response
Daniel Gacek - Exelon - 1,3,5,6
Answer
Document Name
Comment
Exelon concurs with the comment submitted by EEI.
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0
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0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
While EEI supports the proposed SAR, we offer the following suggestions to ensure the project is appropriately bounded.
1.
EEI suggests that the Project Scope statement be modified to limit the applicable resources to those specifically identified by the SAMs white
paper.
2.
While EEI supports and agrees with the finding of the SAMs white paper identified in the Consensus Building Activity section of the SAR, we
disagree that the white paper qualifies as a “consensus” report given it was not vetted broadly by the Industry EEI suggest this statement be removed.
EEI also offer the following non-substantive comments for the SAR:
1.
EEI suggests modifying the title of this SAR to “Modification of MOD-025, MOD-026, MOD-027, PRC-019 and PRC-024 to include Dynamic
Reactive Resources.”
2.
In the section that identifies Standards and SARs that should be referenced, EEI suggests that the PRC-024 SAR reference should be changed to
include a reference to the BOT approved PRC-024-3 Reliability Standard. Additionally, since the PRC-019 SAR has not yet been approved by the
Standards Committee, EEI suggests this reference be removed.
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Bobbi Welch - Midcontinent ISO, Inc. - 2
Answer
Document Name
Comment
MISO supports comments submitted by the MRO NSRF and recommends the following clarifications to the scope of the SAR:
Implementation Plan – include the development of an implementation Plan for the initial testing and reporting of dynamic reactive resources newly
introduced under the applicability of revised standards.
Definition of Essential Reliability Services (ERS) – define Essential Reliability Services (ERS) as the description of ERS has varied over time and
includes some definitions which limit the focus to generation and demand resources. Examples provided below.
· The Essential Reliability Services Task Force (ERSTF) Scope Document approved by the NERC Planning and Operating Committees on March 5,
2014 defines Essential Reliability Services as “the elemental ‘reliability building blocks’ from resources (generation and demand) necessary to maintain
Bulk Power System (BPS) reliability. ERS are operational attributes from conventional generation, such as providing reactive power to maintain system
voltages and physical inertia to maintain system frequency, necessary to reliably operate the BPS.”
http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ERSTF_Final.pdf
· The October 2014 NERC Essential Reliability Services Task Force White Paper “A Concept Paper on Essential Reliability Services that Characterizes
Bulk Power System Reliability” explains Essential Reliability Services as: “ERSs are an integral part of reliable operations to assure the protection of
equipment, and are the elemental “reliability building blocks” provided by generation” including voltage support and frequency support.
· The February 2019 NERC SAMS White Paper, “Transmission Connected Dynamic Reactive Resources and HVDC Equipment – Assessment of
Applicability in Reliability Standards," referenced in the SAR states: “…essential reliability services (ERS) such as (emphasis added) voltage control,
frequency control, and ramping/balancing capability."
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0
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0
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Douglas Webb - Westar Energy - 1,3,5,6 - MRO, Group Name Westar-KCPL
Answer
Document Name
Comment
Westar Energy and Kansas City Power & Light, Evergy companies, incorporate by reference and support the Edison Electric Institute (EEI) response to
Question 2.
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0
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0
Response
Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer
Document Name
Comment
None.
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0
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0
Response
Stephen Stafford - Georgia Transmission Corporation - 1 - SERC
Answer
Document Name
Comment
If the SAR is to be accepted, GTC recommends the scope be modified as follows to address the specific concern of non-generation, transmissionconnected dynamic reactive resources:
Revise the “Applicability – Facilities” section, “Applicability – Functional Entities” section, and Requirements (including applicable attachments) in MOD025, MOD-026, MOD-027, PRC-019 and PRC-024 reliability standards to comprehensively address all varieties of (non-generation) transmissionconnected dynamic reactive resources that are utilized in providing ERS in the BES.
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0
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0
Response
Marty Hostler - Northern California Power Agency - 3,4,5,6, Group Name NCPA
Answer
Document Name
Comment
None
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0
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0
Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1,3,5,6
Answer
Document Name
Comment
AZPS recommends defining what qualifies as a “dynamic reactive resource” within the Glossary of Terms Used in NERC Reliability Standards. AZPS
believes that without a definition there could be a gap in the applicability of the standard. AZPS suggests that the criteria listed on Slide 12 of “Dynamic
vs. Static Resources” from the March 2017 Industry Webinar for Reactive Power Planning, NERC System Analysis and Modeling Subcommittee
(SAMS) should be used as a starting point for the development of the definition.
Dynamic reactive resources:
•
•
•
•
Adjust reactive power output automatically in real-time over a continuous range within a specified voltage bandwidth in response to grid voltage
changes
Maintain set point voltage or operate in voltage droop mode
Many are power electronics ballots
Can respond within electrical cycles using fast-acting controls.
AZPS suggests that the drafting team review the periodic performance of each device type within MOD-025 and recommends that the frequency be no
more than every ten years.
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0
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0
Response
Robert Blackney - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer
Document Name
Comment
Please see comments submitted by Edison Electric Institute.
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0
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0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
Document Name
Comment
Thank you for the opportunity to provide comments.
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0
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0
Response
Spencer Tacke - Modesto Irrigation District - 3,4,6
Answer
Document Name
Comment
1.
Based on WECC’s experience since the Aug. 10, 1996 WSCC (now WECC) System Wide Outage, I would like to suggest that as part of this
SAR, we include the expansion of the scope of those generating resources that need to have their dynamic models verified via MOD-026 & MOD-027,
to include those single generating units 10 MVA or larger (or an aggregate facility rating of 20 MVA or larger), and connected at 60 kV and above.
The detailed analysis of the Aug. 10, 1996 WSCC System Wide Outage demonstrated the real significance that the smaller generators have in their
impact to the transient stability of the WECC Interconnected System. During that Outage, it wasn’t until the smaller U.S. Army Corps of Engineers
McNary Hydroelectric Generators (each of the 13 units were smaller than 75 MVA) in the Pacific Northwest ran into excitation limits and tripped off-line
causing a further and critical voltage sag, that the voltage oscillations on the 500 kV system started, and which eventually led to the complete voltage
collapse and blackout of a major portion of the Pacific and Pacific Northwest System. Their excitation systems were modeled incorrectly at the time,
and that is why the initial simulation analysis did not predict the actual response of the Interconnected System that occurred (see Transactions on
Power Systems, Vol. 14, No. 3, August 1996; “Model Validation for the August 10, 1996 WSCC System Outage”). For this reason, WSCC (WECC)
invoked the mandatory Generating Testing and Model Validation Policy, requiring testing of all generators connected at 60 kV and above, and rated at
10 MVA and above (or an aggregate facility rating of 20 MVA or larger). The effectiveness of this Policy was demonstrated by the analysis of
subsequent system wide disturbances that demonstrated good matches between the simulated responses and the actual systems response during the
disturbances (see “Generating Unit Model Validation: WECC Lessons and Moving Forward” ; 2009 IEEE Power and Energy Society Meeting, Calgary,
AB, Canada, July 26-July 30, 2009). This definitely demonstrated the effectiveness of having accurate generator models for all generators 10 MVA and
larger (or an aggregate facility rating of 20 MVA or larger), and connected at 60 kV and above.
In addition, a final and nearly exact match did not occur for the 1996 Outage simulations until the load of the WECC Interconnected System (typically
placed on 69 kV and below modeled busses) was more accurately modeled by introducing a 20% induction motor load, along with the traditional static
load previously modeled. This fact also demonstrated the extreme importance the lower voltage connected models have on the overall system
response of the WECC high voltage (i.e., greater than or equal to 100 kV) Interconnected System.
And in recent years with the very large influx of renewable generation (many thousands of MWs) in California being added to the WECC System at the
lower levels of 20 MVA and connected at 69 kV and below, it is even more incumbent on us to include in model testing and validation, these smaller
size generating units.
Thank you.
Sincerely,
Spencer Tacke
Senior Elelctrical Engineer
Modesto Irrigation District
1231 11th Street, Modesto, CA 95354
Likes
0
Dislikes
0
Response
Andy Fuhrman - Minnkota Power Cooperative Inc. - 1 - MRO
Answer
Document Name
Comment
MPC supports comments from the MRO NERC Standards Review Forum (NSRF).
Likes
0
Dislikes
0
Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer
Document Name
Comment
The Standard Draft Team should consider and implement a MVAR/MVA size threshold for validation of the dynamic reactive resources along with
clarifying the BES/Non-BES discussion above.
Likes
Dislikes
0
0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1,5
Answer
Document Name
Comment
Reclamation recommends the SAR drafting team thoughtfully assess the cost impacts associated with this SAR to effect changes in a cost-effective
manner. The SAR proposes a significant increase in the scope of the affected standards, which will have a substantial impact on affected entities and
should not be taken without appropriate consideration.
Likes
0
Dislikes
0
Response
Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer
Document Name
Comment
These comments represent the MRO NSRF membership as a whole but would not preclude members from submitting individual comments”.
The use of the wording “Essential Reliability Services (ERS)” requires a NERC approved definition. There are many different pseudo explanations of
what Essential Reliability Services are.
•
•
•
From the 3 Nov 2014 Essential Reliability Services “Tutorial” which explains Essential Reliability Services as ERSs are an integral part of
reliable operations to assure the protection of equipment and are the elemental “reliability building blocks” provided by generation. That include
voltage support and frequency support.
The SAMS White Paper states (within this SAR) “…essential reliability services (ERS) such as (emphasis added) voltage control, frequency
control, and ramping/balancing capability”.
This SAR states “Dynamic reactive resources used to provide Essential Reliability Services (ERS) in the BES include generation resources
(rotating machine and inverter-based) as well as transmission connected dynamic reactive resources (power-electronics based).
With the above inconsistency of what ERS is, the SAR should include the development of an Essential Reliability Services definition.
Likes
0
Dislikes
0
Response
John Pearson - ISO New England, Inc. - 2 - NPCC
Answer
Document Name
Comment
The SAR drafting team should consider an implementation plan specifically for BES dynamic reactive resources initial MOD/PRC testing and reporting.
Likes
0
Dislikes
0
Response
Carl Pineault - Hydro-Qu?bec Production - 1,5
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Document Name
Comment
None
Likes
0
Dislikes
0
Response
Leonard Kula - Independent Electricity System Operator - 2
Answer
Document Name
Comment
The SAR drafting team should consider an implementation plan specifically for BES dynamic reactive resources initial MOD/PRC testing and reporting.
Likes
0
Dislikes
Response
0
Project 2020-02 Transmission-connected
Dynamic Reactive Resources
Summary Response to SAR Comments | February 2022
Introduction
The Standard Authorization Request (SAR) drafting team thanks all who provided comments during the
informal comment period. All comments received were reviewed and the identified common themes are
addressed below. Some comments have been reserved for consideration during the standard drafting
phase of the project, including the financial impact question and risk.
1. TCDRR definition(s) and Applicability section in standards should be clear which assets or
technologies are considered a TCDRR and what is applicable within each Reliability Standard.
The Project 2020-02 standard drafting team (SDT) will use the definition of terms, revise
applicability section(s), and revise standard language to make clear what assets/technologies are
considered a transmission-connected dynamic reactive resource (TCDRR), and may define specific
technologies (SVC, STATCOM, FACTS, HVDC, etc.). The SAR allows the SDT to add, modify or retire
Glossary terms.
2. The SDT should coordinate drafting a Reliability Guideline with a NERC technical committee
rather than revising the standards.
Though there is an existing Reliability Guideline: Reactive Power Planning (December 2016)
covering reactive power planning and related issues, there is currently not a Reliability Guideline
drafted or being drafted that addresses the reliability risks outlined in the SAR or in SAMS white
paper, Transmission Connected Dynamic Reactive Resources – Assessment of Applicability in
Reliability Standards. The 2020-02 SDT is tasked with determining whether revisions to the
standards will appropriately address the reliability risk outlined in the SAR and white paper.
3. The SDT should consider defining addition terms such as essential reliability services.
The SAR allows the creation of new Glossary terms as part of the project scope. This can include
new Glossary terms for all or some of the TCDRR noted in the SAMS white-paper. Essential
reliability services is currently not a defined term in the Glossary of Terms used in NERC Reliability
Standards. The SDT may consider adding new terms, such as essential reliability services, if they
find it necessary as part of the project.
4. Dynamic reactive resources located at a generation Facility should not be considered TCDRR.
The SAR DT agrees with this comment. When a dynamic reactive resource (e.g. FACTS device or
synchronous condenser) is located at a generation Facility, the asset would be covered under the
applicability of existing standards. As described in the SAR, Project 2020-02 is meant to address
non-generation TCDRR under the purview of the Transmission Owner. The SDT will attempt to
make this distinction clear, either in the Applicability section of revised standards or in Glossary
term(s).
RELIABILITY | RESILIENCE | SECURITY
5. The SDT should determine the practicality of staged testing TCDRR as part of MOD-025, MOD026, and MOD-027 implementation before revising the standards.
Modeling data for synchronous condensers, FACTS and HVDC equipment is provided by the
Transmission Owner to Transmission Planners & Planning Coordinators as part of MOD-032.
However, the models are not subsequently validated, unless being reviewed by the Transmission
Planner as part of MOD-033 following a system disturbance. MOD-025/026/027 could provide a
means for the Transmission Owner to validate the models using a staged test, or verify the
model(s) reflect in-service equipment by an alternate means. The Project 2020-02 SDT will
coordinate and advise the SDTs for Project 2020-06 (MOD-026/027) & Project 2021-01 (MOD-025
and PRC-019) on the practicality of performing staged testing. However, the decision of whether
and how to revise MOD-025, MOD-026, MOD-027 to include TCDRR will reside with those
respective drafting teams.
Resources
•
Project 2020-02 Transmission-connected Reactive Dynamic Resources
•
TCR SAR (MOD-026, MOD-027, MOD-025, PRC-019, PRC-024)
•
Industry Comments
Project 2020-02 Transmission-connected Dynamic Reactive Resources
Summary of SAR Comments | February 2022
2
Unofficial Nomination Form
Project 2020-02 Transmission-connected Dynamic Reactive Resources
Standard Authorization Request Drafting Team
Do not use this form for submitting nominations. Use the electronic form to submit nominations for
Standard Authorization Request (SAR) drafting team members by 8 p.m. Eastern, Monday, May 17, 2021.
This unofficial version is provided to assist nominees in compiling the information necessary to submit the
electronic form.
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Chris Larson (via email), or at 404-446-9708.
Background
The problem of increasing amounts of reactive power being supplied by nonsynchronous sources was
identified in NERC’s 2017 Long-term Reliability Assessment. In response to the concern, the Planning
Committee (PC) assigned the System Analysis and Modeling Subcommittee (SAMS) to study the issue. The
SAMS developed the Applicability of Transmission-Connected Reactive Devices white paper, which was
approved by the PC at its December 10-11, 2019 meeting. The PC Executive Committee reviewed the draft
SAR from SAMS at its January meeting and subsequently approved the SAR by email vote ending on
February 11, 2020. The SAR concerning Transmission-Connected Resources (TCR) aims to modify NERC
Reliability Standards MOD-025, MOD-026, MOD-027, PRC-019 and PRC-024 to comprehensively include
all types of dynamic reactive resources (including static var systems and FACTS) and DC transmission
systems used to provide Essential Reliability Services (ERS) in the Bulk Electric System (BES).
Dynamic reactive resources used to provide ERS in the BES include generation resources (rotating
machine and inverter-based) as well as transmission connected dynamic reactive resources (powerelectronics based). Existing Reliability Standards for verifying the capability, modeling and performance of
dynamic reactive resources are only applicable to Facilities comprising generation resources. Augmenting
the applicability of these standards to include (nongeneration) transmission-connected reactive
resources, both rotating machine (i.e. synchronous condenser) and power-electronics based, will enhance
the BES reliability by ensuring that the capability, models and performance are verified and validated for
all varieties of dynamic reactive resources utilized in providing ERS in the BES.
Standard(s) affected: PRC-024. MOD-025, MOD-026, MOD-027, PRC-019 revisions will be coordinated
with other project teams.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls. The time commitment for this project is
expected to be one face-to-face meetings per quarter (on average two full working days each
meeting) with conference calls scheduled as needed to meet the agreed upon timeline the team sets
forth. Face-to-face meetings will be conducted only when CDC health guidelines permit. Team
RELIABILITY | RESILIENCE | SECURITY
members may also have side projects, either individually or by sub-group, to present for discussion
and review. Lastly, an important component of the team effort is outreach. Members of the team will
be expected to conduct industry outreach during the development process to support a successful
ballot. Previous drafting team experience is beneficial but not required. See the project page and
nomination form for additional information.
NERC is seeking individuals who possess experience in the following areas:
•
Developing and verifying dynamic models used in long-term planning assessments, specifically
for transmission-connected reactive resources*
•
Modeling and studying transmission-connected reactive devices during interconnection
studies or long-term planning assessments
•
Performing equipment capability testing for transmission-connected reactive devices and
rotating machines
•
Understanding the large disturbance behavior of transmission-connected reactive devices,
particularly the power electronic controls that govern the performance of these devices during
abnormal grid conditions
* Transmission-connected reactive resources generally refers to FACTS (Flexible AC Transmission
System) devices such as Static Var Compensators (SVCs) and Static Synchronous Compensator
(STATCOMs) as well as other power-electronic devices that fall in this category such as HVDC circuits
and synchronous condensers.
Name:
Organization:
Address:
Telephone:
Email:
Please briefly describe your experience and qualifications to serve on the requested SAR Drafting
Team (Bio):
Unofficial Nomination Form | April – May, 2021
Project 2020-02 Transmission-connected Dynamic Reactive Resources
2
If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Acknowledgement that the nominee has read and understands both the NERC Participant Conduct
Policy and the Standard Drafting Team Scope documents, available on NERC Standards Resources.
Yes, the nominee has read and understands these documents.
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
MRO
NPCC
RF
SERC
Texas RE
WECC
NA – Not Applicable
Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Unofficial Nomination Form | April – May, 2021
Project 2020-02 Transmission-connected Dynamic Reactive Resources
3
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator
Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner
Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
Name:
Telephone:
Organization:
Email:
Name:
Telephone:
Organization:
Email:
Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
1
Name:
Telephone:
Title:
Email:
These functions are defined in the NERC Functional Model, which is available on the NERC web site.
Unofficial Nomination Form | April – May, 2021
Project 2020-02 Transmission-connected Dynamic Reactive Resources
4
Standards Announcement
Project 2020-02 Transmission-connected Dynamic Reactive
Resources
Supplemental Nomination Period Open through May 17, 2021
Now Available
Additional nominations are being sought for Standard Authorization Request (SAR) drafting team
members through 8 p.m. Eastern, Monday, May 17, 2021.
Use the electronic form to submit a nomination and contact Wendy Muller regarding issues with the
system. An unofficial Word version of the nomination form is posted on the Standard Drafting Team
Vacancies page and the project page.
Background
The potential risk of increasing amounts of reactive power being supplied by nonsynchronous sources
was identified in NERC's 2017 Long-term Reliability Assessment. In response to the concern, the Planning
Committee (PC) assigned the System Analysis and Modeling Subcommittee (SAMS) to study the issue.
The SAMS developed the Applicability of Transmission-Connected Reactive Devices white paper, which
was approved by the PC at its December 2019 meeting. The PC Executive Committee reviewed the draft
SAR from SAMS at its January meeting and subsequently approved the SAR by email vote ending on
February 11, 2020. The SAR was posted for industry comment March 30 – May 13, 2020, and drafting
team member nominations were solicited. However, the project was temporarily paused before a SAR
drafting team was appointed.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls. The time commitment for this project is
expected to be one face-to-face meetings per quarter (on average two full working days each
meeting) with conference calls scheduled as needed to meet the agreed upon timeline the team sets
forth. Face-to-face meetings will be conducted only when CDC health guidelines permit. Team
members may also have side projects, either individually or by sub-group, to present for discussion
and review. Lastly, an important component of the team effort is outreach. Members of the team
will be expected to conduct industry outreach during the development process to support a
successful ballot. Previous drafting team experience is beneficial but not required. See the project
page and nomination form for additional information.
Next Steps
The Standards Committee is expected to appoint members to the drafting team in June or July, 2021.
Nominees will be notified shortly after they have been appointed.
RELIABILITY | RESILIENCE | SECURITY
For more information on the Standards Development Process, refer to the Standard Processes
Manual.
For more information or assistance, contact Senior Standards Developer, Chris Larson (via email) or at 404446-9708. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from
the "Service" drop-down menu and specify “Project 2020-02 Transmission-connected Dynamic Reactive
Resources observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | April 28, 2021
Project 2020-06 Transmission-connected Dynamic Reactive Resources
2
Unofficial Nomination Form
Project 2020-02 Transmission-connected Dynamic Resources
Do not use this form for submitting nominations. Use the electronic form to submit nominations for
Project 2020-02 Transmission-connected Dynamic Reactive Resources Standard Authorization Request
(SAR) drafting team members by 8 p.m. Eastern, Monday, December 20, 2021. This unofficial version is
provided to assist nominees in compiling the information necessary to submit the electronic form.
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Chris Larson (via email), or at 404-446-9708.
Background
The problem of increasing amounts of reactive power being supplied by nonsynchronous sources was
identified in NERC’s 2017 Long-term Reliability Assessment. In response to the concern, the Planning
Committee (PC) assigned the System Analysis and Modeling Subcommittee (SAMS) to study the issue. The
SAMS developed the Applicability of Transmission-Connected Reactive Devices white paper, which was
approved by the PC at its December 10-11, 2019 meeting. The PC Executive Committee reviewed the draft
SAR from SAMS at its January meeting and subsequently approved the SAR by email vote ending on
February 11, 2020. The SAR concerning transmission-connected dynamic reactive resources (TCDRR) aims
to modify NERC Reliability Standards MOD-025, MOD-026, MOD-027, PRC-019 and PRC-024 to
comprehensively include all types of dynamic reactive resources (including static var systems and FACTS)
and DC transmission systems used to provide Essential Reliability Services (ERS) in the Bulk Electric System
(BES).
Dynamic reactive resources used to provide ERS in the BES include generation resources (rotating
machine and inverter-based) as well as transmission connected dynamic reactive resources (powerelectronics based). Existing Reliability Standards for verifying the capability, modeling and performance of
dynamic reactive resources are only applicable to Facilities comprising generation resources. Augmenting
the applicability of these standards to include (nongeneration) transmission-connected dynamic reactive
resources, both rotating machine (i.e. synchronous condenser) and power-electronics based, will enhance
the BES reliability by ensuring that the capability, models and performance are verified and validated for
all varieties of dynamic reactive resources utilized in providing ERS in the BES.
Standard(s) affected: PRC-024, MOD-025, MOD-026, MOD-027, PRC-019 revisions will be coordinated
with other project teams.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls. The time commitment for this project is
expected to be one face-to-face meetings per quarter (on average two full working days each
meeting) with conference calls scheduled as needed to meet the agreed upon timeline the team sets
forth. Face-to-face meetings will be conducted only when CDC health guidelines permit. Team
members may also have side projects, either individually or by sub-group, to present for discussion
RELIABILITY | RESILIENCE | SECURITY
and review. Lastly, an important component of the team effort is outreach. Members of the team will
be expected to conduct industry outreach during the development process to support a successful
ballot. Previous drafting team experience is beneficial but not required. See the project page and
nomination form for additional information.
NERC is seeking individuals who possess experience in the following areas:
•
Developing and verifying dynamic models used in long-term planning assessments, specifically
for transmission-connected reactive resources*
•
Modeling and studying transmission-connected reactive devices during interconnection
studies or long-term planning assessments
•
Performing equipment capability testing for transmission-connected reactive devices and
rotating machines
•
Understanding the large disturbance behavior of transmission-connected reactive devices,
particularly the power electronic controls that govern the performance of these devices during
abnormal grid conditions
* Transmission-connected reactive resources generally refers to FACTS (Flexible AC Transmission
System) devices such as Static Var Compensators (SVCs) and Static Synchronous Compensator
(STATCOMs) as well as other power-electronic devices that fall in this category such as HVDC circuits
and synchronous condensers.
Name:
Organization:
Address:
Telephone:
Email:
Please briefly describe your experience and qualifications to serve on the requested SAR Drafting
Team (Bio):
Unofficial Nomination Form | November-December, 2021
Project 2020-02 Transmission-connected Dynamic Resources
2
If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Acknowledgement that the nominee has read and understands both the NERC Participant Conduct
Policy and the Standard Drafting Team Scope documents, available on NERC Standards Resources.
Yes, the nominee has read and understands these documents.
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
MRO
NPCC
RF
SERC
Texas RE
WECC
NA – Not Applicable
Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Unofficial Nomination Form | November-December, 2021
Project 2020-02 Transmission-connected Dynamic Resources
3
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator
Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner
Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
Name:
Telephone:
Organization:
Email:
Name:
Telephone:
Organization:
Email:
Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
1
Name:
Telephone:
Title:
Email:
These functions are defined in the NERC Functional Model, which is available on the NERC web site.
Unofficial Nomination Form | November-December, 2021
Project 2020-02 Transmission-connected Dynamic Resources
4
Standards Announcement
Project 2020-02 Transmission-connected Dynamic Reactive
Resources
Supplemental Nomination Period Open through December 20, 2021
Now Available
Nominations are being sought for additional Standard Authorization Request (SAR) drafting team
members through 8 p.m. Eastern, Monday, December 20, 2021.
Use the electronic form to submit a nomination and contact Wendy Muller with any issues. An unofficial
Word version of the nomination form is posted on the Standard Drafting Team Vacancies page and the
project page.
Background
The potential risk of increasing amounts of reactive power being supplied by nonsynchronous sources
was identified in NERC's 2017 Long-term Reliability Assessment. In response to the concern, the
Planning Committee (PC) assigned the System Analysis and Modeling Subcommittee (SAMS) to study
the issue. The SAMS developed the Applicability of Transmission-Connected Reactive Devices white
paper, which was approved by the PC at its December 2019 meeting. The PC Executive Committee
reviewed the draft SAR from SAMS at its January meeting and subsequently approved the SAR by email
vote ending on February 11, 2020. The SAR was posted for industry comment March 30 – May 13, 2020,
and drafting team member nominations were solicited.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls. The time commitment for this project is
expected to be one face-to-face meetings per quarter (on average two full working days each meeting)
with conference calls scheduled as needed to meet the agreed upon timeline the team sets forth. Faceto-face meetings will be conducted only when CDC health guidelines permit. Team members may also
have side projects, either individually or by sub-group, to present for discussion and review. Lastly, an
important component of the team effort is outreach. Members of the team will be expected to conduct
industry outreach during the development process to support a successful ballot. Previous drafting
team experience is beneficial but not required. See the project page and nomination form for additional
information.
Next Steps
The Standards Committee is expected to appoint supplemental members to the drafting team in
February 2022. Nominees will be notified shortly after they have been appointed.
RELIABILITY | RESILIENCE | SECURITY
For more information on the Standards Development Process, refer to the Standard Processes
Manual.
For more information or assistance, contact Senior Standards Developer, Chris Larson (via email) or at 404446-9708. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from
the "Service" drop-down menu and specify “Project 2020-02 Transmission-connected Dynamic Reactive
Resources observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | November 19, 2021
Project 2020-06 Transmission-connected Dynamic Reactive Resources
2
Agenda Item 4a
Standards Committee
April 20, 2022
Standard Authorization Request (SAR)
Complete and please email this form, with
Complete
and please
email this form, with
attachment(s)
to: sarcomm@nerc.net
attachment(s) to: sarcomm@nerc.net
The North American Electric Reliability Corporation (NERC)
welcomes suggestions to improve the reliability of the bulk
power system through improved Reliability Standards.
SAR Title:
Requested information
Revision of relevant Reliability Standards to include applicability of
transmission-connected dynamic reactive resources
Date Submitted:
February 24, 2020 (Revised on February 3, 2022)
SAR Requester
Hari Singh – Chair, System Analysis & Modeling Subcommittee (SAMS) (Revised by
Project 2020-02 SAR DT)
Organization: Xcel Energy
Telephone:
303-571-7095
Email:
hari.singh@xcelenergy.com
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
Dynamic reactive resources used to provide essential reliability services (ERS) in the BES include
generation resources (rotating machine and inverter-based) as well as transmission connected dynamic
reactive resources (power-electronics based). Existing reliability standards for verifying the capability,
modeling and performance of dynamic reactive resources are only applicable to Facilities comprising
generation resources. Augmenting the applicability of these standards to include (non-generation)
transmission-connected reactive resources – both rotating machine (i.e. synchronous condenser) and
power-electronics based – will enhance the BES reliability by ensuring that the capability, models and
performance is verified and validated for all varieties of dynamic reactive resources utilized in providing
ERS in the BES.
Name:
Requested information
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
Augment the “Applicability – Facilities” and “Applicability-Functional Entities” sections in PRC-024
reliability standard to address (non-generation) transmission-connected dynamic reactive resources –
both rotating machine (i.e. synchronous condenser) and power-electronics (e.g. Flexible AC
Transmission System (FACTS) based. Also modify Requirements (including applicable attachments) as
needed to ensure they continue to address the additional Facilities. As needed, also define new Glossary
Terms for all or some of the transmission-connected dynamic reactive devices noted in the SAMS whitepaper “Transmission Connected Dynamic Reactive Resources – Assessment of Applicability in Reliability
Standards”.
Project Scope (Define the parameters of the proposed project):
Revise the “Applicability – Facilities” section, “Applicability – Functional Entities” section, and
Requirements (including applicable attachments) as needed in PRC-024 reliability standard to
comprehensively address all varieties of transmission-connected dynamic reactive resources that are
utilized in providing ERS in the BES.
The Project 2020-02 Standard Drafting Team will consider defining new terms (Glossary of Terms) and
determine if revisions to PRC-024 are needed. In addition, they will coordinate revisions to other
standards with the appropriate drafting teams MOD-026/027 (Project 2020-06) and PRC-019/MOD-025
(Project 2021-01).
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
The “Applicability – Facilities” and “Applicability-Functional Entities” sections in PRC-024 reliability
standard will be revised to address (non-generation) transmission-connected dynamic reactive
resources based on the recommendations summarized in Table 1 of the SAMS white-paper
“Transmission Connected Dynamic Reactive Resources – Assessment of Applicability in Reliability
Standards”. The white-paper also provides the technical justifications for the recommended revisions
and the associated reliability benefits. Also modify Requirements (including applicable attachments) as
needed to ensure they continue to address the additional Facilities. As needed, also define new
Glossary Terms for all or some of the transmission-connected dynamic reactive devices noted as items
1.a – 1.j in the Additional Considerations section of the SAMS white-paper.
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
Unknown
The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please attach pertinent
information to this form before submittal to NERC.
1
Standard Authorization Request (SAR)
2
Requested information
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
Synchronous condensers, HVDC Links (LCC or VSC), and power-electronics based transmissionconnected reactive resources – also known as FACTS devices, such as Static Var Compensator (SVC),
Static Synchronous Compensator (STATCOM).
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Transmission Owners in addition to the existing Functional Entities
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
“Transmission Connected Dynamic Reactive Resources – Assessment of Applicability in Reliability
Standards” white-paper approved by SAMS members.
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
PRC-019 SAR requested by SPCS and PRC-024 SAR requested by IRPTF
The Project 2020-02 Standard Drafting Team will consider defining new terms (Glossary of Terms) and
determine if revisions to PRC-024 are needed. In addition, they will coordinate revisions to other
standards with the appropriate drafting teams MOD-026/027 (Project 2020-06) and PRC-019/MOD-025
(Project 2021-01).
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
No viable alternatives were found by SAMS.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted to obtain
industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.
2
Standard Authorization Request (SAR)
3
5.
6.
7.
8.
Reliability Principles
Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.
Enter
(yes/no)
Yes
Yes
Yes
Yes
Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
e.g. NPCC
For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC
Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document
Version History
Version
Date
Standard Authorization Request (SAR)
Owner
Change Tracking
4
1
June 3, 2013
1
August 29, 2014
Standards Information Staff
Updated template
2
January 18, 2017
Standards Information Staff
Revised
2
June 28, 2017
Standards Information Staff
Updated template
Standard Authorization Request (SAR)
Revised
5
Agenda Item 4a
Standards Committee
April 20, 2022
Standard Authorization Request (SAR)
Complete and please email this form, with
Complete
and please
email this form, with
attachment(s)
to: sarcomm@nerc.net
attachment(s) to: sarcomm@nerc.net
SAR Title:
Date Submitted:
SAR Requester
The North American Electric Reliability Corporation (NERC)
welcomes suggestions to improve the reliability of the bulk
power system through improved Reliability Standards.
Requested information
Revision of relevant Reliability Standards to include applicability of
transmission-connected dynamic reactive resources
Revise the Applicable Facilities of MOD-025, MOD-026, MOD-027, PRC019 and PRC-024 Standards to comprehensively include all types of
dynamic reactive resources (including static var systems and FACTS) and
DC transmission systems used to provide essential reliability services in
the Bulk Electric System.
February 24, 2020 (Revised on February 3, 2022)
Hari Singh – Chair, System Analysis & Modeling Subcommittee (SAMS) (Revised by
Project 2020-02 SAR DT)
Organization: Xcel Energy
Telephone:
303-571-7095
Email:
hari.singh@xcelenergy.com
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
Dynamic reactive resources used to provide essential reliability services (ERS) in the BES include
generation resources (rotating machine and inverter-based) as well as transmission connected dynamic
reactive resources (power-electronics based). Existing reliability standards for verifying the capability,
modeling and performance of dynamic reactive resources are only applicable to Facilities comprising
generation resources. Augmenting the applicability of these standards to include (non-generation)
transmission-connected reactive resources – both rotating machine (i.e. synchronous condenser) and
Name:
Requested information
power-electronics based – will enhance the BES reliability by ensuring that the capability, models and
performance is verified and validated for all varieties of dynamic reactive resources utilized in providing
ERS in the BES.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
Augment the “Applicability – Facilities” and “Applicability-Functional Entities” sections in MOD-025,
MOD-026, MOD-027, PRC-019 and PRC-024 reliability standards to address (non-generation)
transmission-connected dynamic reactive resources – both rotating machine (i.e. synchronous
condenser) and power-electronics (e.g. Flexible AC Transmission System (FACTS) based. Also modify
Requirements (including applicable attachments) as needed to ensure they continue to address the
additional Facilities. As needed, also define new Glossary Terms for all or some of the transmissionconnected dynamic reactive devices noted in the SAMS white-paper “Transmission Connected Dynamic
Reactive Resources – Assessment of Applicability in Reliability Standards”.
Project Scope (Define the parameters of the proposed project):
Revise the “Applicability – Facilities” section, “Applicability – Functional Entities” section, and
Requirements (including applicable attachments) as needed in MOD-025, MOD-026, MOD-027, PRC-019
and PRC-024 reliability standards to comprehensively address all varieties of transmission-connected
dynamic reactive resources that are utilized in providing ERS in the BES.
The Project 2020-02 Standard Drafting Team will consider defining new terms (Glossary of Terms) and
determine if revisions to PRC-024 are needed. In addition, they will coordinate revisions to other
standards with the appropriate drafting teams MOD-026/027 (Project 2020-06) and PRC-019/MOD-025
(Project 2021-01).
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
The “Applicability – Facilities” and “Applicability-Functional Entities” sections in MOD-025, MOD-026,
MOD-027, PRC-019 and PRC-024 reliability standards will be revised to address (non-generation)
transmission-connected dynamic reactive resources based on the recommendations summarized in
Table 1 of the SAMS white-paper “Transmission Connected Dynamic Reactive Resources – Assessment
of Applicability in Reliability Standards”. The white-paper also provides the technical justifications for
the recommended revisions and the associated reliability benefits. Also modify Requirements (including
applicable attachments) as needed to ensure they continue to address the additional Facilities. As
needed, also define new Glossary Terms for all or some of the transmission-connected dynamic reactive
devices noted as items 1.a – 1.j in the Additional Considerations section of the SAMS white-paper.
The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please attach pertinent
information to this form before submittal to NERC.
1
Standard Authorization Request (SAR)
2
Requested information
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
Unknown
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
Synchronous condensers, HVDC Links (LCC or VSC), and power-electronics based transmissionconnected reactive resources – also known as FACTS devices, such as Static Var Compensator (SVC),
Static Synchronous Compensator (STATCOM).
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Transmission Owners in addition to the existing Functional Entities
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
“Transmission Connected Dynamic Reactive Resources – Assessment of Applicability in Reliability
Standards” white-paper approved by SAMS members.
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
PRC-019 SAR requested by SPCS and PRC-024 SAR requested by IRPTF
The Project 2020-02 Standard Drafting Team will consider defining new terms (Glossary of Terms) and
determine if revisions to PRC-024 are needed. In addition, they will coordinate revisions to other
standards with the appropriate drafting teams MOD-026/027 (Project 2020-06) and PRC-019/MOD-025
(Project 2021-01).
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
No viable alternatives were found by SAMS.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted to obtain
industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.
2
Standard Authorization Request (SAR)
3
3.
4.
5.
6.
7.
8.
Reliability Principles
Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.
Enter
(yes/no)
Yes
Yes
Yes
Yes
Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
e.g. NPCC
For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC
Standard Authorization Request (SAR)
Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document
4
Version History
Version
Date
Owner
Change Tracking
1
June 3, 2013
1
August 29, 2014
Standards Information Staff
Updated template
2
January 18, 2017
Standards Information Staff
Revised
2
June 28, 2017
Standards Information Staff
Updated template
Standard Authorization Request (SAR)
Revised
5
Unofficial Nomination Form
Project 2020-02 Transmission-connected Dynamic Reactive Resources
Generator Ride-through Standard (PRC-024-3 Replacement)
Standard Drafting Team
Do not use this form for submitting nominations. Use the electronic form to submit nominations for
standard drafting team (SDT) members by 8 p.m. Eastern, Thursday, July 14, 2022. This unofficial version
is provided to assist nominees in compiling the information necessary to submit the electronic form.
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Josh Blume (via email), or at 470-755-0346.
Background
The Standard Authorization Request (SAR) presented to the Standards Committee May 18, 2022 is meant
to retire PRC-024-3 and replace it with a performance-based ride-through standard that ensures
generators remain connected to the BPS during system disturbances. Specifically, the SAR focuses on the
generator protection and control systems that can result in the reduction or disconnection of generating
resources during these events. The SAR also ensures protection or controls that fail to ride through
system events are analyzed, addressed with a corrective action plan (if possible), and reported to
necessary entities for situational awareness. From a risk-based perspective, the goal of the standard is to
mitigate the ongoing and systemic performance issues identified across multiple Interconnections and
across many disturbances analyzed by NERC and the Regions. These issues have been identified in
inverter-based resources as well as synchronous generators, with many causes of tripping entirely
unrelated to voltage and frequency protection settings as dictated by the currently effective version of
PRC-024.
Standard affected: PRC-024-3
Previous drafting or review team experience is beneficial, but not required. A brief description of the
desired qualifications, expected commitment, and other pertinent information is included below.
SDT activities include participation in technical conferences, stakeholder communications and outreach
events, periodic drafting team meetings and conference calls. Approximately one face-to-face meeting
per quarter can be expected (on average three full working days each meeting) with conference calls
scheduled as needed to meet the agreed-upon timeline the drafting team sets forth. NERC is seeking
individuals who possess experience with PRC-024 implmentation and protective relay setting background
or Generator Operator and Transmission Owner (owning dynamic reactive resources) experience.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings (held at the Atlanta, GA NERC offices) and conference calls.
RELIABILITY | RESILIENCE | SECURITY
Commented [A1]: The one-pager submitted to the SC states
the nominations are for standard drafting team (not SAR DT)
members. Please confirm which is correct.
Name:
Organization:
Address:
Telephone:
Email:
Please briefly describe your experience and qualifications to serve on the requested SAR Drafting
Team (Bio):
If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
MRO
NPCC
RF
SERC
Texas RE
WECC
NA – Not Applicable
Unofficial Nomination Form for SDT Members | Project 2020-02 Transmission-connected Dynamic Reactive Resources
Generator Ride-Through Standard (PRC-024-3 Replacement) | May-July, 2022
2
Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator
1
Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner
These functions are defined in the NERC Functional Model, which is available on the NERC web site.
Unofficial Nomination Form for SDT Members | Project 2020-02 Transmission-connected Dynamic Reactive Resources
Generator Ride-Through Standard (PRC-024-3 Replacement) | May-July, 2022
3
Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
Name:
Telephone:
Organization:
Email:
Name:
Telephone:
Organization:
Email:
Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
Name:
Telephone:
Title:
Email:
Unofficial Nomination Form for SDT Members | Project 2020-02 Transmission-connected Dynamic Reactive Resources
Generator Ride-Through Standard (PRC-024-3 Replacement) | May-July, 2022
4
Standards Announcement
Project 2020-02 Transmission-connected Dynamic Reactive
Resources Generator Ride-through Standard (PRC-024-3
Replacement)
Drafting Team Nomination Period Open through July 14, 2022
Now Available
Nominations are being sought for standard drafting team members through 8 p.m. Eastern, July 14, 2022.
Use the electronic form to submit a nomination. Contact Wendy Muller regarding issues using the electronic
form. An unofficial Word version of the nomination form is posted on the Standard Drafting Team Vacancies
page and the project page.
Previous drafting or review team experience is beneficial, but not required. A brief description of the desired
qualifications, expected commitment, and other pertinent information is included below.
Standard drafting team activities include participation in technical conferences, stakeholder communications
and outreach events, periodic drafting team meetings and conference calls. Approximately one face-to-face
meeting per quarter can be expected (on average three full working days each meeting) with conference
calls scheduled as needed to meet the agreed-upon timeline the drafting team sets forth. NERC is seeking
individuals who possess experience with PRC-024 implementation and protective relay setting background
or Generator Operator and Transmission Owner (owning dynamic reactive resources) experience.
By submitting a nomination form, you are indicating your willingness and agreement to actively participate
in face-to-face meetings (held at the Atlanta, GA NERC offices) and conference calls.
Next Steps
The Standards Committee is expected to appoint members to the drafting team in August 2022. Nominees
will be notified shortly after they have been appointed.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Josh Blume (via email) or at 404-4462593. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from the
"Service" drop-down menu and specify “Project 2022-02 Transmission-connected Dynamic Reactive
Resources observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
RELIABILITY | RESILIENCE | SECURITY
Standard Authorization Request (SAR)
Complete and submit this form, with attachment(s)
to the NERC Help Desk. Upon entering the Captcha,
please type in your contact information, and attach
the SAR to your ticket. Once submitted, you will
receive a confirmation number which you can use
to track your request.
SAR Title:
Date Submitted:
SAR Requester
The North American Electric Reliability Corporation
(NERC) welcomes suggestions to improve the
reliability of the bulk power system through
improved Reliability Standards.
Requested information
Generator Ride-Through Standard (PRC-024-3 Replacement)
April 28, 2022
Mark Lauby, Senior Vice President and Chief Engineer, NERC
Howard Gugel, Vice President, NERC
John Moura, Director, NERC
Name:
Ryan Quint, Senior Manager, NERC
Rich Bauer, Principal, NERC
Matt Lewis, Manager, NERC
Organization: North American Electric Reliability Corporation
Telephone:
Mark Lauby – 404-446-9723
Email:
mark.lauby@nerc.net
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
(as needed)
Other (Please specify)
Withdraw/retire an Existing Standard
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
The ERO Enterprise has analyzed over 10 disturbances involving widespread loss of solar photovoltaic
(PV) resources and has published multiple disturbance reports highlighting key findings and
recommendations from these analyses. Across all events, a widespread loss of generating resources –
solar PV, wind, synchronous generation, and battery energy storage systems (BESS) – have abnormally
tripped, ceased current injection, or reduced power output with control interactions. Generator ridethrough is a foundational essential reliability service. BPS-connected generating resources remaining
connected during normal and contingency conditions is a critical component of BPS reliability. Ensuring
fault ride-through capability enables dynamic reactive power support, frequency response, and other
RELIABILITY | RESILIENCE | SECURITY
Requested information
services. The unexpected loss of widespread generating assets poses a significant risk to BPS reliability.
The existing PRC-024-3 is an equipment settings standard focused solely on voltage and frequency
protection. However, this standard is serving little to no value for ensuring BPS-connected inverter-based
resources remain connected and supporting the BPS during grid disturbances. Furthermore, NERC has
experienced multiple asset owners during the event analyses who have misconstrued PRC-024-3,
resulting in incorrect or unnecessary protections applied to generating assets that have resulted in
spurious and abnormal tripping events.
The systemic tripping and reductions of inverter-based resources, in addition to notable concurrent
tripping or performance from synchronous generating resources poses a risk to BPS reliability that must
be addressed in a timely manner. This proposed standards project will address this known reliability risk
with a more suitable performance-based standard that ensures generating resource ride-through
performance for expected or planned BPS disturbances rather than focusing solely on a small subset of
protections and controls that can trip generating resources.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
The purpose of this SAR is to retire PRC-024-3 and replace it with a performance-based ride-through
standard that ensures generators remain connected to the BPS during system disturbances. Specifically,
this SAR focuses on the generator protection and control systems that can result in the reduction or
disconnection of generating resources during these events. The SAR also ensures protection or controls
that fail to ride through system events are analyzed, addressed with a corrective action plan (if possible),
and reported to necessary entities for situational awareness. From a risk-based perspective, the goal of
the standard is to mitigate the ongoing and systemic performance issues identified across multiple
Interconnections and across many disturbances analyzed by NERC and the Regions. These issues have
been identified in inverter-based resources as well as synchronous generators, with many causes of
tripping entirely unrelated to voltage and frequency protection settings as dictated by the currently
effective version of PRC-024.
Project Scope (Define the parameters of the proposed project):
The scope of this project includes the following:
• Retire PRC-024-3, and create a new PRC standard or completely overhaul and replace the existing
PRC-024 standard.
• Creates a comprehensive, performance-based ride-through standard with the purpose of ensuring
BES generating resources remain connected and providing essential reliability services during grid
disturbances.
• The scope of protections and controls involved in this ride-through standard shall include all
generator protections and controls that affect the electrical output of the BES generating resource
or plant. To be clear, the project should specify the protections and controls in scope of the ridethrough performance and define the term ride-through, as necessary. This should, at a minimum,
include all generator (synchronous or inverter-based) protections and controls at the individual
Standard Authorization Request (SAR)
2
•
•
Requested information
generators, at the inverters, or within the plant (i.e., plant-level controls and protections or
collector system protections).
The scope of the ride-through standard shall explicitly exclude auxiliary systems and their
protection systems. Abnormal performance or unexpected tripping of these protections do not
pose a systemic BES reliability risk. However, protections and controls directly focused on the
generator and its prime mover (e.g., overspeed, power-load imbalance, overvoltage, phase jump,
overcurrent) or plant-level (e.g., voltage, current, frequency, phase, etc.) have posed notable risks
to BES reliability and should be addressed directly in this standard.
The new standard shall ensure that all unexpected or abnormal tripping or reductions in power
output are reported by the GO to the TOP, BA, and RC.
-Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1 which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g., research paper) to guide development of the Standard or definition):
The following describe the proposed deliverable for this project:
•
The proposed deliverable is a new NERC standard (or significant overhaul and revision of PRC-0243) that includes the following key elements:
A performance-based approach to generator ride-through rather than an equipment settings
standard. The new standard shall include requirements that BES resources shall ride through
grid disturbances and include quantitative measures (see below) on expectations for ridethrough that address all possible causes of tripping and power reductions from BES generating
resources (particularly generator, turbine, inverter, and all plant-level protection and
controls).
A reporting requirement that all trips or reductions in power output are reported by the GO
to the TOP, BA, and RC.
A requirement that abnormal reductions in active power (i.e., tripping from protections or
notable reductions from controls) are analyzed by the GO to develop a corrective action plan,
if possible. Situations where corrective action plans are not able to be developed shall be
reported to the TOP, BA, and RC.
A clear requirement that momentary cessation, or temporary ceasing of current injection
during BPS fault events, is deemed unacceptable performance for BES generating resources.
Inverter-based generating resources employing momentary cessation shall develop a
corrective action to mitigate its use. Legacy facilities prior to the effective date of the standard
should receive an exemption; however, resources with a commercial operation date after the
effective date of the standard (and possibly the PRC-024-3 implementation date) shall be
The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please attach pertinent
information to this form before submittal to NERC.
1
Standard Authorization Request (SAR)
3
Requested information
required to eliminate the use of momentary cessation within “ride through envelopes” (e.g.,
the existing PRC-024 “No Trip Zone”).
The terms ride-through, trip, momentary cessation, and any other relevant terms should be
defined in the NERC Glossary of Terms, if deemed necessary.
A clear requirement that prolonged plant controller interactions that impede the ability of the
resource to dynamically respond to the grid disturbance and preclude the ability to fully
provide essential reliability services are deemed unacceptable and should be addressed by a
corrective action plan.
A requirement that if the TOP, BA, or RC inform the GO of a tripping occurrence, cessation
event, or plant controller interactions that are not reported by the GO, then the GO shall be
responsible for analyzing the facility’s performance during the event, developing a corrective
action plan, and reporting this to the TOP, BA, and RC.
The technical justification regarding the reliability-related need and benefits of this project are described
in extensive detail in multiple NERC disturbance reports. All widespread solar PV loss events analyzed by
the ERO Enterprise have involved extensive tripping and causes of reduction that are largely not address
by PRC-024-3, many of which are unrelated to voltage and frequency tripping entirely. Furthermore, these
multiple events have also involved the loss of synchronous generators for various reasons that should be
considered in the development activities of this proposed project. Key disturbance reports include:
•
NERC 2021 California Disturbances Report (2022)
•
NERC Odessa Disturbance Report (2021)
•
NERC San Fernando Disturbance Report (2020)
•
NERC Palmdale Roost and Angeles Forest Disturbances Report (2019)
•
NERC Canyon 2 Fire Disturbance Report (2018)
•
NERC Blue Cut Fire Disturbance Report (2017)
NERC Reliability Guideline: Improvements to Interconnection Requirements for BPS-Connected InverterBased Resources (2019), developed by the NERC Inverter-Based Resource Performance Working Group
(IRPWG) and endorsed by the NERC Planning Committee, specifically recommends that all Transmission
Owners (TOs) per FAC-001 establish or improve interconnection requirements by including quantitative
requirements related to ride-through performance. Below is an excerpt from this guideline:
Quantitative requirements ensure that resources behave in a manner that supports BPS reliability and also
assists the GOs and inverter manufacturers in specifying equipment to meet these requirements. These
requirements may involve a performance envelope (FRT capability) that must be met by the resource,
typically derived based on interconnection studies, grid codes, Reliability Standards, and other factors
deemed necessary by the TO. Having these requirements ensures that the resources, particularly inverter-
Standard Authorization Request (SAR)
4
Requested information
based resources, are unlikely to operate in a mode that has not been previously studied. Examples of these
quantitative performance requirements include, but are not limited to, the following:
• Pre- and post-fault short-circuit strength (equivalent impedance or short-circuit ratio (SCR)-based
metric)) for worst case contingency conditions
• RMS low voltage ride-through and high voltage ride-through
• Instantaneous transient overvoltage
• Instantaneous change in phase angle
• Low frequency ride-through and high frequency ride-through
• No use of momentary cessation, by exception only
These deliverables developed by the ERO Enterprise and its stakeholder groups serve as a strong
technical basis for ensuring resources successfully ride through grid disturbances and support the BPS
by providing essential reliability services moving forward.
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
Incremental costs are expected for GOs that currently do not analyze the performance of their generating
assets following grid disturbances, which has been shown during the NERC disturbance analyses to be a
systemic reliability issue for solar PV resources in particular. GOs will need to assess their ride-through
capabilities more comprehensively than in the past, which may have some associated costs. Minimal costs
are associated with reporting of tripping occurrences. Facilities with abnormal or unexpected trips that
can be mitigated with corrective actions will have some incremental costs; however, these improvements
will help ensure adequate levels of reliability of the BES. Otherwise, cost impacts for this project are
expected to be minimal.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g., Dispersed Generation Resources):
BES generating resources.
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g., Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Generator Owners, Generator Operators, Reliability Coordinators, Transmission Operators, Transmission
Owners, Transmission Planners, Planning Coordinators
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted to obtain
industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.
2
Standard Authorization Request (SAR)
5
Requested information
This SAR is an outcome of ongoing analyses conducted by the ERO Enterprise regarding widespread
inverter-based resource tripping events. Furthermore, the NERC IRPWG has developed comprehensive
recommendations for improved performance of inverter-based resources, including the recommendation
to develop comprehensive ride-through requirements.
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so, which standard(s) or project number(s)?
No.
Are there alternatives (e.g., guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
NERC has evaluated industry progress toward adopting the recommendations outlined in NERC
guidelines, white papers, its prior Alerts, and other industry efforts. NERC believes that a nationwide
standard for consistent requirements for generating resource ride-through is necessary to immediately
address generating resource ride-through during grid disturbances moving forward.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
Standard Authorization Request (SAR)
Enter
(yes/no)
Yes
6
Market Interface Principles
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.
Yes
Yes
Yes
Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
None
None
For Use by NERC Only
SAR Status Tracking (Check off as appropriate).
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC
Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document
Version History
Version
Date
Owner
Change Tracking
1
June 3, 2013
1
August 29, 2014
Standards Information Staff
Updated template
2
January 18, 2017
Standards Information Staff
Revised
2
June 28, 2017
Standards Information Staff
Updated template
3
February 22, 2019
Standards Information Staff
Added instructions to submit via Help
Desk
4
February 25, 2020
Standards Information Staff
Updated template footer
Standard Authorization Request (SAR)
Revised
7
Unofficial Comment Form
Project 2020-02 Transmission-connected Dynamic Reactive Resources
Generator Ride-through Standard (PRC-024-3 Replacement)
Standard Authorization Request
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on the Generator Ride-through Standard (PRC-024-3 Replacement) Standard
Authorization Request (SAR). Comments must be submitted by 8 p.m. Eastern, Thursday, July 14, 2022.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Standards
Developer, Josh Blume (via email), or at 470-755-0346.
Background Information
The Standard Authorization Request (SAR) presented to the Standards Committee May 18, 2022 is meant
to retire PRC-024-3 and replace it with a performance-based ride-through standard that ensures
generators remain connected to the BPS during system disturbances. Specifically, the SAR focuses on the
generator protection and control systems that can result in the reduction or disconnection of generating
resources during these events. The SAR also ensures protection or controls that fail to ride through
system events are analyzed, addressed with a corrective action plan (if possible), and reported to
necessary entities for situational awareness. From a risk-based perspective, the goal of the standard is to
mitigate the ongoing and systemic performance issues identified across multiple Interconnections and
across many disturbances analyzed by NERC and the Regions. These issues have been identified in
inverter-based resources as well as synchronous generators, with many causes of tripping entirely
unrelated to voltage and frequency protection settings as dictated by the currently effective version of
PRC-024.
Standard affected: PRC-024-3
Questions
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree
but have comments or suggestions for the project scope please provide your recommendation and
explanation.
Yes
No
Comments:
2. Provide any additional comments for the standard drafting team to consider, if desired.
Comments:
RELIABILITY | RESILIENCE | SECURITY
Standards Announcement
Project 2020-02 Transmission-connected Dynamic Reactive
Resources Generator Ride-through Standard (PRC-024-3
Replacement) | Standard Authorization Request
Formal Comment Period Open through July 14, 2022
Now Available
A 45-day formal comment period for the Generator Ride-through Standard (PRC-024-3 Replacement)
Standard Authorization Request is open through 8 p.m. Eastern, Thursday, July 14, 2022.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The drafting team will review all responses received during the comment period and determine the
next steps of the project.
For more information or assistance, contact Standards Developer, Josh Blume (via email) or at 404-4462593. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from the
"Service" drop-down menu and specify “Project 2022-02 Transmission-connected Dynamic Reactive
Resources observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
RELIABILITY | RESILIENCE | SECURITY
Comment Report
Project Name:
2020-02 Transmission-connected Dynamic Reactive Resources | Generator Ride-through (PRC-024-3
Replacement) | Standard Authorization Request
Comment Period Start Date:
5/31/2022
Comment Period End Date:
7/14/2022
Associated Ballots:
There were 40 sets of responses, including comments from approximately 103 different people from approximately 72 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
Questions
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree but have comments or suggestions for
the project scope, please provide your recommendation and explanation.
2. Provide any additional comments for the drafting team to consider, if desired.
Organization
Name
Name
DTE Energy - Adrian
Detroit Edison Raducea
Company
WEC Energy
Group, Inc.
Christine
Kane
Segment(s)
Region
3,5
Group
Name
Group Member
Name
DTE Energy Karie Barczak
- DTE
Electric
3,4,5,6
Duke Energy
Kim Thomas
1,3,4,5,6
RF
Adrian Raducea DTE Energy - 5
Detroit Edison
RF
patricia ireland
DTE Energy
4
RF
WEC Energy
Group
3
RF
WEC Energy
Group, Inc.
4
RF
Clarice Zellmer WEC Energy
Group, Inc.
5
RF
David Boeshaar WEC Energy
Group, Inc.
6
RF
WEC Energy Christine Kane
Group
1,3,5,6
WECC
Tacoma
Power
Group
Member
Region
DTE Energy - 3
Detroit Edison
Company
Matthew
Beilfuss
Tacoma
Jennie Wike
Public Utilities
(Tacoma,
WA)
Group
Group
Member
Member
Organization Segment(s)
Jennie Wike
Tacoma
1,3,4,5,6
Public Utilities
WECC
John Merrell
Tacoma
1
Public Utilities
(Tacoma,
WA)
WECC
Marc Donaldson Tacoma
3
Public Utilities
(Tacoma,
WA)
WECC
Hien Ho
Tacoma
4
Public Utilities
(Tacoma,
WA)
WECC
Terry Gifford
Tacoma
6
Public Utilities
(Tacoma,
WA)
WECC
Ozan Ferrin
Tacoma
5
Public Utilities
(Tacoma,
WA)
WECC
FRCC,RF,SERC,Texas Duke Energy Laura Lee
Duke Energy
RE
Dale Goodwine Duke Energy
Greg Cecil
Duke Energy
1
SERC
5
SERC
6
RF
Florida
Municipal
Power
Agency
FirstEnergy FirstEnergy
Corporation
Pacific Gas
and Electric
Company
LaKenya
VanNorman
Mark Garza
Michael
Johnson
Southern
Pamela
Company Hunter
Southern
Company
Services, Inc.
3,4,5,6
SERC
1,3,4,5,6
1,3,5
1,3,5,6
Florida
Municipal
Power
Agency
(FMPA)
FE Voter
WECC
SERC
PG&E All
Segments
Southern
Company
Chris Gowder
Florida
Municipal
Power
Agency
5
SERC
Dan O'Hagan
Florida
Municipal
Power
Agency
4
SERC
Carl Turner
Florida
Municipal
Power
Agency
3
SERC
Jade Bulitta
Florida
Municipal
Power
Agency
6
SERC
Julie Severino
FirstEnergy FirstEnergy
Corporation
1
RF
Aaron
Ghodooshim
FirstEnergy FirstEnergy
Corporation
3
RF
Robert Loy
FirstEnergy FirstEnergy
Solutions
5
RF
Tricia Bynum
FirstEnergy FirstEnergy
Corporation
6
RF
Mark Garza
FirstEnergyFirstEnergy
4
RF
Marco Rios
Pacific Gas
and Electric
Company
1
WECC
Sandra Ellis
Pacific Gas
and Electric
Company
3
WECC
James Mearns
Pacific Gas
and Electric
Company
5
WECC
Matt Carden
Southern
1
Company Southern
Company
Services, Inc.
SERC
Joel Dembowski Southern
Company Alabama
3
SERC
Power
Company
Northeast
Power
Coordinating
Council
Ruida Shu
1,2,3,4,5,6,7,8,9,10 NPCC
NPCC
Regional
Standards
Committee
Ron Carlsen
Southern
Company Southern
Company
Generation
6
SERC
Jim Howell
Southern
5
Company Southern
Company
Services, Inc.
- Gen
SERC
Gerry Dunbar
Northeast
Power
Coordinating
Council
10
NPCC
Randy
MacDonald
New
Brunswick
Power
2
NPCC
Glen Smith
Entergy
Services
4
NPCC
Alan Adamson
New York
State
Reliability
Council
7
NPCC
David Burke
Orange &
Rockland
Utilities
3
NPCC
Harish Vijay
Kumar
IESO
2
NPCC
David Kiguel
Independent
7
NPCC
Nick Kowalczyk Orange and
Rockland
1
NPCC
Joel Charlebois AESI Acumen
Engineered
Solutions
International
Inc.
5
NPCC
Mike Cooke
Ontario Power 4
Generation,
Inc.
NPCC
Salvatore
Spagnolo
New York
Power
Authority
NPCC
1
Shivaz Chopra
New York
Power
Authority
5
NPCC
Deidre Altobell
Con Ed 4
Consolidated
Edison
NPCC
Dermot Smyth
Con Ed 1
Consolidated
Edison Co. of
New York
NPCC
Peter Yost
Con Ed 3
Consolidated
Edison Co. of
New York
NPCC
Cristhian Godoy Con Ed 6
Consolidated
Edison Co. of
New York
NPCC
Nurul Abser
NB Power
Corporation
1
NPCC
Randy
MacDonald
NB Power
Corporation
2
NPCC
Michael
Ridolfino
Central
Hudson Gas
and Electric
1
NPCC
Vijay Puran
NYSPS
6
NPCC
ALAN
ADAMSON
New York
State
Reliability
Council
10
NPCC
Sean Cavote
PSEG - Public 1
Service
Electric and
Gas Co.
NPCC
Brian Robinson Utility
Services
5
NPCC
Quintin Lee
Eversource
Energy
1
NPCC
John Pearson
ISONE
2
NPCC
Nicolas Turcotte Hydro1
Qu?bec
TransEnergie
NPCC
Chantal Mazza
NPCC
HydroQuebec
2
Western
Electricity
Coordinating
Council
Steven
Rueckert
10
Michele
Tondalo
United
Illuminating
Co.
1
NPCC
Paul
Malozewski
Hydro One
3
Networks, Inc.
NPCC
WECC Entity Steve Rueckert WECC
Monitoring
Phil O'Donnell WECC
10
WECC
10
WECC
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree but have comments or suggestions for
the project scope, please provide your recommendation and explanation.
Brian Lindsey - Entergy - 1,3,6
Answer
No
Document Name
Comment
Should add new R5 to PRC-024-3: "Generator Owners shall analyze and have a corrective action plan (if possible), and report to necessary entities any
failure to ride through a system event."
Likes
0
Dislikes
0
Response
Adrian Raducea - DTE Energy - Detroit Edison Company - 3,5, Group Name DTE Energy - DTE Electric
Answer
No
Document Name
Comment
The proposed standard should cover “tripping” and not include “reductions”, as the specified level can be subjective.
Likes
0
Dislikes
0
Response
Kimberly Turco - Constellation - 5,6
Answer
No
Document Name
Comment
Constellation does not agree with the proposed scope as the scope is far reaching into multiple standards not just PRC-024-3 and the impact to those
standards is not clearly defined.
Kimberly Turco on behalf of Constellation Segements 5 and 6
Likes
0
Dislikes
0
Response
Alison Mackellar - Constellation - 5,6
Answer
No
Document Name
Comment
Constellation does not agree with the proposed scope as the scope is far reaching into multiple standards not just PRC-024-3 and the impact to those
standards is not clearly defined.
Kimberly Turco on behalf of Constellation Segments 5 and 6
Likes
0
Dislikes
0
Response
Thomas Foltz - AEP - 3,5,6
Answer
No
Document Name
Comment
AEP agrees with the concerns related to IBRs and the performance issues that have been previously noted but we do not agree that PRC-024 should
be revised or replaced with ride-through obligations added for synchronous generation. AEP recommends that PRC-024 be retained as it currently is,
and recommends creation of a new standard containing ride-through obligations for IBRs only. AEP does not see a reliability justification for developing
ride-through obligations for synchronous generation and advises against any efforts to do so since, as also noted by EEI, such units have been seen to
perform well in the various cited events.
The following comments are offered in the event that the SDT develops obligations for both synchronous generation and IBRs (contrary to our
recommendation above).
The fourth bullet of the SAR’s Project Scope states “protections and controls directly focused on the generator and its prime mover (e.g., overspeed,
power-load imbalance, overvoltage, phase jump, overcurrent) or plant-level (e.g., voltage, current, frequency, phase, etc.) have posed notable risks to
BES reliability.” AEP does not agree with the proposed inclusion of overspeed and power-load imbalance, as both must be present to protect against
equipment damage. Even if their presence could at times pose a reliability risk to the system, these protective functions need to be retained for the
unit’s own protection and continuing availability. AEP recommends removing overspeed and power-load imbalance from the SAR.
Requirement R3 in the current version of PRC-024 requires the Generator Owner to “document each known regulatory or equipment limitation that
prevents an applicable generating unit with generator frequency or voltage protective relays from meeting the relay setting criteria in Requirements R1
or R2 including (but not limited to) study results, experience from an actual event, or manufacturer’s advice.” Care should be taken to retain this
provision in any new or revised standard.
Likes
0
Dislikes
0
Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
No
Document Name
Comment
The scope states generator overcurrent and plant-level current should be addressed in this standard. Overcurrent is addressed by PRC-025. It does
not seem right to also include current in this standard. Other than the inclusion of overcurrent, the scope seems reasonable.
Likes
0
Dislikes
0
Response
Kendra Buesgens - MRO - 1,2,3,4,5,6 - MRO
Answer
No
Document Name
Comment
The MRO NSRF in general agrees with both the concept and scope of this SAR. However, the MRO NSRF is voting no due to the following concerns:
1. A reporting requirement that all trips or reductions in power output are reported by the GO to the TOP, BA, and RC.
The MRO NSRF disagrees with this deliverable. The Reliability Coordinator (RC), Balancing Authority (BA) and Transmission Operator (TOP) should
be responsible for determining the magnitude threshold and duration-of-time threshold for the Generator Owner (GO)/ Generator Operator (GOP) to
report trips or reductions in power output. This will ensure that the RC, BA & TOP are not burdened by notifications for trips/reductions that do not affect
the Bulk Electrical System (BES) and ultimately take the RC’s, BA’s & TOP’s attention away from matters of higher priority for ensuring the reliability of
the BES. In addition, it is the NSRF belief that the RC, BA & TOP currently has the ability request information about trips or reductions in power output
from the GO/GOP under the regulatory framework of NERC Reliability Standard IRO-010-4 Reliability Coordinator Data Specification and Collection &
NERC Reliability Standard TOP-003-4 - Operational Reliability Data.
Further, reductions in power will occur for a wide variety of reasons such as clouds passing over or the setting of the sun at a solar generation facility, a
drop in wind speed at a wind generation facility, wet coal, changes in condenser circulating water temperature or discharge water temperature limits at a
thermal plant, starting an additional large fan or pump, inlet air temperature changes to gas turbines, reduced water flow at a hydro plant – none of
these causes of power reduction would have any relation to PRC requirements and no additional reporting other than that required by existing NERC
Standard IRO-010 & TOP-003 requirements should be necessary. The MRO NSRF believes this deliverable should say “A reporting requirement that
all trips or reductions in power output in response to grid disturbances are reported by the GO as required by the applicable TOP, BA, and RC.”
2. A requirement that abnormal reductions in active power (i.e., tripping from protections or notable reductions from controls) are analyzed by the GO to
develop a corrective action plan, if possible. Situations where corrective action plans are not able to be developed shall be reported to the TOP, BA, and
RC.
The MRO NSRF disagrees with this deliverable. The MRO NSRF believes that the ‘trip’ portion of this deliverable is already an enforceable
requirement under the regulatory framework of NERC Reliability Standard PRC-004-6 - Protection System Misoperation Identification and Correction.
As written, ‘notable reductions from controls’, lacks the detail required to provide a standard drafting team (SDT) with proper direction to develop a
requirement(s). As this Standard Authorization Request (SAR) relates to dynamic ride-through performance of generators the MRO NSRF would
request that the SAR SDT add an example magnitude threshold and duration-of-time threshold for ‘notable reductions from controls’. Adding the
additional information will prevent any developed requirement(s) from overreaching beyond the intention of this SAR.
3. A clear requirement that momentary cessation, or temporary ceasing of current injection during BPS fault events, is deemed unacceptable
performance for BES generating resources. Inverter-based generating resources employing momentary cessation shall develop a corrective action to
mitigate its use. Legacy facilities prior to the effective date of the standard should receive an exemption; however, resources with a commercial
operation date after the effective date of the standard (and possibly the PRC-024-3 implementation date) shall be required to eliminate the use of
momentary cessation within “ride through envelopes” (e.g., the existing PRC-024 “No Trip Zone”).
The implementation date for NERC Reliability Standard PRC-024-3 — Frequency and Voltage Protection Settings for Generating Resources (NERC
PRC-024-3) is October 01, 2022. As stated by the SAR requestors:
• “The existing PRC-024-3 is an equipment settings standard focused solely on voltage and frequency protection. However, this standard is serving
little to no value for ensuring BPS-connected inverter-based resources remain connected and supporting the BPS during grid disturbances.”
• “The purpose of this SAR is to retire PRC-024-3 and replace it with a performance-based ride-through standard that ensures generators remain
connected to the BPS during system disturbances.”
• “Retire PRC-024-3, and create a new PRC standard or completely overhaul and replace the existing PRC-024 standard.”
Based on these statements the MRO NSRF believes all generators with a commercial operation date prior to the effective date of requirements to be
developed based on this SAR should not have to comply or retrofit. It is clear that any requirements developed based on this SAR will be different from
the requirements of NERC PRC-024-3 and therefore the generators that need to comply should be adjusted accordingly.
4. The performance-based standard should include documented equipment limitation exemptions similar to NERC PRC-024-3 R3 and these should
apply to all generator types rather than just carving out an exemption for the application of momentary cessation on legacy inverter-based resources
(IBR) existing prior to the effective date of the standard (and possible the PRC-024-3 implementation date). For example, if an existing turbine has
frequency limitations that do not meet the requirements of the new ride-through standard, no corrective action plan should be necessary should the
turbine trip in response to a frequency excursion outside of its capability. There appears to be nothing in the SAR that addresses limitations of existing
equipment other than that of legacy IBRs applying momentary cessation.
5. The MRO NSRF believes that there is little justification for retiring NERC PRC-024-3 for synchronous generators and that any new standard should
be focused on IBR performance issues. If the scope is to “create a comprehensive, performance-based ride-through standard with the purpose of
ensuring BES generating resources remain connected and providing essential reliability services during grid disturbances”, why would only PRC-024-3
be considered for retirement rather than to include the retirement of other relay setting standards such as PRC-025-2, which has the purpose to assure
that load responsive relays are set to prevent unnecessary tripping during system disturbances, and/or the elimination of GO applicability in PRC-026-1,
which has the purpose to ensure that load-responsive relays are expected to not trip in response to stable power swings during non-Fault
conditions? The MRO NSRF believes that if a truly comprehensive performance-based ride-through standard is created, then the regulatory burden of
other relay setting standards pertaining to how generator protection responds to grid disturbances should be eliminated by retiring PRC-025-2 and
eliminating the applicability of PRC-026-1 to Generator Owners. It seems that a comprehensive generator ride-through standard would apply to not only
24, 27, and 59 functions (PRC-024-3) but would also include trips of generating resources in response to 21, 50, 51, 51VR, 51VC, 67 (PRC-025-2)
and/or 21, 40, ,50, 51, 78 (PRC-026-1) function operations in response to grid disturbances.
Further, and accounting for the aforementioned comments, the MRO NSRF recommends the drafting team consider whether retiring PRC-024-3 and
replacing it with a performance-based ride-through standard may change, for example, the Generator no trip zones settings. This action would
potentially affect PRC-006, and the SAR should open its scope to contemplate potential changes to that standard, and any other affected standard, if
needed. This comment is to ensure the drafting team crafts a SAR with the necessary scoping parameters to make changes to associated standards as
needed.
6. A clear requirement that prolonged plant controller interactions that impede the ability of the resource to dynamically respond to the grid disturbance
and preclude the ability to fully provide essential reliability services are deemed unacceptable and should be addressed by a corrective action plan.
This requirement seems to be focused on eliminating some of the undesirable IBR performance issues, but the wording of this deliverable could be
interpreted to apply to integrated plant or unit protection schemes that may indeed “impede the ability of the resource to dynamically respond to grid
disturbances” but are designed to protect the boiler or nuclear reactor from pressure or level excursions, steam turbines from overspeed, operation at
resonant frequencies or moisture intrusion, etc. GOs should be able to protect their equipment from catastrophic damage without having to implement a
corrective action plan should these protection or control features impede dynamic response to grid disturbances.
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Southern Indiana Gas and Electric Co., 3,5,6, Todd Anna
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Response
Israel Perez - Salt River Project - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
We do not agree with the proposed scope described in the SAR, as more clarification of expectations and deliverables are needed. The proposed
scope is not clear if the changes would require the installation of additional protection devices to our generators or switchyards and if additional
DCS/computer points need to be monitored. Would the changes require third-party generator studies and at what frequency? We are concerned that
these changes, which are still unclear, will require additional preventative tasks and specialized personnel necessary to perform these tasks. If the
disturbance in the grid is large enough, wouldn’t it be better for our generators to disconnect and/or trip to prevent equipment damage? A unit/generator
restart would have a faster turnover and would be more efficient than having a damaged generator that motored because we couldn’t disconnect it from
the large disturbance of the grid.
In addition, it seems that we must wait until “performance” metrics are outlined and how metrics meet baseline criteria. The reference documents
outline some of the criteria for measurement and submittal methods but not the full metric. The “ride through” criteria is mentioned, as a “no trip zone” in
the attached document but not a clear definition of achieving that target. The process for defining the performance characteristics of a generation
resources is not specified other than a system strength specification which we believe would require a separate criterion for each BES bus depending
on the generation in the vicinity. It would be difficult to define and enforce and even more difficult to monitor.
The events in southern California revealed that generation went into a current cessation mode during a frequency/voltage excursion and PRC-024-3
covers this issue. The event would expand the scope from generation ride through to include any event where generation was reduced or removed from
service for say auxiliary systems being removed from service. This subject might fall under PRC-004. If the tripping or reduction in generation is entirely
unrelated to frequency or voltage, then we should have a separate standard that addresses this issue.
The deliverable noted is a requirement for reporting all trips and abnormal reductions in active power. In our experience most “abnormal” reductions are
prime mover related. If it was intended to only require reporting an abnormal reduction or trip during a system disturbance only, it is not clear that this
deliverable is being met. We agree that generation outages due to frequency and voltage excursions should be tracked but the scope of the SAR goes
well beyond that point. Why take a perfectly fine standard that addresses a known system issue and expand the scope into something that is not clearly
defined. Consider expanding the scope of PRC-004 instead and include operations that affect the output of a BES Generation source and leave PRC024-3 as a frequency and voltage ride through standard.
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Joe Gatten - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
No
Document Name
Comment
Xcel Energy supports the comments offered by EEI, NAGF, and MRO NSRF.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
No
Document Name
Comment
Southern Company does not agree due to the following concerns:
1. A reporting requirement that all trips or reductions in power output are reported by the GO to the TOP, BA, and RC.
Southern Company disagrees with this deliverable. The RC, BA, and TOP should be responsible parties for determining the magnitude threshold
and duration-of-time thresholds GO/GOP to report trips or reductions in power output. This will ensure that the RC, BA & TOP are not burdened
by notifications for trips/reductions that do not affect the Bulk Electrical System (BES) and ultimately take their attention away from matters of higher
priority for ensuring the reliability of the BES. In addition, it is the belief of Southern Company that the RC, BA & TOP already has the ability request
information about trips or reductions in power output from the GO/GOP under the regulatory framework of NERC Reliability Standard IRO010-4 and TOP-003-4.
2. A requirement that abnormal reductions in active power (i.e., tripping from protections or notable reductions from controls) are analyzed by the GO to
develop a corrective action plan, if possible. Situations where corrective action plans are not able to be developed shall be reported to the TOP, BA, and
RC.
Southern Company disagrees with this deliverable. Southern Company believes that the ‘trip’ portion of this deliverable is already an
enforceable requirement under the regulatory framework of NERC Reliability Standard PRC-004-6.
As written, ‘notable reductions from controls’, lacks the detail required to provide a standard drafting team (SDT) with proper direction to develop a
requirement(s). As this Standard Authorization Request (SAR) relates to dynamic ride-through performance of generators Southern Company
requests that the SAR SDT add an example magnitude threshold and duration-of-time threshold for ‘notable reductions from
controls’. Adding the additional information will prevent any developed requirement(s) from overreaching beyond the intention of this SAR. The
communication of unit derates, where necessary for system operation, is likely already being communicated where specified by the RC/BA/TOP data
specifications of IRO-010 and TOP-003.
3. A clear requirement that momentary cessation, or temporary ceasing of current injection during BPS fault events, is deemed unacceptable
performance for BES generating resources. Inverter-based generating resources employing momentary cessation shall develop a corrective action to
mitigate its use. Legacy facilities prior to the effective date of the standard should receive an exemption; however, resources with a commercial
operation date after the effective date of the standard (and possibly the PRC-024-3 implementation date) shall be required to eliminate the use of
momentary cessation within “ride through envelopes” (e.g., the existing PRC-024 “No Trip Zone”).
The opening statement is contrary to real world expectations that the generation resource is not allowed to protect its equipment for BES system
events. If this is the expectation, then the BES system should not be allowed to have fault events in the first place.
The implementation date for NERC Reliability Standard PRC-024-3 — Frequency and Voltage Protection Settings for Generating Resources (NERC
PRC-024-3) is October 01, 2022. As stated by the SAR requestors:
• “The existing PRC-024-3 is an equipment settings standard focused solely on voltage and frequency protection. However, this standard is serving
little to no value for ensuring BPS-connected inverter-based resources remain connected and supporting the BPS during grid disturbances.”
• “The purpose of this SAR is to retire PRC-024-3 and replace it with a performance-based ride-through standard that ensures generators remain
connected to the BPS during system disturbances.”
• “Retire PRC-024-3, and create a new PRC standard or completely overhaul and replace the existing PRC-024 standard.”
Based on these statements Southern Company believes all generators with a commercial operation date prior to the effective date of requirements to
be developed based on this SAR should not have to comply or retrofit. It is clear that any requirements developed based on this SAR will be different
from the requirements of NERC PRC-024-3 and therefore the generators that need to comply should be adjusted accordingly.
4. The premise that there have been notable concurrent tripping or performance from synchronous generating resources due to frequency and voltage
protection settings being too sensitive is flawed. There have not been increasing trends of synchronous machine protection system misoperations to
justify that premise. The application of a ride through standard for synchronous machine generating plants was fully investigated during the original
drafting effort of PRC-024 between 2008-2014. The conclusion of the standard drafting team, after multiple drafts, extended comment and
consideration of comments from industry, direct consultation with FERC by standard drafting team members resulted in the realization that the standard
could go no further than to specify a regions for restricting the tripping of those generators by protective relays for voltage-time and frequency-time
areas that would cause the units to not be tripped for the majority of system events where the voltage or frequency was not normal. Further attempts to
apply a ride through requirement should be abandoned for synchronous machines to avoid wasting everyone’s time by having to restate why it is not
feasible for that generation type.
5. Further, there are limited modifications that can be made to the existing equipment to achieve the goal of 100% ride-thru ability to any grid
disturbance. Simply passing a regulation specifying it must be done does not change the ability of the equipment to do so. The replacement of
existing inverters is not feasible – the power ratings and voltage/current specifications of existing installed invertors do not match the inverters offered
today. The collection system of a PV plant cannot be reconfigured economically once it is in place.
6. Any additional ride through requirements should only be applicable to equipment placed in service after changes are made to this standard which
may require additional ride-thru capabilities for IBR plants. We suggest that the transmission interconnection agreements be the proper method to
assure that newly connected IBR facilities are built to maximize their ride through capability.
7. The lack of a specific grid disturbance for which generating resources are to be required to ride-through is problematic. If specific disturbance
characteristics are specified, the generating community might have a fighting chance to design systems to achieve the goals. The application of global
“you must ride through all grid disturbance” requirements to existing equipment not designed to do so is ludicrous.
8. The SAR states that auxiliary systems and their protection systems are explicitly excluded. The sub-systems of a conventional synchronous
machine generating station are essential for the normal plant operation. Without many of those sub-systems, the main generator cannot run. The
sub-system may be essential to the mechanical operation of the turbine too. Any system disturbance that causes any of those sub-systems to not be
available will immediately affect the turbine/generator ability to run. The controls of the generator and turbine are interlaced and interlinked with the subsystems. They cannot be removed from affecting the entire unit operation. In effect, they cannot be separated from the generator and the unit
availability. During system disturbances where sustained grid low voltage occurs, those sub-systems may or may not experience trouble. During the
initial PRC-024 development, the Luminant company reported that some low voltage contactors dropped out for low voltage conditions, and others did
not. In subsequent grid low voltage disturbances, it was observed that different sets of contactors dropped out. The indefinite response of
magnetically sealed in contactor behavior for low voltage conditions was one of the problems with any meaningful successful application of ride-through
standards to those types of facilities.
9. The SAR indicates that the desire of the standard revision is to address all possible causes of tripping and power reductions.
POSSIBLE CAUSES is indefinite and unachievable. No failsafe system can be built to withstand all possible causes.
Addressing ALL
10. With regard to the SAR question on alternatives, for which the SAR drafters included this text:
NERC has evaluated industry progress toward adopting the recommendations outlined in NERC guidelines, white papers, its prior Alerts, and other
industry efforts. NERC believes that a nationwide standard for consistent requirements for generating resource ride-through is necessary to immediately
address generating resource ride-through during grid disturbances moving forward.
Southern Company has implemented all possible inverter setting changes included in the two NERC alerts on the Loss of Solar Resources. We note
that several of our units have continued to react to major grid disturbances by ceasing to generate. The communication of the adjustment of the
settings, and the limitations to adjustments we have discerned, have been communicated to the parties included in the NERC alert
recommendations. It is for this reason we implore the SDT to look forward rather than backward with change requirements. The electric grid is not in
immediate imminent danger due to this current condition. The requirement of maximizing IBR equipment connectivity and grid disturbance resolution
support is best addressed through the transmission interconnection requirements rather than through reliability standards.
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Anna Todd - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer
No
Document Name
Comment
Southern Indiana Gas and Electric Company d/b/a CenterPoint Energy Indiana South (SIGE) would like to thank the SAR Standards Drafting Team for
the opportunity to provide feedback on Project 2020-02 “Transmission-connected Dynamic Reactive Resources Generator Ride-through Standard
(PRC-024-3 Replacement).” SIGE does not agree with the proposed scope as described in the SAR and would request additional clarifications before
agreeing to the proposed project.
Project 2020-02 describes a proposed deliverable of “A reporting requirement that all trips or reductions in power output are reported by the GO to the
TOP, BA, and RC.” This phrasing should be specific to Protection Systems, as it is unclear at what point an entity is required to report. It should be
defined whether reporting is required every time a unit trips due to any circumstance, or to which point reporting is required. For example, SIGE does
not agree that reporting a trip due to weather should fall under the scope of this standard.
The use of phrasing within the existing PRC-024 standard, such as “No Trip Zone,” are beneficial because they are specific to Voltage and Frequency.
These terms are needed to help regulate the standard.
SIGE does agree with the proposed deliverable of “a clear requirement that momentary cessation, or temporary ceasing of current injection during BPS
fault events, is deemed unacceptable performance for BES generating resources.”
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Michael Johnson - Pacific Gas and Electric Company - 1,3,5 - WECC, Group Name PG&E All Segments
Answer
No
Document Name
Comment
PG&E agrees with the comments provided by EEI that there have been performance issues with Solar PV Inverter Based Resources (IBRs) that need
to be addressed, but as indicated by EEI, PG&E does not agree the replacement of PRC-024-3 is required to address those issues.
The current PRC-024-2 Requirements have worked well for synchronous generators, and it is expected that PRC-024-3 will improve the performance of
those generators in maintaining the reliable operation of the Bulk Electric System (BES). As noted by EEI, there were losses of synchronous generator
in some of the six disturbances noted in the SAR, but none of those appeared to be unexpected, unusual, or a result of non-compliance with the current
PRC-024 Standard.
PG&E personnel responsible for PRC-024 believe trying to add an entire set of additional Requirements for IBRs on top of the current PRC-024
Requirements, or changing the Standard to be performance based for all generators would be extremely complex to implement and maintain, and would
not improve the reliability for synchronous generators. PG&E recommends IBR performance should be covered under a new Standard specifically
developed for the unique characteristics of IBRs.
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Joseph Amato - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer
No
Document Name
Comment
MidAmerican supports MRO NSRF and EEI comments.
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Alan Kloster - Evergy - 1,3,5,6 - MRO
Answer
No
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #1.
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Christine Kane - WEC Energy Group, Inc. - 3,4,5,6, Group Name WEC Energy Group
Answer
No
Document Name
Comment
WEC Energy Group is voting no due to the following concerns:
•
•
•
•
•
Likes
“Purpose or Goal” section calls for complete replacement of PRC-024-3 to ensure generators remain connected during disturbances, but the
“Industry Need” section clearly identifies this issue applies to IBR only. Industry can agree that current standard as is, is very well effective for
traditional synchronous generating resources, therefore WEC believes that standard does not need to be rewritten but rather modified to cover
specific IBR issues. WEC believes that statement “… notable concurrent tripping or performance from synchronous generating resources…” is
not well supported by data from recent disturbances.
Proposed “performance based” term needs to be better defined within the SAR.
If industry recommendation is to include other protective elements or control systems, then it should be done separately and new standards
should be developed. Good examples are PRC-025 and PRC-026.
Some of the “possible causes of tripping and power reductions” listed in SAR are load responsive in nature, therefore should be addressed
within existing Standards that cover load-responsive requirements.
“Detailed Description” section indicates that momentary cessation is deemed unacceptable. Did the SAR requester confirm with all equipment
manufacturers that momentary cassation can completely be eliminated? There are still inverter manufacturers that produce equipment with
momentary cessation in their design because of current limiting components. The SAR suggest a corrective action plan to be developed to
mitigate the issue. What if issue cannot be mitigated?
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Daniela Atanasovski - APS - Arizona Public Service Co. - 1,3,5,6
Answer
No
Document Name
Comment
AZPS agrees with the following comments that were submitted by EEI on behalf of its members:
“The incidental operation of synchronous generators during some of the identified six NERC disturbance reports do not warrant the creation of a new
ride through Reliability Standard replacing PRC-024-3 because the performance of most of the affected resources, outside of the solar PV resources,
performed as designed and expected, and met the requirements of PRC-024-3.
While there were losses of synchronous generators in some of the six disturbance reports cited in the proposed SAR, none appear to be unexpected,
unusual or the result of non-compliance with PRC-024”
“Additionally, if the intent of the SAR is to “create a comprehensive, performance-based ride-through standard,” development of a standard would need
to account for retirement of other relay setting standards such as PRC-025-2 and PRC-026-1, to prevent duplicative requirements and compliance
obligations.”
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Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer
No
Document Name
Comment
Minnesota Power supports EEI’s comments for this question.
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John Pearson - ISO New England, Inc. - 2
Answer
Document Name
Comment
No
In describing the scope, the SAR states “The scope of the ride-through standard shall explicitly exclude auxiliary systems and their protection systems.
Abnormal performance or unexpected tripping of these protections do not pose a systemic BES reliability risk. However, protections and controls
directly focused on the generator and its prime mover (e.g., overspeed, power-load imbalance, overvoltage, phase jump, overcurrent) or plant-level
(e.g., voltage, current, frequency, phase, etc.) have posed notable risks to BES reliability and should be addressed directly in this standard.” However,
auxiliary systems that in turn unexpectedly trip an entire plant pose a risk to reliability. While these systems should not be explicitly modeled, the OP,
BA and RC should be in a position to understand when a facility will trip. As an absolute minimum, this information should be required from facilities
currently being planned and installed.
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF provides the following comments for consideration:
1. The NAGF believes that there is little justification for retiring PRC-024-3 for synchronous generators and that any new standard should be focused on
IBR performance issues. Note that GOs have invested tremendous effort and money in achieving compliance with the PRC standards and are
achieving the desired enhancement of BES reliability. Replacing them with something substantially different would require significant expenditures with
no identifiable benefit. Any new standard should address only gaps in existing standards, as opposed to tearing down and rebuilding them.
2.
Project Scope Comments:
a) Second Bullet: “Creates a comprehensive, performance-based ride-through standard with the purpose of ensuring BES generating resources
remain connected and providing essential reliability services during grid disturbances.”
The NAGF recommends that other relay-setting PRC standards be considered for retirement/modification beyond PRC-024-3. For example, PRC-0252, which has the purpose to assure that load responsive relays are set to prevent unnecessary tripping during system disturbances, and PRC-026-1,
which has the purpose to ensure that load-responsive relays are expected to not trip in response to stable power swings during non-Fault conditions.
The NAGF believes that if a truly comprehensive performance-based ride-through standard is created, then the regulatory burden of other relay setting
PRC standards pertaining to how generator protection responds to grid disturbances should be reviewed and incorporated. It seems that a
comprehensive generator ride-through standard would apply to not only 24, 27, and 59 functions (PRC-024-3) but would also include trips of generating
resources in response to 21, 50, 51, 51VR, 51VC, 67 (PRC-025-2) and/or 21, 40, ,50, 51, 78 (PRC-026-1) function operations in response to grid
disturbances.
3.
Detailed Description of Project Deliverables Comments:
a)
Bullet #3: “A reporting requirement that all trips or reductions in power output are reported by the GO to the TOP, BA, and RC.”
The NAGF believes that this statement is too vague or is stated imprecisely for this deliverable. Reductions in power will occur for a wide variety of
reasons such as clouds passing over or the setting of the sun at a solar farm, a drop in wind speed, wet coal, changes in condenser circulating water
temperature or discharge water temperature limits at a thermal plant, starting an additional large fan or pump, inlet air temperature changes to gas
turbines, reduced water flow at a hydro plant – none of these causes of power reduction would have any relation to PRC requirements and no additional
reporting other than that required by existing TOP requirements should be necessary. We believe this deliverable should be more focused, such as “A
reporting requirement that all trips or reductions in power output in response to grid disturbances are reported by the GO to the TOP, BA, and RC.”
b) Bullet #4: “A requirement that abnormal reductions in active power (i.e., tripping from protections or notable reductions from controls) are analyzed
by the GO to develop a corrective action plan, if possible. Situations where corrective action plans are not able to be developed shall be reported to the
TOP, BA, and RC.”
The NAGF believes that such trip analysis and corrective actions are already addressed by PRC-004 and therefore this deliverable/requirement is
redundant.
c) Bullet #5: “Legacy facilities prior to the effective date of the standard should receive an exemption; however, resources with a commercial
operation date after the effective date of the standard (and possibly the PRC-024-3 implementation date) shall be required to eliminate the use of
momentary cessation within “ride through envelopes” (e.g., the existing PRC-024 “No Trip Zone”).
The NAGF supports the exemption for legacy IBR facilities. The NAGF recommends that the performance-based standard include documented
equipment limitation exemptions similar to PRC-024-3 R3 and these should apply to all generator types rather than just carving out an exemption for the
application of momentary cessation on legacy IBRs existing prior to the effective date of the standard (and possible the PRC-024-3 implementation
date). For example, if an existing turbine has frequency limitations that do not meet the requirements of the new ride-through standard, no corrective
action plan should be necessary should the turbine trip in response to a frequency excursion outside of its capability. There appears to be nothing in
the SAR that addresses limitations of existing equipment other than that of legacy IBRs applying momentary cessation.
d) Bullet #7: “A clear requirement that prolonged plant controller interactions that impede the ability of the resource to dynamically respond to the grid
disturbance and preclude the ability to fully provide essential reliability services are deemed unacceptable and should be addressed by a corrective
action plan.”
The NAGF is concerned with the potential ambiguity associated with this deliverable. This deliverable seems to be focused on eliminating some of the
undesirable IBR performance issues, but the wording of this deliverable could be interpreted to apply to integrated plant or unit protection schemes that
may indeed “impede the ability of the resource to dynamically respond to grid disturbances” but are designed to protect the boiler or nuclear reactor
from pressure or level excursions, steam turbines from overspeed, operation at resonant frequencies or moisture intrusion, etc. Generator Owners
should be able to protect their equipment from catastrophic damage without having to implement a corrective action plan should these protection or
control features impede dynamic response to grid disturbances.
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer
No
Document Name
Comment
On the bottom of page 2, the SAR states: “The scope of protections and controls involved in this ride-through standard shall include all generator
protections and controls that affect the electrical output of the BES generating resource or plant. To be clear, the project should specify the protections
and controls in scope of the ride-through performance and define the term ride-through, as necessary.”
Will the scope include requirements that developers/GOs of any new interconnection projects be required to provide protection and control models to
the TO or PC? The SRC recommends that the SDT indicate all “protection and control equipment, including auxiliary equipment” that will affect the ridethrough capabilities of the generator during disturbances. The SDT should identify the auxiliary systems that the ride-through should not affect.
On page 3, under Detailed Description, the SAR calls for “A requirement that abnormal reductions in active power (i.e., tripping from protections or
notable reductions from controls) are analyzed by the GO to develop a corrective action plan, if possible. Situations where corrective action plans are
not able to be developed shall be reported to the TOP, BA, and RC.”
This description reads much broader than what is described in the SAR purpose. In the purpose it is directed specifically towards “fail to ride through
system events”. Is the intent of the SAR scope to create a requirement to report reductions in active energy which go beyond “fail to ride through
system events” and include abnormal reductions of any cause? The SRC requests the SAR DT clarify the project scope.
On the bottom of page 3, the SAR states, “Legacy facilities prior to the effective date of the standard should receive an exemption; however, resources
with a commercial operation date after the effective date of the standard.” We are concerned that there will be significant amounts of IBR facilities that
will be exempt from these requirements. In addition, this seems to be at odds with the“all” language contained in the last bullet on the bottom of page 2
(and as mentioned in the SRC comments above).
In 2018, a SAR was introduced and denied by the Standards Committee to correct momentary cessation of IBRs that had no such exemption because
of the risks existing facilities were causing on the BES. This SAR does not propose any solutions to address that risk. We recognize that there are
some IBR installations which pre-date the technology to meet the SAR purpose. However there are already numerous amounts of IBRs in operation
which can adopt new technology to meet the SAR’s purpose. A blanket exemption should not be a part of the standards and instead some form of
exemption process should be utilized. Further between the time this standard may be complete and the time it takes effect due to the need for
regulatory approval, which may be over two years. Numerous additional new installation of IBRs would become grandfathered which certainly can meet
the ride through requirements. The SRC recommends exemptions be limited to technical infeasibility.
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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
While EEI agrees in principal that that there have been performance issues, primarily with Solar PV Inverter Based Resources (IBRs), that need to be
addressed, we do not support the retirement of PRC-024.
While there were losses of synchronous generators in some of the six disturbance reports cited in the proposed SAR, none appear to be unexpected,
unusual or the result of non-compliance with PRC-024. As noted below, all of these six events linked within this SAR indicate solar PV performance
problems, not synchronous generator problems.
Additionally, if the intent of the SAR is to “create a comprehensive, performance-based ride-through standard,” development of a standard would need
to account for retirement of other relay setting standards such as PRC-025-2 and PRC-026-1, to prevent duplicative requirements and compliance
obligations.
For these reasons, we do not support the retirement of PRC-024-3. However, we offer an alternative approach in our response to question 2.
NERC 2021 California Disturbances Report (2022)
•
•
•
•
June 24, 2021 – Loss of 765MW of solar PV resources (27 facilities) and 145MW of DERs (no synchronous resources lost).
July 4, 2021 – Loss of 605MW of solar PV resources (33 facilities) and 46MW of DERs; 125MW; additionally, a single 125MW CT tripped due
to two defective sensors as reported by the GO.
July 28, 2021 – Loss of 511MW of solar PV resources (27 facilities) and 46MW of DERs (no synchronous resources lost).
August 25, 2021 – Loss of 583MW of solar PV resources (30 facilities) and 212MW gas turbine tripped as a result of a correct operation of a
RAS scheme. An additional gas turbine tripped during this event due to the failure of the excitation system (failed diodes). As stated in the
report, the diodes were redundant but can only be detected during manual inspection. It is speculated that the redundant diodes failed as a
result of the event, GO has indicated they will increase their inspections to avoid future failures.
NERC Odessa Disturbance Report (2021)
•
•
May 9, 2021 Event – Initial fault occurred during CT startup testing when a surge arrester failed taking out one CT and causing another to run
back for a total loss of 192MW. After this event 1112MW of solar PV output was lost, in addition 36MW of output from 4 wind power plants.
June 26, 2021 Event – Failed H-Frame structure causes the loss of 518MW at 5 PV facilities.
NERC San Fernando Disturbance Report (2020) July 7, 2020
•
Static wire on a 230kV line failed causing the tripping of two lines on a double circuit tower. In addition, a nearby 230kV line relay mis
operated. The result was the initial loss of 205MW of solar PV output. When trying to restore the lines, the second line tripped out causing
the larger event, the loss of 1000MW of solar PV output (no synchronous resources lost).
NERC Palmdale Roost and Angeles Forest Disturbances Report (2019)
•
•
April 20, 2018 (Angeles Forest) – A splice on a 500kV line failed causing a B-C phase fault which was cleared within 2.6 cycles. The fault
caused the loss of 860MW of solar PV output in CAISO and 17MW in LADWP. In addition, a natural gas turbine tripped as a result of the
fault. The report indicates the plan tripped on low fuel pressure causing the natural gas turbine to trip and the reduced output of a combined
cycle steam generator to reduce output to 75MW for a total loss of 200MW. There was an additional loss of 130MW of DER output.
May 11, 2018 (Palmdale Roost) – The disturbance was caused by a bird nest on a 500kV line that caused a line flashover (B phase to ground
fault). As a result, there was a loss of 630MW of solar PV output in CAISO, 48MW in LADWP and 33MW in IID. Additionally, there was
100MW of DER output lost (no indication of any synchronous generation lost during this event).
NERC Canyon 2 Fire Disturbance Report (2018)
•
Canyon 2 Fire Disturbance, Oct. 9, 2017 – Two transmission lines faulted near Anaheim Hills, CA. The first fault occurred on a 220kV line at
12:12 PM and the second occurred at 12:14 PM on a 500kV line. The first fault resulted in the reduction of 682MW of solar PV output, which
the second resulted in the reduction of 937MW of solar PV output (no indication that any synchronous generation was lost).
NERC Blue Cut Fire Disturbance Report (2017)
•
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On Aug. 16, 2016 AM the Blue Cut fire began in Cajon Pass, CA. As a result of the widespread fire SCE experience thirteen 500kV line faults
and LADWP experienced two 287kV faults. Four of the fault events resulted in the loss of 1,200MW of solar PV output (no indication any
synchronous generation was lost).
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
No
Document Name
Comment
Ride-through is not a defined term in the NERC Glossary of Terms nor NPCC Glossary of Terms. The objective of the SAR is commendable, however
the specific characteristics of the disturbances addressed by the new standard needs to be carefully defined. Usually the magnitude and duration of grid
disturbances should be defined. Particular contingencies should be specified and studied to ensure those applicable reasonable foreseeable
disturbances can be assessed and addressed.
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Dana Showalter - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Document Name
Comment
Regarding the 4th bullet in the “Project Scope” section, ERCOT believes the SAR should not exclude auxiliary systems that could impact the facility’s
continued operation. The SDT should review the various types of auxiliary systems in use at in-scope facilities and determine whether to exclude any of
them. ERCOT suggests revising the 4th bullet as follows:
This standard should address protections and controls directly focused on the generator and its prime mover (e.g., overspeed, power-load imbalance,
overvoltage, phase jump, overcurrent) or at the plant level (e.g., voltage, current, frequency, phase, etc.) because they pose notable risks to BES
reliability. The SDT will determine whether this ride-through standard may exclude auxiliary systems that do not impact the facility’s ability to maintain
real and reactive power during a disturbance.
Regarding the 2nd sub-bullet in the “Detailed Description” section, ERCOT suggests the standard contain a requirement for a GO to report only trips or
reductions in real power or improper reactive power response (trips or reductions within some threshold of the performance parameters established in
the standard).
Regarding the 3rd sub-bullet in the “Detailed Description” section, ERCOT suggests clarifying the term “abnormal” to include trips and reductions in real
power or improper reactive power response failing to meet the performance parameters established in the standard. Further, ERCOT suggests the SDT
include a requirement for the GO to develop and implement a corrective action plan (CAP) or report to its TOP, BA and RC any CAP it cannot
implement due to technical infeasibility. Finally, ERCOT suggests removing “if possible” because ERCOT’s proposed language (above) addresses
situations where the GO cannot implement the CAP due to technical infeasibility.
Accordingly, ERCOT suggests modifying the 2nd and 3rd sub-bullets as follows:
•
•
The proposed deliverable is a new NERC standard (or significant overhaul and revision of PRC-024-3) that includes the following key elements:
...
•
•
•
A requirement for a GO to report to its TOP, BA and RC trips or reductions in real power or improper reactive power response (i.e., trips or
reductions within a threshold of the performance parameters established in the standard).
A requirement for a GO to: (a) analyze abnormal trips or reductions in real power or improper reactive power response (i.e., tripping from
protections, notable reductions from controls, trips or reductions in real power or improper reactive power response failing to meet performance
standards established in this standard); and (b) develop and implement a corrective action plan (CAP). If a GO cannot implement a CAP
because it is not technical feasible to do so, the GO must report that fact to its TOP, BA, and RC.
...
Regarding the 4th sub-bullet in the “Detailed Description” section, ERCOT agrees with the SRC that the project should not exempt legacy facilities.
Exempting legacy facilities will not address the reliability-related need this project addresses.
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LaTroy Brumfield - American Transmission Company, LLC - 1
Answer
No
Document Name
Comment
Please address and clearly explain the relationship between the two SARs (“Revision of relevant Reliability Standards to include applicability of
transmission-connected dynamic reactive resources” approved in April, and “Generator Ride-Through Standard (PRC-024-3 Replacement)”. Failure to
provide this clarification will result in confusion between intents and requirements for different types of devices and may not clearly align with the earlier
whitepapers and recommendations.
Additionally-please clarify that Synchronous Condensers, STATCOMs, SVCs and HVDC are not considered generator protection and control
systems and should not be included in this standard. If Synchronous Condensers, STATCOMs, SVCs and HVDC are intended to be included in the
standard, it needs to be revised to reflect that and include proper terminology, consideration of capability, and requirements specific to transmissionconnected dynamic reactive power resources as opposed to generation resources.
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6, Group Name FE Voter
Answer
Document Name
Comment
FirstEnergy supports EEI’s comments.
No
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David Jendras - Ameren - Ameren Services - 1,3,6
Answer
No
Document Name
Comment
Ameren agrees with EEI's comments. A new ride through standard should be created for IBR's only. The performance issues were with IBR's not
synchronous generators.
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LaKenya VanNorman - Florida Municipal Power Agency - 3,4,5,6 - SERC, Group Name Florida Municipal Power Agency (FMPA)
Answer
No
Document Name
Comment
Florida Municipal Power Agency (FMPA) supports comments submitted by NAGF.
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Carl Pineault - Hydro-Qu?bec Production - 1,5
Answer
Yes
Document Name
Comment
At this point, it is hard to disagree with this project since it is still broad and vague
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
BPA supports revision of the current PRC-024-3 rather than creation of a new reliability standard. BPA believes the project will raise the bar on
protection of BPS-connected inverter-based resources.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Yes
Document Name
Comment
Texas RE agrees with the need for this project to develop a comprehensive generator “ride-through” standard in lieu of the current PRC-024’s focus
solely on voltage and frequency protection settings. As the September 2021 Joint Odessa Disturbance Report for Texas Events on May 9, 2021 and
June 26, 2021 (“Odessa Disturbance Report”) highlighted, “the systematic nature of [Inverter-Based Resource tripping or cessation] events across
multiple interconnections and a wide range of facilities, many of which are recently energized, warrants significant enhancements to the NERC
Reliability Standards to address gaps in BES inverter-based resources.” (Odessa Disturbance Report, at 29). These recommendations included the
need for developing a new generator protection and control ride-through standard to replace the current PRC-024-3 to address continued examples of
widespread tripping that are not addressed by the current PRC-024-3 requirements. Texas RE appreciates that the SAR provides an approach to
capture the range of performance issues (PLL loss of synchronism, subcycle ac overvoltage protection, dc reverse current, and wind converter crowbar
failures) that have resulted in widespread tripping incidents across a number of interconnections, including the ERCOT Interconnection.
It further recommended that NERC do so on an expedited timeframe. Texas RE notes that this call of expedited action is even more pressing given the
recent tripping of significant inverter-based resources in the ERCOT Interconnection earlier this year, continuing a pattern of generator performance
issues in this area. NERC has highlighted grid transformation issues as the single greatest risk to grid reliability at the current time. Texas RE
appreciates the SDT’s important role, care, and commitment to addressing these performance issues in this project.
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0
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC Regional Standards Committee
Answer
Yes
Document Name
Comment
The NPCC Regional Standards Committee agrees with the proposed scope as described in the SAR.
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Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
The Project 2020-02 webpage reflects that the initial project SAR, posted for industry comments on 3/30/2020, was revised and subsequently accepted
by the NERC Standards Committee on 4/20/2022. A redline of the SAR accepted by the Standards Committee in April 2022 vs. the initial SAR posted
in March 2020 is posted on the project page. It appears that a different Project 2020-02 SAR (prepared by NERC executives and staff) was presented
to and accepted by the NERC Standards Committee a month later, on 5/18/2022. We suggest that a redline of the SAR accepted by the Standards
Committee in May 2022 vs. the SAR accepted by the Standards Committee in April 2022 (or the initial SAR posted in March 2020) be added to the
project page. It is not clear why the SAR submitted by the Chair of the System Analysis & Modeling Subcommittee and accepted by the Standards
Committee in April 2022 was “abandoned” a month later to be replaced by the SAR submitted by NERC.
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Nazra Gladu - Manitoba Hydro - 1,3,5,6
Answer
Yes
Document Name
Comment
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Leonard Kula - Independent Electricity System Operator - 2
Answer
Yes
Document Name
Comment
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC Entity Monitoring
Answer
Yes
Document Name
Comment
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Jennie Wike - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6 - WECC, Group Name Tacoma Power
Answer
Document Name
Comment
Yes
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Isidoro Behar - Long Island Power Authority - 1
Answer
Yes
Document Name
Comment
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Gail Elliott - International Transmission Company Holdings Corporation - NA - Not Applicable - MRO,RF
Answer
Yes
Document Name
Comment
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Yes
Document Name
Comment
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0
2. Provide any additional comments for the drafting team to consider, if desired.
LaKenya VanNorman - Florida Municipal Power Agency - 3,4,5,6 - SERC, Group Name Florida Municipal Power Agency (FMPA)
Answer
Document Name
Comment
Florida Municipal Power Agency (FMPA) supports comments submitted by NAGF.
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6, Group Name FE Voter
Answer
Document Name
Comment
While FirstEnergy does agree that an assessment needs to be conducted to ensure reliability of the BES due to the changing mix of generating
resources, we do not agree that a reliability standard should result in additional penalties for a GO if generating capacity requirements are not met due
to a fuel shortage caused by unforeseen events. FirstEnergy generators already participate in the PJM capacity market and are required to provide
generating capacity based on summer ICAP testing results. A generator is assessed financial penalties by PJM if it cannot meet its generating capacity
requirements and therefore, we caution against a double jeopardy situation.
We also suggest the RC and BA, not the GO, should be responsible for developing a CAP if generation capacity demands are not met during periods of
constrained resources. It is the responsibility of the Transmission Grid Operator (e.g., PJM), not the GO, to ensure that adequate generating resources
are available during periods of constrained resources. Operating characteristics of IRBs are the cause of constrained resources and mitigation actions
over-and-above PJM generating capacity requirements should not be placed on fossil generation resources.
Further, FirstEnergy supports EEI’s comments, which states:
As an alternative to the proposed PRC-024 SAR, EEI suggests that a new SAR be developed to address performance issues specifically affecting
IBRs. This new SAR could leverage key scope items from this proposed SAR to create a new performance- based NERC Reliability Standard that is
focused on IBRs. As a suggested scope, we propose modifying this SAR as follows:
-- Trips or reductions in active power that occur because the IBR does not operate as expected (excludes cloud cover, setting sun, etc.), but not
associated with protection system trips, (PRC-004 already addresses protection system tripping) are to be analyzed by the GO to develop a corrective
action plan. Situations where an issue cannot be corrected, the GO shall develop a report detailing the limitations of the IBR and provide it to the
responsible TOP, BA, and RC.
-- Momentary cessation, or temporary ceasing of current injection in response to grid disturbances, is deemed unacceptable for BES generating
resources. Inverter-based generating resources employing momentary cessation shall develop a corrective action to mitigate its use unless the issue
cannot be corrected. Legacy facilities prior to the effective date of the standard should receive an exemption; however, resources with a commercial
operation date after the effective date of the standard shall be required to eliminate the use of momentary cessation during system transient
disturbances where the system voltage or frequency falls within the “No Trip Zone” provided in PRC-024-3, which is subject to enforcement October 1,
2022.
-- Include the development of new terms to address terms specific to IBRs or where commonly used industry terms have created some confusion for
IBR owners. E.g., No Trip Zone, trip, momentary cessation, and any other relevant terms that may require clarification within the NERC Glossary of
Terms.
-- Prolonged IBR controller interactions that impede the ability of the resource to respond dynamically to the grid disturbance and preclude the ability to
provide essential reliability services are deemed unacceptable and should be addressed by a corrective action plan. In situation where the GO has
determined the issue cannot be corrected, a report shall be developed detailing the IBR limitation and provide it to the responsible TOP, BA and RC.
--If the TOP, BA, or RC inform the GO/IBR owner of a tripping occurrence, cessation event, or IBR controller interactions
are not reported or otherwise identified by the GO/IBR Owner, the responsible GO shall be responsible for analyzing
facility’s performance during the event, developing a corrective action plan, and making this available to the TOP, BA,
RC or in the situation where the issue cannot be corrected, informing the TOP, BA and RC.
that
the
and
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
The current PRC-024-2, “No Trip Zone” is very clear and easy to understand for frequency and voltage parameters. The SAR Requesters’ logic and
SAR details appear to be pretty thorough, with the exception of replacing the “No Trip Zone” with “fault ride-through capabilities” as proposed in the
revised SAR (dated 4/28/2022). We recommend the SAR Requesters/SAR Drafting Team expand on the proposal to eliminate “No Trip Zone”
requirements, and expand the discussion regarding the replacement “fault ride-through capabilities”.
The revised SAR language seems to suggest that synchronous generating resources suffer from mis-trips and mis-application of the standard due to
deficiencies identified in PRC-024-3 to the same degree that inverter-based resources do. None of the six disturbance reports cited as technical
justification for the SAR reference loss of synchronous generation caused by an inadequate or missing requirement within PRC-024-3. From a reliability
perspective, while GO/GOPs of IBRs stand to benefit from a replacement/overhaul of PRC-024-3, there is no clear benefit to GO/GOPs of traditional
synchronous generating resources. We recommend that the SAR language be revised to clearly delineate the current issues with synchronous
generation resources and the current issues with IBRs driving this proposed standard modification, and how the changes are impacting each
technology.
The proposed scope explicitly excludes auxiliary systems with the rationale that “abnormal performance or unexpected tripping of these protections do
not pose a systemic BES reliability risk” (Page 3, “Project Scope”, 4th bullet point). Components of auxiliary systems like unit auxiliary transformers
(UATs) typically feature protection that are capable of taking a generator offline. Given this, there may be a heightened reliability risk if auxiliary
equipment are not subject to the same requirements of the proposed standard as generator protection and controls. Auxiliary transformers (and BES
GSUs) were added to the applicable equipment scope in the revision from PRC-024-2 to PRC-024-3, so an explanation is requested for why this
inclusion is not being preserved.
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LaTroy Brumfield - American Transmission Company, LLC - 1
Answer
Document Name
Comment
Please clarify momentary cessation of “current injection during BPS fault events.”
Re: this SAR please explain if current injection refers to active current, reactive current or both?
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Dana Showalter - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT provides the following additional comments:
The SAR specifically identifies protections/controls posing risks to BES reliability. The proposed standard should not specify criteria for every potential
quantity that may trigger a trip. Specifying voltage and frequency envelopes should suffice. Operating within those envelopes should not trigger any
other plant control or protection to trip.
Not having high-resolution data limits the ability to identify the root cause of the events referenced in the SAR. High-resolution data, including data from
phasor measurement units (PMUs), digital fault recorders (DFRs), and inverter-based oscillography, is critical to identify the root cause of disturbance
events and, as such, necessary to develop a CAP. Additionally, high resolution data allows a better understanding of the interaction between local wind
turbine ride-through control versus the facility plant controller. ERCOT believes this SAR should require data recording relating to voltage ride through
and to add appropriate language to PRC-002-2.
Finally, ERCOT suggests the SDT consider IEEE 2800 when drafting a proposed standard.
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Gail Elliott - International Transmission Company Holdings Corporation - NA - Not Applicable - MRO,RF
Answer
Document Name
Comment
In place of GOs only notifying the PC and TP when they can’t meet the ride-through requirement or upon request, GOs should be required to
periodically (annually?) provide, or confirm no changes to, their generator protection trip settings to the PC and TP.
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
If an attempt is made to define the ride through then it should consider the Bulk Electrical System (BES) as well as all the applicable/foreseeable
generating resources that can potentially impact the BES.
A suggestion is made to use, consistently, just the Bulk Electrical System (BES) acronym and not to loosely interchange with BPS whose meaning is
different than BES in the NPCC region (Bulk Power System as determined by Directory #1/A#10 methodology)
The SAR mentions that ”Generator ride-through is a foundational essential reliability service.”. To date the “ride-through” is not defined as a reliability
service the same way we understand the following:
•
•
•
Frequency support - provided through the combined interactions of synchronous inertia and frequency response, as services to arrest the
decline in frequency and eventually return the frequency to the desired level
Ramping and Balancing – provided through dispatch by the generating units with active power management capability and ability to respond
to dispatch signals
Voltage Support - provided through planning and confirmation testing of reactive power sufficiency per unique characteristics of their
respective BA systems.
Having generating resources with ride-through capabilities are not a guarantee that the generating units will remain connected to the grid even less of a
guarantee they will provide BES support (reliability services during BES disturbance) since BES support is also a:
•
•
Function of static and dynamic reactive power reserve capabilities to regulate voltage at those respective points in the system
Function of levels of conventional synchronous inertia for respective balancing area/interconnection, and initial frequency deviation following the
largest contingency event for the interconnection
This SAR should only be applicable to the protection/protective functions that trip the protected equipment in response to a BES disturbance, where the
disturbance conditions do not pose a risk of damage to the associated equipment, whose protection must be prioritized (similar with PRC-025-2).
Equipment protection does not amount nor have a simultaneous compounded effect on grid reliability.
The SAR statement related to the cost impact associated to this Project being expected to be minimal, should not be treated as an accurate statement
as long as the entire scope of the project has not even been identified.
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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
As an alternative to the proposed PRC-024 SAR, EEI suggests that a new SAR be developed to address performance issues specifically affecting
IBRs. This new SAR could leverage key scope items from this proposed SAR to create a new performance- based NERC Reliability Standard that is
focused on IBRs. As a suggested scope, we propose modifying this SAR as follows:
•
•
•
•
•
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Trips or reductions in active power that occur because the IBR does not operate as expected (excludes cloud cover, setting sun, etc.), but not
associated with protection system trips, (PRC-004 already addresses protection system tripping) are to be analyzed by the GO to develop a
corrective action plan. Situations where an issue cannot be corrected, the GO shall develop a report detailing the limitations of the IBR and
provide it to the responsible TOP, BA, and RC.
Momentary cessation, or temporary ceasing of current injection in response to grid disturbances, is deemed unacceptable for BES generating
resources. Inverter-based generating resources employing momentary cessation shall develop a corrective action to mitigate its use unless the
issue cannot be corrected. Legacy facilities prior to the effective date of the standard should receive an exemption; however, resources with a
commercial operation date after the effective date of the standard shall be required to eliminate the use of momentary cessation during system
transient disturbances where the system voltage or frequency falls within the “No Trip Zone” provided in PRC-024-3, which is subject to
enforcement October 1, 2022.
Include the development of new terms to address terms specific to IBRs or where commonly used industry terms have created some confusion
for IBR owners. E.g., No Trip Zone, trip, momentary cessation, and any other relevant terms that may require clarification within the NERC
Glossary of Terms.
Prolonged IBR controller interactions that impede the ability of the resource to respond dynamically to the grid disturbance and preclude the
ability to provide essential reliability services are deemed unacceptable and should be addressed by a corrective action plan. In situation where
the GO has determined the issue cannot be corrected, a report shall be developed detailing the IBR limitation and provide it to the responsible
TOP, BA and RC.
If the TOP, BA, or RC inform the GO/IBR owner of a tripping occurrence, cessation event, or IBR controller interactions that are not reported or
otherwise identified by the GO/IBR Owner, the responsible GO shall be responsible for analyzing the facility’s performance during the event,
developing a corrective action plan, and making this available to the TOP, BA, and RC or in the situation where the issue cannot be corrected,
informing the TOP, BA and RC.
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer
Document Name
Comment
The current PRC-024 standard was written with conventional (rotating) generators in mind. Conventional generators are quite sensitive to generator
speed (frequency) and abnormal speeds can damage, i.e. lower the life of, turbine blades. Hence the further away the frequency deviates from 60 Hz,
the shorter the duration allowed for “no-trip.” In contrast, Inverter-Based Resources (IBRs) don’t have rotating parts whose speed is tied to their
connection to the grid. Since IBRs are not affected by deviations in system frequency as much as conventional (rotating) generators, the SRC requests
the PRC-024 SAR be revised to include a recognition for this difference as there may be different ride-through requirements for IBRs than conventional
generators within the same interconnection.
In addition, to aid in industry implementation, the SRC requests the SAR include the requirement to provide some real-world examples; e.g. in Technical
Rationale, to illustrate how proposed standard requirements will ensure both IBRs and conventional generators are able to ride-through faults and how,
had they been in place, would have addressed past issues of inadequate ride-through capability.
Finally, the SRC requests that the SAR ask to expand the requirement in selecting a Standards Drafting Team (SDT) that is stated in Question 5 on the
SAR form. The SRC agrees it is important to include entities that the standard will apply to, but in addition, entities who have a need for the information
or bear responsibility to reliably operate within the bounds of the standard (even if the standard does not directly apply to them from a requirement and
compliance standpoint), should also be included. The requirements set in any standard are intended to ensure the reliability of the BES as a whole
which all registered entity functions have an impact or interest in. This should apply to any and all SARs and the SRC would like to ask NERC to
address a change in the SAR form in the future.
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
Comment
The NAGF notes that the SAR references the term Bulk Power System (BPS) and Bulk Electric System (BES) through the SAR document. Recommend
consistent use of the terms in the Purpose, Project Scope, and Deliverables sections.
In addition, the NAGF notes that the SAR is not consistent with regard to retiring and replacing PRC-024-3 (Purpose or Goal Section, first sentence).
Bullet #1 of the Project Scope states “Retire PRC-024-3, and create a new PRC standard or completely overhaul and replace the existing PRC-024
standard.” Bullet #1 of the Detailed Description of the Project Deliverables states “The proposed deliverable is a new NERC standard (or significant
overhaul and revision of PRC-024-3) that includes…).
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John Pearson - ISO New England, Inc. - 2
Answer
Document Name
Comment
Below are proposed changes for the “proposed deliverable” section of the SAR.
The proposed deliverable is a new NERC standard (or significant overhaul and revision of PRC-024-3) that includes the following key elements:
A performance-based approach to generator ride-through rather than an equipment settings standard. The new standard shall include requirements that
BES resources shall ride through grid disturbances and include quantitative measures (see below) on expectations for ride-through that address all
possible causes of tripping and power reductions from BES generating resources (particularly generator, turbine, inverter, and all plant-level protection
and controls, including auxiliary systems).
A reporting requirement that all trips or abnormal reductions in power output are reported by the GO to the TOP, BA, and RC.
A requirement that abnormal reductions in active power (i.e., tripping from protections or notable reductions from controls) are analyzed by the GO and
shall be reported to the TOP, BA, and RC.
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Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
None.
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Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
Minnesota Power supports EEI’s comments for this question.
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Daniela Atanasovski - APS - Arizona Public Service Co. - 1,3,5,6
Answer
Document Name
Comment
AZPS suggests PRC-024 should remain unchanged as it applies to synchronous generators and that a new SAR be developed to address performance
issues specifically affecting IBR’s that are interconnected to the BES.
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Alan Kloster - Evergy - 1,3,5,6 - MRO
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #2.
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Isidoro Behar - Long Island Power Authority - 1
Answer
Document Name
Comment
The stated purpose of this SAR is to retire PRC-024-3 and replace it with a performance-based ride-through standard that ensures generators remain
connected to the BPS during system disturbances. Additionally, the SAR will focus on the generator protection and control systems that can result in the
reduction or disconnection of generating resources during these events.
As part of the development of the performance based standard or overhaul of PRC-024-3, it is recommended that the standard drafting team include
and highlight specific references to the relevant IEEE Standard P2800-2022 clauses and to relevant FERC Orders (related to ride-through), where
applicable. It will be important for stakeholders to discern similarities and differences between the new or revamped standard and these existing
references.
We can offer another comment, related to PRC-024-3, for consideration in the development of a performance based standard or overhaul of PRC-0243.
For PRC-024-3 applicability section 4.1.2, it mentions that it is for Transmission Owners in the Quebec Interconnection only. There are Transmission
Owners outside the Quebec Interconnection that own BES generator step-up transformers (GSUs). Is PRC-024-3 intended to be applicable to
Transmission Owners that own BES GSUs that are outside the Quebec Interconnection? If so, perhaps the “in the Quebec Interconnection only” should
be removed from applicability section 4.1.2 in the next revision.
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Joseph Amato - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer
Document Name
Comment
MidAmerican supports MRO NSRF and EEI comments.
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Michael Johnson - Pacific Gas and Electric Company - 1,3,5 - WECC, Group Name PG&E All Segments
Answer
Document Name
Comment
PG&E agrees with the comments and suggested scope provided by EEI; a new SAR should be developed to address the unique performance
characteristics of IBRs.
Likes
0
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0
Response
Anna Todd - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer
Document Name
Comment
N/A
Likes
0
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0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Southern Company disagrees with the “Cost Impact Assessment”. We feel that generation resources will need to install high speed recorders to
capture data on electrical events that occur and the reaction of generation resources to said electrical event. These high speed recorders will be
essential for any requirement for analysis and development of corrective action plans. Southern Company purports that it will be costly to engineer,
procure and install this equipment.
Noting that IBR components capable of providing the performance characteristics are just now beginning to be developed and offered by vendors
coupled with regulatory requirements for providing that performance will certainly cause equipment suppliers to increase costs to the users.
With the cause of the concern raised in this SAR being the system disturbance, perhaps a more beneficial result can be achieved by investigating the
causes of the system disturbances that have been resulting in natural responses of the IBR and synchronous machine based generating stations. Our
experience has been that most of the existing IBR systems that operate perfectly given a network with no disturbances.
The recent development and adoption of IEEE P2800 (Standard for Interconnection and Interoperability of Inverter-Based Resources Interconnecting
with Associated Transmission Electric Power Systems) is nowhere to be found in the SAR as a resource. It is Southern Company’s opinion that IEEE
P2800 be fully understood and used by the SDT as a resource of what operational capability limits exist for IBRs. P2800 goes into many of the aspects
that IBRs face from a performance perspective. A common issue with IBRs is loss of synchronism because of the voltage phase angle jump that can
occur with system disturbances. A voltage phase angle shift jump can occur with the voltage magnitudes still within the no-trip zone, leading to
momentary cessation because of loss synchronism of the IBRs synchronizing phase-locked loop control function.
The Functional Entities identified in the PRC-024 standard have no control what-so-ever of the design and performance characteristics of the Inverter
Based Resource manufacturers equipment. This leads to GOs attempting to coerce the IBR manufactures after-the-fact to change equipment settings
and parameters to comply with operational situations that they are either not designed to perform to or, due to the technical nature of the IBR generation
process, cannot perform to. To move to a performance based standard and holding the GO accountable for the design performance of the IBRs is futile
at best. The only performance criteria defined in the SAR so far is impossible for all situations, and that is “A clear requirement that momentary
cessation, or temporary ceasing of current injection during BPS fault events, is deemed unacceptable performance for BES generating resources”.
Likes
0
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0
Response
Joe Gatten - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Document Name
Comment
Xcel Energy supports the comments offered by EEI, NAGF, and MRO NSRF.
Likes
0
Dislikes
0
Response
Kendra Buesgens - MRO - 1,2,3,4,5,6 - MRO
Answer
Document Name
Comment
The MRO NSRF disagrees with the “Cost Impact Assessment”. The MRO NSRF feels that generation resources will need to install high speed
recorders to capture data on electrical events that occur and the reaction of generation resources to said electrical event. These high speed recorders
will be essential for any requirement for analysis and development of corrective action plans. The MRO NSRF believes it will be costly to engineer,
procure and install this equipment.
The MRO NSRF recommends replacing all instances of bulk power system (BPS) with Bulk Electrical System (BES) to ensure proper scoping of the
SAR.
Likes
0
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0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Momentary Cessation Requirements for Existing Generators
While Texas RE appreciates the proposed SAR’s focus on generator performance issues in general and momentary cessation issues in particular,
Texas RE is concerned that the current proposed SAR would exempt facilities in commercial operation prior to the effective date of the new PRC-024-3
requirements from “the use of momentary cessation within ‘ride through envelopes’ (e.g., the existing PRC-024 “No Trip Zone”). (PRC-024 Standard
Authorization Request, at 3-4). The Odessa Disturbance Report observed that momentary cessation issues resulted in generation loss, along with
tripping issues inside of facilities during the event (Odessa Disturbance Report, at 7). In particular, the Odessa Disturbance Report noted: “legacy
inverter momentary cessation setting with plant-level controller interactions prohibited quick active power recovery.” (Odessa Disturbance Report, at
33). The report also noted other forms of momentary cessation issues, including settings that produced fixed reactive power injection with “no ability to
control voltage post-contingency.” (Odessa Disturbance Report, at 20). It further noted that “[t]his type of behavior was not known by ERCOT prior to
the event analysis nor is this type of behavior supporting the BPS post-fault.” (Id.).
Given the significance of these momentary cessation issues during the Odessa Disturbance event and other events over the past six years, Texas RE
encourages the SDT to not limit momentary cessation performance requirements exclusively to new generation facilities. While Texas RE expects the
SDT to move expeditiously with this project, Texas RE notes that the final revised standard may not be effective for several years. As a result, not only
would existing generators not be covered by any momentary cessation requirements, but a number of planned generation resources would be similarly
exempt. Given the growing role of inverter-based resources in the ERCOT Interconnection and others, this could result in a significant reliability gap.
Texas RE notes that momentary cessation issues are currently documented in NERC Reliability Guidelines (E.g., Reliability Guideline: BPS-Connected
Inverter-Based Resource Performance (Sept. 2018) (2018 IBR Performance Guidelines). These existing guidelines note that “Existing and newly
interconnecting inverter-based resources should eliminate the use of momentary cessation to the greatest possible extent.” (2018 IBR Performance
Guidelines, at 11). It is also important to note that one of the key findings in the Odessa Disturbance Report is that while these reliability guidelines are
widely viewed and shared, entities are “not comprehensively adopting the recommendation(s) contained in those materials.” (Odessa Disturbance
Report, at vi). In short, a new Reliability Standard is required.
Texas RE acknowledges it may take time to review and implement settings to avoid certain momentary cessation-type performance issues. As the
2018 IBR Performance Guidelines note, however: “Existing resources may have hardware and/or software limitations based on a design philosophy
using momentary cessation, and it may not be feasible to eliminate its use. For equipment limitations that cannot be addressed, PRC-024-2
Requirement R3.1 states that ‘[t]he [GO] shall communicate the documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and Transmission Planner within 30 calendar days.’” (2018 IBR
Performance Guidelines, at 11-2). The drafting team could consider approaches that permit legacy systems lacking functionality to avoid momentary
cessation issues to document those limitations for any new momentary cessation requirements developed in this project in a manner similar to the
process currently provided in the existing PRC-024-3 Requirement R3.1.
Enhanced Communication Requirements
In addition to considering the incorporation of momentary cessation and other performance notification requirements as appropriate, Texas RE
recommends the drafting team consider creating a new requirement for the GO to notify the GOP, in addition to the TOP, BA, and RC, regarding
abnormal tripping. Since COM-001 and COM-002 do not include GO communications, an additional requirement for the GO to notify the GOP would be
helpful for the GOP to have the information to communicate any GO issues via COM-001 and COM-002.
Likes
0
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0
Response
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
Although PRC-024-3 is not applicable to BPA by registration, the PRC-024-3 Requirements R3 and R4 do impact BPA as a Transmission Planner and
Planning Coordinator and will have substantial impact to BPA’s interconnection requirements. BPA encourages the drafting team to address the
inconsistencies in format of how TPs and PCs receive the data. Data consistency will support more efficient and effective modeling of relay settings
Likes
0
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0
Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC Entity Monitoring
Answer
Document Name
Comment
No additional comments. Thank you for the opportunity to comment.
Likes
0
Dislikes
0
Response
Alison Mackellar - Constellation - 5,6
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
0
Response
Kimberly Turco - Constellation - 5,6
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
0
Response
Adrian Raducea - DTE Energy - Detroit Edison Company - 3,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment
All protection and control system functions that will be in scope should be specifically listed in the standard. Guidance on complying with ride-through
requirements should be provided by including detailed examples. A sufficient phase-in period should be part of the implementation plan to allow GOs
time to achieve the additional coordination that will be required.
Based on the defined project scope the new standard will enforce that unexpected trips, abnormal trips and reductions in power are reported to the
pertinent entities. The term reduction of power needs to be defined since it is open for interpretation. Furthermore, this reporting-out could infringe on
current standards like PRC-004.
Likes
0
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0
Response
Brian Lindsey - Entergy - 1,3,6
Answer
Document Name
Comment
The Cost Impact Assessment states incremental cost impact which is not correct. Additional analyses and design changes are likely based on the
widespread loss of generating resources observed.
Likes
0
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Response
0
Consideration of Comments
Project Name:
2020-02 Modifications to PRC-024-3 (Generator Ride-through) | Standard Authorization Request
Comment Period Start Date: 5/31/2022
Comment Period End Date:
7/14/2022
There were 40 sets of responses, including comments from approximately 103 different people from approximately 72
companies representing 10 of the Industry Segments as shown in the table on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, let us know immediately. Our goal is to give every comment serious consideration in
this process. If you feel there has been an error or omission, contact Director, Standards Development Latrice Harkness (via email) or at
(404) 858-8088.
RELIABILITY | RESILIENCE | SECURITY
Questions
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree but have comments or
suggestions for the project scope, please provide your recommendation and explanation.
2. Provide any additional comments for the drafting team to consider, if desired.
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
2
Organization
Name
Name
DTE Energy - Adrian
Detroit
Raducea
Edison
Company
WEC Energy Christine
Group, Inc. Kane
Segment(s)
Region
3,5
Group Name
DTE Energy - DTE
Electric
3,4,5,6
Group Member
Name
Karie Barczak
Jennie Wike
1,3,4,5,6
WECC
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
Group
Member
Region
DTE Energy - 3
Detroit
Edison
Company
RF
Adrian Raducea DTE Energy - 5
Detroit
Edison
RF
patricia ireland DTE Energy
4
RF
WEC Energy Group Christine Kane WEC Energy 3
Group
RF
Matthew
Beilfuss
Tacoma
Public
Utilities
(Tacoma,
WA)
Group
Group
Member
Member
Organization Segment(s)
Tacoma Power
WEC Energy 4
Group, Inc.
RF
Clarice Zellmer WEC Energy 5
Group, Inc.
RF
David Boeshaar WEC Energy 6
Group, Inc.
RF
Jennie Wike
Tacoma
Public
Utilities
1,3,4,5,6
WECC
John Merrell
Tacoma
Public
Utilities
(Tacoma,
WA)
1
WECC
3
Organization
Name
Name
Segment(s)
Duke Energy Kim Thomas 1,3,5,6
Florida
Municipal
LaKenya
VanNorman
3,4,5,6
Region
Group Name
FRCC,RF,SERC,Te Duke Energy
xas RE
SERC
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
Group Member
Name
Group
Group
Member
Member
Organization Segment(s)
Group
Member
Region
Marc
Donaldson
Tacoma
Public
Utilities
(Tacoma,
WA)
3
WECC
Hien Ho
Tacoma
Public
Utilities
(Tacoma,
WA)
4
WECC
Terry Gifford
Tacoma
Public
Utilities
(Tacoma,
WA)
6
WECC
Ozan Ferrin
Tacoma
Public
Utilities
(Tacoma,
WA)
5
WECC
Laura Lee
Duke Energy 1
SERC
Dale Goodwine Duke Energy 5
SERC
Greg Cecil
Duke Energy 6
RF
Chris Gowder
Florida
Municipal
SERC
5
4
Organization
Name
Name
Segment(s)
Region
Power
Agency
FirstEnergy - Mark Garza
FirstEnergy
Corporation
Group Name
Florida Municipal
Power Agency
(FMPA)
1,3,4,5,6
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
FE Voter
Group Member
Name
Group
Group
Member
Member
Organization Segment(s)
Group
Member
Region
Power
Agency
Dan O'Hagan
Florida
Municipal
Power
Agency
4
SERC
Carl Turner
Florida
Municipal
Power
Agency
3
SERC
Jade Bulitta
Florida
Municipal
Power
Agency
6
SERC
Julie Severino
FirstEnergy - 1
FirstEnergy
Corporation
RF
Aaron
Ghodooshim
FirstEnergy - 3
FirstEnergy
Corporation
RF
Robert Loy
FirstEnergy - 5
FirstEnergy
Solutions
RF
Tricia Bynum
FirstEnergy - 6
FirstEnergy
Corporation
RF
5
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member
Name
Mark Garza
Pacific Gas
and Electric
Company
Michael
Johnson
Southern
Pamela
Company - Hunter
Southern
Company
Services, Inc.
1,3,5
1,3,5,6
WECC
SERC
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
Group
Group
Member
Member
Organization Segment(s)
Group
Member
Region
FirstEnergy- 4
FirstEnergy
RF
PG&E All Segments Marco Rios
Pacific Gas
and Electric
Company
1
WECC
Sandra Ellis
Pacific Gas
and Electric
Company
3
WECC
James Mearns Pacific Gas
and Electric
Company
5
WECC
Southern Company Matt Carden
Southern
1
Company Southern
Company
Services, Inc.
SERC
Joel
Dembowski
Southern
Company Alabama
Power
Company
3
SERC
Ron Carlsen
Southern
Company Southern
Company
Generation
6
SERC
6
Organization
Name
Name
Northeast
Ruida Shu
Power
Coordinating
Council
Segment(s)
Region
1,2,3,4,5,6,7,8 NPCC
,9,10
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
Group Name
NPCC Regional
Standards
Committee
Group Member
Name
Group
Group
Member
Member
Organization Segment(s)
Group
Member
Region
Jim Howell
Southern
5
Company Southern
Company
Services, Inc.
- Gen
SERC
Gerry Dunbar
Northeast
10
Power
Coordinating
Council
NPCC
Randy
MacDonald
New
Brunswick
Power
2
NPCC
Glen Smith
Entergy
Services
4
NPCC
Alan Adamson New York
State
Reliability
Council
7
NPCC
David Burke
Orange &
Rockland
Utilities
3
NPCC
Harish Vijay
Kumar
IESO
2
NPCC
David Kiguel
Independent 7
NPCC
7
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member
Name
Group
Group
Member
Member
Organization Segment(s)
Nick Kowalczyk Orange and
Rockland
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
Group
Member
Region
1
NPCC
Joel Charlebois AESI 5
Acumen
Engineered
Solutions
International
Inc.
NPCC
Mike Cooke
Ontario
4
Power
Generation,
Inc.
NPCC
Salvatore
Spagnolo
New York
Power
Authority
1
NPCC
Shivaz Chopra
New York
Power
Authority
5
NPCC
Deidre Altobell Con Ed 4
Consolidated
Edison
NPCC
Dermot Smyth Con Ed 1
Consolidated
Edison Co. of
New York
NPCC
8
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member
Name
Group
Group
Member
Member
Organization Segment(s)
Peter Yost
Con Ed 3
Consolidated
Edison Co. of
New York
NPCC
Cristhian
Godoy
Con Ed 6
Consolidated
Edison Co. of
New York
NPCC
Nurul Abser
NB Power
1
Corporation
NPCC
Randy
MacDonald
NB Power
2
Corporation
NPCC
Michael
Ridolfino
Central
1
Hudson Gas
and Electric
NPCC
Vijay Puran
NYSPS
6
NPCC
ALAN
ADAMSON
New York
State
Reliability
Council
10
NPCC
Sean Cavote
PSEG - Public 1
Service
Electric and
Gas Co.
Brian Robinson Utility
Services
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
Group
Member
Region
5
NPCC
NPCC
9
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member
Name
Group
Group
Member
Member
Organization Segment(s)
Quintin Lee
Eversource
Energy
1
NPCC
John Pearson
ISONE
2
NPCC
Nicolas
Turcotte
Hydro1
Qu?bec
TransEnergie
NPCC
Chantal Mazza HydroQuebec
Western
Steven
Electricity
Rueckert
Coordinating
Council
10
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
WECC Entity
Monitoring
Group
Member
Region
2
NPCC
Michele
Tondalo
United
1
Illuminating
Co.
NPCC
Paul
Malozewski
Hydro One
Networks,
Inc.
3
NPCC
Steve Rueckert WECC
10
WECC
Phil O'Donnell WECC
10
WECC
10
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree but have comments or
suggestions for the project scope, please provide your recommendation and explanation.
Brian Lindsey - Entergy - 1,3,6
Answer
No
Document Name
Comment
Should add new R5 to PRC-024-3: "Generator Owners shall analyze and have a corrective action plan (if possible), and report to necessary
entities any failure to ride through a system event."
Likes
0
Dislikes
0
Response
Thank you for the comment. The drafting team will take this into consideration when drafting the SAR.
Adrian Raducea - DTE Energy - Detroit Edison Company - 3,5, Group Name DTE Energy - DTE Electric
Answer
No
Document Name
Comment
The proposed standard should cover “tripping” and not include “reductions”, as the specified level can be subjective.
Likes
0
Dislikes
0
Response
Thank you for the comment. The team has decided to not include synchronous generators in the SAR.
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
11
Kimberly Turco - Constellation - 5,6
Answer
No
Document Name
Comment
Constellation does not agree with the proposed scope as the scope is far reaching into multiple standards not just PRC-024-3 and the
impact to those standards is not clearly defined.
Kimberly Turco on behalf of Constellation Segements 5 and 6
Likes
0
Dislikes
0
Response
Thank you. This comment is vague and the team is unable to provide a response.
Alison Mackellar - Constellation - 5,6
Answer
No
Document Name
Comment
Constellation does not agree with the proposed scope as the scope is far reaching into multiple standards not just PRC-024-3 and the
impact to those standards is not clearly defined.
Kimberly Turco on behalf of Constellation Segments 5 and 6
Likes
0
Dislikes
0
Response
Thank you. This comment is vague and the team is unable to provide a response.
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
12
Thomas Foltz - AEP - 3,5,6
Answer
No
Document Name
Comment
AEP agrees with the concerns related to IBRs and the performance issues that have been previously noted but we do not agree that PRC024 should be revised or replaced with ride-through obligations added for synchronous generation. AEP recommends that PRC-024 be
retained as it currently is, and recommends creation of a new standard containing ride-through obligations for IBRs only. AEP does not
see a reliability justification for developing ride-through obligations for synchronous generation and advises against any efforts to do so
since, as also noted by EEI, such units have been seen to perform well in the various cited events.
The following comments are offered in the event that the SDT develops obligations for both synchronous generation and IBRs (contrary to
our recommendation above).
The fourth bullet of the SAR’s Project Scope states “protections and controls directly focused on the generator and its prime mover (e.g.,
overspeed, power-load imbalance, overvoltage, phase jump, overcurrent) or plant-level (e.g., voltage, current, frequency, phase, etc.)
have posed notable risks to BES reliability.” AEP does not agree with the proposed inclusion of overspeed and power-load imbalance, as
both must be present to protect against equipment damage. Even if their presence could at times pose a reliability risk to the system,
these protective functions need to be retained for the unit’s own protection and continuing availability. AEP recommends removing
overspeed and power-load imbalance from the SAR.
Requirement R3 in the current version of PRC-024 requires the Generator Owner to “document each known regulatory or equipment
limitation that prevents an applicable generating unit with generator frequency or voltage protective relays from meeting the relay
setting criteria in Requirements R1 or R2 including (but not limited to) study results, experience from an actual event, or manufacturer’s
advice.” Care should be taken to retain this provision in any new or revised standard.
Likes
0
Dislikes
0
Response
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
13
Thank you for the comment. The SAR has the option to create a new standard. This (and R3) will be passed along for consideration by
standard drafting team.
The team has addressed this comment in the redlined SAR to reflect the suggested changes.
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
No
Document Name
Comment
The scope states generator overcurrent and plant-level current should be addressed in this standard. Overcurrent is addressed by PRC025. It does not seem right to also include current in this standard. Other than the inclusion of overcurrent, the scope seems reasonable.
Likes
0
Dislikes
0
Response
Thank you for the comment. The team agrees that there is possible overlap with PRC-025 if overcurrent related trips are included in the
ride-through standard. As such, the team has modified the SAR to reflect the fact that PRC-025, and other selected relay setting
standards, may be impacted by the new standard and may need to be revised.
Kendra Buesgens - MRO - 1,2,3,4,5,6 - MRO
Answer
No
Document Name
Comment
The MRO NSRF in general agrees with both the concept and scope of this SAR. However, the MRO NSRF is voting no due to the following
concerns:
1. A reporting requirement that all trips or reductions in power output are reported by the GO to the TOP, BA, and RC.
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
14
The MRO NSRF disagrees with this deliverable. The Reliability Coordinator (RC), Balancing Authority (BA) and Transmission Operator
(TOP) should be responsible for determining the magnitude threshold and duration-of-time threshold for the Generator Owner (GO)/
Generator Operator (GOP) to report trips or reductions in power output. This will ensure that the RC, BA & TOP are not burdened by
notifications for trips/reductions that do not affect the Bulk Electrical System (BES) and ultimately take the RC’s, BA’s & TOP’s attention
away from matters of higher priority for ensuring the reliability of the BES. In addition, it is the NSRF belief that the RC, BA & TOP
currently has the ability request information about trips or reductions in power output from the GO/GOP under the regulatory framework
of NERC Reliability Standard IRO-010-4 Reliability Coordinator Data Specification and Collection & NERC Reliability Standard TOP-003-4 Operational Reliability Data.
Further, reductions in power will occur for a wide variety of reasons such as clouds passing over or the setting of the sun at a solar
generation facility, a drop in wind speed at a wind generation facility, wet coal, changes in condenser circulating water temperature or
discharge water temperature limits at a thermal plant, starting an additional large fan or pump, inlet air temperature changes to gas
turbines, reduced water flow at a hydro plant – none of these causes of power reduction would have any relation to PRC requirements
and no additional reporting other than that required by existing NERC Standard IRO-010 & TOP-003 requirements should be
necessary. The MRO NSRF believes this deliverable should say “A reporting requirement that all trips or reductions in power output in
response to grid disturbances are reported by the GO as required by the applicable TOP, BA, and RC.”
2. A requirement that abnormal reductions in active power (i.e., tripping from protections or notable reductions from controls) are
analyzed by the GO to develop a corrective action plan, if possible. Situations where corrective action plans are not able to be developed
shall be reported to the TOP, BA, and RC.
The MRO NSRF disagrees with this deliverable. The MRO NSRF believes that the ‘trip’ portion of this deliverable is already an enforceable
requirement under the regulatory framework of NERC Reliability Standard PRC-004-6 - Protection System Misoperation Identification and
Correction.
As written, ‘notable reductions from controls’, lacks the detail required to provide a standard drafting team (SDT) with proper direction to
develop a requirement(s). As this Standard Authorization Request (SAR) relates to dynamic ride-through performance of generators the
MRO NSRF would request that the SAR SDT add an example magnitude threshold and duration-of-time threshold for ‘notable reductions
from controls’. Adding the additional information will prevent any developed requirement(s) from overreaching beyond the intention of
this SAR.
3. A clear requirement that momentary cessation, or temporary ceasing of current injection during BPS fault events, is deemed
unacceptable performance for BES generating resources. Inverter-based generating resources employing momentary cessation shall
Consideration of Comments | Project 2020-02 Modifications to PRC-024
Generator Ride-through | May 2023
15
develop a corrective action to mitigate its use. Legacy facilities prior to the effective date of the standard should receive an exemption;
however, resources with a commercial operation date after the effective date of the standard (and possibly the PRC-024-3 implementation
date) shall be required to eliminate the use of momentary cessation within “ride through envelopes” (e.g., the existing PRC-024 “No Trip
Zone”).
The implementation date for NERC Reliability Standard PRC-024-3 — Frequency and Voltage Protection Settings for Generating Resources
(NERC PRC-024-3) is October 01, 2022. As stated by the SAR requestors:
• “The existing PRC-024-3 is an equipment settings standard focused solely on voltage and frequency protection. However, this
standard is serving little to no value for ensuring BPS-connected inverter-based resources remain connected and supporting the BPS
during grid disturbances.”
• “The purpose of this SAR is to retire PRC-024-3 and replace it with a performance-based ride-through standard that ensures
generators remain connected to the BPS during system disturbances.”
• “Retire PRC-024-3, and create a new PRC standard or completely overhaul and replace the existing PRC-024 standard.”
Based on these statements the MRO NSRF believes all generators with a commercial operation date prior to the effective date of
requirements to be developed based on this SAR should not have to comply or retrofit. It is clear that any requirements developed based
on this SAR will be different from the requirements of NERC PRC-024-3 and therefore the generators that need to comply should be
adjusted accordingly.
4. The performance-based standard should include documented equipment limitation exemptions similar to NERC PRC-024-3 R3 and
these should apply to all generator types rather than just carving out an exemption for the application of momentary cessation on legacy
inverter-based resources (IBR) existing prior to the effective date of the standard (and possible the PRC-024-3 implementation date). For
example, if an existing turbine has frequency limitations that do not meet the requirements of the new ride-through standard, no
corrective action plan should be necessary should the turbine trip in response to a frequency excursion outside of its capability. There
appears to be nothing in the SAR that addresses limitations of existing equipment other than that of legacy IBRs applying momentary
cessation.
5. The MRO NSRF believes that there is little justification for retiring NERC PRC-024-3 for synchronous generators and that any new
standard should be focused on IBR performance issues. If the scope is to “create a comprehensive, performance-based ride-through
standard with the purpose of ensuring BES generating resources remain connected and providing essential reliability services during grid
disturbances”, why would only PRC-024-3 be considered for retirement rather than to include the retirement of other relay setting
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standards such as PRC-025-2, which has the purpose to assure that load responsive relays are set to prevent unnecessary tripping during
system disturbances, and/or the elimination of GO applicability in PRC-026-1, which has the purpose to ensure that load-responsive relays
are expected to not trip in response to stable power swings during non-Fault conditions? The MRO NSRF believes that if a truly
comprehensive performance-based ride-through standard is created, then the regulatory burden of other relay setting standards
pertaining to how generator protection responds to grid disturbances should be eliminated by retiring PRC-025-2 and eliminating the
applicability of PRC-026-1 to Generator Owners. It seems that a comprehensive generator ride-through standard would apply to not only
24, 27, and 59 functions (PRC-024-3) but would also include trips of generating resources in response to 21, 50, 51, 51VR, 51VC, 67 (PRC025-2) and/or 21, 40, ,50, 51, 78 (PRC-026-1) function operations in response to grid disturbances.
Further, and accounting for the aforementioned comments, the MRO NSRF recommends the drafting team consider whether retiring
PRC-024-3 and replacing it with a performance-based ride-through standard may change, for example, the Generator no trip zones
settings. This action would potentially affect PRC-006, and the SAR should open its scope to contemplate potential changes to that
standard, and any other affected standard, if needed. This comment is to ensure the drafting team crafts a SAR with the necessary
scoping parameters to make changes to associated standards as needed.
6. A clear requirement that prolonged plant controller interactions that impede the ability of the resource to dynamically respond to the
grid disturbance and preclude the ability to fully provide essential reliability services are deemed unacceptable and should be addressed by
a corrective action plan.
This requirement seems to be focused on eliminating some of the undesirable IBR performance issues, but the wording of this deliverable
could be interpreted to apply to integrated plant or unit protection schemes that may indeed “impede the ability of the resource to
dynamically respond to grid disturbances” but are designed to protect the boiler or nuclear reactor from pressure or level excursions,
steam turbines from overspeed, operation at resonant frequencies or moisture intrusion, etc. GOs should be able to protect their
equipment from catastrophic damage without having to implement a corrective action plan should these protection or control features
impede dynamic response to grid disturbances.
Likes
1
Dislikes
Southern Indiana Gas and Electric Co., 3,5,6, Todd Anna
0
Response
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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17
1. The applicability of the defining of a thresh hold will be considered where applicable when drafting the standard in the
performance criteria. The SAR has been has been modified to reflect this quote. The information will be passed along to the
standard drafting team.
2. The team will look at PRC-004 and make sure there is no overlap, this SAR focusing on performance criteria IBRs. Thank you for the
proposal this will be reviewed in the standard drafting process when applicable.
3. This will be passed on to the drafting team, please refer to NAGF response to comment regarding legacy PRC-024 policy.
4. Refer to previous comment.
5. The team has considered the comments and have modified the SAR to reflect these specified standards and any other applicable
standards.
6. Please refer to comment 3D in NAGF response to comment. The redlined SAR reflects this change.
Israel Perez - Salt River Project - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
We do not agree with the proposed scope described in the SAR, as more clarification of expectations and deliverables are needed. The
proposed scope is not clear if the changes would require the installation of additional protection devices to our generators or switchyards
and if additional DCS/computer points need to be monitored. Would the changes require third-party generator studies and at what
frequency? We are concerned that these changes, which are still unclear, will require additional preventative tasks and specialized
personnel necessary to perform these tasks. If the disturbance in the grid is large enough, wouldn’t it be better for our generators to
disconnect and/or trip to prevent equipment damage? A unit/generator restart would have a faster turnover and would be more efficient
than having a damaged generator that motored because we couldn’t disconnect it from the large disturbance of the grid.
In addition, it seems that we must wait until “performance” metrics are outlined and how metrics meet baseline criteria. The reference
documents outline some of the criteria for measurement and submittal methods but not the full metric. The “ride through” criteria is
mentioned, as a “no trip zone” in the attached document but not a clear definition of achieving that target. The process for defining the
performance characteristics of a generation resources is not specified other than a system strength specification which we believe would
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require a separate criterion for each BES bus depending on the generation in the vicinity. It would be difficult to define and enforce and
even more difficult to monitor.
The events in southern California revealed that generation went into a current cessation mode during a frequency/voltage excursion and
PRC-024-3 covers this issue. The event would expand the scope from generation ride through to include any event where generation was
reduced or removed from service for say auxiliary systems being removed from service. This subject might fall under PRC-004. If the
tripping or reduction in generation is entirely unrelated to frequency or voltage, then we should have a separate standard that addresses
this issue.
The deliverable noted is a requirement for reporting all trips and abnormal reductions in active power. In our experience most
“abnormal” reductions are prime mover related. If it was intended to only require reporting an abnormal reduction or trip during a
system disturbance only, it is not clear that this deliverable is being met. We agree that generation outages due to frequency and voltage
excursions should be tracked but the scope of the SAR goes well beyond that point. Why take a perfectly fine standard that addresses a
known system issue and expand the scope into something that is not clearly defined. Consider expanding the scope of PRC-004 instead
and include operations that affect the output of a BES Generation source and leave PRC-024-3 as a frequency and voltage ride through
standard.
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Response
Thank you for the comment. The Project 2021-04 Modifications to PRC-002 drafting team is in charge of monitoring efforts. The drafting
team will coordinate with the PRC-002 team in the future pertaining to the necessary recording devices.
The metrics will be forwarded to the drafting team for their consideration.
This SAR team has modified this requirement and is now only applied to grid system events. The SAR has also been modified and
expanded to include IBR AUX systems.
Current cessation mode would be included under generation ride-through topic.
Joe Gatten - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
No
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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Document Name
Comment
Xcel Energy supports the comments offered by EEI, NAGF, and MRO NSRF.
Likes
0
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0
Response
Thank you for the comment. Please see response to MRO.
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
No
Document Name
Comment
Southern Company does not agree due to the following concerns:
1. A reporting requirement that all trips or reductions in power output are reported by the GO to the TOP, BA, and RC.
Southern Company disagrees with this deliverable. The RC, BA, and TOP should be responsible parties for determining the magnitude
threshold and duration-of-time thresholds GO/GOP to report trips or reductions in power output. This will ensure that the RC, BA &
TOP are not burdened by notifications for trips/reductions that do not affect the Bulk Electrical System (BES) and ultimately take their
attention away from matters of higher priority for ensuring the reliability of the BES. In addition, it is the belief of Southern Company that
the RC, BA & TOP already has the ability request information about trips or reductions in power output from the GO/GOP under the
regulatory framework of NERC Reliability Standard IRO-010-4 and TOP-003-4.
2. A requirement that abnormal reductions in active power (i.e., tripping from protections or notable reductions from controls) are
analyzed by the GO to develop a corrective action plan, if possible. Situations where corrective action plans are not able to be developed
shall be reported to the TOP, BA, and RC.
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Southern Company disagrees with this deliverable. Southern Company believes that the ‘trip’ portion of this deliverable is already an
enforceable requirement under the regulatory framework of NERC Reliability Standard PRC-004-6.
As written, ‘notable reductions from controls’, lacks the detail required to provide a standard drafting team (SDT) with proper direction to
develop a requirement(s). As this Standard Authorization Request (SAR) relates to dynamic ride-through performance of generators
Southern Company requests that the SAR SDT add an example magnitude threshold and duration-of-time threshold for ‘notable
reductions from controls’. Adding the additional information will prevent any developed requirement(s) from overreaching beyond the
intention of this SAR. The communication of unit derates, where necessary for system operation, is likely already being communicated
where specified by the RC/BA/TOP data specifications of IRO-010 and TOP-003.
3. A clear requirement that momentary cessation, or temporary ceasing of current injection during BPS fault events, is deemed
unacceptable performance for BES generating resources. Inverter-based generating resources employing momentary cessation shall
develop a corrective action to mitigate its use. Legacy facilities prior to the effective date of the standard should receive an exemption;
however, resources with a commercial operation date after the effective date of the standard (and possibly the PRC-024-3
implementation date) shall be required to eliminate the use of momentary cessation within “ride through envelopes” (e.g., the existing
PRC-024 “No Trip Zone”).
The opening statement is contrary to real world expectations that the generation resource is not allowed to protect its equipment for BES
system events. If this is the expectation, then the BES system should not be allowed to have fault events in the first place.
The implementation date for NERC Reliability Standard PRC-024-3 — Frequency and Voltage Protection Settings for Generating Resources
(NERC PRC-024-3) is October 01, 2022. As stated by the SAR requestors:
• “The existing PRC-024-3 is an equipment settings standard focused solely on voltage and frequency protection. However, this
standard is serving little to no value for ensuring BPS-connected inverter-based resources remain connected and supporting the BPS
during grid disturbances.”
• “The purpose of this SAR is to retire PRC-024-3 and replace it with a performance-based ride-through standard that ensures
generators remain connected to the BPS during system disturbances.”
• “Retire PRC-024-3, and create a new PRC standard or completely overhaul and replace the existing PRC-024 standard.”
Based on these statements Southern Company believes all generators with a commercial operation date prior to the effective date of
requirements to be developed based on this SAR should not have to comply or retrofit. It is clear that any requirements developed based
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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21
on this SAR will be different from the requirements of NERC PRC-024-3 and therefore the generators that need to comply should be
adjusted accordingly.
4. The premise that there have been notable concurrent tripping or performance from synchronous generating resources due to
frequency and voltage protection settings being too sensitive is flawed. There have not been increasing trends of synchronous machine
protection system misoperations to justify that premise. The application of a ride through standard for synchronous machine generating
plants was fully investigated during the original drafting effort of PRC-024 between 2008-2014. The conclusion of the standard drafting
team, after multiple drafts, extended comment and consideration of comments from industry, direct consultation with FERC by standard
drafting team members resulted in the realization that the standard could go no further than to specify a regions for restricting the
tripping of those generators by protective relays for voltage-time and frequency-time areas that would cause the units to not be tripped
for the majority of system events where the voltage or frequency was not normal. Further attempts to apply a ride through requirement
should be abandoned for synchronous machines to avoid wasting everyone’s time by having to restate why it is not feasible for that
generation type.
5. Further, there are limited modifications that can be made to the existing equipment to achieve the goal of 100% ride-thru ability to any
grid disturbance. Simply passing a regulation specifying it must be done does not change the ability of the equipment to do so. The
replacement of existing inverters is not feasible – the power ratings and voltage/current specifications of existing installed invertors do
not match the inverters offered today. The collection system of a PV plant cannot be reconfigured economically once it is in place.
6. Any additional ride through requirements should only be applicable to equipment placed in service after changes are made to this
standard which may require additional ride-thru capabilities for IBR plants. We suggest that the transmission interconnection
agreements be the proper method to assure that newly connected IBR facilities are built to maximize their ride through capability.
7. The lack of a specific grid disturbance for which generating resources are to be required to ride-through is problematic. If specific
disturbance characteristics are specified, the generating community might have a fighting chance to design systems to achieve the
goals. The application of global “you must ride through all grid disturbance” requirements to existing equipment not designed to do so is
ludicrous.
8. The SAR states that auxiliary systems and their protection systems are explicitly excluded. The sub-systems of a conventional
synchronous machine generating station are essential for the normal plant operation. Without many of those sub-systems, the main
generator cannot run. The sub-system may be essential to the mechanical operation of the turbine too. Any system disturbance that
causes any of those sub-systems to not be available will immediately affect the turbine/generator ability to run. The controls of the
generator and turbine are interlaced and interlinked with the sub-systems. They cannot be removed from affecting the entire unit
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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operation. In effect, they cannot be separated from the generator and the unit availability. During system disturbances where sustained
grid low voltage occurs, those sub-systems may or may not experience trouble. During the initial PRC-024 development, the Luminant
company reported that some low voltage contactors dropped out for low voltage conditions, and others did not. In subsequent grid low
voltage disturbances, it was observed that different sets of contactors dropped out. The indefinite response of magnetically sealed in
contactor behavior for low voltage conditions was one of the problems with any meaningful successful application of ride-through
standards to those types of facilities.
9. The SAR indicates that the desire of the standard revision is to address all possible causes of tripping and power
reductions. Addressing ALL POSSIBLE CAUSES is indefinite and unachievable. No failsafe system can be built to withstand all possible
causes.
10. With regard to the SAR question on alternatives, for which the SAR drafters included this text:
NERC has evaluated industry progress toward adopting the recommendations outlined in NERC guidelines, white papers, its prior Alerts,
and other industry efforts. NERC believes that a nationwide standard for consistent requirements for generating resource ride-through is
necessary to immediately address generating resource ride-through during grid disturbances moving forward.
Southern Company has implemented all possible inverter setting changes included in the two NERC alerts on the Loss of Solar
Resources. We note that several of our units have continued to react to major grid disturbances by ceasing to generate. The
communication of the adjustment of the settings, and the limitations to adjustments we have discerned, have been communicated to the
parties included in the NERC alert recommendations. It is for this reason we implore the SDT to look forward rather than backward with
change requirements. The electric grid is not in immediate imminent danger due to this current condition. The requirement of
maximizing IBR equipment connectivity and grid disturbance resolution support is best addressed through the transmission
interconnection requirements rather than through reliability standards.
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Response
Thank you for the comment.
1. The applicability of defining a threshold will be considered where applicable when drafting the standard in the performance
criteria.
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2. The team will look at PRC-004 and make sure there is no overlap, this SAR focusing on performance criteria IBRs. This will be
reviewed during the standard drafting process when applicable.
3. Please refer to MRO comment.
4. Concerns about the applicability of the proposed standards to synchronous generators will be passed along to standard drafting
team. The SAR has the option to create a new standard.
5. The exemption will be considered based on existing facilities capability and limitations.
6. The SAR includes this. The drafting team cannot support the ride-through requirement was solely covered by interconnection
agreement.
7. The performance requirements for disturbances will be determined by the standard drafting team when applicable.
8. The team agrees with the comments and recognizes the difficulty including auxiliary systems in this standard.
9. The SAR has been redlined to limit to trips or power reduction in response to grid events.
10. The standard is focused on performance and acknowledges grid disturbances.
Michael Johnson - Pacific Gas and Electric Company - 1,3,5 - WECC, Group Name PG&E All Segments
Answer
No
Document Name
Comment
PG&E agrees with the comments provided by EEI that there have been performance issues with Solar PV Inverter Based Resources (IBRs)
that need to be addressed, but as indicated by EEI, PG&E does not agree the replacement of PRC-024-3 is required to address those
issues.
The current PRC-024-2 Requirements have worked well for synchronous generators, and it is expected that PRC-024-3 will improve the
performance of those generators in maintaining the reliable operation of the Bulk Electric System (BES). As noted by EEI, there were
losses of synchronous generator in some of the six disturbances noted in the SAR, but none of those appeared to be unexpected, unusual,
or a result of non-compliance with the current PRC-024 Standard.
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PG&E personnel responsible for PRC-024 believe trying to add an entire set of additional Requirements for IBRs on top of the current PRC024 Requirements, or changing the Standard to be performance based for all generators would be extremely complex to implement and
maintain, and would not improve the reliability for synchronous generators. PG&E recommends IBR performance should be covered
under a new Standard specifically developed for the unique characteristics of IBRs.
Likes
0
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0
Response
Thank you for the comment. Please see response to EEI.
Joseph Amato - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer
No
Document Name
Comment
MidAmerican supports MRO NSRF and EEI comments.
Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to EEI.
Alan Kloster - Evergy - 1,3,5,6 - MRO
Answer
No
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #1.
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Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to EEI.
Christine Kane - WEC Energy Group, Inc. - 3,4,5,6, Group Name WEC Energy Group
Answer
No
Document Name
Comment
WEC Energy Group is voting no due to the following concerns:
•
•
•
•
•
“Purpose or Goal” section calls for complete replacement of PRC-024-3 to ensure generators remain connected during
disturbances, but the “Industry Need” section clearly identifies this issue applies to IBR only. Industry can agree that current
standard as is, is very well effective for traditional synchronous generating resources, therefore WEC believes that standard does
not need to be rewritten but rather modified to cover specific IBR issues. WEC believes that statement “… notable concurrent
tripping or performance from synchronous generating resources…” is not well supported by data from recent disturbances.
Proposed “performance based” term needs to be better defined within the SAR.
If industry recommendation is to include other protective elements or control systems, then it should be done separately and new
standards should be developed. Good examples are PRC-025 and PRC-026.
Some of the “possible causes of tripping and power reductions” listed in SAR are load responsive in nature, therefore should be
addressed within existing Standards that cover load-responsive requirements.
“Detailed Description” section indicates that momentary cessation is deemed unacceptable. Did the SAR requester confirm with
all equipment manufacturers that momentary cassation can completely be eliminated? There are still inverter manufacturers that
produce equipment with momentary cessation in their design because of current limiting components. The SAR suggest a
corrective action plan to be developed to mitigate the issue. What if issue cannot be mitigated?
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Thank you for the comment. Concerns about the applicability of the proposed standards to synchronous generators will be passed along
to standard drafting team. The SAR has the option to create a new standard.
By “performance based” term this SAR extends the scope of NERC PRC-024-3 from a protective settings standard to defining performance
requirements of BES generating resources remain connected and providing essential reliability services during grid disturbances,
something stated within the project scope.
The drafting team does not think any “possible causes of tripping and power reductions” listed in this SAR are load driven. It is focused on
BES Generating Resources. PRC-025 and PRC-026 have been added to the SAR for future review.
Momentary cessation of legacy units will also be considered by the standards drafting team.
Daniela Atanasovski - APS - Arizona Public Service Co. - 1,3,5,6
Answer
No
Document Name
Comment
AZPS agrees with the following comments that were submitted by EEI on behalf of its members:
“The incidental operation of synchronous generators during some of the identified six NERC disturbance reports do not warrant the
creation of a new ride through Reliability Standard replacing PRC-024-3 because the performance of most of the affected resources,
outside of the solar PV resources, performed as designed and expected, and met the requirements of PRC-024-3.
While there were losses of synchronous generators in some of the six disturbance reports cited in the proposed SAR, none appear to be
unexpected, unusual or the result of non-compliance with PRC-024”
“Additionally, if the intent of the SAR is to “create a comprehensive, performance-based ride-through standard,” development of a
standard would need to account for retirement of other relay setting standards such as PRC-025-2 and PRC-026-1, to prevent duplicative
requirements and compliance obligations.”
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Response
Thank you for the comment. Please see response to EEI.
Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer
No
Document Name
Comment
Minnesota Power supports EEI’s comments for this question.
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0
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0
Response
Thank you for the comment. Please see response to EEI.
John Pearson - ISO New England, Inc. - 2
Answer
No
Document Name
Comment
In describing the scope, the SAR states “The scope of the ride-through standard shall explicitly exclude auxiliary systems and their
protection systems. Abnormal performance or unexpected tripping of these protections do not pose a systemic BES reliability risk.
However, protections and controls directly focused on the generator and its prime mover (e.g., overspeed, power-load imbalance,
overvoltage, phase jump, overcurrent) or plant-level (e.g., voltage, current, frequency, phase, etc.) have posed notable risks to BES
reliability and should be addressed directly in this standard.” However, auxiliary systems that in turn unexpectedly trip an entire plant
pose a risk to reliability. While these systems should not be explicitly modeled, the OP, BA and RC should be in a position to understand
when a facility will trip. As an absolute minimum, this information should be required from facilities currently being planned and installed.
Likes
0
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Dislikes
0
Response
Thank you for the comment. The updated SAR has resolved and addressed this comment.
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF provides the following comments for consideration:
1. The NAGF believes that there is little justification for retiring PRC-024-3 for synchronous generators and that any new standard should
be focused on IBR performance issues. Note that GOs have invested tremendous effort and money in achieving compliance with the PRC
standards and are achieving the desired enhancement of BES reliability. Replacing them with something substantially different would
require significant expenditures with no identifiable benefit. Any new standard should address only gaps in existing standards, as
opposed to tearing down and rebuilding them.
2.
Project Scope Comments:
a) Second Bullet: “Creates a comprehensive, performance-based ride-through standard with the purpose of ensuring BES generating
resources remain connected and providing essential reliability services during grid disturbances.”
The NAGF recommends that other relay-setting PRC standards be considered for retirement/modification beyond PRC-024-3. For
example, PRC-025-2, which has the purpose to assure that load responsive relays are set to prevent unnecessary tripping during system
disturbances, and PRC-026-1, which has the purpose to ensure that load-responsive relays are expected to not trip in response to stable
power swings during non-Fault conditions. The NAGF believes that if a truly comprehensive performance-based ride-through standard is
created, then the regulatory burden of other relay setting PRC standards pertaining to how generator protection responds to grid
disturbances should be reviewed and incorporated. It seems that a comprehensive generator ride-through standard would apply to not
only 24, 27, and 59 functions (PRC-024-3) but would also include trips of generating resources in response to 21, 50, 51, 51VR, 51VC, 67
(PRC-025-2) and/or 21, 40, ,50, 51, 78 (PRC-026-1) function operations in response to grid disturbances.
3.
Detailed Description of Project Deliverables Comments:
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a)
Bullet #3: “A reporting requirement that all trips or reductions in power output are reported by the GO to the TOP, BA, and RC.”
The NAGF believes that this statement is too vague or is stated imprecisely for this deliverable. Reductions in power will occur for a wide
variety of reasons such as clouds passing over or the setting of the sun at a solar farm, a drop in wind speed, wet coal, changes in
condenser circulating water temperature or discharge water temperature limits at a thermal plant, starting an additional large fan or
pump, inlet air temperature changes to gas turbines, reduced water flow at a hydro plant – none of these causes of power reduction
would have any relation to PRC requirements and no additional reporting other than that required by existing TOP requirements should
be necessary. We believe this deliverable should be more focused, such as “A reporting requirement that all trips or reductions in power
output in response to grid disturbances are reported by the GO to the TOP, BA, and RC.”
b) Bullet #4: “A requirement that abnormal reductions in active power (i.e., tripping from protections or notable reductions from
controls) are analyzed by the GO to develop a corrective action plan, if possible. Situations where corrective action plans are not able to
be developed shall be reported to the TOP, BA, and RC.”
The NAGF believes that such trip analysis and corrective actions are already addressed by PRC-004 and therefore this
deliverable/requirement is redundant.
c) Bullet #5: “Legacy facilities prior to the effective date of the standard should receive an exemption; however, resources with a
commercial operation date after the effective date of the standard (and possibly the PRC-024-3 implementation date) shall be required to
eliminate the use of momentary cessation within “ride through envelopes” (e.g., the existing PRC-024 “No Trip Zone”).
The NAGF supports the exemption for legacy IBR facilities. The NAGF recommends that the performance-based standard include
documented equipment limitation exemptions similar to PRC-024-3 R3 and these should apply to all generator types rather than just
carving out an exemption for the application of momentary cessation on legacy IBRs existing prior to the effective date of the standard
(and possible the PRC-024-3 implementation date). For example, if an existing turbine has frequency limitations that do not meet the
requirements of the new ride-through standard, no corrective action plan should be necessary should the turbine trip in response to a
frequency excursion outside of its capability. There appears to be nothing in the SAR that addresses limitations of existing equipment
other than that of legacy IBRs applying momentary cessation.
d) Bullet #7: “A clear requirement that prolonged plant controller interactions that impede the ability of the resource to dynamically
respond to the grid disturbance and preclude the ability to fully provide essential reliability services are deemed unacceptable and should
be addressed by a corrective action plan.”
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The NAGF is concerned with the potential ambiguity associated with this deliverable. This deliverable seems to be focused on eliminating
some of the undesirable IBR performance issues, but the wording of this deliverable could be interpreted to apply to integrated plant or
unit protection schemes that may indeed “impede the ability of the resource to dynamically respond to grid disturbances” but are
designed to protect the boiler or nuclear reactor from pressure or level excursions, steam turbines from overspeed, operation at resonant
frequencies or moisture intrusion, etc. Generator Owners should be able to protect their equipment from catastrophic damage without
having to implement a corrective action plan should these protection or control features impede dynamic response to grid disturbances.
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0
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0
Response
Thank you for the comment. Concerns about the applicability of the proposed standards to synchronous generators will be passed along
to standard drafting team. The SAR has the option to create a new standard.
The team has considered the comments and modified the SAR to reflect these specified standards and any other applicable standards.
The SAR has been modified to reflect the changes to 3A as suggested. Concerns regarding PRC-004 and PRC-024-3 legacy exemption
retention will be passed along to the standard drafting team to be considered.
3D was reflected in redlines to SAR. This comment will be reviewed while drafting the standard.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer
No
Document Name
Comment
On the bottom of page 2, the SAR states: “The scope of protections and controls involved in this ride-through standard shall include all
generator protections and controls that affect the electrical output of the BES generating resource or plant. To be clear, the project
should specify the protections and controls in scope of the ride-through performance and define the term ride-through, as necessary.”
Will the scope include requirements that developers/GOs of any new interconnection projects be required to provide protection and
control models to the TO or PC? The SRC recommends that the SDT indicate all “protection and control equipment, including auxiliary
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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31
equipment” that will affect the ride-through capabilities of the generator during disturbances. The SDT should identify the auxiliary
systems that the ride-through should not affect.
On page 3, under Detailed Description, the SAR calls for “A requirement that abnormal reductions in active power (i.e., tripping from
protections or notable reductions from controls) are analyzed by the GO to develop a corrective action plan, if possible. Situations where
corrective action plans are not able to be developed shall be reported to the TOP, BA, and RC.”
This description reads much broader than what is described in the SAR purpose. In the purpose it is directed specifically towards “fail to
ride through system events”. Is the intent of the SAR scope to create a requirement to report reductions in active energy which go
beyond “fail to ride through system events” and include abnormal reductions of any cause? The SRC requests the SAR DT clarify the
project scope.
On the bottom of page 3, the SAR states, “Legacy facilities prior to the effective date of the standard should receive an exemption;
however, resources with a commercial operation date after the effective date of the standard.” We are concerned that there will be
significant amounts of IBR facilities that will be exempt from these requirements. In addition, this seems to be at odds with the“all”
language contained in the last bullet on the bottom of page 2 (and as mentioned in the SRC comments above).
In 2018, a SAR was introduced and denied by the Standards Committee to correct momentary cessation of IBRs that had no such
exemption because of the risks existing facilities were causing on the BES. This SAR does not propose any solutions to address that
risk. We recognize that there are some IBR installations which pre-date the technology to meet the SAR purpose. However there are
already numerous amounts of IBRs in operation which can adopt new technology to meet the SAR’s purpose. A blanket exemption
should not be a part of the standards and instead some form of exemption process should be utilized. Further between the time this
standard may be complete and the time it takes effect due to the need for regulatory approval, which may be over two years. Numerous
additional new installation of IBRs would become grandfathered which certainly can meet the ride through requirements. The SRC
recommends exemptions be limited to technical infeasibility.
Likes
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0
Response
Thank you for your comment. It will be considered when the standard is drafted. Models are not within the scope of this drafting team
since this a performance standard. This question more refers to MOD-026 and MOD-027
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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32
The drafting team understands that the auxiliary systems are critical. However, considering that complexity of identifying the auxiliary
equipment to be included in the standard, it has been decided not to include them in the scope. The team assumes that the equipment
owner will take the necessary steps to make sure that the auxiliary systems will not trip unexpectedly to degrade the performance of the
generation resources during systems events. The drafting team has discussed this point and will be discussing this more in-depth when
drafting the standard.
The drafting team does not intend to create a requirement that goes beyond “riding through system events”. The team agrees with your
concern and modified the SAR accordingly to only be for grid-related disturbances.
The team shares your concern related to legacy equipment and modified the SAR to reflect the comment regarding legacy systems and
exemptions.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
While EEI agrees in principal that that there have been performance issues, primarily with Solar PV Inverter Based Resources (IBRs), that
need to be addressed, we do not support the retirement of PRC-024.
While there were losses of synchronous generators in some of the six disturbance reports cited in the proposed SAR, none appear to be
unexpected, unusual or the result of non-compliance with PRC-024. As noted below, all of these six events linked within this SAR indicate
solar PV performance problems, not synchronous generator problems.
Additionally, if the intent of the SAR is to “create a comprehensive, performance-based ride-through standard,” development of a
standard would need to account for retirement of other relay setting standards such as PRC-025-2 and PRC-026-1, to prevent duplicative
requirements and compliance obligations.
For these reasons, we do not support the retirement of PRC-024-3. However, we offer an alternative approach in our response to
question 2.
NERC 2021 California Disturbances Report (2022)
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•
•
•
•
June 24, 2021 – Loss of 765MW of solar PV resources (27 facilities) and 145MW of DERs (no synchronous resources lost).
July 4, 2021 – Loss of 605MW of solar PV resources (33 facilities) and 46MW of DERs; 125MW; additionally, a single 125MW CT
tripped due to two defective sensors as reported by the GO.
July 28, 2021 – Loss of 511MW of solar PV resources (27 facilities) and 46MW of DERs (no synchronous resources lost).
August 25, 2021 – Loss of 583MW of solar PV resources (30 facilities) and 212MW gas turbine tripped as a result of a correct
operation of a RAS scheme. An additional gas turbine tripped during this event due to the failure of the excitation system (failed
diodes). As stated in the report, the diodes were redundant but can only be detected during manual inspection. It is speculated
that the redundant diodes failed as a result of the event, GO has indicated they will increase their inspections to avoid future
failures.
NERC Odessa Disturbance Report (2021)
•
•
May 9, 2021 Event – Initial fault occurred during CT startup testing when a surge arrester failed taking out one CT and causing
another to run back for a total loss of 192MW. After this event 1112MW of solar PV output was lost, in addition 36MW of output
from 4 wind power plants.
June 26, 2021 Event – Failed H-Frame structure causes the loss of 518MW at 5 PV facilities.
NERC San Fernando Disturbance Report (2020) July 7, 2020
•
Static wire on a 230kV line failed causing the tripping of two lines on a double circuit tower. In addition, a nearby 230kV line relay
mis operated. The result was the initial loss of 205MW of solar PV output. When trying to restore the lines, the second line
tripped out causing the larger event, the loss of 1000MW of solar PV output (no synchronous resources lost).
NERC Palmdale Roost and Angeles Forest Disturbances Report (2019)
•
•
April 20, 2018 (Angeles Forest) – A splice on a 500kV line failed causing a B-C phase fault which was cleared within 2.6 cycles. The
fault caused the loss of 860MW of solar PV output in CAISO and 17MW in LADWP. In addition, a natural gas turbine tripped as a
result of the fault. The report indicates the plan tripped on low fuel pressure causing the natural gas turbine to trip and the
reduced output of a combined cycle steam generator to reduce output to 75MW for a total loss of 200MW. There was an
additional loss of 130MW of DER output.
May 11, 2018 (Palmdale Roost) – The disturbance was caused by a bird nest on a 500kV line that caused a line flashover (B phase
to ground fault). As a result, there was a loss of 630MW of solar PV output in CAISO, 48MW in LADWP and 33MW in
IID. Additionally, there was 100MW of DER output lost (no indication of any synchronous generation lost during this event).
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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NERC Canyon 2 Fire Disturbance Report (2018)
•
Canyon 2 Fire Disturbance, Oct. 9, 2017 – Two transmission lines faulted near Anaheim Hills, CA. The first fault occurred on a
220kV line at 12:12 PM and the second occurred at 12:14 PM on a 500kV line. The first fault resulted in the reduction of 682MW
of solar PV output, which the second resulted in the reduction of 937MW of solar PV output (no indication that any synchronous
generation was lost).
NERC Blue Cut Fire Disturbance Report (2017)
•
On Aug. 16, 2016 AM the Blue Cut fire began in Cajon Pass, CA. As a result of the widespread fire SCE experience thirteen 500kV
line faults and LADWP experienced two 287kV faults. Four of the fault events resulted in the loss of 1,200MW of solar PV output
(no indication any synchronous generation was lost).
Likes
0
Dislikes
0
Response
Thank you for the comment. Concerns about the applicability of the proposed standards to synchronous generators will be passed along
to standard drafting team. The SAR has the option to create a new standard. The team has considered the comments and modified the
SAR to reflect these specified standards and any other applicable standards.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
No
Document Name
Comment
Ride-through is not a defined term in the NERC Glossary of Terms nor NPCC Glossary of Terms. The objective of the SAR is commendable,
however the specific characteristics of the disturbances addressed by the new standard needs to be carefully defined. Usually the
magnitude and duration of grid disturbances should be defined. Particular contingencies should be specified and studied to ensure those
applicable reasonable foreseeable disturbances can be assessed and addressed.
Likes
0
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Dislikes
0
Response
Thank you for your comment. The existing SAR allows the standard drafting team to develop a term for the NERC Glossary to include the
definition of "ride-through" as well as other relevant terms that might be used in the standard. The drafting team also agrees that
specification of disturbance characteristics (e.g., type of fault, duration, voltage class, etc.) will be a critical part of the ride-through
standard drafting process.
Dana Showalter - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Document Name
Comment
Regarding the 4th bullet in the “Project Scope” section, ERCOT believes the SAR should not exclude auxiliary systems that could impact
the facility’s continued operation. The SDT should review the various types of auxiliary systems in use at in-scope facilities and determine
whether to exclude any of them. ERCOT suggests revising the 4th bullet as follows:
This standard should address protections and controls directly focused on the generator and its prime mover (e.g., overspeed, power-load
imbalance, overvoltage, phase jump, overcurrent) or at the plant level (e.g., voltage, current, frequency, phase, etc.) because they pose
notable risks to BES reliability. The SDT will determine whether this ride-through standard may exclude auxiliary systems that do not
impact the facility’s ability to maintain real and reactive power during a disturbance.
Regarding the 2nd sub-bullet in the “Detailed Description” section, ERCOT suggests the standard contain a requirement for a GO to report
only trips or reductions in real power or improper reactive power response (trips or reductions within some threshold of the performance
parameters established in the standard).
Regarding the 3rd sub-bullet in the “Detailed Description” section, ERCOT suggests clarifying the term “abnormal” to include trips and
reductions in real power or improper reactive power response failing to meet the performance parameters established in the standard.
Further, ERCOT suggests the SDT include a requirement for the GO to develop and implement a corrective action plan (CAP) or report to
its TOP, BA and RC any CAP it cannot implement due to technical infeasibility. Finally, ERCOT suggests removing “if possible” because
ERCOT’s proposed language (above) addresses situations where the GO cannot implement the CAP due to technical infeasibility.
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36
Accordingly, ERCOT suggests modifying the 2nd and 3rd sub-bullets as follows:
•
•
•
•
•
The proposed deliverable is a new NERC standard (or significant overhaul and revision of PRC-024-3) that includes the following
key elements:
...
A requirement for a GO to report to its TOP, BA and RC trips or reductions in real power or improper reactive power response (i.e.,
trips or reductions within a threshold of the performance parameters established in the standard).
A requirement for a GO to: (a) analyze abnormal trips or reductions in real power or improper reactive power response (i.e.,
tripping from protections, notable reductions from controls, trips or reductions in real power or improper reactive power
response failing to meet performance standards established in this standard); and (b) develop and implement a corrective action
plan (CAP). If a GO cannot implement a CAP because it is not technical feasible to do so, the GO must report that fact to its TOP,
BA, and RC.
...
Regarding the 4th sub-bullet in the “Detailed Description” section, ERCOT agrees with the SRC that the project should not exempt legacy
facilities. Exempting legacy facilities will not address the reliability-related need this project addresses.
Likes
0
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0
Response
Thank you for the comments.
The Auxiliary Systems concern has been addressed in the redlined SAR.
The SAR has been modified to address reporting concerns. Thresholds may be addressed by the drafting team.
Legacy systems should only be exempt if, after engineering analysis, corrective action is not possible or practical (need to define
practical). The language was modified to reflect the changes regarding implementation of a Corrective Action Plan and removed "if
possible".
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer
No
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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Document Name
Comment
Please address and clearly explain the relationship between the two SARs (“Revision of relevant Reliability Standards to include
applicability of transmission-connected dynamic reactive resources” approved in April, and “Generator Ride-Through Standard (PRC-0243 Replacement)”. Failure to provide this clarification will result in confusion between intents and requirements for different types of
devices and may not clearly align with the earlier whitepapers and recommendations.
Additionally-please clarify that Synchronous Condensers, STATCOMs, SVCs and HVDC are not considered generator protection and control
systems and should not be included in this standard. If Synchronous Condensers, STATCOMs, SVCs and HVDC are intended to be included
in the standard, it needs to be revised to reflect that and include proper terminology, consideration of capability, and requirements
specific to transmission-connected dynamic reactive power resources as opposed to generation resources.
Likes
0
Dislikes
0
Response
Thank you for the comment. The team has had an additional SAR added to the project to cover the Generation Ride-through. The original
SAR will be included with the Ride-through SAR for the team to use when drafting the standard(s) for this project. Each of the two SARs
will be used when addressing their respective aspects of this project.
Devices that are only reactive devices are not included in the current SAR. This comment pertains to the first SAR of this project and not
the current SAR.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6, Group Name FE Voter
Answer
No
Document Name
Comment
FirstEnergy supports EEI’s comments.
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to EEI.
David Jendras - Ameren - Ameren Services - 1,3,6
Answer
No
Document Name
Comment
Ameren agrees with EEI's comments. A new ride through standard should be created for IBR's only. The performance issues were with
IBR's not synchronous generators.
Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to EEI.
LaKenya VanNorman - Florida Municipal Power Agency - 3,4,5,6 - SERC, Group Name Florida Municipal Power Agency (FMPA)
Answer
No
Document Name
Comment
Florida Municipal Power Agency (FMPA) supports comments submitted by NAGF.
Likes
0
Dislikes
0
Response
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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39
Thank you for the comment. Please see response to NAGF.
Carl Pineault - Hydro-Qu?bec Production - 1,5
Answer
Yes
Document Name
Comment
At this point, it is hard to disagree with this project since it is still broad and vague
Likes
0
Dislikes
0
Response
Thank you for the comment.
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
BPA supports revision of the current PRC-024-3 rather than creation of a new reliability standard. BPA believes the project will raise the
bar on protection of BPS-connected inverter-based resources.
Likes
0
Dislikes
0
Response
Thank you for the comment.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Yes
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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40
Document Name
Comment
Texas RE agrees with the need for this project to develop a comprehensive generator “ride-through” standard in lieu of the current PRC024’s focus solely on voltage and frequency protection settings. As the September 2021 Joint Odessa Disturbance Report for Texas
Events on May 9, 2021 and June 26, 2021 (“Odessa Disturbance Report”) highlighted, “the systematic nature of [Inverter-Based Resource
tripping or cessation] events across multiple interconnections and a wide range of facilities, many of which are recently energized,
warrants significant enhancements to the NERC Reliability Standards to address gaps in BES inverter-based resources.” (Odessa
Disturbance Report, at 29). These recommendations included the need for developing a new generator protection and control ridethrough standard to replace the current PRC-024-3 to address continued examples of widespread tripping that are not addressed by the
current PRC-024-3 requirements. Texas RE appreciates that the SAR provides an approach to capture the range of performance issues
(PLL loss of synchronism, subcycle ac overvoltage protection, dc reverse current, and wind converter crowbar failures) that have resulted
in widespread tripping incidents across a number of interconnections, including the ERCOT Interconnection.
It further recommended that NERC do so on an expedited timeframe. Texas RE notes that this call of expedited action is even more
pressing given the recent tripping of significant inverter-based resources in the ERCOT Interconnection earlier this year, continuing a
pattern of generator performance issues in this area. NERC has highlighted grid transformation issues as the single greatest risk to grid
reliability at the current time. Texas RE appreciates the SDT’s important role, care, and commitment to addressing these performance
issues in this project.
Likes
0
Dislikes
0
Response
Thank you for your comment and the timeline input recommendation.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC Regional Standards Committee
Answer
Yes
Document Name
Comment
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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41
The NPCC Regional Standards Committee agrees with the proposed scope as described in the SAR.
Likes
0
Dislikes
0
Response
Thank you for the comment.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Thank you for the response.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
The Project 2020-02 webpage reflects that the initial project SAR, posted for industry comments on 3/30/2020, was revised and
subsequently accepted by the NERC Standards Committee on 4/20/2022. A redline of the SAR accepted by the Standards Committee in
April 2022 vs. the initial SAR posted in March 2020 is posted on the project page. It appears that a different Project 2020-02 SAR
(prepared by NERC executives and staff) was presented to and accepted by the NERC Standards Committee a month later, on
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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5/18/2022. We suggest that a redline of the SAR accepted by the Standards Committee in May 2022 vs. the SAR accepted by the
Standards Committee in April 2022 (or the initial SAR posted in March 2020) be added to the project page. It is not clear why the SAR
submitted by the Chair of the System Analysis & Modeling Subcommittee and accepted by the Standards Committee in April 2022 was
“abandoned” a month later to be replaced by the SAR submitted by NERC.
Likes
0
Dislikes
0
Response
Thank you for your comment and support. The team will proceed with the two SARs assigned by the SC and will be considered when
drafting the standards.
Nazra Gladu - Manitoba Hydro - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you for the response.
Leonard Kula - Independent Electricity System Operator - 2
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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Response
Thank you for the response.
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC Entity Monitoring
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you for the response.
Jennie Wike - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6 - WECC, Group Name Tacoma Power
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you for the response.
Isidoro Behar - Long Island Power Authority - 1
Answer
Yes
Document Name
Comment
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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44
Likes
0
Dislikes
0
Response
Thank you for the response.
Gail Elliott - International Transmission Company Holdings Corporation - NA - Not Applicable - MRO,RF
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you for the response.
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you for the response.
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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45
2. Provide any additional comments for the drafting team to consider, if desired.
LaKenya VanNorman - Florida Municipal Power Agency - 3,4,5,6 - SERC, Group Name Florida Municipal Power Agency (FMPA)
Answer
Document Name
Comment
Florida Municipal Power Agency (FMPA) supports comments submitted by NAGF.
Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to NAGF.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6, Group Name FE Voter
Answer
Document Name
Comment
While FirstEnergy does agree that an assessment needs to be conducted to ensure reliability of the BES due to the changing mix of
generating resources, we do not agree that a reliability standard should result in additional penalties for a GO if generating capacity
requirements are not met due to a fuel shortage caused by unforeseen events. FirstEnergy generators already participate in the PJM
capacity market and are required to provide generating capacity based on summer ICAP testing results. A generator is assessed financial
penalties by PJM if it cannot meet its generating capacity requirements and therefore, we caution against a double jeopardy situation.
We also suggest the RC and BA, not the GO, should be responsible for developing a CAP if generation capacity demands are not met
during periods of constrained resources. It is the responsibility of the Transmission Grid Operator (e.g., PJM), not the GO, to ensure that
adequate generating resources are available during periods of constrained resources. Operating characteristics of IRBs are the cause of
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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constrained resources and mitigation actions over-and-above PJM generating capacity requirements should not be placed on fossil
generation resources.
Further, FirstEnergy supports EEI’s comments, which states:
As an alternative to the proposed PRC-024 SAR, EEI suggests that a new SAR be developed to address performance issues specifically
affecting IBRs. This new SAR could leverage key scope items from this proposed SAR to create a new performance- based NERC Reliability
Standard that is focused on IBRs. As a suggested scope, we propose modifying this SAR as follows:
-- Trips or reductions in active power that occur because the IBR does not operate as expected (excludes cloud cover, setting sun, etc.),
but not associated with protection system trips, (PRC-004 already addresses protection system tripping) are to be analyzed by the GO to
develop a corrective action plan. Situations where an issue cannot be corrected, the GO shall develop a report detailing the limitations of
the IBR and provide it to the responsible TOP, BA, and RC.
-- Momentary cessation, or temporary ceasing of current injection in response to grid disturbances, is deemed unacceptable for BES
generating resources. Inverter-based generating resources employing momentary cessation shall develop a corrective action to mitigate
its use unless the issue cannot be corrected. Legacy facilities prior to the effective date of the standard should receive an exemption;
however, resources with a commercial operation date after the effective date of the standard shall be required to eliminate the use of
momentary cessation during system transient disturbances where the system voltage or frequency falls within the “No Trip Zone”
provided in PRC-024-3, which is subject to enforcement October 1, 2022.
-- Include the development of new terms to address terms specific to IBRs or where commonly used industry terms have created some
confusion for IBR owners. E.g., No Trip Zone, trip, momentary cessation, and any other relevant terms that may require clarification
within the NERC Glossary of Terms.
-- Prolonged IBR controller interactions that impede the ability of the resource to respond dynamically to the grid disturbance and
preclude the ability to provide essential reliability services are deemed unacceptable and should be addressed by a corrective action
plan. In situation where the GO has determined the issue cannot be corrected, a report shall be developed detailing the IBR limitation
and provide it to the responsible TOP, BA and RC.
that
--If the TOP, BA, or RC inform the GO/IBR owner of a tripping occurrence, cessation event, or IBR controller interactions
are not reported or otherwise identified by the GO/IBR Owner, the responsible GO shall be responsible for analyzing
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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the
BA, and
Likes
facility’s performance during the event, developing a corrective action plan, and making this available to the TOP,
RC or in the situation where the issue cannot be corrected, informing the TOP, BA and RC.
0
Dislikes
0
Response
Thank you for the comment. The team has redlined to the SAR to only include systems disturbance or system electrical events. Please also
see response to EEI.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
The current PRC-024-2, “No Trip Zone” is very clear and easy to understand for frequency and voltage parameters. The SAR Requesters’
logic and SAR details appear to be pretty thorough, with the exception of replacing the “No Trip Zone” with “fault ride-through
capabilities” as proposed in the revised SAR (dated 4/28/2022). We recommend the SAR Requesters/SAR Drafting Team expand on the
proposal to eliminate “No Trip Zone” requirements, and expand the discussion regarding the replacement “fault ride-through
capabilities”.
The revised SAR language seems to suggest that synchronous generating resources suffer from mis-trips and mis-application of the
standard due to deficiencies identified in PRC-024-3 to the same degree that inverter-based resources do. None of the six disturbance
reports cited as technical justification for the SAR reference loss of synchronous generation caused by an inadequate or missing
requirement within PRC-024-3. From a reliability perspective, while GO/GOPs of IBRs stand to benefit from a replacement/overhaul of
PRC-024-3, there is no clear benefit to GO/GOPs of traditional synchronous generating resources. We recommend that the SAR language
be revised to clearly delineate the current issues with synchronous generation resources and the current issues with IBRs driving this
proposed standard modification, and how the changes are impacting each technology.
The proposed scope explicitly excludes auxiliary systems with the rationale that “abnormal performance or unexpected tripping of these
protections do not pose a systemic BES reliability risk” (Page 3, “Project Scope”, 4th bullet point). Components of auxiliary systems like
unit auxiliary transformers (UATs) typically feature protection that are capable of taking a generator offline. Given this, there may be a
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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48
heightened reliability risk if auxiliary equipment are not subject to the same requirements of the proposed standard as generator
protection and controls. Auxiliary transformers (and BES GSUs) were added to the applicable equipment scope in the revision from PRC024-2 to PRC-024-3, so an explanation is requested for why this inclusion is not being preserved.
Likes
0
Dislikes
0
Response
Thank you for the comment. The team has added the language for IBR aux systems and excluded traditional generation.
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer
Document Name
Comment
Please clarify momentary cessation of “current injection during BPS fault events.”
Re: this SAR please explain if current injection refers to active current, reactive current or both?
Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to EEI.
Dana Showalter - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT provides the following additional comments:
Consideration of Comments | Project 2020-02 Modifications to PRC-024
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49
The SAR specifically identifies protections/controls posing risks to BES reliability. The proposed standard should not specify criteria for
every potential quantity that may trigger a trip. Specifying voltage and frequency envelopes should suffice. Operating within those
envelopes should not trigger any other plant control or protection to trip.
Not having high-resolution data limits the ability to identify the root cause of the events referenced in the SAR. High-resolution data,
including data from phasor measurement units (PMUs), digital fault recorders (DFRs), and inverter-based oscillography, is critical to
identify the root cause of disturbance events and, as such, necessary to develop a CAP. Additionally, high resolution data allows a better
understanding of the interaction between local wind turbine ride-through control versus the facility plant controller. ERCOT believes this
SAR should require data recording relating to voltage ride through and to add appropriate language to PRC-002-2.
Finally, ERCOT suggests the SDT consider IEEE 2800 when drafting a proposed standard.
Likes
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Dislikes
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Response
Thank you for the comment. The team has redlined the SAR to reflect these changes regarding data recording.
Gail Elliott - International Transmission Company Holdings Corporation - NA - Not Applicable - MRO,RF
Answer
Document Name
Comment
In place of GOs only notifying the PC and TP when they can’t meet the ride-through requirement or upon request, GOs should be required
to periodically (annually?) provide, or confirm no changes to, their generator protection trip settings to the PC and TP.
Likes
0
Dislikes
0
Response
Thank you for the comment. This will be passed to the standard drafting team for consideration.
Constantin Chitescu - Ontario Power Generation Inc. - 5
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50
Answer
Document Name
Comment
If an attempt is made to define the ride through then it should consider the Bulk Electrical System (BES) as well as all the
applicable/foreseeable generating resources that can potentially impact the BES.
A suggestion is made to use, consistently, just the Bulk Electrical System (BES) acronym and not to loosely interchange with BPS whose
meaning is different than BES in the NPCC region (Bulk Power System as determined by Directory #1/A#10 methodology)
The SAR mentions that ”Generator ride-through is a foundational essential reliability service.”. To date the “ride-through” is not defined
as a reliability service the same way we understand the following:
•
•
•
Frequency support - provided through the combined interactions of synchronous inertia and frequency response, as services to
arrest the decline in frequency and eventually return the frequency to the desired level
Ramping and Balancing – provided through dispatch by the generating units with active power management capability and ability
to respond to dispatch signals
Voltage Support - provided through planning and confirmation testing of reactive power sufficiency per unique characteristics of
their respective BA systems.
Having generating resources with ride-through capabilities are not a guarantee that the generating units will remain connected to the grid
even less of a guarantee they will provide BES support (reliability services during BES disturbance) since BES support is also a:
•
•
Function of static and dynamic reactive power reserve capabilities to regulate voltage at those respective points in the system
Function of levels of conventional synchronous inertia for respective balancing area/interconnection, and initial frequency
deviation following the largest contingency event for the interconnection
This SAR should only be applicable to the protection/protective functions that trip the protected equipment in response to a BES
disturbance, where the disturbance conditions do not pose a risk of damage to the associated equipment, whose protection must be
prioritized (similar with PRC-025-2).
Equipment protection does not amount nor have a simultaneous compounded effect on grid reliability.
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The SAR statement related to the cost impact associated to this Project being expected to be minimal, should not be treated as an
accurate statement as long as the entire scope of the project has not even been identified.
Likes
0
Dislikes
0
Response
Thank you for the comment. The team has redlined the SAR to reflect possible new costs. NERC has been specific when designating the
terms BES vs BPS in the SAR, these will remain distinct and not all BES. The drafting team will determine specific ride-through
requirements. This comment will be passed along to the standard drafting team.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
As an alternative to the proposed PRC-024 SAR, EEI suggests that a new SAR be developed to address performance issues specifically
affecting IBRs. This new SAR could leverage key scope items from this proposed SAR to create a new performance- based NERC Reliability
Standard that is focused on IBRs. As a suggested scope, we propose modifying this SAR as follows:
•
•
Trips or reductions in active power that occur because the IBR does not operate as expected (excludes cloud cover, setting sun,
etc.), but not associated with protection system trips, (PRC-004 already addresses protection system tripping) are to be analyzed
by the GO to develop a corrective action plan. Situations where an issue cannot be corrected, the GO shall develop a report
detailing the limitations of the IBR and provide it to the responsible TOP, BA, and RC.
Momentary cessation, or temporary ceasing of current injection in response to grid disturbances, is deemed unacceptable for BES
generating resources. Inverter-based generating resources employing momentary cessation shall develop a corrective action to
mitigate its use unless the issue cannot be corrected. Legacy facilities prior to the effective date of the standard should receive an
exemption; however, resources with a commercial operation date after the effective date of the standard shall be required to
eliminate the use of momentary cessation during system transient disturbances where the system voltage or frequency falls
within the “No Trip Zone” provided in PRC-024-3, which is subject to enforcement October 1, 2022.
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•
•
•
Include the development of new terms to address terms specific to IBRs or where commonly used industry terms have created
some confusion for IBR owners. E.g., No Trip Zone, trip, momentary cessation, and any other relevant terms that may require
clarification within the NERC Glossary of Terms.
Prolonged IBR controller interactions that impede the ability of the resource to respond dynamically to the grid disturbance and
preclude the ability to provide essential reliability services are deemed unacceptable and should be addressed by a corrective
action plan. In situation where the GO has determined the issue cannot be corrected, a report shall be developed detailing the
IBR limitation and provide it to the responsible TOP, BA and RC.
If the TOP, BA, or RC inform the GO/IBR owner of a tripping occurrence, cessation event, or IBR controller interactions that are not
reported or otherwise identified by the GO/IBR Owner, the responsible GO shall be responsible for analyzing the facility’s
performance during the event, developing a corrective action plan, and making this available to the TOP, BA, and RC or in the
situation where the issue cannot be corrected, informing the TOP, BA and RC.
Likes
0
Dislikes
0
Response
Thank you for the comment.
The standard drafting team will take into consideration that IBR ride-through performance is the chief motivation behind the present
PRC-024 SAR.
The points applicable to generation ride-through will be considered in the context of a revised or new generation ride-through standard.
Momentary cessation is an aspect of ride-through performance. The final standard may not be specific to causes of unsatisfactory ridethrough but only describe the system conditions and/or events during which generation must ride-through and what constitutes
satisfactory ride-through performance. Exemptions for legacy generation and possibly other factors for which exemptions should be
permitted will be considered. The team has redlined the SAR to address these concerns. The fourth point regarding interactions that
affect reliability services in general may go beyond the scope of disturbance ride-through which the SAR is limited to. The SAR has been
redlined to make it more specific, when the team starts to draft the standard this will be noted and considered.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer
Document Name
Comment
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The current PRC-024 standard was written with conventional (rotating) generators in mind. Conventional generators are quite sensitive to
generator speed (frequency) and abnormal speeds can damage, i.e. lower the life of, turbine blades. Hence the further away the
frequency deviates from 60 Hz, the shorter the duration allowed for “no-trip.” In contrast, Inverter-Based Resources (IBRs) don’t have
rotating parts whose speed is tied to their connection to the grid. Since IBRs are not affected by deviations in system frequency as much
as conventional (rotating) generators, the SRC requests the PRC-024 SAR be revised to include a recognition for this difference as there
may be different ride-through requirements for IBRs than conventional generators within the same interconnection.
In addition, to aid in industry implementation, the SRC requests the SAR include the requirement to provide some real-world examples;
e.g. in Technical Rationale, to illustrate how proposed standard requirements will ensure both IBRs and conventional generators are able
to ride-through faults and how, had they been in place, would have addressed past issues of inadequate ride-through capability.
Finally, the SRC requests that the SAR ask to expand the requirement in selecting a Standards Drafting Team (SDT) that is stated in
Question 5 on the SAR form. The SRC agrees it is important to include entities that the standard will apply to, but in addition, entities who
have a need for the information or bear responsibility to reliably operate within the bounds of the standard (even if the standard does
not directly apply to them from a requirement and compliance standpoint), should also be included. The requirements set in any standard
are intended to ensure the reliability of the BES as a whole which all registered entity functions have an impact or interest in. This should
apply to any and all SARs and the SRC would like to ask NERC to address a change in the SAR form in the future.
Likes
0
Dislikes
0
Response
Thank you. Your comments will be considered during the drafting of the standard. The team will review and provide real world examples
if available/applicable.
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
Comment
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The NAGF notes that the SAR references the term Bulk Power System (BPS) and Bulk Electric System (BES) through the SAR document.
Recommend consistent use of the terms in the Purpose, Project Scope, and Deliverables sections.
In addition, the NAGF notes that the SAR is not consistent with regard to retiring and replacing PRC-024-3 (Purpose or Goal Section, first
sentence). Bullet #1 of the Project Scope states “Retire PRC-024-3, and create a new PRC standard or completely overhaul and replace the
existing PRC-024 standard.” Bullet #1 of the Detailed Description of the Project Deliverables states “The proposed deliverable is a new
NERC standard (or significant overhaul and revision of PRC-024-3) that includes…).
Likes
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Response
Thank you for the comment. The team will make sure to use terms consistently moving forward.
These terms are consistent, the scope allows these actions. The Purpose and Scope both articulate the retirement of the current PRC-0243 and replacing it with a new or modified version.
John Pearson - ISO New England, Inc. - 2
Answer
Document Name
Comment
Below are proposed changes for the “proposed deliverable” section of the SAR.
The proposed deliverable is a new NERC standard (or significant overhaul and revision of PRC-024-3) that includes the following key
elements:
A performance-based approach to generator ride-through rather than an equipment settings standard. The new standard shall include
requirements that BES resources shall ride through grid disturbances and include quantitative measures (see below) on expectations for
ride-through that address all possible causes of tripping and power reductions from BES generating resources (particularly generator,
turbine, inverter, and all plant-level protection and controls, including auxiliary systems).
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A reporting requirement that all trips or abnormal reductions in power output are reported by the GO to the TOP, BA, and RC.
A requirement that abnormal reductions in active power (i.e., tripping from protections or notable reductions from controls) are analyzed
by the GO and shall be reported to the TOP, BA, and RC.
Likes
0
Dislikes
0
Response
Thank you for the comment. These concerns have been addressed in the redlined SAR.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Thank you for the response.
Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
Minnesota Power supports EEI’s comments for this question.
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Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to EEI (question 2).
Daniela Atanasovski - APS - Arizona Public Service Co. - 1,3,5,6
Answer
Document Name
Comment
AZPS suggests PRC-024 should remain unchanged as it applies to synchronous generators and that a new SAR be developed to address
performance issues specifically affecting IBR’s that are interconnected to the BES.
Likes
0
Dislikes
0
Response
The standard drafting team will take into consideration that IBR ride-through performance is the chief motivation behind the present
PRC-024 SAR.
Alan Kloster - Evergy - 1,3,5,6 - MRO
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #2.
Likes
Dislikes
0
0
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Response
Thank you for the comment. Please see response to EEI (question 2).
Isidoro Behar - Long Island Power Authority - 1
Answer
Document Name
Comment
The stated purpose of this SAR is to retire PRC-024-3 and replace it with a performance-based ride-through standard that ensures
generators remain connected to the BPS during system disturbances. Additionally, the SAR will focus on the generator protection and
control systems that can result in the reduction or disconnection of generating resources during these events.
As part of the development of the performance based standard or overhaul of PRC-024-3, it is recommended that the standard drafting
team include and highlight specific references to the relevant IEEE Standard P2800-2022 clauses and to relevant FERC Orders (related to
ride-through), where applicable. It will be important for stakeholders to discern similarities and differences between the new or
revamped standard and these existing references.
We can offer another comment, related to PRC-024-3, for consideration in the development of a performance based standard or overhaul
of PRC-024-3.
For PRC-024-3 applicability section 4.1.2, it mentions that it is for Transmission Owners in the Quebec Interconnection only. There are
Transmission Owners outside the Quebec Interconnection that own BES generator step-up transformers (GSUs). Is PRC-024-3 intended to
be applicable to Transmission Owners that own BES GSUs that are outside the Quebec Interconnection? If so, perhaps the “in the Quebec
Interconnection only” should be removed from applicability section 4.1.2 in the next revision.
Likes
0
Dislikes
0
Response
Thank you for the comment. This will be passed along to the drafting team along with consideration to IEEE-2800-2022 when drafting the
standard.
Joseph Amato - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
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Answer
Document Name
Comment
MidAmerican supports MRO NSRF and EEI comments.
Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to EEI (comment 2).
Michael Johnson - Pacific Gas and Electric Company - 1,3,5 - WECC, Group Name PG&E All Segments
Answer
Document Name
Comment
PG&E agrees with the comments and suggested scope provided by EEI; a new SAR should be developed to address the unique
performance characteristics of IBRs.
Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to EEI (question 2).
Anna Todd - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer
Document Name
Comment
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N/A
Likes
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Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Southern Company disagrees with the “Cost Impact Assessment”. We feel that generation resources will need to install high speed
recorders to capture data on electrical events that occur and the reaction of generation resources to said electrical event. These high
speed recorders will be essential for any requirement for analysis and development of corrective action plans. Southern Company
purports that it will be costly to engineer, procure and install this equipment.
Noting that IBR components capable of providing the performance characteristics are just now beginning to be developed and offered by
vendors coupled with regulatory requirements for providing that performance will certainly cause equipment suppliers to increase costs
to the users.
With the cause of the concern raised in this SAR being the system disturbance, perhaps a more beneficial result can be achieved by
investigating the causes of the system disturbances that have been resulting in natural responses of the IBR and synchronous machine
based generating stations. Our experience has been that most of the existing IBR systems that operate perfectly given a network with no
disturbances.
The recent development and adoption of IEEE P2800 (Standard for Interconnection and Interoperability of Inverter-Based Resources
Interconnecting with Associated Transmission Electric Power Systems) is nowhere to be found in the SAR as a resource. It is Southern
Company’s opinion that IEEE P2800 be fully understood and used by the SDT as a resource of what operational capability limits exist for
IBRs. P2800 goes into many of the aspects that IBRs face from a performance perspective. A common issue with IBRs is loss of
synchronism because of the voltage phase angle jump that can occur with system disturbances. A voltage phase angle shift jump can
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occur with the voltage magnitudes still within the no-trip zone, leading to momentary cessation because of loss synchronism of the IBRs
synchronizing phase-locked loop control function.
The Functional Entities identified in the PRC-024 standard have no control what-so-ever of the design and performance characteristics of
the Inverter Based Resource manufacturers equipment. This leads to GOs attempting to coerce the IBR manufactures after-the-fact to
change equipment settings and parameters to comply with operational situations that they are either not designed to perform to or, due
to the technical nature of the IBR generation process, cannot perform to. To move to a performance based standard and holding the GO
accountable for the design performance of the IBRs is futile at best. The only performance criteria defined in the SAR so far is impossible
for all situations, and that is “A clear requirement that momentary cessation, or temporary ceasing of current injection during BPS fault
events, is deemed unacceptable performance for BES generating resources”.
Likes
0
Dislikes
0
Response
Thank you for comment. The SAR has been redlined to reflect the additional cost of high speed data recording devices, if or when
required.
Joe Gatten - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Document Name
Comment
Xcel Energy supports the comments offered by EEI, NAGF, and MRO NSRF.
Likes
0
Dislikes
0
Response
Thank you for the comment. Please see responses to the respective entities (question 2).
Kendra Buesgens - MRO - 1,2,3,4,5,6 - MRO
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Answer
Document Name
Comment
The MRO NSRF disagrees with the “Cost Impact Assessment”. The MRO NSRF feels that generation resources will need to install high
speed recorders to capture data on electrical events that occur and the reaction of generation resources to said electrical event. These
high speed recorders will be essential for any requirement for analysis and development of corrective action plans. The MRO NSRF
believes it will be costly to engineer, procure and install this equipment.
The MRO NSRF recommends replacing all instances of bulk power system (BPS) with Bulk Electrical System (BES) to ensure proper scoping
of the SAR.
Likes
0
Dislikes
0
Response
Thank you for the response. The team has redlined and modified the SAR to address the concern.
The team checked with NERC SAR authors to reconfirm the distinct differences between terms is intentional and it will be left as-is.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Momentary Cessation Requirements for Existing Generators
While Texas RE appreciates the proposed SAR’s focus on generator performance issues in general and momentary cessation issues in
particular, Texas RE is concerned that the current proposed SAR would exempt facilities in commercial operation prior to the effective
date of the new PRC-024-3 requirements from “the use of momentary cessation within ‘ride through envelopes’ (e.g., the existing PRC024 “No Trip Zone”). (PRC-024 Standard Authorization Request, at 3-4). The Odessa Disturbance Report observed that momentary
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cessation issues resulted in generation loss, along with tripping issues inside of facilities during the event (Odessa Disturbance Report, at
7). In particular, the Odessa Disturbance Report noted: “legacy inverter momentary cessation setting with plant-level controller
interactions prohibited quick active power recovery.” (Odessa Disturbance Report, at 33). The report also noted other forms of
momentary cessation issues, including settings that produced fixed reactive power injection with “no ability to control voltage postcontingency.” (Odessa Disturbance Report, at 20). It further noted that “[t]his type of behavior was not known by ERCOT prior to the
event analysis nor is this type of behavior supporting the BPS post-fault.” (Id.).
Given the significance of these momentary cessation issues during the Odessa Disturbance event and other events over the past six years,
Texas RE encourages the SDT to not limit momentary cessation performance requirements exclusively to new generation facilities. While
Texas RE expects the SDT to move expeditiously with this project, Texas RE notes that the final revised standard may not be effective for
several years. As a result, not only would existing generators not be covered by any momentary cessation requirements, but a number of
planned generation resources would be similarly exempt. Given the growing role of inverter-based resources in the ERCOT
Interconnection and others, this could result in a significant reliability gap.
Texas RE notes that momentary cessation issues are currently documented in NERC Reliability Guidelines (E.g., Reliability Guideline: BPSConnected Inverter-Based Resource Performance (Sept. 2018) (2018 IBR Performance Guidelines). These existing guidelines note that
“Existing and newly interconnecting inverter-based resources should eliminate the use of momentary cessation to the greatest possible
extent.” (2018 IBR Performance Guidelines, at 11). It is also important to note that one of the key findings in the Odessa Disturbance
Report is that while these reliability guidelines are widely viewed and shared, entities are “not comprehensively adopting the
recommendation(s) contained in those materials.” (Odessa Disturbance Report, at vi). In short, a new Reliability Standard is required.
Texas RE acknowledges it may take time to review and implement settings to avoid certain momentary cessation-type performance
issues. As the 2018 IBR Performance Guidelines note, however: “Existing resources may have hardware and/or software limitations
based on a design philosophy using momentary cessation, and it may not be feasible to eliminate its use. For equipment limitations that
cannot be addressed, PRC-024-2 Requirement R3.1 states that ‘[t]he [GO] shall communicate the documented regulatory or equipment
limitation, or the removal of a previously documented regulatory or equipment limitation, to its Planning Coordinator and Transmission
Planner within 30 calendar days.’” (2018 IBR Performance Guidelines, at 11-2). The drafting team could consider approaches that permit
legacy systems lacking functionality to avoid momentary cessation issues to document those limitations for any new momentary
cessation requirements developed in this project in a manner similar to the process currently provided in the existing PRC-024-3
Requirement R3.1.
Enhanced Communication Requirements
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In addition to considering the incorporation of momentary cessation and other performance notification requirements as appropriate,
Texas RE recommends the drafting team consider creating a new requirement for the GO to notify the GOP, in addition to the TOP, BA,
and RC, regarding abnormal tripping. Since COM-001 and COM-002 do not include GO communications, an additional requirement for
the GO to notify the GOP would be helpful for the GOP to have the information to communicate any GO issues via COM-001 and COM002.
Likes
0
Dislikes
0
Response
Thank you for the comment. Please see response to EEI (comment 2).
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
Although PRC-024-3 is not applicable to BPA by registration, the PRC-024-3 Requirements R3 and R4 do impact BPA as a Transmission
Planner and Planning Coordinator and will have substantial impact to BPA’s interconnection requirements. BPA encourages the drafting
team to address the inconsistencies in format of how TPs and PCs receive the data. Data consistency will support more efficient and
effective modeling of relay settings
Likes
0
Dislikes
0
Response
Thank you for the comment. The team will pass this on to the standard drafting team for consideration.
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC Entity Monitoring
Answer
Document Name
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Comment
No additional comments. Thank you for the opportunity to comment.
Likes
0
Dislikes
0
Response
Thank you for the response.
Alison Mackellar - Constellation - 5,6
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
0
Response
Kimberly Turco - Constellation - 5,6
Answer
Document Name
Comment
N/A
Likes
0
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Dislikes
0
Response
Adrian Raducea - DTE Energy - Detroit Edison Company - 3,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment
All protection and control system functions that will be in scope should be specifically listed in the standard. Guidance on complying
with ride-through requirements should be provided by including detailed examples. A sufficient phase-in period should be part of the
implementation plan to allow GOs time to achieve the additional coordination that will be required.
Based on the defined project scope the new standard will enforce that unexpected trips, abnormal trips and reductions in power are
reported to the pertinent entities. The term reduction of power needs to be defined since it is open for interpretation. Furthermore, this
reporting-out could infringe on current standards like PRC-004.
Likes
0
Dislikes
0
Response
Thank you for the comment. This will be passed along to the standard drafting team.
Brian Lindsey - Entergy - 1,3,6
Answer
Document Name
Comment
The Cost Impact Assessment states incremental cost impact which is not correct. Additional analyses and design changes are likely based
on the widespread loss of generating resources observed.
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Likes
0
Dislikes
0
Response
Thank you for comment. The SAR has been redlined to reflect the additional cost of high speed data recording devices, if or when
required.
End of Report
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Standard Authorization Request (SAR)
Complete and submit this form, with attachment(s)
to the NERC Help Desk. Upon entering the Captcha,
please type in your contact information, and attach
the SAR to your ticket. Once submitted, you will
receive a confirmation number which you can use
to track your request.
SAR Title:
Date Submitted:
SAR Requester
Name:
The North American Electric Reliability Corporation
(NERC) welcomes suggestions to improve the
reliability of the bulk power system through
improved Reliability Standards.
Requested information
Generator Ride-Through Standard (PRC-024-3 Replacement)
April 28, 2022 (revised March 31, 2023)
Mark Lauby, Senior Vice President and Chief Engineer, NERC
Howard Gugel, Vice President, NERC
John Moura, Director, NERC
Ryan Quint, Senior Manager, NERC
Rich Bauer, Principal, NERC
Matt Lewis, Manager, NERC
As revised by the Project 2020-02 SAR Drafting Team
Organization: North American Electric Reliability Corporation
Telephone:
Mark Lauby – 404-446-9723
Email:
mark.lauby@nerc.net
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify, or Retire a Glossary Term
Variance development or revision
(as needed)
Other (Please specify)
Withdraw/retire an Existing Standard
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
The ERO Enterprise has analyzed over 10 disturbances involving widespread loss of solar photovoltaic
(PV) resources and has published multiple disturbance reports highlighting key findings and
recommendations from these analyses. Across all events, a widespread loss of generating resources –
solar PV, wind, synchronous generation, and battery energy storage systems (BESS) – have abnormally
tripped, ceased current injection, or reduced power output with control interactions. Generator ridethrough is a foundational essential reliability service. BPS-connected generating resources remaining
RELIABILITY | RESILIENCE | SECURITY
Requested information
connected during normal and contingency conditions is a critical component of BPS reliability. Ensuring
fault ride-through capability enables dynamic reactive power support, frequency response, and other
services. The unexpected loss of widespread generating assets poses a significant risk to BPS reliability.
The existing PRC-024-3 is an equipment settings standard focused solely on voltage and frequency
protection. However, this standard is serving little to no value in ensuring BPS-connected inverter-based
resources remain connected and support the BPS during grid disturbances. Furthermore, NERC has
experienced multiple asset owners during the event analyses who have misconstrued PRC-024-3,
resulting in incorrect or unnecessary protections applied to generating assets that have resulted in
spurious and abnormal tripping events.
The systemic tripping and reductions of inverter-based resources, in addition to notable concurrent
tripping or performance from synchronous generating resources, poses a risk to BPS reliability that must
be addressed in a timely manner. This proposed standards project will address this known reliability risk
with a more suitable performance-based standard that ensures generating resource ride-through
performance for expected or planned BPS disturbances rather than focusing solely on a small subset of
protections and controls that can trip generating resources.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
The purpose of this SAR is to retire PRC-024-3 and replace it with a performance-based ride-through
standard that ensures generators remain connected to the BPS during system disturbances. Specifically,
this SAR focuses on the generator protection and control systems that can result in the reduction or
disconnection of generating resources during these events. The SAR also ensures protection or controls
that fail to ride through system events are analyzed, addressed with a corrective action plan (if possible),
and reported to necessary entities for situational awareness. From a risk-based perspective, the goal of
the standard is to mitigate the ongoing and systemic performance issues identified across multiple
Interconnections and across many disturbances analyzed by NERC and the Regions. These issues have
been identified in inverter-based resources as well as synchronous generators, with many causes of
tripping entirely unrelated to voltage and frequency protection settings as dictated by the currently
effective version of PRC-024.
Project Scope (Define the parameters of the proposed project):
The scope of this project includes the following:
• Retire PRC-024-3, and create a new PRC standard or completely overhaul and replace the existing
PRC-024 standard.
• Allow for the possible modification or retirement of other relay-setting standards such as but not
limited to PRC-006, PRC-019, PRC-025, and PRC-026, to prevent duplicative requirements and
compliance obligations.
• Creates a comprehensive, performance-based ride-through standard to ensure BES generating
resources remain connected and providing essential reliability services during grid disturbances.
Standard Authorization Request (SAR)
2
•
•
•
•
•
Requested information
The scope of protections and controls involved in this ride-through standard shall include all
generator protections and controls that affect the electrical output of the BES generating resource
or plant. To be clear, the project should specify the protections and controls in the scope of the
ride-through performance and define the term ride-through, as necessary. This should, at a
minimum, include all generator (synchronous or inverter-based) protections and controls at the
individual generators, at the inverters, or within the plant (i.e., plant-level controls and protections
or collector system protections).
For synchronous generators, the scope of the ride-through standard shall explicitly exclude
auxiliary systems and their protection systems. These protections have not posed a systemic BES
reliability risk. However, protections and controls directly focused on the generator and its prime
mover impacting the ride-through performance should be addressed in the standard.
For Inverter Based Resources (IBRs), auxiliary systems and their protection systems that can affect
ride through performance shall be considered by the Standard Drafting Team.
The new standard shall ensure that all unexpected or abnormal tripping or reductions in power
output are reported by the GO to the TOP, BA, and RC.
This team will also consider requirements for high-speed data recording relating to system events
and will coordinate, as appropriate, with Project 2021-04 Modifications to PRC-002.
-Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide (1) a technical justification 1 that includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g., research paper) to guide the development of the Standard or definition):
The following describes the proposed deliverable for this project:
•
The proposed deliverable is a new NERC standard (or significant overhaul and revision of PRC-0243) that includes the following key elements:
A performance-based approach to generator ride-through rather than an equipment settings
standard. The new standard shall include requirements that BES resources shall ride through
grid disturbances and include quantitative measures (see below) on expectations for ridethrough that address all possible causes of tripping and power reductions from BES generating
resources (particularly generator, turbine, inverter, and all plant-level protection and
controls).
A reporting requirement that all trips or reductions in power output in response to grid
disturbances are reported by the GO to the applicable TOP, BA, and RC
A requirement that abnormal reductions in active power (i.e., tripping from protections or
notable reductions from controls) in response to grid disturbances are analyzed by the GO to
The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please attach pertinent
information to this form before submittal to NERC.
1
Standard Authorization Request (SAR)
3
Requested information
develop and implement a Corrective Action Plan. Situations, where corrective action plans
are not able to be developed, shall be reported to the TOP, BA, and RC.
A clear requirement that momentary cessation, or temporary ceasing of current injection
during BPS fault events, is deemed unacceptable performance for BES generating resources.
Inverter-based generating resources employing momentary cessation shall develop a
corrective action to mitigate its use. Legacy facilities that were connected before the effective
date of the standard and cannot comply due to documented inherent equipment limitations,
may be considered for an exemption; however, resources with a commercial operation date
after the effective date of the standard (and possibly the PRC-024-3 implementation date)
shall be required to eliminate the use of momentary cessation within “ride through envelopes”
(e.g., the existing PRC-024 “No Trip Zone”).
The terms ride-through, trip, momentary cessation, and any other relevant terms should be
defined in the NERC Glossary of Terms if deemed necessary.
A clear requirement that prolonged plant controller interactions that are unnecessary to
protect equipment or system and impede the ability of the resource to dynamically respond
to the grid disturbance and preclude the ability to fully provide essential reliability services are
deemed unacceptable and should be addressed by a corrective action plan.
A requirement that if the TOP, BA, or RC informs the GO of a tripping occurrence, cessation
event, or plant controller interactions that are not reported by the GO, then the GO shall be
responsible for analyzing the facility’s performance during the event, developing a corrective
action plan, and reporting this to the TOP, BA, and RC.
The technical justification regarding the reliability-related need and benefits of this project are described
in extensive detail in multiple NERC disturbance reports. All widespread solar PV loss events analyzed by
the ERO Enterprise have involved extensive tripping and causes of reduction that is largely not addressed
by PRC-024-3, many of which are unrelated to voltage and frequency tripping entirely. Furthermore, these
multiple events have also involved the loss of synchronous generators for various reasons that should be
considered in the development activities of this proposed project. Key disturbance reports include:
•
NERC 2021 California Disturbances Report (2022)
•
NERC Odessa Disturbance Report (2021)
•
NERC San Fernando Disturbance Report (2020)
•
NERC Palmdale Roost and Angeles Forest Disturbances Report (2019)
•
NERC Canyon 2 Fire Disturbance Report (2018)
•
NERC Blue Cut Fire Disturbance Report (2017)
NERC Reliability Guideline: Improvements to Interconnection Requirements for BPS-Connected InverterBased Resources (2019), developed by the NERC Inverter-Based Resource Performance Working Group
Standard Authorization Request (SAR)
4
Requested information
(IRPWG) and endorsed by the NERC Planning Committee, specifically recommends that all Transmission
Owners (TOs) per FAC-001 establish or improve interconnection requirements by including quantitative
requirements related to ride-through performance. Below is an excerpt from this guideline:
Quantitative requirements ensure that resources behave in a manner that supports BPS reliability and also
assists the GOs and inverter manufacturers in specifying equipment to meet these requirements. These
requirements may involve a performance envelope (FRT capability) that must be met by the resource,
typically derived based on interconnection studies, grid codes, Reliability Standards, and other factors
deemed necessary by the TO. Having these requirements ensures that the resources, particularly inverterbased resources, are unlikely to operate in a mode that has not been previously studied. Examples of these
quantitative performance requirements include, but are not limited to, the following:
• Pre- and post-fault short-circuit strength (equivalent impedance or short-circuit ratio (SCR)-based
metric)) for worst-case contingency conditions
• RMS low voltage ride-through and high voltage ride-through
• Instantaneous transient overvoltage
• Instantaneous change in phase angle
• Low frequency ride-through and high frequency ride-through
• No use of momentary cessation, by exception only
These deliverables developed by the ERO Enterprise and its stakeholder groups serve as a strong
technical basis for ensuring resources successfully ride through grid disturbances and support the BPS
by providing essential reliability services moving forward.
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
Incremental costs are expected for GOs that currently do not analyze the performance of their generating
assets following grid disturbances, which has been shown during the NERC disturbance analyses to be a
systemic reliability issue for solar PV resources in particular. GOs will need to assess their ride-through
capabilities more comprehensively than in the past, which may have some associated costs. Minimal costs
are associated with reporting of tripping occurrences. Facilities with abnormal or unexpected trips that
can be mitigated with corrective actions will have some incremental costs; however, these improvements
will help ensure adequate levels of reliability of the BES. Otherwise, cost impacts for this project are
expected to be minimal. Additionally, if high speed data recording is not available in the required
locations, entities may be required to install such equipment which would have some increased cost
impact.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g., Dispersed Generation Resources):
BES generating resources.
Standard Authorization Request (SAR)
5
Requested information
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g., Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Generator Owners, Generator Operators, Reliability Coordinators, Transmission Operators, Transmission
Owners, Transmission Planners, Planning Coordinators
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
This SAR is an outcome of ongoing analyses conducted by the ERO Enterprise regarding widespread
inverter-based resource tripping events. Furthermore, the NERC IRPWG has developed comprehensive
recommendations for improved performance of inverter-based resources, including the recommendation
to develop comprehensive ride-through requirements.
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so, which standard(s) or project number(s)?
PRC-006, PRC-019, PRC—025, PRC-026
Are there alternatives (e.g., guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
NERC has evaluated industry progress toward adopting the recommendations outlined in NERC
guidelines, white papers, its prior Alerts, and other industry efforts. NERC believes that a nationwide
standard for consistent requirements for generating resource ride-through is necessary to immediately
address generating resource ride-through during grid disturbances moving forward.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for an emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained, and implemented.
5. Facilities for communication, monitoring, and control shall be provided, used, and maintained
for the reliability of interconnected bulk power systems.
Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted to obtain
industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.
2
Standard Authorization Request (SAR)
6
Requested information
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, and qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored, and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions from achieving
compliance with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.
Enter
(yes/no)
Yes
Yes
Yes
Yes
Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
None
None
For Use by NERC Only
SAR Status Tracking (Check off as appropriate).
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC
Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document
Version History
Version
1
Date
June 3, 2013
Standard Authorization Request (SAR)
Owner
Change Tracking
Revised
7
1
August 29, 2014
Standards Information Staff
Updated template
2
January 18, 2017
Standards Information Staff
Revised
2
June 28, 2017
Standards Information Staff
Updated template
3
February 22, 2019
Standards Information Staff
Added instructions to submit via Help
Desk
4
February 25, 2020
Standards Information Staff
Updated template footer
Standard Authorization Request (SAR)
8
Standard Authorization Request (SAR)
Complete and submit this form, with attachment(s)
to the NERC Help Desk. Upon entering the Captcha,
please type in your contact information, and attach
the SAR to your ticket. Once submitted, you will
receive a confirmation number which you can use
to track your request.
SAR Title:
Date Submitted:
SAR Requester
The North American Electric Reliability Corporation
(NERC) welcomes suggestions to improve the
reliability of the bulk power system through
improved Reliability Standards.
Requested information
Generator Ride‐Through Standard (PRC‐024‐3 Replacement)
April 28, 2022
Mark Lauby, Senior Vice President and Chief Engineer, NERC
Howard Gugel, Vice President, NERC
John Moura, Director, NERC
Name:
Ryan Quint, Senior Manager, NERC
Rich Bauer, Principal, NERC
Matt Lewis, Manager, NERC
Organization: North American Electric Reliability Corporation
Telephone:
Mark Lauby – 404‐446‐9723
Email:
mark.lauby@nerc.net
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
(as needed)
Other (Please specify)
Withdraw/retire an Existing Standard
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
The ERO Enterprise has analyzed over 10 disturbances involving widespread loss of solar photovoltaic
(PV) resources and has published multiple disturbance reports highlighting key findings and
recommendations from these analyses. Across all events, a widespread loss of generating resources –
solar PV, wind, synchronous generation, and battery energy storage systems (BESS) – have abnormally
tripped, ceased current injection, or reduced power output with control interactions. Generator ride‐
through is a foundational essential reliability service. BPS‐connected generating resources remaining
connected during normal and contingency conditions is a critical component of BPS reliability. Ensuring
fault ride‐through capability enables dynamic reactive power support, frequency response, and other
RELIABILITY | RESILIENCE | SECURITY
Requested information
services. The unexpected loss of widespread generating assets poses a significant risk to BPS reliability.
The existing PRC‐024‐3 is an equipment settings standard focused solely on voltage and frequency
protection. However, this standard is serving little to no value for ensuring BPS‐connected inverter‐based
resources remain connected and supporting the BPS during grid disturbances. Furthermore, NERC has
experienced multiple asset owners during the event analyses who have misconstrued PRC‐024‐3,
resulting in incorrect or unnecessary protections applied to generating assets that have resulted in
spurious and abnormal tripping events.
The systemic tripping and reductions of inverter‐based resources, in addition to notable concurrent
tripping or performance from synchronous generating resources poses a risk to BPS reliability that must
be addressed in a timely manner. This proposed standards project will address this known reliability risk
with a more suitable performance‐based standard that ensures generating resource ride‐through
performance for expected or planned BPS disturbances rather than focusing solely on a small subset of
protections and controls that can trip generating resources.
Purpose or Goal (How does this proposed project provide the reliability‐related benefit described
above?):
The purpose of this SAR is to retire PRC‐024‐3 and replace it with a performance‐based ride‐through
standard that ensures generators remain connected to the BPS during system disturbances. Specifically,
this SAR focuses on the generator protection and control systems that can result in the reduction or
disconnection of generating resources during these events. The SAR also ensures protection or controls
that fail to ride through system events are analyzed, addressed with a corrective action plan (if possible),
and reported to necessary entities for situational awareness. From a risk‐based perspective, the goal of
the standard is to mitigate the ongoing and systemic performance issues identified across multiple
Interconnections and across many disturbances analyzed by NERC and the Regions. These issues have
been identified in inverter‐based resources as well as synchronous generators, with many causes of
tripping entirely unrelated to voltage and frequency protection settings as dictated by the currently
effective version of PRC‐024.
Project Scope (Define the parameters of the proposed project):
The scope of this project includes the following:
Retire PRC‐024‐3, and create a new PRC standard or completely overhaul and replace the existing
PRC‐024 standard.
Allow for the possible modification or retirement of other relay setting standards such as but not
limited to PRC‐006, PRC‐019, PRC‐025, and PRC‐026, to prevent duplicative requirements and
compliance obligations.
Creates a comprehensive, performance‐based ride‐through standard with the purpose of ensuring
BES generating resources remain connected and providing essential reliability services during grid
disturbances.
The scope of protections and controls involved in this ride‐through standard shall include all
generator protections and controls that affect the electrical output of the BES generating resource
Standard Authorization Request (SAR)
2
Requested information
or plant. To be clear, the project should specify the protections and controls in scope of the ride‐
through performance and define the term ride‐through, as necessary. This should, at a minimum,
include all generator (synchronous or inverter‐based) protections and controls at the individual
generators, at the inverters, or within the plant (i.e., plant‐level controls and protections or
collector system protections).
For synchronous generators, Tthe scope of the ride‐through standard shall explicitly exclude
auxiliary systems and their protection systems. Abnormal performance or unexpected tripping of
tThese protections have do not posed a systemic BES reliability risk. However, protections and
controls directly focused on the generator and its prime mover impacting the ride‐through
performance should be addressed in the standard. (e.g., overspeed, power‐load imbalance,
overvoltage, pole out of step sliphase jump, overcurrent) or plant‐level (e.g., voltage, current,
frequency, phase, etc.) have posed notable risks to BES reliability and should be addressed directly
in this standard.
For Inverter Based Resources (IBRs), auxiliary systems and their protection systems that can affect
ride through performance shall be considered by the Standard Drafting Team.
The new standard shall ensure that all unexpected or abnormal tripping or reductions in power
output are reported by the GO to the TOP, BA, and RC.
This team will also consider requirements for high speed data recording relating to system events
and will coordinate, as appropriate, with Project 2021‐04 Modifications to PRC‐002.
‐Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification1 which includes a discussion of the reliability‐related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g., research paper) to guide development of the Standard or definition):
The following describe the proposed deliverable for this project:
The proposed deliverable is a new NERC standard (or significant overhaul and revision of PRC‐024‐
3) that includes the following key elements:
A performance‐based approach to generator ride‐through rather than an equipment settings
standard. The new standard shall include requirements that BES resources shall ride through
grid disturbances and include quantitative measures (see below) on expectations for ride‐
through that address all possible causes of tripping and power reductions from BES generating
resources (particularly generator, turbine, inverter, and all plant‐level protection and
controls).
A reporting requirement that all trips or reductions in power output in response to grid
disturbances are reported by the GO to the applicable TOP, BA, and RC
1 The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please attach pertinent
information to this form before submittal to NERC.
Standard Authorization Request (SAR)
3
Requested information
A reporting requirement that all trips or reductions in power output are reported by the GO
to the TOP, BA, and RC.
A requirement that abnormal reductions in active power (i.e., tripping from protections or
notable reductions from controls) in response to grid disturbances are analyzed by the GO to
develop and implement a Ccorrective Aaction Pplan, if possible. Situations where corrective
action plans are not able to be developed shall be reported to the TOP, BA, and RC.
A clear requirement that momentary cessation, or temporary ceasing of current injection
during BPS fault events, is deemed unacceptable performance for BES generating resources.
Inverter‐based generating resources employing momentary cessation shall develop a
corrective action to mitigate its use. Legacy facilities that were connected prior to the effective
date of the standard and cannot comply due to documented inherent equipment limitations,
may be considered for should receive an exemption; however, resources with a commercial
operation date after the effective date of the standard (and possibly the PRC‐024‐3
implementation date) shall be required to eliminate the use of momentary cessation within
“ride through envelopes” (e.g., the existing PRC‐024 “No Trip Zone”).
The terms ride‐through, trip, momentary cessation, and any other relevant terms should be
defined in the NERC Glossary of Terms, if deemed necessary.
A clear requirement that prolonged plant controller interactions that are unnecessary to
protect equipment or system and impede the ability of the resource to dynamically respond
to the grid disturbance and preclude the ability to fully provide essential reliability services are
deemed unacceptable and should be addressed by a corrective action plan.
A requirement that if the TOP, BA, or RC inform the GO of a tripping occurrence, cessation
event, or plant controller interactions that are not reported by the GO, then the GO shall be
responsible for analyzing the facility’s performance during the event, developing a corrective
action plan, and reporting this to the TOP, BA, and RC.
The technical justification regarding the reliability‐related need and benefits of this project are described
in extensive detail in multiple NERC disturbance reports. All widespread solar PV loss events analyzed by
the ERO Enterprise have involved extensive tripping and causes of reduction that are largely not address
by PRC‐024‐3, many of which are unrelated to voltage and frequency tripping entirely. Furthermore, these
multiple events have also involved the loss of synchronous generators for various reasons that should be
considered in the development activities of this proposed project. Key disturbance reports include:
NERC 2021 California Disturbances Report (2022)
NERC Odessa Disturbance Report (2021)
NERC San Fernando Disturbance Report (2020)
NERC Palmdale Roost and Angeles Forest Disturbances Report (2019)
NERC Canyon 2 Fire Disturbance Report (2018)
Standard Authorization Request (SAR)
4
Requested information
NERC Blue Cut Fire Disturbance Report (2017)
NERC Reliability Guideline: Improvements to Interconnection Requirements for BPS‐Connected Inverter‐
Based Resources (2019), developed by the NERC Inverter‐Based Resource Performance Working Group
(IRPWG) and endorsed by the NERC Planning Committee, specifically recommends that all Transmission
Owners (TOs) per FAC‐001 establish or improve interconnection requirements by including quantitative
requirements related to ride‐through performance. Below is an excerpt from this guideline:
Quantitative requirements ensure that resources behave in a manner that supports BPS reliability and also
assists the GOs and inverter manufacturers in specifying equipment to meet these requirements. These
requirements may involve a performance envelope (FRT capability) that must be met by the resource,
typically derived based on interconnection studies, grid codes, Reliability Standards, and other factors
deemed necessary by the TO. Having these requirements ensures that the resources, particularly inverter‐
based resources, are unlikely to operate in a mode that has not been previously studied. Examples of these
quantitative performance requirements include, but are not limited to, the following:
Pre‐ and post‐fault short‐circuit strength (equivalent impedance or short‐circuit ratio (SCR)‐based
metric)) for worst case contingency conditions
RMS low voltage ride‐through and high voltage ride‐through
Instantaneous transient overvoltage
Instantaneous change in phase angle
Low frequency ride‐through and high frequency ride‐through
No use of momentary cessation, by exception only
These deliverables developed by the ERO Enterprise and its stakeholder groups serve as a strong
technical basis for ensuring resources successfully ride through grid disturbances and support the BPS
by providing essential reliability services moving forward.
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
Incremental costs are expected for GOs that currently do not analyze the performance of their generating
assets following grid disturbances, which has been shown during the NERC disturbance analyses to be a
systemic reliability issue for solar PV resources in particular. GOs will need to assess their ride‐through
capabilities more comprehensively than in the past, which may have some associated costs. Minimal costs
are associated with reporting of tripping occurrences. Facilities with abnormal or unexpected trips that
can be mitigated with corrective actions will have some incremental costs; however, these improvements
will help ensure adequate levels of reliability of the BES. Otherwise, cost impacts for this project are
expected to be minimal. Additionally, if high speed data recording is not available on the required
locations, entities may be required to install such equipment which would have some increased cost
impact.
Standard Authorization Request (SAR)
5
Requested information
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g., Dispersed Generation Resources):
BES generating resources.
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g., Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Generator Owners, Generator Operators, Reliability Coordinators, Transmission Operators, Transmission
Owners, Transmission Planners, Planning Coordinators
Do you know of any consensus building activities2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
This SAR is an outcome of ongoing analyses conducted by the ERO Enterprise regarding widespread
inverter‐based resource tripping events. Furthermore, the NERC IRPWG has developed comprehensive
recommendations for improved performance of inverter‐based resources, including the recommendation
to develop comprehensive ride‐through requirements.
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so, which standard(s) or project number(s)?
PRC‐006, PRC‐019, PRC—025, PRC‐026No.
Are there alternatives (e.g., guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
NERC has evaluated industry progress toward adopting the recommendations outlined in NERC
guidelines, white papers, its prior Alerts, and other industry efforts. NERC believes that a nationwide
standard for consistent requirements for generating resource ride‐through is necessary to immediately
address generating resource ride‐through during grid disturbances moving forward.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
2 Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted to obtain
industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.
Standard Authorization Request (SAR)
6
4.
5.
6.
7.
8.
Requested information
Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non‐sensitive information that is required for compliance
with reliability standards.
Enter
(yes/no)
Yes
Yes
Yes
Yes
Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
None
None
For Use by NERC Only
SAR Status Tracking (Check off as appropriate).
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC
Standard Authorization Request (SAR)
Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document
7
Version History
Version
Date
Owner
Change Tracking
1
June 3, 2013
Revised
1
August 29, 2014
Standards Information Staff Updated template
2
January 18, 2017
Standards Information Staff Revised
2
June 28, 2017
Standards Information Staff Updated template
3
February 22, 2019
Standards Information Staff Added instructions to submit via Help
Desk
4
February 25, 2020
Standards Information Staff Updated template footer
Standard Authorization Request (SAR)
8
Limited Disclosure
Agenda Item 8
Standards Committee
December 13, 2023
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) Waiver
Action
•
Approve the following waiver of provisions of the Standard Processes Manual (SPM) for
Project 2020-02:
Initial formal comment and ballot period reduced from 45 days to as few as 25
calendar days, with ballot pools formed in the first 10 days and initial ballot and nonbinding poll of Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs)
conducted during the last 10 days of the comment period (Sections 4.7 and 4.9)
Additional formal comment and ballot period(s) reduced from 45 days to as few as
15 calendar days, with ballot(s) conducted during the last 5 days of the comment
period. (Sections 4.9 and 4.12)
Final ballot reduced from 10 days to 5 calendar days. (Section 4.9)
Background
The SAR ensures generators remain connected to the bulk power system (BPS) during system
disturbances. Specifically, this SAR focuses on the generator protection and control systems
that can result in the reduction or disconnection of generating resources during these events.
The SAR also ensures that protection or controls that fail to ride through system events are
analyzed, addressed with a corrective action plan (if possible), and reported to necessary
entities for situational awareness. However, those items are now covered within Project 202302. From a risk-based perspective, the goal of the standard is to mitigate the ongoing and
systemic performance issues identified across multiple Interconnections and across many
disturbances analyzed by NERC and the Regions. These issues have been identified in InverterBased Resources (IBR) and synchronous generators, with many causes of tripping entirely
unrelated to voltage and frequency protection settings as dictated by the currently effective
version of PRC-024.
At the April 19, 2023 meeting, the Standards Committee (SC) accepted the most recent revised
SAR submitted by the Project 2020-02 Standard Drafting Team.
NERC Standard Processes Manual Section 16.0 Waiver provides as follows:
The SC may waive any of the provisions contained in this manual for good cause
shown, but limited to the following circumstances:
Limited Disclosure
•
In response to a national emergency declared by the United
States or Canadian governments that involves the reliability of the
Bulk Electric System (BES) or cyber attack on the BES;
•
Where necessary to meet regulatory deadlines;
•
Where necessary to meet deadlines imposed by the NERC Board
of Trustees; or
Limited Disclosure
•
Where the SC determines that a modification to a proposed
Reliability Standard or its requirement(s), a modification to a
defined term, a modification to an Interpretation, or a
modification to a variance has already been vetted by the industry
through the standards development process or is so insubstantial
that developing the modification through the processes contained
in this manual will add significant time delay.
FERC Order 901 directs the development of new or modified reliability standards that include
new requirements for disturbance monitoring, data sharing, post-event performance
validation, and correction of IBR performance. This set of directives from the report comprises
the first three sets of Standards Projects that must be completed and filed with FERC. This first
set (disturbance monitoring data sharing and post-event performance validation and correction
of IBR performance) must be filed with FERC by November 4, 2024.
NERC Standards Development has identified three active projects (2020-02, 2021-04, and 202302) that are directly impacted by these associated FERC directives. Project 2020-02 DT
leadership and NERC staff request that the SC approve a waiver for specific provisions of the
SPM regarding the length of comment periods and ballots in order to meet the November 2024
development deadline for 2020-02 as established by FERC.
Summary
Project 2020-02 DT leadership and NERC staff recommend that the SC shorten the initial formal
comment and ballot period from 45 days to as few as 25 days and any additional formal
comment and ballot period(s) from 45 days to as few as 15 days. In addition, Project 2020-02
DT leadership and NERC staff recommend that the SC shorten the final ballot from 10 days to 5
days.
Limited Disclosure
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
PRC‐024‐4 is posted for a 25‐day formal comment period with initial ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization
Request (SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
Anticipated Actions
Date
25‐day formal comment period with initial ballot
March 27 ‐ April 22, 2024
15‐day formal comment period and additional ballot
May 20 ‐ June 4, 2024
15‐day formal comment period and additional ballot
July 1 ‐ 16, 2024
Final Ballot
July 18 ‐ 24, 2024
Board adoption
August 14, 2024
Initial Draft of PRC‐024‐4
March 2024
Page 1 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Initial Draft of PRC‐024‐4
March 2024
Page 2 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
A. Introduction
1.
Title:
Frequency and Voltage Protection Settings for Synchronous Generators
and Synchronous Condensers
2.
Number:
3.
Purpose: To assure that protection of synchronous generators and synchronous
condensers do not cause tripping during defined frequency and voltage excursions in
support of the Bulk Power System (BPS).
4.
Applicability:
PRC‐024‐4
4.1. Functional Entities:
4.1.1. Generator Owners that apply protection listed in Sections 4.2.1 or 4.2.2.
4.1.2. Transmission Owners that apply protection listed in Section 4.2.2.
4.1.3. Transmission Owners (in the Quebec Interconnection only) that own a
BES generator step‐up (GSU) transformer or main power transformer
(MPT)1 and apply protection listed in Section 4.2.1.
4.1.4. Planning Coordinators (in the Quebec Interconnection only)
4.2. Facilities2:
4.2.1 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the generating resource(s); or (ii)
provide signals to the generating resource(s) to trip; and are applied to
the following:
4.2.1.1
Bulk Electric System (BES) synchronous generators.
4.2.1.2
BES GSU transformer(s) for synchronous generators.
4.2.1.3
High‐side of the synchronous generator‐connected unit
auxiliary transformer3 (UAT) installed on BES generating
resource(s).
4.2.1.4
Elements that are designed primarily for the delivery of
capacity from multiple synchronous generators connecting to
a common bus identified in the BES Definition, Inclusion I4, to
the point where those resources aggregate to greater than 75
MVA.
1
For the purpose of this standard, the MPT is the power transformer that steps up voltage from multiple small synchronous
generators, e.g. multiple small hydro generators connecting to a common bus.
2 It is not required to install or activate the protections described in Facilities Section 4.2.
3 These transformers are variously referred to as station power UAT, or station service transformer(s) used to provide overall
auxiliary power to the synchronous generators. This UAT is the transformer connected on the generator bus between the low
side of the GSU and the generator terminal.
Initial Draft of PRC‐024‐4
March 2024
Page 3 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
4.2.1.5
MPT of multiple synchronous generators connecting to a
common bus as identified in the BES Definition, Inclusion I4.
4.2.2 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip transmission connected synchronous
condensers; or (ii) provide signals to trip transmission connected
synchronous condenser and are applied to the following:
4.2.2.1
BES synchronous condensers
4.2.2.2
BES step‐up transformer(s) for synchronous condensers.
4.2.2.3
High‐side of the synchronous condenser‐connected unit
auxiliary transformer (UAT).
4.2.3 Exemptions: Protection on all auxiliary equipment within the
synchronous generator or synchronous condenser Facility.
5.
Effective Date: See Implementation Plan for PRC‐024‐4
Initial Draft of PRC‐024‐4
March 2024
Page 4 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
B. Requirements and Measures
R1.
Each Generator Owner and Transmission Owner shall set applicable frequency
protection4 in accordance with PRC‐024 Attachment 1 such that the applicable
protection does not cause the synchronous generator(s) or condenser(s) to trip
within the “no trip zone” during a frequency excursion with the following exceptions:
[Violation Risk Factor: Medium] [Time Horizon: Long‐term Planning]
Applicable frequency protection may be set to trip within a portion of the “no
trip zone” for documented and communicated regulatory or equipment
limitations in accordance with Requirement R3.
M1. Each Generator Owner and Transmission Owner shall have evidence that the
applicable frequency protection has been set in accordance with Requirement R1,
such as dated setting sheets, calibration sheets, calculations, or other documentation.
R2.
Each Generator Owner and Transmission Owner shall set applicable voltage
protection5 in accordance with PRC‐024 Attachment 2, such that the applicable
protection does not cause the synchronous generator(s) or condenser(s) to trip
within the “no trip zone” during a voltage excursion at the high‐side of the GSU or
MPT, subject to the following exceptions: [Violation Risk Factor: Medium] [Time
Horizon: Long‐term Planning]
If the Transmission Planner allows less stringent voltage protection settings than
those required to meet PRC‐024 Attachment 2, then the Generator Owner or
Transmission Owner may set its protection within the voltage recovery
characteristics of a location‐specific Transmission Planner’s study.
Applicable voltage protection may be set to trip during a voltage excursion
within a portion of the “no trip zone” for documented and communicated
regulatory or equipment limitations in accordance with Requirement R3.
M2. Each Generator Owner and Transmission Owner shall have evidence that applicable
voltage protection has been set in accordance with Requirement R2, such as dated
setting sheets, voltage‐time boundaries, calibration sheets, coordination plots,
dynamic simulation studies, calculations, or other documentation.
R3.
Each Generator Owner and Transmission Owner shall document each known
regulatory or equipment limitation6 that prevents an applicable synchronous
generator(s) or condenser(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. [Violation
Risk Factor: Lower] [Time Horizon: Long‐term Planning]
4 Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s) or condenser(s); or (ii) provide
signals to the synchronous generator(s) or condenser(s) to trip.
5 Ibid.
6 Excludes limitations caused by the setting capability of the frequency, voltage, and volts per hertz protective relays for the
synchronous generator(s) or condenser(s). This does not exclude limitations originating in the equipment protected by the
relay.
Initial Draft of PRC‐024‐4
March 2024
Page 5 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
3.1. The Generator Owner and Transmission Owner shall communicate the
documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and
Transmission Planner within 30 calendar days of any of the following:
Identification of a regulatory or equipment limitation.
Repair of the equipment causing the limitation that removes the limitation.
Replacement of the equipment causing the limitation with equipment that
removes the limitation.
Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life‐time frequency excursion allowance.
M3. Each Generator Owner and Transmission Owner shall have evidence that it has
documented and communicated any known regulatory or equipment limitations that
resulted in an exception to Requirements R1 or R2 in accordance with Requirement
R3, such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
R4.
Each Generator Owner and Transmission Owner shall provide its applicable protection
settings associated with Requirements R1 and R2 to the Planning Coordinator or
Transmission Planner that models the associated synchronous generator(s) or
condenser(s) within 60 calendar days of receipt of a written request for the data and
within 60 calendar days of any change to those previously requested settings unless
directed by the requesting Planning Coordinator or Transmission Planner that the
reporting of protection setting changes is not required. [Violation Risk Factor: Lower]
[Time Horizon: Operations Planning]
M4. Each Generator Owner and Transmission Owner shall have evidence that it
communicated applicable protection settings in accordance with Requirement R4,
such as dated e‐mails, correspondence or other evidence and copies of any requests it
has received for that information.
Initial Draft of PRC‐024‐4
March 2024
Page 6 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full‐time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
The Generator Owner and Transmission Owner shall keep data or evidence
of Requirements R1 through R4 for five years or until the next audit,
whichever is longer.
If a Generator Owner or Transmission Owner is found non‐compliant, the
Generator Owner or Transmission Owner shall keep information related to
the non‐compliance until mitigation is complete and approved for the time
period specified above, whichever is longer.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Initial Draft of PRC‐024‐4
March 2024
Page 7 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous Condensers
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
R2.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
set its applicable frequency
protection so that it does not
trip according to Requirement
R1.
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does not
trip according to Requirement
R2.
The Generator Owner or
Transmission Owner failed to
document any known non‐
protection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar
R3.
The Generator Owner or
Transmission Owner
documented the known non‐
protection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 30 calendar days but less
than or equal to 60 calendar
days of identifying the
limitation.
Initial Draft of PRC‐024‐4
March 2024
The Generator Owner or
Transmission Owner
documented the known non‐
protection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 60 calendar days but less
than or equal to 90 calendar
days of identifying the
limitation.
The Generator Owner or
Transmission Owner
documented the known non‐
protection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 90 calendar days but less
than or equal to 120 calendar
days of identifying the
limitation.
Page 8 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous Condensers
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
days of identifying the
limitation.
R4.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 60 calendar days but less
than or equal to 90 calendar
days of any change to those
settings.
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
60 calendar days but less than
or equal to 90 calendar days of
a written request.
Initial Draft of PRC‐024‐4
March 2024
The Generator Owner or
Transmission Owner provided
its protection settings more
than 90 calendar days but less
than or equal to 120 calendar
days of any change to those
settings.
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
90 calendar days but less than
or equal to 120 calendar days
of a written request.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 120 calendar days but less
than or equal to 150 calendar
days of any change to those
settings.
OR
The Generator Owner or
Transmission Owner or
provided protection settings
more than 120 calendar days
but less than or equal to 150
calendar days of a written
request.
The Generator Owner or
Transmission Owner failed to
provide its protection settings
within 150 calendar days of any
change to those settings.
OR
The Generator Owner or
Transmission Owner failed to
provide protection settings
within 150 calendar days of a
written request.
Page 9 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
D. Regional Variances
D.A.
Variance for the Quebec Interconnection
This Variance replaces Requirement R2 of the continent‐wide standard in its entirety
and adds a new requirement, Requirement D.A.5., applicable to Planning
Coordinators in the Quebec Interconnection.
This Variance replaces continent‐wide Requirement R2 in its entirety with the
following:
D.A.2.
Each Generator Owner and Transmission Owner shall set applicable
voltage protection6 in accordance with PRC‐024 Attachment 2B, such that
the applicable protection does not cause the synchronous generator(s) or
condenser(s) to trip within the “no trip zone” during a voltage excursion
at the high‐side of the GSU or MPT, subject to the following exceptions:
[Violation Risk Factor: Medium] [Time Horizon: Long‐term Planning]
For newly designated strategic power plants, applicable protections
must comply with the high voltage durations for such plants within 48
calendar months of the notification made pursuant to Requirement
D.A.5. During this transition period, voltage protections must at least
comply with the high voltage durations for “all power plants”.
Synchronous generator(s) are permitted to be set to trip during a
voltage excursion bounded by the “no trip zone” of PRC‐024
Attachment 2B for documented and communicated regulatory or
equipment limitations in accordance with Requirement R3.
If the Transmission Planner allows less stringent voltage protection
settings than those required to meet PRC‐024 Attachment 2B, then
the Generator Owner or Transmission Owner may set its protection
within the voltage recovery characteristics of a location‐specific
Transmission Planner’s study.
M.D.A.2. Each Generator Owner and Transmission Owner shall have evidence that
applicable voltage protection has been set in accordance with
Requirement R2, such as dated setting sheets, voltage‐time boundaries,
calibration sheets, coordination plots, dynamic simulation studies,
calculations, or other documentation.
This Variance adds the following Requirement:
D.A.5
Each Planning Coordinator shall designate, at least once every five
calendar years, the strategic power plants that must comply with
Attachment 2B and notify, within 30 calendar days of its designation,
each Generator Owner or Transmission Owner that owns facilities7 in the
7 Facilities in the strategic power plants include facilities with synchronous generator(s) from the generator up to and including
the MPT or GSU.
Initial Draft of PRC‐024‐4
March 2024
Page 10 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
strategic power plants. [Violation Risk Factor: Medium] [Time Horizon:
Long‐term planning]
M.D.A.5 Each Planning Coordinator shall have evidence that it designated, at least
once every five calendar years, strategic power plants in accordance with
Requirement D.A.5, Part 5 and shall have dated evidence that each
Generator Owner or Transmission Owner has been notified in accordance
with Requirement D.A.5, part 5.2. Evidence may include, but is not
limited to letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
Initial Draft of PRC‐024‐4
March 2024
Page 11 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous Condensers
Violation Severity Levels
This Variance adds a VSL for D.A.5 and modifies the VSL for R2 as follows:
Violation Severity Levels
R#
Lower
VSL
D.A.2. N/A
D.A.5.
N/A
Moderate VSL
High VSL
N/A
N/A
Severe VSL
The Generator Owner or Transmission
Owner failed to set its applicable
voltage protection so that it does not
trip in accordance with Requirement
D.A.2.
OR
The Generator Owner or Transmission
Owner set its applicable voltage
protection in accordance with
Requirement D.A.2 but, for strategic
power plants, failed to do so within 48
months of notification.
The Planning Coordinator failed to
The Planning Coordinator designated
The Planning Coordinator designated
designate, at least once every five
strategic power plants at least once
strategic power plants at least once
years, the strategic power plants that
every five calendar years but notified
every five calendar years but notified
each Generator Owner or Transmission each Generator Owner or Transmission must comply with Attachment 2B.
Owner that owns facilities in the
Owner that owns facilities in the
strategic power plants between 46
strategic power plants between 31
OR
days and 45 days after its designation. days and 60 days after its designation.
The Planning Coordinator failed to
notify, each Generator Owner or
Transmission Owner that owns
facilities in the strategic power plants
or notified them more than 60 days
after its designation.
E. Associated Documents
Implementation Plan
Initial Draft of PRC‐024‐4
March 2024
Page 12 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Version History
Version
Date
Action
Change Tracking
1
May 9, 2013
Adopted by the NERC Board of
Trustees
1
March 20, 2014
FERC Order issued approving PRC‐
024‐1. (Order becomes effective on
7/1/16.)
2
February 12, 2015
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2014‐01:
Applicability revised to
clarify application of
requirements to BES
dispersed power
producing resources
2
May 29, 2015
FERC Letter Order in Docket No.
RD15‐3‐000 approving PRC‐024‐2
Modifications to adjust
the applicability to
owners of dispersed
generation resources.
3
February 6, 2020
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2018‐04
3
July 9, 2020
FERC Letter Order approved PRC‐024‐
3. Docket No. RD20‐7‐000
3
July 17, 2020
Effective Date
10/1/2022
Initial Draft of PRC‐024‐4
March 2024
Page 13 of 22
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Attachment 1
(Frequency No Trip Boundaries by Interconnection8)
Eastern Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1.1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Frequency Boundary Data Points – Eastern Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥60.5
Instantaneous9
10(90.935‐1.45713*f)
≤57.8
≤59.5
Instantaneous11
10(1.7373*f‐100.116)
<60.5
Continuous operation
> 59.5
Continuous operation
Table 1.2
8 The figures do not visually represent the “no trip zone” boundaries before 0.1 seconds and after 10,000 seconds. The
Frequency Boundary Data Points Table defines the entirety of the “no trip zone” boundaries.
9 Frequency is calculated over a window of time. While the frequency boundaries include the option to trip instantaneously for
frequencies outside the specified range, this calculation should occur over a time window. Typical window/filtering lengths are
three to six cycles (50 – 100 milliseconds). Instantaneous trip settings based on instantaneously calculated frequency
measurement is not permissible.
Initial Draft of PRC‐024‐4
March 2024
Page 14 of 22
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Western Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
56
0.1
1
10
100
1000
10000
Time (Sec)
Figure1.3
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Frequency Boundary Data Points – Western Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.7
≥61.6
≥60.6
<60.6
Instantaneous11
30
180
Continuous operation
≤57.0
≤57.3
≤57.8
≤58.4
≤59.4
Instantaneous11
0.75
7.5
30
180
>59.4
Continuous operation
Table 1.4
Initial Draft of PRC‐024‐4
March 2024
Page 15 of 22
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Frequency (Hz)
Quebec Interconnection Boundaries
67
66
65
64
63
62
61
60
59
58
57
56
55
No Trip Zone*
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1.5
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Frequency Boundary Data Points – Quebec Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (Sec)
>66.0
Instantaneous11
<55.5
Instantaneous11
≥63.0
5
≤56.5
0.35
≥61.5
90
≤57.0
2
≥60.6
660
≤57.5
10
<60.6
Continuous operation
≤58.5
90
≤59.4
660
>59.4
Continuous operation
Table 1.6
Initial Draft of PRC‐024‐4
March 2024
Page 16 of 22
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
ERCOT Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1.7
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Frequency Boundary Data Points – ERCOT Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
Instantaneous11
≤57.5
Instantaneous11
≥61.6
30
≤58.0
2
≥60.6
540
≤58.4
30
<60.6
Continuous operation
≤59.4
540
>59.4
Continuous operation
Table 1.8
Initial Draft of PRC‐024‐4
March 2024
Page 17 of 22
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Attachment 2
Voltage (per unit)8
(Voltage No-Trip Boundaries – Eastern, Western, and ERCOT Interconnections)
The Voltage No Trip Zone ends at 4
seconds for applicability to PRC‐024
1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
No Trip Zone*
0
0.5
1
1.5
2
2.5
3
3.5
4
Time (sec)
High Voltage Duration
Low Voltage Duration
10
Figure 2.1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Voltage Boundary Data Points
High Voltage Duration
Low Voltage Duration
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
≥1.200
0.00
<0.45
0.15
≥1.175
0.20
<0.65
0.30
≥1.15
0.50
<0.75
2.00
≥1.10
<1.10
1.00
4.00
<0.90
≥ 0.90
3.00
4.00
Table 2.2
8Voltage at the high‐side of the GSU or MPT.
Initial Draft of PRC‐024‐4
March 2024
Page 18 of 22
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Attachment 2A: Voltage Boundary Clarifications
(Eastern, Western, and ERCOT Interconnections)
Boundary Details:
1. Unless otherwise specified by the Transmission Planner, the per unit voltage base for
these boundaries is the nominal transmission system voltage (e.g., 100 kV, 115 kV, 138
kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the boundaries assume RMS fundamental frequency phase‐to‐ground or
phase‐to‐phase per unit voltage.
5. For applicability to PRC‐024, the “no trip zone” ends at 4 seconds.
Evaluating Protection Settings
The voltage values in the Attachment 2 voltage boundaries are voltages at the high‐side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high‐side of the transformer with a low side below 100kV and a high‐side 100kV or above.
When evaluating protection settings, consider the voltage differences between where the
protection is measuring voltage and the high‐side of the GSU/MPT. A steady state calculation or
dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high‐side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Initial Draft of PRC‐024‐4
March 2024
Page 19 of 22
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Attachment 2B
(Voltage No-Trip Boundaries – Quebec Interconnection)
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
2.5
0 0.1
0.033
0.15
0.5
1
2
3
4
5
30
300
Time (sec)
Low Voltage/High Voltage Duration – Synchronous Generators and Condensers
High Voltage Duration - Strategic Power Plants
Figure 1
* The area outside the “No Trip Zone” is not a “Must Trip Zone.”
Initial Draft of PRC‐024‐4
March 2024
Page 20 of 22
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Voltage Boundary Data Points – Quebec Interconnection
High Voltage Duration for all
High Voltage Duration for strategic1
Synchronous Generators and
Power Plants
Condensers
Voltage (per unit)
Minimum Time (sec)
‐‐‐
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
Voltage (per unit)
Minimum Time (sec)
>1.50
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
0.033
0.10
2.50
5.00
30
300
continuous
‐‐‐
0.033
0.10
2.00
30
300
continuous
Table 1
Voltage Boundary Data Points – Quebec Interconnection
Low Voltage Duration for all Synchronous Generators and Condensers
Voltage (per unit)
Minimum Time (sec)
<0.25
0.15
<0.75
1.00
<0.85
2.00
<0.90
30
≥0.90
continuous
Table 2
Initial Draft of PRC‐024‐4
March 2024
Page 21 of 22
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and Synchronous
Condensers
Attachment 2C
(Voltage Boundary Clarifications Quebec Interconnection)
Boundary Details:
1. The per unit voltage base for these boundaries is the nominal operating voltage (e.g.,
120 kV, 161 kV, 230 kV, 315 kV, 735 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the Quebec Interconnection boundaries assume positive‐sequence values.
Evaluating Protection Settings
The voltage values in the Attachment 2B voltage boundaries are voltages at the high‐side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high‐side of the transformer that connects to the interconnecting voltage. When evaluating
protection settings, consider the voltage differences between where the protection is
measuring voltage and the high‐side of the GSU/MPT. A steady state calculation or dynamic
simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high‐side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Initial Draft of PRC‐024‐4
March 2024
Page 22 of 22
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
PRC-024-4 is posted for a 25-day formal comment period with initial ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization
Request (SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
Anticipated Actions
Date
25-day formal comment period with initial ballot
March 27, 2024 - April
22, 2024
15-day formal comment period and additional ballot
May 20, 2024 – June 4,
2024
15-day formal comment period and additional ballot
July 1, 2024 – July 16,
2024
Final Ballot
July 18, 2024 – July 24,
2024
Board adoption
August 14, 2024
Initial Draft of PRC-024-43
September March 202419
Page 1 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Initial Draft of PRC-024-43
September March 202419
Page 2 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
A. Introduction
1.
Title:
Frequency and Voltage Protection Settings for Generating
ResourcesSynchronous Generators and Synchronous Condensers
2.
Number:
3.
Purpose: To set assure that protection of Ssynchronous Ggenerators and
Ssynchronous Ccondensers generating resource(s) remain connected does not cause
tripping during defined frequency and voltage excursions in support of the Bulk
Electric SystemPower System (BEPS).
4.
Applicability:
PRC-024-43
4.1. Functional Entities:
4.1.1. Generator Owners that apply protection listed in Sections 4.2.1 or 4.2.2.
4.1.1.4.1.2.
Transmission Owners that apply protection listed in Section 4.2.2.
4.1.2.4.1.3. Transmission Owners (in the Quebec Interconnection only) that
own a BES generator step-up (GSU) transformer or main power
transformer (MPT)1 and apply protection listed in Section 4.2.1.
4.1.3.4.1.4.
Planning Coordinators (in the Quebec Interconnection only)
4.2. Facilities2:
4.2.1 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the generating resource(s); or (ii)
provide signals to the generating resource(s) to either trip or cease
injecting current; and are applied to the following:
4.2.1.1
Bulk Electric System (BES) synchronous generatorsgenerating
resource(s).
4.2.1.2
BES GSU transformer(s) for synchronous generators.
4.2.1.3
High -side of the synchronous generator-connected unit
auxiliary transformer3 (UAT) installed on BES generating
resource(s).
1
For the purpose of this standard, the MPT is the power transformer that steps up voltage from multiple small
synchronous generators, e.g. multiple small hydro generators connecting to a common bus. the collection system
voltage to the nominal transmission/interconnecting system voltage for dispersed power producing resources.
2
It is not required to install or activate the protections described in Facilities Section 4.2.
3
These transformers are variously ably referred to as station power UAT, or station service transformer(s) used to
provide overall auxiliary power to the generating resource(s)synchronous generators. This UAT is the transformer
connected on the generator bus between the low side of the GSU and the generator terminal.
Initial Draft of PRC-024-43
September March 202419
Page 3 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
4.2.1.4
Individual synchronous generators utilized as dispersed power
producing resource(s) identified in the BES Definition,
Inclusion I4.
4.2.1.54.2.1.4 Elements that are designed primarily for the delivery of
capacity from the individualispersed power producing
resources multiple synchronous generators connecting to a
common bus identified in the BES Definition, Inclusion I4, to
the point where those resources aggregate to greater than 75
MVA.
4.2.1.5
MPT4 of multiple synchronous generators connecting to a
common bus utilized as dispersed power producing resources
resource(s) as identified in the BES Definition, Inclusion I4.
4.2.2 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip tranmission connected synchronous
condensers; or (ii) provide signals to trip transmission connected
synchronous condenser and are applied to the following:
4.2.2.1
BES synchronous condensers
4.2.2.2
BES step-up transformer(s) for synchronous condensers.
4.2.1.64.2.2.3 High- side of the synchronous condenser-connected unit
auxiliary transformer5 (UAT).
4.2.24.2.3
Exemptions: Protection on all auxiliary equipment within the
synchronous generator or synchronous condenser generating Facility.
5.
Effective Date: See Implementation Plan for PRC-024-43
4
For the purpose of this standard, the MPT is the power transformer that steps up voltage from the collection
system voltage to the nominal transmission/interconnecting system voltage for dispersed power producing
resources.
5
These transformers are variably referred to as station power UAT, or station service transformer(s) used to
provide overall auxiliary power to the synchronous condenser
Initial Draft of PRC-024-43
September March 202419
Page 4 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
B. Requirements and Measures
R1.
Each Generator Owner and Transmission Owner shall set its applicable frequency
protection6 in accordance with PRC-024 Attachment 1 such that the applicable
protection does not cause the generating synchronous generator(s) or condenser(s)
to trip or cease injecting current within the “no trip zone” during a frequency
excursion with the following exceptions: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
•
Applicable frequency protection may be set to trip or cease injecting current
within a portion of the “no trip zone” for documented and communicated
regulatory or equipment limitations in accordance with Requirement R3.
M1. Each Generator Owner and Transmission Owner shall have evidence that the
applicable frequency protection has been set in accordance with Requirement R1,
such as dated setting sheets, calibration sheets, calculations, or other documentation.
R2.
Each Generator Owner and Transmission Owner shall set its applicable voltage
protection7 in accordance with PRC-024 Attachment 2, such that the applicable
protection does not cause the generating resource synchronous generator(s) or
condenser(s) to trip or cease injecting current within the “no trip zone” during a
voltage excursion at the high- side of the GSU or MPT, subject to the following
exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
•
If the Transmission Planner allows less stringent voltage protection settings than
those required to meet PRC-024 Attachment 2, then the Generator Owner or
Transmission Owner may set its protection within the voltage recovery
characteristics of a location-specific Transmission Planner’s study.
•
Applicable voltage protection may be set to trip or cease injecting current during
a voltage excursion within a portion of the “no trip zone” for documented and
communicated regulatory or equipment limitations in accordance with
Requirement R3.
M2. Each Generator Owner and Transmission Owner shall have evidence that applicable
voltage protection has been set in accordance with Requirement R2, such as dated
setting sheets, voltage-time boundaries, calibration sheets, coordination plots,
dynamic simulation studies, calculations, or other documentation.
6
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated
control systems) that respond to electrical signals and: (i) directly trip the generating resource(s) synchronous
generator(s) or condenser(s); or (ii) provide signals to the generating resource(s) synchronous generator(s) or
condenser(s) to either trip or cease injecting current.
7
Ibid.
Initial Draft of PRC-024-43
September March 202419
Page 5 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
R3.
Each Generator Owner and Transmission Owner shall document each known
regulatory or equipment limitation8 that prevents an applicable generating
resource(s) synchronous generator(s) or condenser(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. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
3.1. The Generator Owner and Transmission Owner shall communicate the
documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and
Transmission Planner within 30 calendar days of any of the following:
•
Identification of a regulatory or equipment limitation.
•
Repair of the equipment causing the limitation that removes the limitation.
•
Replacement of the equipment causing the limitation with equipment that
removes the limitation.
•
Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life-time frequency excursion allowance.
M3. Each Generator Owner and Transmission Owner shall have evidence that it has
documented and communicated any known regulatory or equipment limitations that
resulted in an exception to Requirements R1 or R2 in accordance with Requirement
R3, such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
R4.
Each Generator Owner and Transmission Owner shall provide its applicable protection
settings associated with Requirements R1 and R2 to the Planning Coordinator or
Transmission Planner that models the associated generating resource(s) synchronous
generator(s) or condenser(s) within 60 calendar days of receipt of a written request
for the data and within 60 calendar days of any change to those previously requested
settings unless directed by the requesting Planning Coordinator or Transmission
Planner that the reporting of protection setting changes is not required. [Violation
Risk Factor: Lower] [Time Horizon: Operations Planning]
M4. Each Generator Owner and Transmission Owner shall have evidence that it
communicated applicable protection settings in accordance with Requirement R4,
such as dated e-mails, correspondence or other evidence and copies of any requests it
has received for that information.
8
Excludes limitations caused by the setting capability of the frequency, voltage, and volts per hertz protective
relays for the generating resource(s) synchronous generator(s) or condenser(s). This does not exclude limitations
originating in the equipment protected by the relay. This also does not exclude limitations of frequency, voltage,
and volts per hertz protection embedded in control systems.
Initial Draft of PRC-024-43
September March 202419
Page 6 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
Initial Draft of PRC-024-43
September March 202419
Page 7 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
The Generator Owner and Transmission Owner shall keep data or evidence
of Requirements R1 through R4 for 3five years or until the next audit,
whichever is longer.
•
If a Generator Owner or Transmission Owner is found non-compliant, the
Generator Owner or Transmission Owner shall keep information related to
the non-compliance until mitigation is complete and approved for the time
period specified above, whichever is longer.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Initial Draft of PRC-024-43
September March 202419
Page 8 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating ResourcesGenerators and Synchronous Condensers
Violation Severity Levels
Violation Severity Levels
R#
R1.
R2.
R3.
Lower VSL
Moderate VSL
High VSL
N/A
N/A
N/A
Severe VSL
The Generator Owner or
Transmission Owner failed to
set its applicable frequency
protection so that it does
not trip or enter momentary
cessation according to
Requirement R1.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does
not trip or enter momentary
cessation according to
Requirement R2.
The Generator Owner or
The Generator Owner or
The Generator Owner or
The Generator Owner or
Transmission Owner
Transmission Owner
Transmission Owner
Transmission Owner failed to
documented the known non- documented the known non- documented the known non- document any known nonprotection system
protection system
protection system
protection system
equipment limitation that
equipment limitation that
equipment limitation that
equipment limitation that
prevented it from meeting
prevented it from meeting
prevented it from meeting
prevented it from meeting
the criteria in Requirement
the criteria in Requirement
the criteria in Requirement
the criteria in Requirement
R1 or R2 and communicated R1 or R2 and communicated R1 or R2 and communicated R1 or R2.
the documented limitation
the documented limitation
the documented limitation
OR
to its Planning Coordinator
to its Planning Coordinator
to its Planning Coordinator
The Generator Owner or
and Transmission Planner
and Transmission Planner
and Transmission Planner
more than 30 calendar days more than 60 calendar days more than 90 calendar days Transmission Owner failed to
communicate the
Initial Draft 2 of PRC-024-34
March September 201924
Page 9 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating ResourcesGenerators and Synchronous Condensers
Violation Severity Levels
R#
Lower VSL
R4.
Moderate VSL
High VSL
Severe VSL
but less than or equal to 60
calendar days of identifying
the limitation.
but less than or equal to 90
calendar days of identifying
the limitation.
but less than or equal to 120
calendar days of identifying
the limitation.
documented limitation to its
Planning Coordinator and
Transmission Planner within
120 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner
provided its protection
settings more than 60
calendar days but less than
or equal to 90 calendar days
of any change to those
settings.
The Generator Owner or
Transmission Owner
provided its protection
settings more than 90
calendar days but less than
or equal to 120 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner
provided its protection
settings more than 120
calendar days but less than
or equal to 150 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner failed
to provide its protection
settings within 150 calendar
days of any change to those
settings.
OR
OR
OR
The Generator Owner or
Transmission Owner
provided protection settings
more than 60 calendar days
but less than or equal to 90
calendar days of a written
request.
The Generator Owner or
Transmission Owner
provided protection settings
more than 90 calendar days
but less than or equal to 120
calendar days of a written
request.
The Generator Owner or
Transmission Owner or
provided protection settings
more than 120 calendar days
but less than or equal to 150
calendar days of a written
request.
The Generator Owner or
Transmission Owner failed to
provide protection settings
within 150 calendar days of a
written request.
Initial Draft 2 of PRC-024-34
March September 201924
OR
Page 10 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
D. Regional Variances
D.A.
Variance for the Quebec Interconnection
This Variance extends the applicability of Requirements R1, R3, and R4 to
Transmission Owners in the Quebec Interconnection that own a BES GSU or MPT
and apply protection listed in Section 4.2.1, Facilities. This Variance also replaces
Requirement R2 of the continent-wide standard in its entirety and adds a new
requirement, Requirement D.A.5., applicable to Planning Coordinators in the
Quebec Interconnection.
In Requirements R1, R3, and R4, all references to “Generator Owner” are replaced
with “Generator Owner and Transmission Owner.”
This Variance replaces continent-wide Requirement R2 in its entirety with the
following:
D.A.2.
Initial Draft 2 of PRC-024-34
March September 201924
Each Generator Owner and Transmission Owner shall set its applicable
voltage protection65 in accordance with PRC-024 Attachment 2Ba, such
that the applicable protection does not cause the generating
resourcesynchronous generator(s) or condenser(s) to trip or cease
injecting current within the “no trip zone” during a voltage excursion
within the “no trip zone” at the high -side of the GSU or MPT, subject to
the following exceptions: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
•
For newly designated strategic power plants, applicable protections
must comply with the high voltage durations for such plants within 48
calendar months of the notification made pursuant to Requirement
D.A.5. During this transition period, voltage protections must at least
comply with the high voltage durations for “all power plants”.
•
The generating resource(s)Synchronous generator(s) are permitted to
be set to trip or to cease injecting current during a voltage excursion
bounded by the “no trip zone” of PRC-024 Attachment 2Ba for
documented and communicated regulatory or equipment limitations
in accordance with Requirement R3.
•
If the Transmission Planner allows less stringent voltage protection
settings than those required to meet PRC-024 Attachment 2Ba, then
the Generator Owner or Transmission Owner may set its protection
within the voltage recovery characteristics of a location-specific
Transmission Planner’s study.
•
Inverter-based resources voltage protection settings may be set to
cease injecting current momentarily during a voltage excursion at the
high side of the MPT, bounded by the “no trip zone” of PRC-024
Attachment 2a, under the following conditions:
Page 11 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
o After a minimum delay of 0.022 s, when the positive-sequence
voltage exceeds 1.25 per unit (p.u.) Normal operation must
resume once the voltage drops back below 1.25 p.u at the high
side of the MPT.
o After a minimum delay of 0.022 s, when the phase-to-ground root
mean square (RMS) voltages exceeds 1.4 p.u., as measured at
generator terminals, on one or multiple phases. Normal operation
must resume once the positive-sequence voltage drops back
below the 1.25 p.u. at the high side of the MPT.
M.D.A.2. Each Generator Owner and Transmission Owner shall have evidence that
applicable voltage protection has been set in accordance with
Requirement R2, such as dated setting sheets, voltage-time boundaries,
calibration sheets, coordination plots, dynamic simulation studies,
calculations, or other documentation.
This Variance adds the following Requirement:
D.A.5
Each Planning Coordinator shall designate, at least once every five
calendar years, the strategic power plants that must comply with
Attachment 2Ba and notify, within 30 calendar days of its designation,
each Generator Owner or Transmission Owner that owns facilities9 in the
strategic power plants. [Violation Risk Factor: Medium] [Time Horizon:
Long-term planning]
M.D.A.5
Each Planning Coordinator shall have evidence that it designated, at least
once every five calendar years, strategic power plants in accordance with
Requirement D.A.5, Part 5 and shall have dated evidence that each
Generator Owner or Transmission Owner has been notified in accordance
with Requirement D.A.5, part 5.2. Evidence may include, but is not
limited to: letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
9
Facilities in the strategic power plants include facilities with synchronous generator(s) from the generator up to
and including the MPT or GSU.
Initial Draft 2 of PRC-024-34
March September 201924
Page 12 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating ResourcesGenerators and Synchronous Condensers
Violation Severity Levels
This Variance adds a VSL for D.A.5 and modifies the VSL for R2 as follows:
Violation Severity Levels
R#
D.A.2.
Lower
VSL
Moderate VSL
High VSL
N/A
N/A
N/A
Severe VSL
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does not
trip or enter momentary
cessation in accordance with
Requirement D.A.2.
OR
D.A.5.
N/A
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or
Transmission Owner that owns
Initial Draft 2 of PRC-024-34
March September 201924
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or
Transmission Owner that owns
The Generator Owner or
Transmission Owner set its
applicable voltage protection in
accordance with Requirement
D.A.2 but, for strategic power
plants, failed to do so within 48
months of notification.
The Planning Coordinator failed
to designate, at least once
every five years, the strategic
power plants that must comply
with Attachment 2Ba.
Page 13 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating ResourcesGenerators and Synchronous Condensers
Violation Severity Levels
R#
Lower
VSL
Moderate VSL
High VSL
Severe VSL
facilities in the strategic power plants facilities in the strategic power plants
between 31 days and 45 days after its between 46 days and 60 days after its OR
designation.
designation.
The Planning Coordinator failed
to notify, each Generator
Owner or Transmission Owner
that owns facilities in the
strategic power plants or
notified them more than 60
days after the its designation.
Initial Draft 2 of PRC-024-34
March September 201924
Page 14 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
E. Associated Documents
Implementation Plan
Initial Draft 2 of PRC-024-34
March September 201924
Page 15 of 27
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generating
ResourcesGenerators and Synchronous Condensers
Version History
Version
Date
Action
Change Tracking
1
May 9, 2013
Adopted by the NERC Board of
Trustees
1
March 20, 2014
FERC Order issued approving PRC024-1. (Order becomes effective
on 7/1/16.)
2
February 12, 2015
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2014-01:
Applicability revised to
clarify application of
requirements to BES
dispersed power
producing resources
2
May 29, 2015
FERC Letter Order in Docket No.
RD15-3-000 approving PRC-024-2
Modifications to adjust
the applicability to
owners of dispersed
generation resources.
3
February 6, 2020
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2018-04
3
July 9, 2020
FERC Letter Order approved
PRC024-3. Docket No. RD20-7-000
3
July 17, 2020
Effective Date
Initial Draft 2 of PRC-024-34
March September 201924
10/1/2022
Page 16 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
Attachment 1
(Frequency No Trip Boundaries by Interconnection10)
Eastern Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1.1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Frequency Boundary Data Points – Eastern Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥60.5
Instantaneous11
10(90.935-1.45713*f)
≤57.8
≤59.5
Instantaneous11
10(1.7373*f-100.116)
<60.5
Continuous operation
> 59.5
Continuous operation
Table 1.2
10
The figures do not visually represent the “no trip zone” boundaries before 0.1 seconds and after 10,000 seconds.
The Frequency Boundary Data Points Table defines the entirety of the “no trip zone” boundaries.
11
Frequency is calculated over a window of time. While the frequency boundaries include the option to trip
instantaneously for frequencies outside the specified range, this calculation should occur over a time window.
Typical window/filtering lengths are three to six cycles (50 – 100 milliseconds). Instantaneous trip settings based
on instantaneously calculated frequency measurement is not permissible.
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 17 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
Western Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
56
0.1
1
10
100
1000
10000
Time (Sec)
Figure 21.3
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Frequency Boundary Data Points – Western Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.7
≥61.6
≥60.6
<60.6
Instantaneous11
30
180
Continuous operation
≤57.0
≤57.3
≤57.8
≤58.4
≤59.4
Instantaneous11
0.75
7.5
30
180
>59.4
Continuous operation
Table 21.4
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 18 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
Frequency (Hz)
Quebec Interconnection Boundaries
67
66
65
64
63
62
61
60
59
58
57
56
55
No Trip Zone*
0.1
1
10
100
1000
10000
Time (Sec)
Figure 31.5
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Frequency Boundary Data Points – Quebec Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (Sec)
>66.0
≥63.0
≥61.5
≥60.6
<60.6
Instantaneous11
5
90
660
Continuous operation
<55.5
≤56.5
≤57.0
≤57.5
≤58.5
≤59.4
Instantaneous11
0.35
2
10
90
660
>59.4
Continuous operation
Table 31.6
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 19 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
ERCOT Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 41.7
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Frequency Boundary Data Points – ERCOT Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥61.6
≥60.6
<60.6
Instantaneous11
30
540
Continuous operation
≤57.5
≤58.0
≤58.4
≤59.4
Instantaneous11
2
30
540
>59.4
Continuous operation
Table 41.8
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 20 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
PRC-024 — Attachment 2
Voltage (per unit)8
(Voltage No-Trip Boundaries – Eastern, Western, and ERCOT Interconnections)
The Voltage No Trip Zone ends at 4
seconds for applicability to PRC-024
1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
No Trip Zone*
0
0.5
1
1.5
2
2.5
3
3.5
4
Time (sec)
High Voltage Duration
12Figure
Low Voltage Duration
2.1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Voltage Boundary Data Points
High Voltage Duration
Low Voltage Duration
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
≥1.200
≥1.175
≥1.15
≥1.10
<1.10
0.00
0.20
0.50
1.00
4.00
<0.45
<0.65
<0.75
<0.90
≥ 0.90
0.15
0.30
2.00
3.00
4.00
Table 12.2
8
Voltage at the high-side of the GSU or MPT.
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 21 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
Attachment 2A: Voltage Boundary Clarifications – Eastern,
Western, and ERCOT Interconnections
Boundary Details:
1. Unless otherwise specified by the Transmission Planner, the per unit voltage base for
these boundaries is the nominal transmission system voltage (e.g., 100 kV, 115 kV, 138
kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the boundaries assume RMS fundamental frequency phase-to-ground or
phase-to-phase per unit voltage.
5. For applicability to PRC-024, the “no trip zone” ends at 4 seconds.
Evaluating Protection Settings:
The voltage values in the Attachment 2 voltage boundaries are voltages at the high -side of the
GSU/MPT. For generating resources with multiple stages of step up to reach interconnecting
voltage, this is the high- side of the transformer with a low side below 100kV and a high- side
100kV or above. When evaluating protection settings, consider the voltage differences between
where the protection is measuring voltage and the high -side of the GSU/MPT. A steady state
calculation or dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high- side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 22 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
PRC-024— Attachment 2Ba
(Voltage No-Trip Boundaries – Quebec Interconnection)
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 23 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
2.5
0 0.1
0.5
0.15
1
2
3
4
5
30
300
Time (sec)
0.033
Low Voltage/High Voltage Duration – Synchronous Generators and Condensers
High Voltage Duration - Strategic Power Plants
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 24 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
May cease current injection momentarily
under specified conditions
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
2.5
0 0.1
0.5
0.15
1
2
3
4
5
30
300
Time (sec)
0.033
Low Voltage/High Voltage Duration - All Power Plants
Low Voltage Duration – Inverter-Based Resources
High Voltage Duration - Strategic Power Plants
Figure 1
* The area outside the "“No Trip Zone"” is not a "“Must Trip Zone."”
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 25 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
Voltage Boundary Data Points – Quebec Interconnection
High Voltage Duration for all Power
High Voltage Duration for strategic1
Plants Synchronous Generators and
Power Plants
Condensers
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
-->1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
--0.033
0.10
2.00
30
300
continuous
>1.50
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
0.033
0.10
2.50
5.00
30
300
continuous
Table 1
Voltage Boundary Data Points – Quebec Interconnection
Low Voltage Duration for all Power
Low Voltage Duration for InverterPlantsSynchronous Generators and
Based Resources
Condensers
Voltage (per unit)
Minimum Time (sec)
Voltage (pu)
Minimum Time (sec)
<0.25
<0.75
<0.85
<0.90
≥0.90
0.15
1.00
2.00
30
continuous
<0.25
<0.75
<0.85
<0.90
≥0.90
3.4*V(pu)+0.15
1.00
2.00
30
continuous
Table 2
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 26 of 27
PRC-024-34 Frequency and Voltage Protection Settings for Synchronous Generating Resources
Generators and Synchronous Condensers
Attachment 2Ca: Voltage Boundary Clarifications – Quebec
Interconnection
Boundary Details:
1. The per unit voltage base for these boundaries is the nominal operating voltage (e.g.,
120 kV, 161 kV, 230 kV, 315 kV, 735 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the Quebec Interconnection boundaries assume positive-sequence values.
Evaluating Protection Settings:
The voltage values in the Attachment 2Ba voltage boundaries are voltages at the high- side of
the GSU/MPT. For generating resources with multiple stages of step up to reach
interconnecting voltage, this is the high- side of the transformer that connects to the
interconnecting voltage. When evaluating protection settings, consider the voltage differences
between where the protection is measuring voltage and the high -side of the GSU/MPT. A
steady state calculation or dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high -side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Initial Draft 2 of PRC-024-34
MarchSeptember 201924
Page 27 of 27
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
Anticipated Actions
Date
25‐day formal comment period with initial ballot
March 27 ‐ April 22, 2024
15‐day formal comment period and additional ballot
May 20 ‐ June 4, 2024
15‐day formal comment period and additional ballot
July 1 ‐ 16, 2024
Final Ballot
July 18 ‐ 24, 2024
Board adoption
August 14, 2024
Initial Draft of PRC‐029‐1
March 2024
Page 1 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Continuous Operating Region – The range of voltages, measured at the high‐side of the main
power transformer, that are ≥ 0.9 per unit and ≤ 1.1 per unit.
Mandatory Operating Region – The range of voltages, measured at the high‐side of the main
power transformer, that are > 0.1 per unit and < 0.9 per unit – or – > 1.1 and ≤ 1.2 per unit.
Permissive Operating Region – The range of voltages, measured at the high‐side of the main
power transformer, that is ≤ 0.1 per unit.
Initial Draft of PRC‐029‐1
March 2024
Page 2 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
A. Introduction
1. Title:
Frequency and Voltage Ride‐through Requirements for Inverter‐Based
Generating Resources
2. Number:
PRC‐029‐1
3. Purpose:
To ensure that Inverter‐Based Resources (IBRs) remain connected and
perform operationally as expected to support of the Bulk Power System (BPS) during
and after defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.1.2. Transmission Owner1
4.2
Facilities: For purposes of this standard, the term “applicable Inverter‐Based
Resource” or “applicable Inverter‐Based Resources” refers to the following:
4.2.1. BPS IBRs
4.2.2. IBR Registration Criteria
5. Effective Date: See Implementation Plan for Project 2020‐02 – PRC‐029‐1
1 For owners of Voltage Source Converter – High‐voltage Direct Current (VSC‐HVDC) transmission facilities that are dedicated
connections for IBR to the BPS
Initial Draft of PRC‐029‐1
March 2024
Page 3 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
B. Requirements and Measures
R1.
Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that
each IBR remains electrically connected and continues to exchange current in
accordance with the no‐trip zones and operation regions as specified in
Attachment 1 unless needed to clear a fault or a documented equipment limitation
exists in accordance with Requirement R6. [Violation Risk Factor: High] [Time Horizon:
Operations Assessment]
M1. Each Generator Owner and Transmission Owner shall have evidence of actual
recorded data or other evidence for each applicable IBR demonstrating adherence to
ride‐through requirements, as specified in Requirement R1.
R2. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that
during a System disturbance, each IBR’s voltage performance adheres to the following,
unless a documented equipment limitation exists in accordance with Requirement R6.
[Violation Risk Factor: High] [Time Horizon: Operations Assessment]
2.1.
While the voltage at the high‐side of the main power transformer remains
within the Continuous Operation Region as specified in Attachment 1, each IBR
shall:
2.1.1 Continue to deliver the pre‐disturbance level of active power or
available active power, whichever is less, and continue to deliver active
power and reactive power up to its apparent power limit.
2.1.2 If the IBR cannot deliver both active and reactive power due to a
current or apparent power limit, when the applicable voltage is below
95% and still within the Continuous Operation Region, then preference
shall be given to active or reactive power according to requirements
specified by the Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator.
2.2.
While voltage at the high‐side of the main power transformer is within the
Mandatory Operation Region as specified in Attachment 1, each IBR shall:
2.2.1 Exchange current, up to the maximum capability while maintaining
automatic voltage regulation, on the affected phases during both
symmetrical and asymmetrical voltage disturbances.
2.2.2 Adjust reactive current injection at the high‐side of the main power
transformer so that the magnitude of the reactive current responds to
changes in voltage at the high‐side of the main power transformer in
accordance with default reactive prioritization unless the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission
Operator specifies a certain magnitude of reactive power response to
voltage changes or specifies active power priority instead of reactive
power priority.
2.3.
The IBR shall not itself cause voltage at the high‐side of the main power
transformer to exceed the applicable Attachment 1 Table 1 or Table 2 no‐trip
Initial Draft of PRC‐029‐1
March 2024
Page 4 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
zone voltage thresholds and time durations in its response from Mandatory or
Permissive Operation Regions to the Continuous Operating Region.
2.4.
Each IBR shall restore active power output to the pre‐disturbance or available
level within 1.0 second when the voltage at the high‐side of the main power
transformer returns to the Continuous Operation Region from the Mandatory
Operation Region or Permissive Operation Region (including operation in
current block mode) as specified in Attachment 1, unless the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission
Operator specifies a lower post‐disturbance active power level requirement or
specifies a different post‐disturbance active power restoration time.
2.5.
Each IBR shall only trip to prevent equipment damage, when the voltage at the
high‐side of the main power transformer is outside of the no‐trip zone as
specified in Attachment 1.
M2. Each Generator Owner and Transmission Owner shall have evidence of actual
recorded data or other evidence for each applicable IBR demonstrating adherence to
performance requirements, as specified in Requirement R2, during each System
disturbance which has occurred within the associated Planning Coordinator(s) area(s).
R3. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that
during a transient overvoltage as a result of a switching event whereby instantaneous
voltage at the high‐side of the main power transformer exceeds
1.2 per unit, each IBR shall either: [Violation Risk Factor: Lower] [Time Horizon:
Operations Assessment]
Remain electrically connected and continue to exchange current in accordance
with instantaneous transient overvoltage levels and durations specified in
Attachment 2; or
Remain electrically connected in current block mode in accordance with
instantaneous transient overvoltage levels and durations specified in
Attachment 2, and restart current exchange within 5 cycles of the instantaneous
voltage falling below (and remaining below) 1.2 per unit.
M3. Each Generator Owner and Transmission Owner shall have evidence of actual
recorded data or other evidence for each applicable IBR demonstrating adherence to
performance requirements, as specified in Requirement R3, during each transient
overvoltage period which has occurred within the associated Planning Coordinator(s)
area(s).
R4. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure each
IBR remains electrically connected and continues to exchange current during a
frequency excursion event whereby the frequency remains within the “no trip zone”
according to Attachment 3 and the absolute rate of change of frequency (ROCOF)2
2 Rate of change of frequency (ROCOF) is calculated as the average rate of change for multiple calculated system frequencies
for a time period of greater than or equal to 0.1 second. ROCOF is not calculated during the fault occurrence and clearance.
Initial Draft of PRC‐029‐1
March 2024
Page 5 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
magnitude is less than or equal to 5 Hz/second. [Violation Risk Factor: Lower] [Time
Horizon: Operations Assessment]
M4. Each Generator Owner and Transmission Owner shall have evidence of actual
recorded data or other evidence for each applicable IBR demonstrating adherence to
ride‐through requirements, as specified in Requirement R4, during each frequency
excursion event which has occurred within the associated Planning Coordinator(s)
area(s).
R5. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure each
IBR remains electrically connected and continues to exchange current during
instantaneous positive sequence voltage phase angle changes that are initiated by
non‐fault switching events on the transmission system and are changes of less than 25
electrical degrees at the high‐side of the main power transformer. [Violation Risk
Factor: Lower] [Time Horizon: Operations Assessment]
5.1.
When the instantaneous positive sequence voltage phase angle change is more
than 25 electrical degrees at the high‐side of the main power transformer and
is initiated by a non‐fault switching event on the transmission system, the IBR
may trip, but shall only trip to prevent equipment damage.
M5. Each Generator Owner and Transmission Owner shall have evidence of actual
recorded data or other evidence for each applicable IBR demonstrating adherence to
ride‐through requirements, as specified in Requirement R5, during instantaneous
positive sequence voltage phase angle changes that are changes of less than 25
electrical degrees at the high‐side of the main power transformer and that such
changes are not initiated by non‐fault switching events.
R6. Each Generator Owner and Transmission Owner with a documented equipment
limitation that would prevent an applicable IBR that is in‐service by the effective date
of this standard from meeting voltage ride‐through requirements as detailed in
Requirements R1 and R2 shall communicate each equipment limitation to the
associated Planning Coordinator(s), Transmission Planner(s), and Reliability
Coordinator(s). [Violation Risk Factor: Lower] [Time Horizon: Long‐term Planning]
6.1.
Each Generator Owner and Transmission Owner shall include in its
documentation:
6.1.1 Identifying information of the IBR (name, facility #, other)
6.1.2 Which aspects of voltage ride‐through requirements that the IBR would
be unable to meet
6.1.3 Identify the specific piece(s) of equipment causing the limitation
6.1.4 Information regarding any plans to repair or replace the limiting
equipment that would remove the limitation (such as estimated date of
repair/replacement)
6.2.
Each Generator Owner and Transmission Owner with a previously
communicated equipment limitation that repairs or replaces the equipment
causing the limitation shall document and communicate such equipment
Initial Draft of PRC‐029‐1
March 2024
Page 6 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
change to the associated Planning Coordinator(s), Transmission Planner(s), and
Reliability Coordinator(s) within 30 days of the equipment change.
M6. Each Generator Owner and Transmission Owner shall have evidence of equipment
limitations, as specified in Requirement R6, documented prior to the effective date of
PRC‐029‐1. Each Generator Owner and Transmission Owner with changes to
equipment shall have evidence of communication to each associated Planning
Coordinator, Transmission Planner, and Reliability Coordinator. Acceptable types of
evidence may include, but are not limited to, meeting minutes, agreements, copies of
procedures or protocols in effect between entities or between departments of a
vertically integrated system, or email correspondence.
Initial Draft of PRC‐029‐1
March 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full‐time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
Each Generator Owner and Transmission Owner shall retain evidence with
each requirement in this standard for five calendar years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Initial Draft of PRC‐029‐1
March 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
IBR remains electrically
connected and continued to
exchange current in
accordance with Attachment
1, unless needed to clear a
fault, in accordance with
Requirement R1.
R2.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
IBR adhered to performance
requirements during each
System disturbance, as
specified in Requirement R2.
R3.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
IBR adhered to performance
requirements during each
transient overvoltage period
as specified in Requirement
R3.
Initial Draft of PRC‐029‐1
March 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R4.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
IBR adhered to performance
requirements during each
frequency excursion event, as
specified in Requirement R4.
R5.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
IBR adhered to performance
requirements during each
instantaneous positive
sequence voltage phase angle
change of less than 25
electrical degrees, as specified
in Requirement R5.
R6.
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator, Transmission
Planner, and Reliability
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator, Transmission
Planner, and Reliability
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator, Transmission
Planner, and Reliability
The Generator Owner or
Transmission Owner failed to
document evidence of
equipment limitations
consistent with Requirement
R6 and prior to the effective
date of PRC‐029‐1
Requirement R6.
Initial Draft of PRC‐029‐1
March 2024
OR
Page 10 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Coordinator more than 30
calendar days but less than or
equal to 60 calendar days after
the change to the equipment.
Coordinator more than 60
calendar days but less than or
equal to 90 calendar days after
the change to the equipment.
Coordinator more than 90
calendar days but less than or
equal to 120 calendar days
after the change to the
equipment.
Severe VSL
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator, Transmission
Planner, and Reliability
Coordinator more than 120
calendar days after the change
to the equipment.
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
Initial Draft of PRC‐029‐1
March 2024
Page 11 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Version History
Version
Date
Initial Draft
3/27/24
Initial Draft of PRC‐029‐1
March 2024
Change
Tracking
Action
DRAFT
Page 12 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-Through Requirements for AC-Connected Wind IBR
Voltage (per unit)
Minimum Ride-Through
Time (sec)
≥1.200
N/A
≥1.1
1.0
≥1.05
1800
< 0.90
3.00
< 0.70
2.50
< 0.50
1.20
< 0.25
0.16
< 0.10
0.16
Table 2: Voltage Ride-Through Requirements for All Other IBR
Voltage (per unit)
Minimum Ride-Through
Time (sec)
≥1.200
N/A
≥1.1
1.0
≥1.05
1800
< 0.90
6.00
< 0.70
3.00
< 0.50
1.20
< 0.25
0.32
< 0.10
0.32
1. Table 1 applies to applicable wind IBR unless connected via a dedicated VSC‐HVDC
transmission facility.
2. Table 2 applies to all other IBR types not covered in Table 1; including, but not
limited to, the following IBR:
a. Isolated IBR, regardless of their energy resource, interconnecting via a dedicated
VSC‐HVDC transmission facility.
b. Other IBR plants or hybrid plants consisting of photovoltaic (PV) and ESS.
Initial Draft of PRC‐029‐1
March 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
3. In the case of hybrid IBR consisting of wind and various other IBR technologies, the
applicable table shall be based on direction by the Transmission Planner.
4. The voltage base for per unit calculation is the nominal phase‐to‐ground or
phase‐to‐phase transmission system voltage unless otherwise defined by the
Planning Coordinator or Transmission Planner.
5. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase to neutral or phase to phase fundamental root mean square (RMS) voltage at
the high side of the MPT.
6. Tables 1 and 2 are only applicable when the frequency is within the no trip zone as
specified in Table 3 of Attachment 3.
7. At any given voltage value, each IBR shall not trip until the time duration at that
voltage exceeds the specified minimum ride‐through time duration. If the voltage is
continuously varying over time, it is necessary to add the duration within each band
of Tables 1 and 2 over the 10‐second time period to determine compliance.
8. The specified duration of the Mandatory Operation Regions and the Permissive
Operation Regions in Tables 1 and 2 is cumulative over one or more disturbances
within a 10 second time period.
9. The IBR may trip for more than four deviations of the applicable voltage at the high‐
side of the main power transformer outside of the Continuous Operation Region
within any 10 second time period.
10. If the positive sequence voltage at the high‐side of the main power transformer
enters the Permissive Operation Region, an IBR may operate in current block mode
if necessary to protect the equipment.
Initial Draft of PRC‐029‐1
March 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Voltage (per unit)
No‐Trip Zone
0.1
1.3
1.2
1.1
1
0.9
0.8
No – Trip Zone
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
1
10
Time (seconds)
Voltage (per unit)
Figure 1: Voltage Ride‐Through Requirements for AC‐Connected Wind IBR
No‐Trip Zone
0.1
1.3
1.2
1.1
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
1
10
Time (seconds)
Figure 2: Voltage Ride‐Through Requirements for All Other IBR
Initial Draft of PRC‐029‐1
March 2024
Page 15 of 18
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Attachment 2: Transient Overvoltage Ride-Through Criteria
Table 3: Transient Overvoltage Ride-Through Criteria
Voltage (per unit) at the
high side of the MPT
Minimum Ride-Through
Time (millisec)
> 1.8
May trip
> 1.7
0.2
> 1.6
1.0
> 1.4
3.0
> 1.2
15.0
1. The voltage base for per unit calculation is the nominal instantaneous phase‐to‐
ground or phase‐to‐phase voltage at the high side of the MPT unless otherwise
defined by the Planning Coordinator or Transmission Planner.
2. If surge protection devices are installed within the plant, the per unit voltage refers
to the residual voltage with the surge arresters applied.
3. Each IBR shall not trip unless the cumulative time of one or more instances over a
1‐minute time window in which the instantaneous voltage exceeds the respective
voltage threshold and the minimum ride‐through time.
1.9
Voltage (per unit)
1.8
1.7
1.6
1.5
1.4
No‐Trip Zone
1.3
1.2
0
2
4
6
8
10
12
14
16
Minimum Ride‐Through Time (milliseconds)
Figure 3: Transient Overvoltage Ride‐Through Criteria
Initial Draft of PRC‐029‐1
March 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Attachment 3: Frequency Ride-Through Criteria
Table 4: Frequency Ride-Through Capability Requirements
Averaged System
Frequency (Hz)
Minimum Ride-Through
Time (sec)
≥64
May trip
≥61.8
6
> 61.5
299
> 61.2
660
< 58.8
660
< 58.5
299
< 57.0
6
< 56
May trip
1. Measurements are taken at the high‐side of the main power transformer for each phase
(phase to neutral).
2. Measurements are averaged over a set time period (such as 3‐6 cycles) to calculate
averaged system frequency at the high‐side of the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency values, each IBR shall not trip until the time duration at that
frequency exceeds the specified minimum ride‐through time duration.
5. The specified durations of Table 4 are cumulative over one or more disturbances within
a 15‐minute time period.
Initial Draft of PRC‐029‐1
March 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
65
64
63
Frequency (Hz)
62
61
60
No‐Trip Zone
59
58
57
56
55
0.1
1
10
100
1000
Time (seconds)
Figure 4: PRC‐029 Frequency Envelopes
Initial Draft of PRC‐029‐1
March 2024
Page 18 of 18
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Reliability Standards PRC-024-4 and PRC-029-1
Applicable Standard(s)
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators and
Synchronous Condensers
PRC‐029‐1 Frequency and Voltage Ride Through Requirements for Inverter‐Based
Generating Resources
Requested Retirement(s)
PRC‐024‐3 Frequency and Voltage Protection Settings for Generating Resources
Prerequisite Standard(s)
PRC‐028‐1 Disturbance Monitoring and Reporting Requirements for Inverter‐Based
Resources
Proposed Definition(s)
None
Applicable Entities
See subject Reliability Standards.
Background
The purpose of Project 2020‐02 is to modify Reliability Standard PRC‐024‐3 or replace it with a
performance‐based ride‐through standard that ensures generators remain connected to the
Bulk‐Power System (BPS) during system disturbances. Specifically, the project focuses on using
disturbance monitoring data to substantiate inverter‐based resource (IBR) ride‐through
performance during grid disturbances. The project also ensures associated generators that fail to
ride‐through system events are addressed with a corrective action plan (if possible) and reported to
necessary entities for situational awareness.
The purpose for this project is based on the culmination of multiple analyses conducted by the ERO
Enterprise regarding widespread inverter‐based resource tripping events. Furthermore, the NERC
Inverter‐Based Resource Performance Subcommittee1 has developed comprehensive
1 See documents at the NERC IRPS website: https://www.nerc.com/comm/RSTC/Pages/IRPS.aspx and the previous Inverter‐Based
Resource Performance Working Group website https://www.nerc.com/comm/RSTC/Pages/IRPWG.aspx
RELIABILITY | RESILIENCE | SECURITY
recommendations for improved performance of inverter‐based resources, including the
recommendation to develop comprehensive ride‐through requirements.
In October 2023, FERC issued Order No. 9012 which directs the development of new or modified
Reliability Standards that include new requirements for disturbance monitoring, data sharing, post‐
event performance validation, and correction of IBR performance. In January 2024, NERC submitted
a filing to FERC outlining a comprehensive work plan to address the directives within Order No.
901.3 Within the work plan, NERC identified three active Standards Development projects that
would need to be filed for regulatory approval with FERC by November 4, 2024. These projects
include 2020‐02 Modifications to PRC‐024 (Generator Ride‐through)4, 2021‐04 Modifications to
PRC‐002‐25, and 2023‐02 Analysis and Mitigation of BES Inverter‐Based Resource Performance
Issues6.
Project 2020‐02
Proposed Reliability Standard PRC‐029‐1 is a new Reliability Standard that includes ride‐through
requirements and performance requirements for IBRs. The scope of this project was adjusted to
align with associated regulatory directives from FERC Order No. 901 and the scope of the other
projects related to “Milestone 2” of the NERC work plan. The components of this project’s Standard
Authorization Request (SAR) that related to the inclusions of new data recording requirements are
covered in Project 2021‐04 and the proposed new PRC‐028‐1 Reliability Standard. Components of
this project’s SAR that relate to analytics and corrective actions plans are covered in Project 2023‐02
and the proposed new PRC‐030‐1 Reliability Standard.
PRC‐029‐1 includes requirements for Generator Owner and Transmission Owner IBR to continue to
inject current and perform frequency support during a BPS disturbance. The standard also
specifically requires Generator Owner and Transmission Owner IBR to prohibit momentary cessation
in the no‐trip zone during disturbances.
PRC‐024‐4 includes modifications to revise applicable facility types to remove IBR and to include
synchronous condensers.
2 See FERC Order 901, Docket No. RM22‐12‐000; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019‐
3157&optimized=false; October 19, 2023
3 See INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF
RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%2
0901%20Work%20Plan_packaged%20‐%20public%20label.pdf; January 17, 2024
4 See NERC Standards Development Project page for Project 2002‐02; https://www.nerc.com/pa/Stand/Pages/Project_2020‐
02_Transmission‐connected_Resources.aspx
5 See NERC Standards Development Project page for Project 2021‐04; https://www.nerc.com/pa/Stand/Pages/Project‐2021‐04‐
Modifications‐to‐PRC‐002‐2.aspx
6 See NERC Standards Development Project page for Project 2023‐02; https://www.nerc.com/pa/Stand/Pages/Project‐2023‐02‐
Performance‐of‐IBRs.aspx
Implementation Plan
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | March 2024
2
General Considerations
The ERO Enterprise acknowledges that there are IBRs currently in operation and unable to meet
voltage ride‐through requirements due to their inability to modify their coordinated protection and
control settings. Consistent with FERC Order No. 901, a limited and documented exemption process
for those IBR is appropriate and included within this Implementation Plan. Other NERC Standards
Development projects will be pursued to address ongoing identification and mitigation of any
potential reliability impacts to the BPS for such exemptions.
Effective Date and Phased-in Compliance Dates
The effective dates for the proposed Reliability Standards are provided below. Where the standard
drafting team identified the need for a longer implementation period for compliance with a
particular section of a proposed Reliability Standard (i.e., an entire Requirement or a portion
thereof), the additional time for compliance with that section is specified below. The phased‐in
compliance dates for those particular sections represent the date that entities must begin to comply
with that particular section of the Reliability Standard, even where the Reliability Standard goes into
effect at an earlier date.
PRC-024-4
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐024‐4
shall become effective on the first day of the first calendar quarter that is 6 months after the
effective date of the applicable governmental authority’s order approving the standard, or as
otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard
PRC‐024‐4 shall become effective on the first day of the first calendar quarter that is 6 months after
the date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐029‐1
shall become effective on the first day of the first calendar quarter that is six months after the
effective date of the applicable governmental authority’s order approving the standard, or as
otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard
PRC‐029‐1 shall become effective on the first day of the first calendar quarter that is six months
after the date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for
in that jurisdiction.
Compliance Date for PRC-029-1 - Requirement R6
Entities shall not be required to comply with Requirement R6 until six months after the effective
date of Reliability Standard PRC‐029‐1. This compliance date is intended to assure equipment
limitations have additional time to complete the equipment limitation process as outlined below.
Implementation Plan
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | March 2024
3
Retirement Date
PRC-024-3
Reliability Standard PRC‐024‐3 shall be retired immediately prior to the effective date of Reliability
Standards PRC‐024‐04 and PRC‐029‐1 in the particular jurisdiction in which the revised standard is
becoming effective.
Equipment Limitations and Process for Requirement R6
Consistent with FERC Order No. 901, a limited and documented exemption for some legacy IBR with
certain documented equipment limitations are acceptable. Per the Order, these IBRs are
“…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.”7
To assure compliance with Requirement R6 and alignment with FERC Order No. 901, only those IBR
that are in operation as of the effective date of PRC‐029‐1 may be considered for potential
exemption. Further, only those IBR that are unable to meet voltage ride‐through requirements due
to their inability to modify their coordinated protection and control settings may be considered for
potential exemption.
Generator Owners with IBR that meet these criteria for equipment limitations must identify which
of those IBR will be unable to meet voltage ride‐through requirements, as described in Requirement
R6. For each identified IBR, the associated Generator Owner must document:
Identifying information of the IBR (name, facility #, other)
Which aspects of voltage ride‐through requirements that the IBR would be unable to meet
Information regarding the limiting equipment
Information regarding any plans to repair or replace the limiting equipment that would
remove the limitation (such as estimated date of repair/replacement)
For each identified IBR, the associated Generator Owner must communicate the documented
information listed above to the associated Planning Coordinator(s), Transmission Planner(s), and
Reliability Coordinator(s), per the Requirement R6 no later than the effective date of Requirement
R6.
7 Order No. 901 at p. 193.
Implementation Plan
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | March 2024
4
Unofficial Comment Form
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on Project 2020-02 Modifications to PRC-024 (Generator Ride-through) by 8
p.m. Eastern, Monday, April 22, 2024.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Manager of
Standards Development, Jamie Calderon (via email), or at 404-960-0568.
Background Information
The goal of Project 2020-02 is to mitigate the recent and ongoing disturbance ride-through performance
issues identified across multiple Interconnections and numbers of disturbances analyzed by NERC and the
Regions. These issues have been associated with Inverter-Based Resources (IBR) with many causes of their
tripping or cessation unrelated to voltage and frequency protection settings requirements in the currently
effective version of PRC-024, PRC-024-3. Proposed Reliability Standard PRC-024-4 includes revisions to
limit its applicability to synchronous generators and synchronous condensers only and remains as a
protection-based standard. A new standard, PRC-029-1, is proposed as a true disturbance ride-through
Reliability Standard with applicability to inverter-based resources..
In October 2023, FERC issued Order No. 901, which directed NERC to develop new or modified existing
Reliability Standards that include new requirements for disturbance monitoring, data sharing, post-event
performance validation, and correction of IBR performance. Project 2020-02 was one of three projects
identified by NERC that must be completed and filed with FERC by November 4, 2024 to address Order
No. 901 directives. At their December 2023 meeting, the Standards Committee approved a waiver for
Project 2020-02, allowing formal comment periods to be reduced from 45 days to 25 calendar days, ballot
pools reduced from 30 days to as few as 10 days, and final ballot periods to be reduced from 10 days to as
few as 5 calendar days.
Questions
1. Do you agree with the need for creating a new Standard (PRC-029-1) to address gaps the InverterBased Resource Performance Subcommittee (IRPSC) identified within the PRC-024-3 Project 2020-02
SAR and to address the expectations of FERC Order No. 901?
Yes
No
Comments:
RELIABILITY | RESILIENCE | SECURITY
2. Do you agree that the language within PRC-029-1 requirements R1, R2, and R6 regarding IBR plantlevel performance during grid voltage disturbances is clear?
Yes
No
Comments:
3. Do you agree with the drafting team’s proposals for including IBR transient overvoltage, frequency,
ROCOF, and instantaneous voltage phase-angle jump ride-through performance criteria in PRC-029-1
Requirements R3, R4, and R5?
Yes
No
Comments:
4. Provide any additional comments for the Drafting Team to consider, if desired.
Comments:
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Unofficial Comment Form | March 2024
2
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-024-4 – Frequency and Voltage Protection Settings for Synchronous
Generators and Synchronous Condensers
General Rationale
The drafting team proposes to modify PRC‐024‐3 to retain the Reliability Standard as a protection‐based
standard with applicability to only synchronous generators and synchronous condensers. This proposal is
a consequence of both the different natures of synchronous and inverter‐based generation resources and
several recent events exhibiting significant IBR ride‐through deficiencies. The behavior of rotating
synchronous generators during faults and other disturbances on the transmission system is well
established and understood in comparison to IBR generation. The disturbance ride‐through vulnerabilities
of synchronous generators are pole slipping instability and undervoltage dropout of critical plant auxiliary
equipment, leading to tripping of a generator. Pole slipping can be managed by active power dispatch and
system condition constraints, and is outside the scope of PRC‐024‐3. Undervoltage dropout of critical
auxiliary equipment is also outside the scope of PRC‐024‐3 because of complexities associated with
auxiliary systems and how such equipment behaves under low voltage conditions.
The Project 2020‐02 Standard Authorization Request (SAR) notes that auxiliary equipment has not posed a
ride‐through risk and the SAR specifically excludes modifications in PRC‐024‐3 for auxiliary equipment.
Over‐frequency protection, under‐frequency protection, and voltage protection may or may not be
applied to synchronous generating units. If applied however, settings should be coordinated between the
needs of generating unit protection, reasonable expected excursions of system frequency and voltage in a
straightforward fashion, e.g., as no‐trip zones within PRC‐024‐3 attachments, as well as the coordination
of generating unit capabilities, voltage regulating controls, and protection within PRC‐019‐2. Excitation
and governing controls affect synchronous generator ride‐through behavior to some degree but because
of progressive improvement, standardization, and level of maturity of these controls, they are rarely if
ever cause unnecessary tripping during disturbances.
In addition, there are other existing NERC standards to prevent unnecessary tripping of the generators
during a system disturbance such as PRC‐025‐2 “Generator Relay Loadability”, and PRC‐026‐2 “Relay
Performance During Stable Power Swings”. For these reasons, there is no need to impose actual
disturbance ride‐through requirements on synchronous units and only include restrictions for frequency
and voltage protection setting ranges as maintained in PCR‐024‐4.
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for setting frequency, voltage, and volts per hertz protection for
synchronous generators and synchronous condensers is the Generator Owner (GO) and Transmission
RELIABILITY | RESILIENCE | SECURITY
Owner (TO). Planning Coordinators (PC) are also retained as applicable entities but are only in the Quebec
Interconnection. Modifications are proposed in PRC‐024‐4 to expand functional entity applicability to
includes those Transmission Owners that apply protection, as listed in new Facility applicability section
4.2.2.
Facilities (4.2)
Applicability Facilities subparts in Section 4.1.1 were modified to restrict PRC‐024‐4 to synchronous
generators. Section 4.2.2 was added as new subparts to identify which synchronous condensers and
equipment.
Rationale for Requirements R1 through R4
Modifications were made to Requirements R1, R2, R3, and R4 to include the Transmission Owner as an
functional entity applicable to each requirement.
Modifications were made to Requirements R1, R2, R3, and R4 to include language for synchronous
condensers and to remove language that relates to inverter‐based resource functionality (i.e., “cease
injecting current”).
Technical Rationale for Reliability Standard PRC‐024‐4
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | March 2024
2
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1 – Frequency and Voltage Ride-Through Requirements for
Inverter-Based Generating Resources
General Rationale
The drafting team has created a new Reliability Standard (PRC‐029‐1) to address inverter‐based resource
(IBR) disturbance ride‐through performance criteria. This proposal is a consequence of both the different
natures of synchronous and inverter‐based generation resources and several recent events exhibiting
significant IBR ride‐through deficiencies. The proposed PRC‐029‐1 coincides with ride‐through
requirements of IEEE 2800 but is structured to follow language from FERC Order No. 901, which states
that “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.”1
The lack of standardization of IBR technology (equipment/controller behavior) has created reliability
challenges associated with the interconnection of IBR facilities to the power grid. The nature of the fast
switching of power electronics of IBR generation and the electronic interface to the transmission system is
such that disturbance ride‐through behavior is largely determined by manufacturer‐specific equipment
and controls system designs. These controls may be programmed but also have more restrictive limits on
current, both in magnitude and duration. IBR responses to grid disturbances are highly controlled and
managed by using fast switching of power electronics devices dependent upon manufacturer specific
control system design that can be programmed in many ways and with various and concurrent ride‐
‐through performance objectives. Rather than attempting to restrict the myriad of control approaches,
protections, and settings, it is more straightforward to require ride‐through during defined frequency and
voltage excursions.
In contrast to synchronous generation, the need for IBR ride‐through requirements has been heightened
by recent events during which IBRs have not met PRC‐024‐3 frequency and voltage ride‐through
expectations, often due to controls and protection only indirectly associated with the system voltage and
frequency excursions. In addition to ride‐through, there is the question of what IBRs should be doing as
they ride‐through. IBR responses to system disturbances can be beneficial or detrimental to both their
own ride‐through and system reliability, often depending on adjustable control settings. Thus, it is
essential to set expectations on performance during ride‐through as well as ride‐through capability.
IBR do not provide inertia or short circuit contributions, unlike synchronous machines. The drafting team
thinks that IBR should compensate for their lack of inertia and short circuit contributions with wider
1 P 195, FERC Order No. 901; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019‐3157&optimized=false; October 17,
2023
RELIABILITY | RESILIENCE | SECURITY
tolerances for frequency and voltage excursions. This is the reason for the differences in the frequency
and voltage tables and graphs between the two standards.
The proposed PRC‐029 must be understood as an event‐based standard. Compliance with PRC‐029 is
determined from IBR ride‐through performance during transmission system events in the field and not
from interconnection studies, transmission planning studies, operational planning studies, or from IBR
models. An IBR becomes noncompliant with PRC‐029 only when an event in the field occurs that shows
that one or more requirements were not satisfied. This intent is clarified by Operations Assessment as the
Time Horizon designation of requirements R1‐R5.
FERC Order No. 901 Directives
PRC‐029‐1 is proposed in consideration of directives from FERC Order No. 901 that were assigned to the
Project 2020‐02 drafting team. The following directives were assigned to this drafting team for inclusion in
this Standards Project (paragraph numbers of the FERC Order are included for reference):
Paragraph 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.”
Paragraph 190: “The new or modified Reliability Standards must require registered IBRs to
continue to inject current and perform frequency support during a Bulk‐Power System
disturbance.”
Paragraph 190: “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.”
Paragraph 190: “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.”
Paragraph 193: “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.”
Paragraph 193: “Further, we direct NERC to ensure that any such exemption would be applicable
for only existing equipment that is unable to meet voltage ride‐through 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.).”
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Paragraph 193: “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).”
Paragraph 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, we direct NERC to
develop new or modified Reliability Standards to mitigate the reliability impacts to the Bulk‐Power
System of such an exemption.”
Paragraph 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 pre‐disturbance output level
in a quick and stable manner after a Bulk‐Power System.”
Paragraph 209: “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.”
Paragraph 209: “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.”
Paragraph 226: “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 rule prior to
that date.” (pertains multiple projects)
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for assuring acceptable ride‐through performance of IBR is the
Generator Owner (GO) and Transmission Owner (TO).
Facilities (4.2)
Applicability Facilities includes only those IBR that also meet NERC registration criteria. Language used
within PRC‐029‐1 applicability only refers to IBR as a whole plant/facility. Consistent with FERC Order
No. 901, IBR performance is based on the overall IBR plant and disturbance monitoring equipment
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requirements established under the proposed PRC‐028‐1. Requirements within PRC‐029‐1 do not apply to
individual inverter units or measurements taken at individual inverter unit terminals.
Rationale for Requirement R1
The objective of Requirement R1 is to ensure an applicable IBR will ride‐through a grid voltage
disturbance consistent with the no‐trip zone and Operation Regions specified in Attachment 1. IBR must
be able to demonstrate performance that they remain electrically connected, i.e., shall not trip, and
continue to exchange current, i.e., shall not enter momentary cessation.
The drafting team determined that the definition of “no‐trip zones” and “Operation Regions” should be
consistent with those terms as used within IEEE 2800‐2022. Additionally, the team determined the
voltage thresholds of each Operation Region are based on measurements taken on the high‐side of the
main power transformer in PRC‐029‐1.
Exceptions to Attachment 1 performance criteria are allowable when 1) an IBR needs to trip to clear a
fault within its zone of protection, and 2) a documented equipment limitation prevents an IBR from riding
through the disturbance in accordance with Requirement R6.
Rationale for Requirement R2
In addition to having minimum voltage ride‐through capability specified in Requirement R1, an applicable
IBR is also required to adhere to certain voltage ride‐through performance criteria during a system
disturbance. Acceptable performance criteria is dependent on the Operation Region that an IBR is
presently in, or it’s change from one Operation Region to another Operation Region. Requirement R2
includes specific performance criteria and is needed to assure consistent IBR performance during each
Operation Region in Attachment 1.
Rationale for Requirement R2.1
This subpart of Requirement 2 ensures, when the voltage at the high‐side of the main power transformer
(MPT) recovers to the Continuous Operation Region from either the Mandatory Operation Region or the
Permissive Operation Region, an IBR is expected to deliver the pre‐disturbance level of active power or
available active power, whichever is less. This requires an IBR to exit the “High Voltage Ride Through
(HVRT)” or “Low Voltage Ridge Through (LVRT)” modes properly such that it does not cause reduction in
the active power when the system already recovers the voltage within the Continuous Operation Region.
When the voltage at the high‐side of the MPT is greater than 0.9 per‐unit and less than 0.95 per‐unit, IBRs
are expected to exit the LVRT mode and come back to “normal operating mode”. If an IBR has a default
total current limit of 1.0 per‐unit, the apparent power production of an IBR will be limited to be below 1.0
per‐unit (e.g., the per‐unit value of IBR terminal voltage). In such case, IBR needs to configure a
preference setting, either to maintain pre‐disturbance active power or maximize the reactive power in
order to further help with voltage recovery, according to requirements specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
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Rationale for Requirement R2.2
This subpart of Requirement 2 ensures when the voltage at the high‐side of the MPT is within the
Mandatory Operation Region, IBRs are expected to enter the HVRT and LVRT mode such that it will inject
or absorb reactive current proportional to the level of terminal voltage deviations it measures. IBR shall
follow Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator
specified certain magnitude of reactive power response to voltage changes, if available.
By default, reactive current prioritization shall be configured unless Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator requires active power priority.
Rationale for Requirement R2.3
This subpart of Requirement 2 ensures when a fault is cleared on the transmission system, the voltage
regulators of connected IBRs must adjust the reactive current injection to restore the transmission system
voltage to the pre‐disturbance voltage as defined by the automatic voltage regulator (AVR) setpoint. The
drafting team acknowledges that tuning of the AVR requires a balance between multiple competing
physical factors, e.g., rise time, overshoot, and transient stability. However, it is anticipated that IBR
controls will be tuned to allow for a stable post‐disturbance voltage recovery without causing excessive
overshoot or undershoot of the setpoint. When such overshoots do occur, they must not exceed the
magnitude and duration of the applicable table given in Attachment 1. Furthermore, this standard
anticipates that control system tuning to prevent such over/under voltages will focus on the speed at
which the controller responds to setpoint changes rather than on the magnitude of the reactive current
response. For example, reductions in k‐factor to prevent over/under voltages should only be considered
as a last resort.
Rationale for Requirement R2.4
This subpart of Requirement 2 ensures that IBR returns to effective pre‐disturbance operation unless
otherwise specified or needed by the Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator.
Rationale for Requirement R2.5
This subpart of Requirement 2 ensures that voltage protection settings of IBR are based on maximum
equipment capabilities rather than settings based directly on, or just outside, of the no‐trip zone.
Rationale for Requirement R3
The objective of Requirement R3 is to provide transient overvoltage ride‐through for IBR during the non‐
fault switching event. Voltage transients are commonly occurring on the BPS due to switching actions,
fault clearing, lightning, etc. IBR shall ride‐through the transient overvoltage condition specified in
Attachment 2 during the non‐fault switching events in the transmission systems. During this transient
overvoltage event, IBRs should continue to inject current, but it does not have to respond to transient
overvoltage, i.e., enter reactive priority mode and/or change magnitude of current output.
If necessary, IBRs may operate in current blocking mode, when instantaneous voltage exceeds
1.2 p.u., to help ensure stable response that does not lead to tripping and to eliminate the IBR as a
Technical Rationale for Reliability Standard PRC‐029‐1
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5
possible cause for the overvoltage. If IBRs operate in the current blocking mode, it shall restart
current exchange in less than or equal to five cycles following instantaneous voltage falling below, and
remaining below, 1.2 p.u. This is different than momentary cessation, which involves a resource returning
over a longer time frame with a specified delay and ramp rate.
The drafting team notes that IBR should not be set to trip on an instantaneous, unfiltered voltage
measurements, except due to known equipment limitations.
Rationale for Requirement R4
The objective of Requirement R4 is to ensure that IBR remains electrically connected and exchanging
current during a frequency excursion event.
Grid frequency reflects the balance of system generation and load. A system event that causes a
generation/load imbalance will cause system frequency to deviate from nominal. The system may
experience an over‐frequency event (in the case of more generation than load) or an under‐frequency
event (in the case of less generation than load). Inertia resists the deviation from nominal frequency,
giving the operators additional time to rebalance generation and load. System inertia depends on the
amount of rotating mass connected to the system (such as the synchronous generators or motors). The
larger the system inertia, the slower the system frequency will deviate from the nominal value and the
lower the grid Rate Of Change Of Frequency (ROCOF), giving more time to try to rebalance generation and
load. Also, higher system inertia may minimize the risk of Cascading generation loss caused by the
operation of generator frequency protection.
A reduction in system inertia is an inevitable consequence of a power system transiting toward more IBR
and less synchronous generators. As discussed in the previous paragraph, less system inertia means the
frequency will deviate from the nominal value more quickly during a generation/load imbalance event
and will expose the system to a higher ROCOF. A wider frequency ride‐through capability for IBR may be
required to avoid the risk of widespread tripping. To reduce the risk of widespread IBR tripping during
frequency disturbances, and more generally to ensure the reliability of future grids with high IBR
penetration, the drafting team proposes a 6‐second frequency ride‐through capability requirement for
frequencies in the ranges of 61.8Hz to 64Hz or 57.0Hz to 56.0Hz range. The proposed 6‐second time
frame of the frequency ride‐through capability requirement is beyond the IEEE 2800 standard frequency
ride‐through requirement and beyond frequency ride‐through requirements for synchronous machines
under proposed PRC‐024‐4.
IBR lacks the inertia and short circuit contributions of synchronous machines. To compensate for the lack
of inertia and short circuit contributions, they should have wider tolerances for frequency and voltage
excursions to meet the future power system with a higher percentage of IBR. Synchronous resources are
more sensitive to frequency deviations than IBR resources. All IBR resources (except for type 3 wind
turbines) interface to the grid through fast switching of power electronics devices. These power electronic
devices are much less sensitive to the transmission system frequency excursion than non‐hydraulic
turbine synchronous resources (steam turbines and combustion turbines). In the case of the non‐
hydraulic turbine synchronous resources, the turbine is usually considered to be more restrictive than the
Technical Rationale for Reliability Standard PRC‐029‐1
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generator in limiting IBR frequency ride‐through because of possible mechanical resonances in the many
stages of turbine blades. Off‐nominal frequencies may bring blade vibrational frequencies closer to a
mechanical resonate frequency and cause damage due to the vibration stresses. However, inverter‐
interfaced‐IBR does not share this vibrational failure mode. Therefore, IBR should be capable of riding
through the increased proposed 6‐second frequency ride‐through requirement without risk of equipment
damage or need for frequency protection to operate.
Requirement R4 does not prescribe specific frequency protection settings for IBR equipment. IBR
frequency protection settings should only be set to protect the IBR from damage caused by operation at
off‐nominal frequency. An IBR owner must ensure that the IBR frequency protection does not prevent an
IBR from meeting the R4 ride‐through requirement.
This standard requires that IBR remains electrically connected and continues to exchange current during a
frequency excursion event in which the frequency remains within the no‐trip zone\ according to
Attachment 3 and the absolute ROCOF magnitude is less than or equal to 5 Hz/second. Some IBR
controllers and their ability to remain electrically connected and continue to exchange current to the grid
are sensitive to ROCOF during a frequency excursion event. If needed to maintain the stability of the IBR
or prevent equipment damage, the R4 requirement allows the IBR to trip for an absolute ROCOF
exceeding 5Hz/sec within the no‐trip zone as shown in Attachment 3. Failure to ride‐through due to
ROCOF exceeding 5Hz/sec shall only be allowed during a generator/load imbalance event that causes the
frequency to deviate from nominal.
The ROCOF protection should not operate at the onset of a fault, during a fault, or at fault clearance, i.e.,
it should be disabled for faults. The IBR shall ride‐through any system disturbance while the voltage at the
high side of the main power transformer remains within the no‐trip zones as specified in Attachment 1.
Furthermore, to reduce the risk of IBR tripping on ROCOF protection, ROCOF shall be calculated as the
average rate of change for multiple calculated system frequencies for some time greater than or equal to
0.1 seconds.
Rationale for Requirement R5
The objective of Requirement R5 is to ensure IBR remains electrically connected and exchanging current
during instantaneous positive sequence voltage phase angle changes initiated by certain non‐fault
switching events.
Unlike synchronous generators, for which the synchronization mechanism to the grid is naturally
preserved by the inertia, the grid following voltage source inverters (VSI) used for the majority of existing
IBR facilities are equipped with the Phase‐lock‐loop (PLL) device for synchronization purposes. A typical
synchronous reference frame PLL schematic is given in Fig. 1, where the three‐phase voltages in the abc
reference frame (va, vb, and vc) are transformed to the dq frame (vd’ and vq’) by the Park’s transformation
and the phase angle θ is controlled by a feedback loop that regulates the q component to zero.
Technical Rationale for Reliability Standard PRC‐029‐1
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Figure 1: Schematic Diagram of a Synchronous Reference Frame PLL
When the inverter operates in the steady state, it is locked to the grid voltage via the PLL, assuming the PI
controller is well tuned. In this case the phase displacement between the grid voltage and that measured
by the PLL, Δθ is zero, as shown in Fig. 2.
Figure 2: Phasor Diagram of Grid Voltage and Current
When a grid disturbance occurs, such as a close‐in fault or a relatively large switching event, the grid
voltage may experience a rapid phase angle shift. In such cases, the phase displacement Δθ can be large
enough to pose challenges for the PLL to track the terminal voltage, cause control instability within the
inverter, such as the inner current control loop or the DC link control loop, and even lead to tripping of
the inverter due to the malfunction of the controls.
Since phase angle jumps are common occurrences on the BPS, this standard requires the IBR to be
designed and operated to ride‐through a minimum phase angle jump of 25 electrical degrees. This is a
typical value and aligns with the requirement in IEEE 2800 2022. Furthermore, for a phase angle jump of
25 degrees or more, the IBR shall only trip to prevent equipment damage.
Some IBR equipment has PLL loss of synchronism protection, referring to a protective function that
operates when the angle displacement Δθ exceeds a threshold for a predetermined period of time (on the
order of a couple of milliseconds). Historically, this protection has been used by some inverter
manufacturers, especially for inverters in distribution systems. For the IBR connected to the BPS, this
protection function should be disabled. If it is enabled, the phase angle jump protection setting shall be
configured such that the IBR shall only trip to prevent equipment damage.
Technical Rationale for Reliability Standard PRC‐029‐1
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Commented [JC1]: Please confirm where these example
figures came from and if we can cite them in our document. Are
these public?
Rationale for Requirement R6
The objective of Requirement R5 is to ensure legacy IBR may need to obtain an exemption to the voltage
ride‐through requirements if hardware replacements or other costly upgrades would be necessary to
comply with Requirements R1 or Requirement R2. This provision allows such exemptions as long as such
limitations are documented and communicated to the Planning Coordinator, and Reliability Coordinator
of the respective footprints in which the IBR project is located. The Planning Coordinator, and Reliability
Coordinator will then need to take the voltage ride‐through limitations into account in planning and
operations.
Limitations must not be construed as complete exemptions from the applicable Attachment 1 table but
must be specific as to which voltage band(s) and associated duration(s) cannot be satisfied or specific as
to the number of cumulative voltage deviations within a ten‐second time period that the equipment can
ride‐through if less than four. Limitation descriptions should identify the specific equipment and explain
the characteristic(s) of that equipment that prevent ride‐through. If any equipment limitation is removed
or otherwise corrected, it is likewise necessary to communicate to the Planning Coordinator, and
Reliability Coordinator of this.
FERC Order No. 901 states that this provision would be limited to exempting “certain registered IBRs from
voltage ride‐through performance requirements.” This is the reason that no similar provisions are
included for exemptions for frequency, rate‐of‐change‐of‐frequency (ROCOF) ,phase angle change
ride‐through requirements.
Technical Rationale for Reliability Standard PRC‐029‐1
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Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-024-4
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐024‐4. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to BulkPower System instability, separation, or a cascading sequence of
failures, or could place the Bulk‐Power System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to BulkPower System instability, separation, or a cascading sequence of failures, or could place the Bulk‐Power System at
an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk‐Power System, or the ability to effectively
monitor and control the Bulk‐Power System. However, violation of a medium risk requirement is unlikely to lead to Bulk‐ Power System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the BulkPower
System, or the ability to effectively monitor, control, or restore the BulkPower System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Power System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk‐Power System, or the ability to effectively monitor and control the Bulk‐Power System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk‐Power
System, or the ability to effectively monitor, control, or restore the Bulk‐Power System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk‐Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of the measured does not meet the
intent of the requirement.
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non‐compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
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The VRF did not change from the previously FERC approved PRC‐024‐3 Reliability Standard.
VSLs for PRC-024-4, Requirement R1
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to set its
applicable frequency protection so
that it does not trip according to
Requirement R1.
VSL Justifications for PRC-024-4, Requirement R1
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
FERC VSL G1
Violation Severity Level Assignments consequence of lowering the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-024-4, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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The VRF did not change from the previously FERC approved PRC‐024‐3 Reliability Standard.
VSLs for PRC-024-4, Requirement R2
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to set its
applicable voltage protection so that
it does not trip according to
Requirement R2.
VSL Justifications for PRC-024-4, Requirement R2
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
FERC VSL G1
Violation Severity Level Assignments consequence of lowering the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-024-4, Requirement R2
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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The VRF did not change from the previously FERC approved PRC‐024‐3 Reliability Standard.
VSLs for PRC-024-4, Requirement R3
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner documented
the known non‐protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 30
calendar days but less than or
equal to 60 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner documented
the known non‐protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 60
calendar days but less than or
equal to 90 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner documented
the known non‐protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 90
calendar days but less than or
equal to 120 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner failed to
document any known non‐
protection system equipment
limitation that prevented it from
meeting the criteria in Requirement
R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar days of
identifying the limitation.
VSL Justifications for PRC-024-4, Requirement R3
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
FERC VSL G1
Violation Severity Level Assignments consequence of lowering the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
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VSL Justifications for PRC-024-4, Requirement R3
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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The VRF did not change from the previously FERC approved PRC‐024‐3 Reliability Standard.
VSLs for PRC-024-4, Requirement R4
Lower
Moderate
High
The Generator Owner or
Transmission Owner provided its
protection settings more than 60
calendar days but less than or
equal to 90 calendar days of any
change to those settings.
OR
The Generator Owner or
Transmission Owner provided its
protection settings more than 90
calendar days but less than or
equal to 120 calendar days of any
change to those settings.
OR
The Generator Owner or
Transmission Owner provided its
protection settings more than 120
calendar days but less than or
equal to 150 calendar days of any
change to those settings.
OR
The Generator Owner or
Transmission Owner provided
protection settings more than 60
calendar days but less than or
equal to 90 calendar days of a
written request.
The Generator Owner or
Transmission Owner provided
protection settings more than 90
calendar days but less than or
equal to 120 calendar days of a
written request.
The Generator Owner or
Transmission Owner or provided
protection settings more than 120
calendar days but less than or
equal to 150 calendar days of a
written request.
Severe
The Generator Owner or
Transmission Owner failed to
provide its protection settings within
150 calendar days of any change to
those settings.
OR
The Generator Owner or
Transmission Owner failed to
provide protection settings within
150 calendar days of a written
request.
VSL Justifications for PRC-024-4, Requirement R4
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
FERC VSL G1
Violation Severity Level Assignments consequence of lowering the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
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VSL Justifications for PRC-024-4, Requirement R4
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐029‐1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to BulkPower System instability, separation, or a cascading sequence of
failures, or could place the Bulk‐Power System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to BulkPower System instability, separation, or a cascading sequence of failures, or could place the Bulk‐Power System at
an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk‐Power System, or the ability to effectively
monitor and control the Bulk‐Power System. However, violation of a medium risk requirement is unlikely to lead to Bulk‐ Power System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the BulkPower
System, or the ability to effectively monitor, control, or restore the BulkPower System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Power System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk‐Power System, or the ability to effectively monitor and control the Bulk‐Power System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk‐Power
System, or the ability to effectively monitor, control, or restore the Bulk‐Power System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk‐Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the
requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non‐compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for PRC-029-1, Requirement R1
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride‐through system
disturbances. Failure to ride‐through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
Similar requirements in PRC‐024‐3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R1
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable IBR
remains electrically connected and
continued to exchange current in
accordance with Attachment 1,
unless needed to clear a fault, in
accordance with Requirement R1.
VSL Justifications for PRC-029-1, Requirement R1
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride‐through system
disturbances. Failure to ride‐through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
Similar requirements in PRC‐024‐3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R2
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable IBR
adhered to performance
requirements during each System
disturbance, as specified in
Requirement R2.
VSL Justifications for PRC-029-1, Requirement R2
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R2
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R3
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R3
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable IBR
adhered to performance
requirements during each transient
overvoltage period as specified in
Requirement R3.
VSL Justifications for PRC-029-1, Requirement R3
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R3
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R4
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R4
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable IBR
adhered to performance
requirements during each frequency
excursion event, as specified in
Requirement R4.
VSL Justifications for PRC-029-1, Requirement R4
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R4
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐029‐1
VRF and VSL Justifications | March 2024
16
VRF Justifications for PRC-029-1, Requirement R5
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐029‐1
VRF and VSL Justifications | March 2024
17
VSLs for PRC-029-1, Requirement R5
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable IBR
adhered to performance
requirements during each
instantaneous positive sequence
voltage phase angle change of less
than 25 electrical degrees, as
specified in Requirement R5.
VSL Justifications for PRC-029-1, Requirement R5
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐029‐1
VRF and VSL Justifications | March 2024
18
VSL Justifications for PRC-029-1, Requirement R5
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐029‐1
VRF and VSL Justifications | March 2024
19
VRF Justifications for PRC-029-1, Requirement R6
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐029‐1
VRF and VSL Justifications | March 2024
20
VSLs for PRC-029-1, Requirement R6
Lower
Moderate
High
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the documented
limiting equipment but failed to
document and communicate the
change to its Planning Coordinator,
Transmission Planner, and
Reliability Coordinator more than
30 calendar days but less than or
equal to 60 calendar days after the
change to the equipment.
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the documented
limiting equipment but failed to
document and communicate the
change to its Planning Coordinator,
Transmission Planner, and
Reliability Coordinator more than
60 calendar days but less than or
equal to 90 calendar days after the
change to the equipment.
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the documented
limiting equipment but failed to
document and communicate the
change to its Planning Coordinator,
Transmission Planner, and
Reliability Coordinator more than
90 calendar days but less than or
equal to 120 calendar days after
the change to the equipment.
Severe
The Generator Owner or
Transmission Owner failed to
document evidence of equipment
limitations consistent with
Requirement R6 and prior to the
effective date of PRC 029 1
Requirement R6.
OR
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs or
replaces the documented limiting
equipment but failed to document
and communicate the change to its
Planning Coordinator, Transmission
Planner, and Reliability Coordinator
more than 120 calendar days after
the change to the equipment.
VSL Justifications for PRC-029-1, Requirement R6
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐029‐1
VRF and VSL Justifications | March 2024
21
VSL Justifications for PRC-029-1, Requirement R6
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐029‐1
VRF and VSL Justifications | March 2024
22
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough) | PRC-024-4 and PRC-029-1
Formal Comment Period Open through April 22, 2024
Ballot Pools Forming through April 5, 2024
Now Available
A 25-day formal comment period for Project 2020-02 Modifications to PRC-024 (Generator Ridethrough), is open through 8 p.m. Eastern, Monday, April 22, 2024.
The Standards Committee approved waivers to the Standard Processes Manual at their December 2023
meeting. These waivers were sought by NERC Standards staff for reduced formal comment and ballot
periods. This will assist the drafting teams in expediting the standards development process due to firm
timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket No. RM22-12-000
on October 19, 2023.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot pool.
Contact ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Friday, April 5, 2024. Registered Ballot Body
members can join the ballot pools here.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
RELIABILITY | RESILIENCE | SECURITY
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
Initial ballots for the standards and implementation plan, as well as non-binding polls of the associated
Violation Risk Factors and Violation Severity Levels will be conducted April 12 - 22, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Manager of Standards Development, Jamie Calderon (via email)
or at 404-960-0568 Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
(Generator Ride-through) observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | March 2024
2
Comment Report
Project Name:
2020-02 Modifications to PRC-024 (Generator Ride-through) | Draft 1
Comment Period Start Date:
3/27/2024
Comment Period End Date:
4/22/2024
Associated Ballots:
2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan IN 1 OT
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 | Non-binding Poll IN 1 NB
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 IN 1 ST
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 | Non-binding Poll IN 1 NB
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 IN 1 ST
There were 79 sets of responses, including comments from approximately 180 different people from approximately 111 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
Questions
1. Do you agree with the need for creating a new Standard (PRC-029-1) to address gaps the Inverter-Based Resource Performance
Subcommittee (IRPSC) identified within the PRC-024-3 Project 2020-02 SAR and to address the expectations of FERC Order No. 901?
2. Do you agree that the language within PRC-029-1 requirements R1, R2, and R6 regarding IBR plant-level performance during grid voltage
disturbances is clear?
3. Do you agree with the drafting team’s proposals for including IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage
phase-angle jump ride-through performance criteria in PRC-029-1 Requirements R3, R4, and R5?
4. Provide any additional comments for the Drafting Team to consider, if desired.
Organization
Name
Name
BC Hydro and Adrian
Power
Andreoiu
Authority
Santee
Cooper
Carey
Salisbury
WEC Energy Christine
Group, Inc. Kane
Southern
Colby
Company Galloway
Southern
Company
Services, Inc.
Segment(s)
1
1,3,5,6
3
1,3,5,6
Region
WECC
Group Name
BC Hydro
Santee
Cooper
WEC Energy
Group
MRO,RF,SERC,Texas Southern
RE,WECC
Company
Group
Member
Name
Group Member
Organization
Group
Member
Segment(s)
Hootan
Jarollahi
BC Hydro and
Power
Authority
3
WECC
Helen
Hamilton
Harding
BC Hydro and
Power
Authority
5
WECC
Adrian
Andreoiu
BC Hydro and
Power
Authority
1
WECC
Lachelle
Brooks
Santee Cooper 1,3,5,6
SERC
Paul Camilletti Santee Cooper 1,3,5,6
SERC
Christine Kane WEC Energy
Group
3
RF
Matthew
Beilfuss
WEC Energy
Group, Inc.
4
RF
Clarice Zellmer WEC Energy
Group, Inc.
5
RF
David
Boeshaar
WEC Energy
Group, Inc.
6
RF
Matt Carden
Southern
Company Southern
Company
Services, Inc.
1
SERC
Joel
Dembowski
Southern
3
Company Alabama Power
Company
SERC
Ron Carlsen
Southern
Company Southern
Company
Generation
SERC
6
Group
Member
Region
Leslie Burke
California ISO Darcy
O'Connell
2
WECC
Southern
Company Southern
Company
Generation
5
SERC
California ISO
2
WECC
New York
Independent
System
Operator
2
NPCC
John Pearson
ISO New
England, Inc.
2
NPCC
Helen Lainis
Independent
Electricity
System
Operator
2
NPCC
ISO/RTO
Ali Miremadi
Council (IRC) Gregory
Standards
Campoli
Review
Committee
Elizabeth Davis PJM
2
Interconnection
RF
Charles Yeung Southwest
Power Pool,
Inc.
2
MRO
Bobbi Welch
2
RF
2
Texas RE
Austin Energy
6
Texas RE
Michael Dillard Austin Energy
5
Texas RE
Lovita Griffin
Austin Energy
3
Texas RE
Tony Hua
Austin Energy
4
Texas RE
Thomas
Standifur
Austin Energy
1
Texas RE
Jennie Wike
Tacoma Public 1,3,4,5,6
Utilities
WECC
John Merrell
Tacoma Public 1
Utilities
(Tacoma, WA)
WECC
Midcontinent
ISO, Inc.
Kennedy Meier Electric
Reliability
Council of
Texas, Inc.
Austin
Energy
Imane Mrini 6
Jennie Wike Jennie Wike
Austin Energy Imane Mrini
WECC
Tacoma
Power
ACES Power Jodirah
Marketing
Green
1,3,4,5,6
FirstEnergy - Mark Garza 4
FirstEnergy
Corporation
John
Nierenberg
Tacoma Public 3
Utilities
(Tacoma, WA)
WECC
Hien Ho
Tacoma Public 4
Utilities
(Tacoma, WA)
WECC
Terry Gifford
Tacoma Public 6
Utilities
(Tacoma, WA)
WECC
Ozan Ferrin
Tacoma Public 5
Utilities
(Tacoma, WA)
WECC
Hoosier Energy 1
Electric
Cooperative
RF
Jason
Procuniar
Buckeye Power, 4
Inc.
RF
Scott Brame
North Carolina 3,4,5
Electric
Membership
Corporation
SERC
Bill Pezalla
Old Dominion
Electric
Cooperative
SERC
Sara Orr
Golden Spread 5
Electric
Cooperative,
Inc.
Texas RE
Kris Carper
Arizona Electric 1
Power
Cooperative,
Inc.
WECC
MRO,RF,SERC,Texas ACES
Bob Soloman
RE,WECC
Collaborators
FE Voter
3,4
Julie Severino FirstEnergy FirstEnergy
Corporation
1
RF
Aaron
Ghodooshim
3
RF
FirstEnergy FirstEnergy
Corporation
Black Hills
Rachel
Corporation Schuldt
Northeast
Ruida Shu
Power
Coordinating
Council
6
1,2,3,4,5,6,7,8,9,10 NPCC
Robert Loy
FirstEnergy FirstEnergy
Solutions
5
RF
Mark Garza
FirstEnergyFirstEnergy
1,3,4,5,6
RF
Stacey
Sheehan
FirstEnergy FirstEnergy
Corporation
6
RF
Black Hills
Micah Runner Black Hills
Corporation Corporation
All Segments Josh Combs
Black Hills
Corporation
1
WECC
3
WECC
Rachel Schuldt Black Hills
Corporation
6
WECC
Carly Miller
Black Hills
Corporation
5
WECC
Sheila
Suurmeier
Black Hills
Corporation
5
WECC
Gerry Dunbar
Northeast
Power
Coordinating
Council
10
NPCC
1
NPCC
United
1
Illuminating Co.
NPCC
NPCC RSC
Deidre Altobell Con Edison
Michele
Tondalo
Stephanie
Orange and
Ullah-Mazzuca Rockland
Michael
Ridolfino
1
NPCC
Central Hudson 1
Gas & Electric
Corp.
NPCC
Randy Buswell Vermont
Electric Power
Company
1
NPCC
James Grant
2
NPCC
1
NPCC
NYISO
Dermot Smyth Con Ed Consolidated
Edison Co. of
New York
David Burke
Orange and
Rockland
3
NPCC
Peter Yost
Con Ed Consolidated
Edison Co. of
New York
3
NPCC
Salvatore
Spagnolo
New York
Power
Authority
1
NPCC
Sean Bodkin
Dominion 6
Dominion
Resources, Inc.
NPCC
David Kwan
Ontario Power 4
Generation
NPCC
Silvia Mitchell NextEra Energy 1
- Florida Power
and Light Co.
NPCC
Sean Cavote
4
NPCC
5
NPCC
Utility Services 5
NPCC
PSEG
Jason Chandler Con Edison
Tracy
MacNicoll
Shivaz Chopra New York
Power
Authority
6
NPCC
Vijay Puran
New York State 6
Department of
Public Service
NPCC
David Kiguel
Independent
7
NPCC
Joel Charlebois AESI
7
NPCC
Joshua London Eversource
Energy
1
NPCC
Emma
Halilovic
Hydro One
1,2
Networks, Inc.
NPCC
Emma
Halilovic
Hydro One
1,2
Networks, Inc.
NPCC
Chantal Mazza Hydro Quebec 1,2
NPCC
Emma
Halilovic
Hydro One
1,2
Networks, Inc.
NPCC
Chantal Mazza Hydro Quebec 1,2
NPCC
Nicolas
Turcotte
Hydro-Quebec 1
(HQ)
NPCC
Jeffrey
Streifling
NB Power
Corporation
1,4,10
NPCC
Jeffrey
Streifling
NB Power
Corporation
1,4,10
NPCC
Jeffrey
Streifling
NB Power
Corporation
1,4,10
NPCC
7
NPCC
Joel Charlebois AESI
Elevate
Energy
Consulting
Ryan Quint NA - Not
Applicable
Dominion Dominion
Resources,
Inc.
Sean Bodkin 6
Stephen
Whaite
Tim Kelley
Stephen
Whaite
Tim Kelley
NA - Not Applicable Elevate
Energy
Consulting
Ryan Quint
Elevate Energy
Consulting
NA - Not
Applicable
N/A
N/A
NA - Not
Applicable
Connie Lowe
Dominion 3
Dominion
Resources, Inc.
NA - Not
Applicable
Lou Oberski
Dominion 5
Dominion
Resources, Inc.
NA - Not
Applicable
Larry Nash
Dominion 1
Dominion
Virginia Power
NA - Not
Applicable
Rachel Snead
Dominion 5
Dominion
Resources, Inc.
NA - Not
Applicable
ReliabilityFirst
Ballot Body
Member and
Proxies
Lindsey
Mannion
ReliabilityFirst
10
RF
Stephen
Whaite
ReliabilityFirst
10
RF
SMUD and
BANC
Nicole Looney Sacramento
Municipal
Utility District
3
WECC
Dominion
RF
WECC
Associated Todd
Electric
Bennett
Cooperative,
Inc.
3
AECI
Charles Norton Sacramento
Municipal
Utility District
6
WECC
Wei Shao
Sacramento
Municipal
Utility District
1
WECC
Foung Mua
Sacramento
Municipal
Utility District
4
WECC
Nicole Goi
Sacramento
Municipal
Utility District
5
WECC
Kevin Smith
Balancing
Authority of
Northern
California
1
WECC
Michael Bax
Central Electric 1
Power
Cooperative
(Missouri)
SERC
Adam Weber
Central Electric 3
Power
Cooperative
(Missouri)
SERC
Gary Dollins
M and A
Electric Power
Cooperative
3
SERC
William Price
M and A
Electric Power
Cooperative
1
SERC
Olivia Olson
Sho-Me Power 1
Electric
Cooperative
SERC
Mark Ramsey
N.W. Electric
Power
Cooperative,
Inc.
1
SERC
Heath Henry
NW Electric
Power
3
SERC
Cooperative,
Inc.
Tony Gott
KAMO Electric
Cooperative
3
SERC
Micah
Breedlove
KAMO Electric
Cooperative
1
SERC
Brett Douglas
Northeast
Missouri
Electric Power
Cooperative
1
SERC
Skyler
Wiegmann
Northeast
Missouri
Electric Power
Cooperative
3
SERC
Mark Riley
Associated
Electric
Cooperative,
Inc.
1
SERC
Brian
Ackermann
Associated
Electric
Cooperative,
Inc.
6
SERC
Chuck Booth
Associated
Electric
Cooperative,
Inc.
5
SERC
Jarrod
Murdaugh
Sho-Me Power 3
Electric
Cooperative
SERC
1. Do you agree with the need for creating a new Standard (PRC-029-1) to address gaps the Inverter-Based Resource Performance
Subcommittee (IRPSC) identified within the PRC-024-3 Project 2020-02 SAR and to address the expectations of FERC Order No. 901?
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
We recommend adding these IBR related requirements to PRC-024, rather than creating a new Standard.
Likes
0
Dislikes
0
Response
Kimberly Turco - Constellation - 6
Answer
No
Document Name
Comment
Constellation does not agree with creating a new IBR specific standard (PRC-29) to address the gaps in the Inverter-Based Resource. While
Constellation recognizes that there has been some grid disturbance in the Odessa/California/Utah regions in the past couple years as a result of
some IBRs not performing as intended, the creation of a new standard is a quick reaction without ensuring existing equipment's are capable to
fully comply.
Kimberly Turco on behalf of Constellation Segments 5 and 6
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
No
Texas RE supports creating a new standard to address Inverter-Based Resources (IBR) gaps identified. Texas RE is concerned, however, with the
structure of the standard as it is presently proposed.
As currently drafted, the proposed PRC-029-1 would wholly eliminate existing frequency and voltage protection setting verification
requirements for IBR resources. Texas RE submits that this is contrary to FERC’s intent in directing NERC to develop a comprehensive ridethrough standard for IBR resources. FERC Order No. 901 explicitly directs NERC to draft a standard “that require[s] IBR generator owners and
operators to use appropriate settings (i.e., inverter, plant controller, and protection) to ride through frequency and voltage system excursions
and that permit IBR tripping only to protect IBR equipment in scenarios similar to when synchronous generation resources use tripping as
protection from internal faults.” (Order No, 901, paragraph 190). FERC’s intent behind the order was to expand the scope of applicable devices
beyond protection system equipment subject to the current PRC-024 requirements to embrace a range of devices that can trip an IBR facility
(inverters, plant controller, etc.). The ultimate goal is to better ensure that IBRs provide reliable performance during voltage and frequency
excursions.
Texas RE submits, however, that FERC did not intent to exclude IBR entities from the existing verification processes or significant limit the ability
of the ERO to review protection system settings prior to an actual disturbance event. In its order, FERC specifically referenced the 2021 Odessa
Disturbance Report jointly prepared by NERC and Texas RE staff (“2021 Odessa Disturbance Report”). The 2021 Odessa Disturbance Report in
turn called for the development of a ride-through standard to replace PRC-024-3 because “the events analyzed by NERC regarding fault-induced
reductions in solar PV output and wind output have identified issues with controls and protections unrelated to voltage and frequency.” (2021
Odessa Report, at 29). While calling for a more comprehensive standard, however, the report simultaneously identified pervasive issues with
protection system settings within the scope of the current PRC-024 standards. The report noted: “Numerous plant owner/operators have
stated that they do not have sufficient technical staff on hand to interpret the results and will simply install what the consultant
recommends. This is leading to poorly coordinated protection systems within the facility, causing unreliable performance from BPS-connected
solar PV facilities in multiple interconnections.” (2021 Odessa Report, at 17 (emphasis added)). In short, while acknowledging that the current
PRC-024 standard is overly narrow, FERC and the various reports FERC references make clear that protection system verification failures remain
an important contributing factor in the numerous disturbance events involving IBRs over the past few years.
As proposed, PRC-029-1 would result in a reliability gap by requiring that protection system settings no longer require verification. The
Standard Drafting Team (SDT) explains in the draft PRC-029-1 Technical Rationale that “[a]n IBR becomes noncompliant with PRC‐029 only
when an event in the field occurs that shows that one or more requirements were not satisfied.” Under the SDT’s proposed approach,
therefore, the existing PRC-024 protection system setting verification requirements would be eliminated and the sole mechanism to verify
performance would be an IBR’s failure to perform during a disturbance event. Texas RE posits that this approach is inconsistent with the intent
of FERC’s order to expand the applicable devices and settings that an IBR-entity must ensure are properly set to avoid unnecessary tripping
during events. It is also inconsistent with findings that entities continue to experience issues properly setting (and verifying) existing protection
systems within the scope of the current PRC-024 requirements.
Rather than pursue this approach, Texas RE suggests that the SDT consider retaining the existing protection system verification requirements as
a foundational step, but augment those requirements with a general performance standard. Moreover, while Texas RE does not believe the
SDT needs or should develop a comprehensive and prescriptive list of devices that must be appropriate set and coordinated to ensure IBR
performance, the SDT should consider which measures and evidence would be appropriate for the GO and TO to demonstrate that its settings
meet the various no-trip zone parameters described in Attachment 1. This should include sufficient evidence to show that protection system
settings are properly set to not trip within appropriate no trip zones, as well as that other settings for inverters, plant controllers, and other
devices are properly coordinated. Such clarity will ensure that at least minimum performance can be audited and verified prior to a
disturbance event – the goal of the standards process.
Additionally, Texas RE noticed during the webinar, SDT stated that the requirements do not apply to individual IBR units. Requirement R1
seems to indicate that each IBR unit needs to remain electrically connected and continue to exchange current in accordance with the no-trip
zones and operation regions.
Lastly, Texas RE recommends the SDT consider changing ‘each IBR’ to ‘each IBR Facility’ for all the Requirements.
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0
Response
Joy Brake - Nova Scotia Power Inc. - NA - Not Applicable - NPCC
Answer
No
Document Name
Comment
A performance standard should be based on function not technology type which is always changing. An IBR generation facility should meet the
same performance threshold as traditional generation, with additional support devices as necessary incorporated into the facility design to
meet the same level of performance as a traditional unit.
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0
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0
Response
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Comment
PRC-024-3 has not been in effect long enough to be deemed inadequate to address “gaps” and issues described in IBR disturbance reports. It
became effective on 10/1/2022, which was long after major disturbances occurred, and as written, covers major causes of IBR disturbances
such as voltage, frequency, and momentary cessation. Most importantly, the Standard clearly stated applicability to individual IBR units and it
clearly stated no-trip zones. The Standard could have been modified to include and cover other recommendations from the disturbance report
such as PLL protection and ramp rate mis-coordination.
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0
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0
Response
Alison MacKellar - Constellation - 5
Answer
No
Document Name
Comment
Constellation does not agree with creating a new IBR specific standard (PRC-29) to address the gaps in the Inverter-Based Resource. While
Constellation recognizes that there has been some grid disturbance in the Odessa/California/Utah regions in the past couple years as a result of
some IBRs not performing as intended, the creation of a new standard is a quick reaction without ensuring existing equipment's are capable to
fully comply.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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0
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0
Response
Michael Goggin - Grid Strategies LLC - 5
Answer
No
Document Name
Comment
A major concern with the separate Standards, as drafted, is that ride through performance is not required for synchronous generators under
PRC-024-4, but it is for IBRs under PRC-029. PRC-02-4 simply requires protective relays to be set so they do not trip the generator within
specified bounds, but it allows a resource to trip offline for other reasons. PRC-024-4 also allows a plant to trip if protection systems trip
auxiliary plant equipment, per section 4.2.3. In contrast, PRC-029 requires IBRs to remain electrically connected and to continue to exchange
current within the specified voltage and frequency bounds. Said another way, an IBR and a synchronous resource could both trip during the
same disturbance, and the IBR would be in violation of PRC-029 but the synchronous generator would not be in violation of PRC-024-4, as long
as the synchronous generator did not trip due to the settings of its protection system.
To ensure grid reliability and resilience, all resources including IBRs and synchronous resources should ride through grid disturbances. The
failure of synchronous generators to ride through grid disturbances threatens grid reliability as much or more than the failure of IBRs, as
synchronous resources are often producing at a higher level of output, are more typically relied on as capacity resources, and often take longer
to come back online and ramp up to full output if they trip due to a disturbance.
FERC Order 901 directed NERC to treat IBR resources similarly to how NERC Standards treat synchronous generators, writing that the IBR
Standard should “permit IBR tripping only to protect the IBR equipment in scenarios similar to when synchronous generation resources use
tripping as protection from internal faults.”{C}[1] Allowing synchronous generators to trip but requiring IBRs to ride through the same or similar
disturbance could be challenged at FERC as undue discrimination.
Not requiring ride-through performance from synchronous generators is also at odds with the intent for this project that NERC stated in its
February 2023 comments on the FERC proposed rulemaking that led to Order 901: “A comprehensive, performance-based ride-through
standard is needed to assure future grid reliability. To that end, NERC re-scoped an existing project, 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 generating resources.”[2] FERC’s Order 901 also noted NERC’s statement that this project would require ride-through
performance from all generating resources,[3] so a failure to require ride-through performance from synchronous generators may be contrary
to both NERC and FERC’s intent.
The drafting team should make PRC-024-4 a ride-through performance requirement like PRC-029, or alternatively create a single standard that
applies to both types of resources (with any necessary clarifications or minor differences in requirements to reflect the differences in IBR and
synchronous generator technologies).
{C}[1]{C} Order 901, https://www.ferc.gov/media/e-1-rm22-12-000, at paragraph 190
{C}[2]{C}https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Comments_IBR%20Standards%20NOPR.pdf, at 21-22
{C}[3]{C} Order 901, https://www.ferc.gov/media/e-1-rm22-12-000, at paragraph 185
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0
Response
Carey Salisbury - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer
No
Document Name
Comment
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0
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0
Response
David Campbell - David Campbell On Behalf of: Natalie Johnson, Enel Green Power, 5; - David Campbell
Answer
Document Name
Comment
No
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0
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0
Response
Thomas Foltz - AEP - 5
Answer
Yes
Document Name
Comment
While AEP agrees with creating PRC-029-1 to address the identified gaps, AEP recommends the SDTs for PRC-028, PRC-029 and PRC-030 review
each proposed standard obligations to ensure there is a consistent, integrated plan across these projects and standards to achieve the goal of
correcting the past performance of Invertor-Based Resources and IBR units. Having a coherent strategy document that explains how these
three standards complement each other (and not be duplicative) would be beneficial.
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0
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0
Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
Synchronous generation and Inverter-based resources should have separate standards due to their unique differences. Presently, behavior of
Synchronous generation during disturbances and faults is very well understood compared to IBR technology.
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0
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0
Response
Helen Lainis - Independent Electricity System Operator - 2
Answer
Yes
Document Name
IESO Comments for PRC-024 PRC-029 Draft 1.docx
Comment
Complete set of comments for all Qs attached in file: IESO Comments for PRC-024 and PRC-029 Draft 1
Likes
1
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Ontario Power Generation Inc., 5, Chitescu Constantin
0
Response
Brian Lindsey - Entergy - 1
Answer
Yes
Document Name
Comment
Yes, we need a separate a standard. The technologies are different enough that a separate standard will reduce confusion.
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0
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0
Response
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Yes
Document Name
Comment
AECI supports comments provided by the NAGF
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0
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0
Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Yes
Document Name
Comment
FirstEnergy supports the need for the new standard (PRC-029-1).
In addition, FE supports EEI’s comments which state:
EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
Additionally, Requirement R2, subpart 2.5 could be understood to mean that IBRs whenever the voltage at the high-side of the main power
transformer is within the no-trip zone, as specified in Attachment 1, must not trip even if it might lead to equipment damage. We offer the
following proposed edits in boldface to Requirement R2, subpart 2.5 to clarify the requirement. NERC Reliability Standards should never
mandate that equipment run to failure.
2.5 Each IBR shall only trip to prevent equipment damage, Whenever the voltage at the high‐side of the main power transformer is within of
the no‐trip zone, as specified in Attachment 1, each IBR shall continue to operate except when the continued operation of the IBR would lead
to equipment damage.
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0
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0
Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Yes
Document Name
Comment
Black Hills Corporation agrees that there is a gap in PRC-024-3 regarding performance of inverter-based resources (IBR). However, more
consideration should be given to creating “protection-based” Standards for IBR, whether as an update to existing Standard PRC-024-3 or new
Standard PRC-029-1 rather than the “event-based” approach currently being taken in PRC-029-1.
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0
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0
Response
Stefanie Burke - Portland General Electric Co. - 6
Answer
Yes
Document Name
Comment
PGE requests that the Standard Drafting Team (SDT) add clarity regarding Attachment A: Voltage Boundary Clarifications, Section: Evaluating
Protection Settings, a. The most probable real and reactive loading conditions for the unit under study.
Loading conditions vary depending on the type of unit, location, time of year, etc. How should an entity assess “most probable” loading
conditions? Are entities being required to account for the worst case scenarios providing the greatest voltage change(s), not just a probable
condition that may represent little to no significant voltage difference?
PGE also notes that the Table References and Figure References are not aligned
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0
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0
Response
Colin Chilcoat - Invenergy LLC - 6
Answer
Yes
Document Name
Comment
Yes, the technological differences warrant separate standards for IBRs and synchronous generation.
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0
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0
Response
David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
Yes
Document Name
Comment
Ameren agrees with EEI's comments.
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0
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0
Response
Rhonda Jones - Invenergy LLC - 5
Answer
Document Name
Comment
Yes
Yes, the technological differences warrant separate standards for IBRs and synchronous generation.
Likes
0
Dislikes
0
Response
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Yes
Document Name
Comment
None
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0
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0
Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Yes
Document Name
Comment
Duke Energy recommends the implementation of EEI comments.
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0
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0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Yes
EEI supports the development of a new Reliability Standard to address gaps in Inverter-Based Resource Performance and while the SAR does
not include any language that specifically addresses FERC Order No. 901, EEI has no concerns with the SDT adjusting PRC-029 in line with the
directives contained in this Order.
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0
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0
Response
Imane Mrini - Austin Energy - 6, Group Name Austin Energy
Answer
Yes
Document Name
Comment
AE supports comments provided by Texas RE and the NAGF
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0
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0
Response
Daniel Gacek - Exelon - 1
Answer
Yes
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
Likes
0
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0
Response
Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Yes
But we have additional comments.
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0
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0
Response
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer
Yes
Document Name
Comment
SRP believes that there is a huge lack of oversight in regard to inverter-based resources. Regulation on IBR controls is somewhat late but we are
glad is happening.
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0
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0
Response
David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
Yes
Document Name
Comment
Vistra agrees with AEP.
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0
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0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
Yes
OPG supports IESO’s comments.
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0
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0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Yes
Document Name
Comment
See EEI Comments
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0
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0
Response
Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Southern Company believes that separating synchronous machine facilities from IBR facilities simplifies the complication that would exist by
addressing both types of facilities in the same standard. While the existing "legacy" facilities have demonstrated imperfect ride-through
performance (reactions) during system initiated disturbances, Southern believes that the application of ride-through requirements should only
be applicable to facilities designed, built, and commissioned after the development of such a standard. The existing "legacy" facilities were not
designed or built to achieve the desired ride-through performance that is specified in PRC-029-1, requirements R1-R5 of this proposed
standard, and should not be subject to those requirements. The demonstrated performance, while not matching the ideal performance
dictated by this proposed standard, is not catastrophic to the interconnection. The notion that generator owners have not taken any actions to
improve the reaction of the legacy facilities to system disturbances is false. Southern Company has reviewed and modified control and
protection settings for inverter operations at multiple facilities since the issuance of the first two NERC Alerts on the Loss of Solar facilities and
during the multiple disturbance analysis evaluations. Addressing the desired performance with new facilities which will have the component
design and control strategies sufficient to meet the desired performance should be a measure adequate to address the frequency control,
voltage control, and stability needs and concerns of the interconnection.
Perhaps a more reasonable approach towards achieving better IBR facility ride through performance during system disturbance events, is to
require evaluations with every instance of a plant output hiccup. The proposed required evaluation process in PRC-030, requiring corrective
action plans to minimize/eliminate/eradicate the reason for the hiccup, would address, where possible, action taken through control or
protection system setting changes, or through hardware changes - for equipment placed in service after the effective date of this draft
standard).
Southern would offer general concerns with synchronizing language across all draft standards. For example, M1 states: “shall have evidence of
actual recorded data or other evidence for each applicable IBR demonstrating adherence to ride-through requirements”. This seems like an
opportunity to clarify by explicitly referencing standard(s) addressing data collection. This example repeats in some form in each “M”
paragraph. Should the evidence of actual recorded data in M1 and other measures synch up with the phased in approach to PRC-028?
Finally, Southern Company supports EEI and NAGF comments.
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Response
Richard Vendetti - NextEra Energy - 5
Answer
Yes
Document Name
Comment
NextEra aligns with EEI's comments:
EEI supports the development of a new Reliability Standard to address gaps in Inverter-Based Resource Performance and while the SAR does
not include any language that specifically addresses FERC Order No. 901, EEI has no concerns with the SDT adjusting PRC-029 in line with the
directives contained in this Order.
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0
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0
Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company, 3,
1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Yes
Document Name
Comment
PG&E agrees with creating the new Standard PRC-029-1 to address IBRs.
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0
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0
Response
Kinte Whitehead - Exelon - 3
Answer
Yes
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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0
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0
Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Yes
Document Name
Comment
See EEI comments
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0
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0
Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
See comments submitted by Edison Electric Institute
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0
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Response
0
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Yes
Document Name
Comment
Thank you for leaning heavily on IEEE 2800.
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0
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0
Response
Ryan Quint - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable, Group Name Elevate Energy Consulting
Answer
Yes
Document Name
Comment
Yes, generator ride-through is an essential reliability service and the changing generation technology to inverter-based has led to the need for
improved, applicable, appropriate, and technically accurate requirements that suit IBRs. However, it is critically important that the
implementation of these requirements consider all stakeholder needs and capture important technical considerations so that the requirements
sufficiently mitigate risks without causing unnecessary costs or burdens on any responsible entity.
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0
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0
Response
Jennie Wike - Jennie Wike On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma
Power
Answer
Yes
Document Name
Comment
Likes
0
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Response
0
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer
Yes
Document Name
Comment
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0
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0
Response
Michael Brytowski - Great River Energy - 3
Answer
Yes
Document Name
Comment
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0
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0
Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District,
3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Tim Kelley, Group Name SMUD and BANC
Answer
Yes
Document Name
Comment
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0
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0
Response
Ben Hammer - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Brittany Millard - Lincoln Electric System - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Ruchi Shah - AES - AES Corporation - 5
Answer
Yes
Document Name
Comment
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0
0
Response
Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer
Yes
Document Name
Comment
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0
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0
Response
George E Brown - Pattern Operators LP - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Yes
Document Name
Comment
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0
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0
Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Yes
Document Name
Comment
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0
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0
Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Yes
Document Name
Comment
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0
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0
Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Yes
Document Name
Comment
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0
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0
Response
Wendy Kalidass - U.S. Bureau of Reclamation - 5
Answer
Document Name
Comment
Likes
0
Yes
Dislikes
0
Response
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3 - WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Yes
Document Name
Comment
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0
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0
Response
Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
Yes
Document Name
Comment
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0
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0
Response
Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Glen Farmer - Avista - Avista Corporation - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Dave Krueger - SERC Reliability Corporation - 10
Answer
Yes
Document Name
Comment
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Dislikes
0
0
Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
Yes
Document Name
Comment
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0
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0
Response
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Yes
Document Name
Comment
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0
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0
Response
Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
Yes
Document Name
Comment
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0
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0
Response
Shonda McCain - Omaha Public Power District - 6
Answer
Document Name
Yes
Comment
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0
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0
Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Yes
Document Name
Comment
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0
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0
Response
Katrina Lyons - Georgia System Operations Corporation - 4
Answer
Yes
Document Name
Comment
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0
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0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Yes
Document Name
Comment
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0
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Response
0
Joshua Phillips - Southwest Power Pool, Inc. (RTO) - 2
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Pearson - ISO New England, Inc. - 2
Answer
Yes
Document Name
Comment
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0
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0
Response
Mark Flanary - Midwest Reliability Organization - 10
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
Answer
Document Name
Comment
Yes
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0
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0
Response
Wesley Yeomans - New York State Reliability Council - 10
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
2020-02_EPRI Comments on Draft NERC PRC-029 (IBR ride-through) Reliability Standard.pdf
Comment
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0
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Response
0
2. Do you agree that the language within PRC-029-1 requirements R1, R2, and R6 regarding IBR plant-level performance during grid voltage
disturbances is clear?
Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
Answer
No
Document Name
Comment
The ISO/RTO Council (IRC) Standards Review Committee (SRC) recommends the following modifications to improve the clarity and better
convey the intent of the standard.
Recommended changes to R1:
“…as specified in Attachment 1 except when needed to clear a fault or a documented and communicated equipment limitation exists in
accordance with Requirement R6.”
Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that each IBR remains electrically connected and continues to
exchange current in accordance with the no‐trip zones and operation regions as specified in Attachment 1 unless needed to clear a fault or a
documented equipment limitation exists in accordance with Requirement R6.
Recommended changes to M1:
“…demonstrating adherence to ride‐through requirements, as specified in Requirement R1, or shall have evidence of a documented and
communicated equipment limitation, as specified in Requirement R6.”
Recommended changes to R2:
“…each IBR’s voltage performance adheres to the following, unless a documented and communicated equipment limitation exists…”
The SRC recommends that the SDT to review and align the data in Attachment 1 to ensure that the data in Tables 1 and 2 aligns with what is
shown in Figures 1 and 2. Currently, the graphs in Figures 1 and 2 do not match what is indicated in the Tables. For example, rows 1-3 in Tables
1 and 2 are identical, yet Figure 2 does not match Figure 1 by indicating a Voltage Ride-Through Requirement of 1.0.
It appears that the SDT’s intent is to require continuous operation between 95% and 105% voltage with a minimum ride-through time of at
least 1800 seconds (half an hour) when voltage is above 105% and not exceeding 110%. If the intent is actually that equipment must be able to
operate continuously at voltages up to 110%, then the tables and plots should be labelled with a descriptor that clearly indicates that indefinite
or continuous operation is required rather than operation for a minimum ride-through time (1800 seconds). For example, a version of Table 2
that achieves the SDT’s apparent intent could look like the following:
Voltage (per unit)
Minimum Ride-Through Time (sec)
>1.2
N/A
<=1.2 and >1.1
1.0
<=1.1 and >1.05
1800
<=1.05 and >=0.95
Continuous
<0.95 and >=0.90
Continuous*
*current limitation permitted, with active or reactive power preference as specified
<0.90 and >=0.70
6
<0.70 and >=0.50
3
<0.50 and >=0.25
1.2
<0.25
0.32
While the above comments point out areas of ambiguity in the draft standard that need to be clarified, the SRC recommends that Table 1 and
Table 2 be modified to require IBR plants remain connected indefinitely when the voltage is between 1.05 and 1.1 pu. The current draft
standard requires units to remain online for 1800 seconds in this range, and the logic behind this threshold is not clear. The current PRC-024
standard requires units to remain on-line indefinitely for the above range. [All SRC entities support the comments in this paragraph except
MISO].
In addition, the SRC recommends a part be added to the standard to directly address the Permissive Operating Region, similar to what is done
in Part 2.1 (for the Continuous Operation Region) and Part 2.2 (for the Mandatory Operation Region) as, the rules surrounding the Permissive
Operating Region are unclear if this is not addressed. For example, there should be some linkage between the body of the standard and
Attachment 1, item 10. The SRC proposes the following language for consideration (new Part 2.3):
2.3 While voltage at the high‐side of the main power transformer is within the Permissive Operation Region as specified in Attachment 1, an
IBR may operate in current block mode only if necessary to protect the equipment. Otherwise, each IBR shall follow the requirements for the
Mandatory Operation Region in Requirement R2, Part 2.2.
Recommended changes to R6:
The SRC is concerned that Requirement R6 as proposed provides an overly broad exemption, as the standard is silent as to what criteria must
be met to qualify for an exemption and contains no requirement that a Corrective Action Plan be developed or that the equipment limitations
be resolved or addressed. Only notification to other entities is required. The SRC recommends that the SDT:
•
•
Develop more specific criteria as to what qualifies as an equipment limitation[1], OR A technical justification that addresses why
corrective actions will not be applied nor implemented.
Require exemptions be submitted to NERC and/or the Regional Entities for pre-approval in order to qualify for the exemption.
The SRC suggests there should be explicit requirements to both ‘document equipment limitations’ and to ‘communicate’ those documented
limitations to the appropriate parties. The SRC proposes the following modifications to address this issue:
“Each Generator Owner and Transmission Owner with a known equipment limitation that would prevent an applicable IBR that is in‐service by
the effective date of this standard from meeting voltage ride‐through requirements as detailed in Requirements R1 and R2 shall document
each equipment limitation, develop a Corrective Action Plan to address the limitation, and communicate both the limitation and the
Corrective Action Plan to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s).
Recommended changes to M6:
Each Generator Owner and Transmission Owner shall have evidence of known equipment Limitations accompanied by a Corrective Action Plan,
as specified in Requirement R6, having been documented and communicated to each associated Planning Coordinator, Transmission Planner,
and Reliability Coordinator prior to the effective date of PRC‐029‐1.
Each Generator Owner and Transmission Owner with changes to equipment shall have evidence of communication to each associated Planning
Coordinator, Transmission Planner, and Reliability Coordinator.
[1] See Implementation Plan (page 4), “only those IBR that are unable to meet voltage ride-through requirements due to their inability to
modify their coordinated protection and control settings may be considered for potential exemption.” See Technical Rationale (page 9); i.e.
specify which voltage band(s) and associated duration(s) cannot be satisfied or specific as to the number of cumulative voltage deviations within
a ten‐second time period that the equipment can ride‐through if less than four… identify the specific equipment and explain the characteristic(s)
of that equipment that prevent ride‐through.
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Michael Brytowski - Great River Energy - 3
Answer
No
Document Name
Attachment 1 figures 1 and 2 .pdf
Comment
Comments: GRE requests the SDT review and align the data in Attachment 1 so the data in Tables 1 and 2 aligns with what is shownin Figures 1
and 2. Currently, the graphs in Figures 1 and 2 do not match what is indicated in the Tables. (uploaded)
GRE recommends a part be added to the standard to directly address the Permissive Operating Region, similar to what is done in Part 2.1 (for
Continuous Operation Region) and Part 2.2 (for Mandatory Operation Region) as, if left unaddressed, is unclear. For example, there should be
some linkage between the body of the standard and Attachment 1, item 10. MRO NSRF proposes the following language for consideration (new
Part 2.3):
2.3 While voltage at the high‐side of the main power transformer is within the Permissive Operation Region as specified in Attachment 1, an
IBR may operate in current block mode only if necessary to protect the equipment. Otherwise, each IBR shall follow the requirements for the
Mandatory Operation Region in Requirement R2.2.
GRE is concerned that requirement R6 provides an overly broad exemption as written as the standard is silent as to what criteria must be met.
Only notification to other reliability entities is required with no requirement to develop and implement a Corrective Action Plan. MRO NSRF
recommends the SDT:
Develop more specific criteria as to what qualifies as an equipment limitation[1], OR
Require exemptions be submitted to NERC and/or the Regional Entities for approval in order to qualify for the exemption.
[1] See Implementation Plan (page 4), i.e. “only those IBR that are unable to meet voltage ride-through requirements due to their inability to
modify their coordinated protection and control settings may be considered for potential exemption.” See Technical Rationale (page 9); i.e.
specify which voltage band(s) and associated duration(s) cannot be satisfied or specific as to the number of cumulative voltage deviations within
a ten‐second time period that the equipment can ride‐through if less than four… identify the specific equipment and explain the characteristic(s)
of that equipment that prevent ride‐through.
R2: GRE agrees with the present flexibility that some of the IBR VRT performance could be modified to meet the individual system needs by the
applicable Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator. However, some clarity may be
required on how this process is initiated and what type is evidence is required to demonstrate request is received and implemented. This may
be an additional requirement assigned to the Transmission Planner. Each Transmission Planner, Planning Coordinator, and Transmission
Operator that jointly specifies the following voltage ride-through performance requirements within their area(s) different than those specified
under R2, shall make those requirements available to each associated applicable IBR Generator Owner and Transmission Owner.
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Mark Flanary - Midwest Reliability Organization - 10
Answer
No
Document Name
Comment
See comments below under question 4.
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
No
Comment
R2.5 & R5.1, et al. Each IBR shall only trip … “Trip” may be ambiguous. Does this mean disconnecting from the system to de-energize the IBR
equipment, as in opening a circuit breaker? Or does it mean cease exchanging current? Or something else?
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John Pearson - ISO New England, Inc. - 2
Answer
No
Document Name
Comment
For R1, We recommend adding language to refer to plants that were previously exchanging current before the disturbance. For example, A
BESS that is fully charged would be connected to the BES, but would not be exchanging current. For R2, change “each IBR’s voltage
performance” to voltage ride through performance. For R6, exemptions should not be automatically allowed. This would allow for bad designs
relying on an exemption. Exemptions should only be for existing or legacy units. New units should not have the option for exemption.
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Joshua Phillips - Southwest Power Pool, Inc. (RTO) - 2
Answer
No
Document Name
Comment
Southwest Power Pool joins the ISO/RTO Council Standards Review Committee comments.
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Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
No
Document Name
Comment
In the opinion of ACES, the newly proposed Glossary Terms are unnecessary and seemingly incongruous terms. For example, if the Mandatory
Operating Region is required, should it not also be continuous? It is our opinion that these terms add little to no value and instead only create
confusion where none was previously present. We recommend striking these new terms from the standard.
In ACES’ opinion, R1 appears to be overly broad so as to require an applicable IBR to be operational at all times. This does not appear to allow
for full facility outages without first having a “documented equipment limitation” per R6. Thus, as written, the GO will run the risk of noncompliance with either R1, R6, or both whenever a full facility outage of an IBR is required. Furthermore, it is unclear how R1 differs from R2
other than seeming to requiring the GO to ensure the GOP always keeps the unit online during to normal operation. We recommend striking
R1 from the standard.
Additionally, we do not agree with the language of Requirement R2, Part 2.1.1. As written, R2 does not define what type of System disturbance
is applicable and Part 2.1.1 requires the GO to continue producing active power at the pre-disturbance levels or its maximum capability;
whichever is less. We have concerns with this approach. Namely, during an over frequency deviation event wherein the high side MPT voltage
remains ≥ 0.9 p.u. and ≤ 1.1 p.u. In this instance, the frequency response algorithm within the IBR would attempt to reduce active power
output. Due to the fast-acting nature of IBRs, it is likely that an IBR facility(ies) would respond to and correct such an event before a
synchronous generating resource(s). However, in the aforementioned hypothetical example, to comply with R2.1.1, the IBR frequency response
control would need to be either disabled or limited in its response to an over frequency System disturbance. In our opinion, this is not
beneficial to the reliability of the BES. While possibly unlikely at the current time, this hypothetical scenario becomes increasingly likely as
conventional synchronous generating resources are retired in favor of IBRs.
Furthermore, it is the opinion of ACES that R6 should be modified to include any potential regulatory limitations. This suggested approach is in
line with the approach taken in PRC-024-4 R3. We recommend the modifying R6 as follows:
R6. Each Generator Owner and Transmission Owner shall document each known regulatory or equipment limitation that prevents an
applicable IBR that is in‐service by the effective date of this standard from meeting voltage or frequency ride‐through requirements as detailed
in Requirements R1 through R5.
6.1 Each Generator Owner and Transmission Owner shall include in its documentation:
6.1.1 Identifying information of the IBR (name, facility #, other)
6.1.2 Which aspects of voltage ride‐through requirements that the IBR would be unable to meet
6.1.3 Identify the specific piece(s) of equipment causing the limitation.
6.2 The Generator Owner and Transmission Owner shall communicate the documented regulatory or equipment limitation, or the removal of a
previously documented regulatory or equipment limitation, to its Planning Coordinator and Transmission Planner, and Reliability Coordinator
within 30 calendar days of any of the following:
6.2.1 Identification of a regulatory or equipment limitation.
6.2.2 Repair of the equipment causing the limitation that removes the limitation.
6.2.3 Replacement of the equipment causing the limitation with equipment that removes the limitation.
Lastly, the values specified in Table 1 and Table 2 in Attachment 1 do not align with the graphs shown in Figure 1 and Figure 2, respectively.
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Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
No
Document Name
Comment
See comments submitted by Edison Electric Institute
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI comments
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Kinte Whitehead - Exelon - 3
Answer
Document Name
Comment
No
Exelon supports the comments submitted by the EEI for this question.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Document Name
Comment
Electric Reliability Council of Texas, Inc. (ERCOT) joins the comments of the ISO/RTO Council (IRC) Standards Review Committee (SRC) and
adopts them as its own in addition to the following comments, except to the extent of any specific differences between the SRC comments and
the following comments from ERCOT.
As detailed below, the currently proposed language for Requirement R1 is not clear. Additionally, ERCOT believes that plant‑level requirements
are insufficient because individual IBR unit performance failures continue to occur and could, in aggregate, be just as impactful or more
impactful than the complete loss of an IBR plant. The performance threshold should be coordinated with the threshold in PRC-030, and ERCOT
believes a reasonable threshold would be the lesser of either 20% of the plant’s gross nameplate rating, or 20 MW. In an IBR-dominated
electric system, these aggregated losses could cause unreliable operations if not corrected. The past 8-10 years have demonstrated that IBR
owners will not voluntarily correct these performance issues in the absence of a mandatory reliability standard.
SDT’s proposed language (ERCOT finds the bold portions unclear):
“Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that each IBR remains electrically connected and continues to
exchange current in accordance with the no‐trip zones and operation regions as specified in Attachment 1 unless needed to clear a fault or a
documented equipment limitation exists in accordance with Requirement R6.”
ERCOT’s proposed language:
“Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that each IBR, and its IBR units, remains electrically connected
and continues to exchange current in accordance with the no‐trip zones and operation regions as specified in Attachment 1 unless the IBR, or
its IBR units, needs to be tripped to clear a fault or a documented equipment limitation exists in accordance with Requirement R6.”
In addition to the concerns with Requirement R1 noted above, ERCOT is concerned that Requirement R2 does not clarify the timeframe
encompassed by the term “System disturbance.” Without further clarification, “System disturbance” may be interpreted to only describe the
fault itself, even though control instability may manifest itself immediately after the fault clears or during the milliseconds or seconds after the
fault clears, during which time frequency and voltage support are still critical. While IEEE 2800 defines the disturbance period, and there is an
expectation that an IBR will perform acceptably in the continuous operation region, Requirement R2 is not clear that “riding-through” a
disturbance includes both the fault and the non-fault portions of the disturbance along with the transition from ride-through mode to a new
steady-state (i.e., the post-disturbance period). ERCOT suggests a 10-second window as a bright-line criterion.
SDT's proposed language for Requirement R2.
“R2. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that during a System disturbance, each IBR’s voltage
performance adheres to the following, unless a documented equipment limitation exists in accordance with Requirement R6.”
ERCOT’s proposed language for Requirement R2:
“R2. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that during, and up to ten seconds after, a System
disturbance, each IBR’s voltage performance and its associated IBR units’ voltage performance adheres to the following, unless a documented
equipment limitation exists in accordance with Requirement R6.”
For Requirement R2, Part 2.2.2, ERCOT agrees that location-specific flexibility may be needed and defined by the TP, PC, RC, and or TOP;
however, the language should clearly mandate that in such instances, the established performance requirements must also be
met. Additionally, the current wording does not address the possibility that reactive current “response” could be in the wrong direction if not
properly configured, and the language should be clarified to address this issue. ERCOT proposes the following language for Part 2.2.2 to
capture the full spectrum of current priority modes from full aggressive reactive priority mode, to a de‑tuned reactive response while in
reactive priority mode, to an active priority mode.
“Adjust reactive current injection at the high-side of the main power transformer so that the magnitude of the reactive current properly
responds to changes in voltage at the high-side of the main power transformer in accordance with default reactive prioritization or as required
by any applicable Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator that specifies a certain
magnitude and timeliness of reactive power response to voltage changes, that specifies a maximum allowed active current reduction to
provide reactive current, or that specifies active power priority instead of reactive power priority.”
ERCOT also recommends including the following language to help prevent unnecessary misoperations due to the use of unfiltered
measurements or instantaneous (no time delay) settings for protection systems, consistent with NERC recommendations for addressing easily
preventable performance failures.
R2.2.3 “Utilize sufficient time delays or filtering methods for any voltage measurements utilized by its protection equipment to prevent
unnecessary trips due to calculation errors or transients.”
ERCOT finds the bolded portions of the SDT’s proposed language for Requirement R2, Part 2.3 to be unclear:
“The IBR shall not itself cause voltage at the high‐side of the main power transformer to exceed the applicable Attachment 1 Table 1 or Table 2
no‐trip zone voltage thresholds and time durations in its response from Mandatory or Permissive Operation Regions to the Continuous
Operating Region.”
ERCOT proposes the following language to clarify the issue:
“The IBR shall not itself cause voltage at the high‐side of the main power transformer to exceed the applicable Attachment 1 Table 1 or Table 2
no‐trip zone voltage thresholds and time durations in its response as it transitions from Mandatory or Permissive Operation Regions to the
Continuous Operating Region.”
ERCOT would also point out that the last clause may not be necessary because the IBR should not cause high voltage at any time, and the SDT
could consider the following alternative language:
“The IBR shall not itself cause voltage at the high‐side of the main power transformer to exceed the applicable Attachment 1 Table 1 or Table 2
no‐trip zone voltage thresholds and time durations.”
Consistent with the comments above on Requirement R2, Part 2.2.2, Requirement R2, Part 2.4 should be revised as follows to clarify that the
other requirements or specifications from the RC/PC/TP/TOP must still be met:
“Each IBR shall restore active power output to the pre‐disturbance or available level within 1.0 second when the voltage at the high‐side of the
main power transformer returns to the Continuous Operation Region from the Mandatory Operation Region or Permissive Operation Region
(including operation in current block mode) as specified in Attachment 1, or as required by any applicable Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator that specifies a lower post‐disturbance active power level requirement or that
specifies a different post‐disturbance active power restoration time.”
Requirement R2, Part 2.5 may not be clear, in light of the new defined terms, that partial trips (including trips of individual IBR units) should not
be allowed. While this topic should be coordinated with PRC-030, it goes to the heart of momentary cessation in that staying connected but
not supporting frequency and voltage can, in aggregate, be just as detrimental to reliability as a full trip. The SDT should consider revising Part
2.5 to ensure that it is clear that there would be a violation at a particular level (e.g., the lesser of 20% of the unit’s rated output, or 20 MW) of
IBR unit trips. This could be graduated in severity level starting at the 20% or 20 MW level and increasing thereafter (e.g., 20%, 40%, 60%, 80%,
and above).
ERCOT’s proposed language for Part 2.5: “Each IBR, or its IBR units, shall only trip to prevent equipment damage, when the voltage at the high‐
side of the main power transformer is outside of the no‐trip zone as specified in Attachment 1.”
ERCOT also has concerns with the SDT’s proposed Requirement R6 language:
“Each Generator Owner and Transmission Owner with a documented equipment limitation that would prevent an applicable IBR that is in‐
service by the effective date of this standard from meeting voltage ride‐through requirements as detailed in Requirements R1 and R2 shall
communicate each equipment limitation to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s).”
More specifically, the first bolded phrase (“a documented equipment limitation”) appears to allow complete GO/TO discretion to declare a
limitation with no process for review, approval, or acceptance of the limitation by any other entity. Only a communication to the PC, TP, and RC
is required. It is unclear if the SDT’s intention is that at some point these documented limitations would be reviewed or evaluated under the
NERC CMEP (and it is unclear what standard the limitation documentation would be held to under such a review). At a minimum, Measure M6
and/or the Technical Rationale should provide more information about what an acceptable limitation might be and guidance for CMEP staff to
use in evaluating the validity of limitations and the associated documentation.
The second bolded portion (“shall communicate each equipment limitation to the associated Planning Coordinator(s), Transmission Planner(s),
and Reliability Coordinator(s)”) is necessary, but may not be effective from a reliability perspective. A mere description of a limitation sent in
an email or letter would not be useful for the PC/TP/RC but would meet the letter of Requirement R6. If the purpose of the communication is
for PCs, TPs, and RCs to be able to assess the limitation and incorporate it into system studies, either Requirement R6 or the Technical
Rationale should clarify that the communication needs to be in a format that is acceptable and useful to the PC/TP/RC (most likely in the form
of an updated model that reflects the limitation). Additional burdensome administrative requirements to cover this communication process
are not suggested, but at the very least the Technical Rationale should include guidance and set expectations to ensure that the
communication will be useful to ensure the reliability of the grid. Additionally, ERCOT notes that FERC Order 901 recognized 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.” ERCOT recommends that Requirement R6 be clarified to indicate that the equipment limitation process is only available to
the limited subset of IBRs described in Order 901.
Additionally, ERCOT notes that Requirement R6, Part 6.2 does not require the TO/GO to actually improve ride-through capability even when
equipment is replaced:
“Each Generator Owner and Transmission Owner with a previously communicated equipment limitation that repairs or replaces the equipment
causing the limitation shall document and communicate such equipment changes to the associated Planning Coordinator(s), Transmission
Planner(s), and Reliability Coordinator(s) within 30 days of the equipment change.”
Rather than focusing on communication of changes, Part 6.2 should require the TO/GO to comply with all PRC-029 requirements and should
not allow any documented limitations whenever equipment is changed or replaced; this approach would better align with FERC Order
901. PRC-029 should also include a requirement that mandates the implementation of software settings changes and upgrades (that do not
require replacement of physical equipment) that improve ride-through capability. This is referenced in the implementation plan, but is absent
from the actual requirements in PRC-029.
Equipment limitations may also not be currently captured in dynamic models, and the list of requirements should be updated to reflect this
issue. The MOD standards may not accurately account for the provision of this information to all entities that perform studies (including
stability limit and IROL determination studies that RCs perform); this would constitute a reliability gap. RCs and PC/TPs must be able to assess
the impact of these exemptions to be able address the reliability impact under FERC Order 901.
Finally, ERCOT notes that FERC Order 901 requires NERC 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.” While it is clear that the SDT has determined that the
standard should allow for documented exemptions for equipment limitations, the requirement language is unclear as to how or whether this
exemption process is truly “limited” as required in Order 901, especially in light of the explicit reference to IBRs “that are unable to modify their
coordinated protection and control settings to meet the requirements without physical modification of the IBRs’ equipment.” As ERCOT notes
below, exemptions should be limited to scenarios where a responsible entity cannot otherwise achieve the necessary ride-through
performance without physical equipment changes (inability to meet ride-through requirements that can be addressed simply by making
software- or parameterization-type changes should not be grounds for an exemption) OR to scenarios where, even without making the
remaining physical changes, the loss of a contingency would not cause instability, Cascading Outages, or uncontrolled separation that adversely
impact the BPS.
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Shonda McCain - Omaha Public Power District - 6
Answer
Document Name
Comment
No
OPPD supports comments provided by GRE: Michael Brytowski, Great River Energy, 3, 4/17/2024
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company, 3,
1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
No
Document Name
Comment
Requirement 1 and 2
These requirements mention that the IBRs should respond to the voltage changes with reactive current injection during a system disturbance,
however, the magnitude of this response is not identified. The magnitude and expectation of the response should be clarified due to the fact
that it can vary by unit and unit capabilities.
Measures 1, 2, 3, 4, and 5
With regards to data recording, it is unclear what counts as recording? If the expectation is the same as contained in PRC-028-01 Draft 2, that
should be specified; or otherwise identify alternate means of data recording.
What if an entity does not have a recorded event to show compliance with the standard and prove its ability to ride through a system event?
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Richard Vendetti - NextEra Energy - 5
Answer
No
Document Name
Comment
NextEra aligns with EEI's comments:
EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
EEI also does not support Requirement R2, subpart 2.5 because it contains unneeded language, which adds confusion and implies that GOs can
only trip outside of the trip zone if their equipment might become damaged. This has never been an obligation for synchronous generators,
and we do not agree that this should be an obligation for IBRs. If NERC or the SDT believe that the no-trip zone needs to be expanded, they
should justify such a change and present it for industry review and comment, otherwise, Requirement R2, subpart 2.5 should be deleted.
And while we support Requirement R6 and the provisions to notify PCs, TPs and RC about equipment limitations that would prevent an
applicable IBR from meeting ride‐through requirements as detailed in Requirements R1 and R2, the Requirement does not go far enough
because there may be technical reasons why an applicable IBR is unable to meet Requirement R3 through R5, as well. To address this concern,
R6 should be expanded to include Requirement R1 through R5.
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Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
No
Document Name
Comment
In regard to R1:
Does M1 imply that actual recorded data must be kept as evidence of ride-thru compliance for every in-scope IBR, for every system
disturbance? Thesame question applies to R2-M2, R3-M3, R4-M4, and R5-M5.
The disturbance characteristic must be specified in order to trigger captures of performance information for every disturbance at every IBR
facility - the characteristic which defines each type of disturbance must be defined in order to capture the record.
For each of the Measures M1 - M5, what "other evidence" can demonstrate compliance with R1-R5 other than recorded data? How does the
drafting team believe that generator owners can assure this performance expectation can be achieved prior to an actual event? There is no
test verification that can be performed to confirm the expected performance. Consider providing some examples of what is acceptable as
“other evidence”.
R1 mentions “operation regions specified in Attachment 1. R2, Part 2.1 mentions “continuous operation region as specified in Attachment 1”
and Part 2.2 mentions “mandatory operation regions as specified in Attachment 1”. However, nowhere in attachment 1, is there mention of
"continuous, mandatory, or permissive" operation regions.
In regard to R2:
For R2, Continuous Operation Region is not specified in Att. 1; it is merely a defined term in the draft standard. Southern Company suggests
that the referenced region be shown on the graph of Att.1, or that the words from the defined term simply be placed in the sub-requirement
directly rather than creating a defined term. The term region implies an area (volt-time). If the definition is simply specifying voltage level
magnitude, simply state that. The definition labels are confusing; does permissive operation mean the IBR has permission to trip if the voltage
is less than 0.1pu? It is observed that the values in the "mandatory operating region" match some of the borders of the "no trip zone" in
Attachment 1, yet there is a time element that must be accounted for in determining if a trip is in compliance or not with the curve of Att.
1. For example, how can a long term (1-9 second) event where the voltage is 0.4pu be a Mandatory Operating Region? The voltage ride-thru
curve does not specify this (for example).
Regarding the R2.2 and R2.3 requirement specifications, IBR facilities do not have per phase voltage regulation in their current designs, so the
feasibility of successfully reacting to low system voltage (R2.2) with rapid reactive power injection while not possibly causing high voltage
locally (R2.3) is questionable.
Regarding R2.1.1 & R2.1.2, it should also reference Interconnection Agreements (IA) limits since some IBR facilities have both solar and battery
storage with an IA limit less than the aggregate sum.
Regarding R2.1.1 and R2.1.2, the idea that IBR Facility Power Plant Controllers operate to apparent power limits, is not in line with normal
practices. Most PPC interfaces do not provide an apparent power reading or control function option. PPCs communicate separate MW and
MVAR setpoints to all the of the site IBR Units and they follow or provide as capable the MWs and deliver MVARs up to the inverter reactive
power limit.
Southern Company recommends changing wording to:
R2.1.1:Continue to deliver the predisturbance level of active power or available active power, whichever is less, and continue to deliver active p
ower and reactive power up to its reactive power limit.
R2.1.2:If the IBR cannot deliver both active and reactive power due to a current or reactive power limit, when the applicable voltage is below 9
5% and still within the Continuous Operation Region, then preference shall be given to active or reactive power according to requirements spec
ified by the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
R2.1.2 discusses giving preference to either active or reactive power based on requirements specified by transmission entities. There is some
concern that this could be interpreted as a fluid preference that could require IBRs to actively configure active vs reactive capabilities.
Regarding R2.3, what happens if TOP has several lines down for maintenance in the area, which causes the part of the system the IBR facility is
located, go from a strong system to a weak system?
R2.4 does not take into consideration other dynamic system conditions as a result of the fault and the effects on the PPC during a fault
recovery. An example of this is Primary Frequency Response due to system frequency excursions during fault recovery. The active power
recovery may be reduced or frozen during an underfrequency event while an IBR Resource is in recovery, thereby extending the time of the
recovery.
R2 specifies performance for continuous and mandatory operation region, but not for permissive operation region. The performance during
permissive operation region is in Attachment 1. Performance for all regions should be in Requirement R2.
Regarding R2.1.1, the first part, where IBR is required to continue to deliver the pre-disturbance level of active power or available active power,
whichever is less is fine. However, the second part (and continue to deliver active power and reactive power up to its apparent power limit) is
conflicting with the first part of this requirement. If the IBR plant’s available active power was 50% of nameplate rating due availability of wind,
solar irradiance, etc., then the second part of the requirement is stating that plant is required to produce reactive power to its apparent power
limit given its available active power equal to 50% of nameplate rating. This is not correct.
In regard to R2.1, the clause 7.2.2.2 of the IEEE Std 2800 includes an exception when negative-sequence voltage is higher than certain
threshold for a given time duration. Why the SDT not include this exception in the PRC-029?
In regard to R2.2, it appears the intent is to require that inject balanced current, during symmetrical faults, and unbalanced current during
asymmetrical faults. However, the language is confusing. First, there is no plant level voltage regulation during a fault condition. Second, during
unbalanced faults, what does a voltage regulation mean? One option is replace both Part 2.2.1 and Part 2.2.2 with following: The IBR shall
inject current based on voltage deviation on high-side of main power transformer and as specified by the TP, PC, RC, or TOP.
In regard to R2.3,this requirement is confusing. Table 1 and 2 in Attachment 1 includes both low- and high-voltage thresholds. One meaning
could be that the IBR shall not cause voltage to exceed LVRT threshold for a specified time duration. The true meaning is unclear. Is it correct
that the intent is to focus on HVRT thresholds and time duration? The time duration for voltage > 1.2 per unit is not specified. Does this mean
that IBR shall not cause overvoltage > 1.2 per unit whatsoever? If so, it needs to be written clearly.
In regard toR2.5, if there is no expectation for IBR to ride-through disturbance outside of no-trip zone, then there is no need for this
requirement. For example, if voltage is zero for greater than specified time duration in Tables 1 and 2, say 1 second, then what is the point in
staying connected and feeding into fault unless there is a risk of equipment damage? Additionally, there is no such expectation for frequency
ride-through requirement R4.
R2.5 is not practical for the GO to determine where every individual piece of equipment would be damaged. There is no need to require
tripping just before equipment damage if IEEE 2800 is guidance for equipment manufacturers.
In regard to Attachment 1:
1. There is no mention of continuous, mandatory, or permissive operation region in tables 1 and 2. Consider adding a column in tables 1
2.
3.
4.
5.
6.
and 2 to show these operation regions.
For Table 1 and 2:
o ≥1.20 should be >1.2
o ≥1.1 should be >1.1
o ≥1.05 should be >1.5
In IEEE Std 2800, the cumulative ride-through duration of 1800 second when voltage is > 1.05 is applicable to all nominal voltages
except for 500kV nominal operating voltage. For 500kV nominal operating voltage, the equipment rated to 550kV (1.10 per unit) is
available per ANSI C84.1. In IEEE Std 2800, see Note 1 under Table 12. Consider clarifying this in the PRC-029.
Note 7: A time window of 10-second is mentioned. However, when V>1.05, the ride-through duration is 1800 second, which is over a
3600-second time window in IEEE 2800.
Note 10: The purpose of current blocking in IEEE 2800 was not to protect the equipment but to rather to avoid tripping due to
consequences of injecting current and hence, failure of ride-through.
Figures 1 & 2: why does the X-axis start at 0.1 second and not zero?
Finally, Southern Company supports EEI and NAGF comments.
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Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
No
Document Name
Comment
In 2.1.1 the “apparent power limit” is what is capable during the System disturbance correct? What is the “applicable voltage” to determine
95% in 2.1.2 (and why is per unit not used)? Where are the “requirements specified” by the TP/PC/RC/TOP and how does a GO or TO
determine which one to use? If in the Planning world, the requirements should be specified in the TPL Standards. It is unclear what actions a
TO/GO will take and be consistently applied. Since this is an event driven compliance review in the Operations Assessment time horizon, why
would a TP or PC provide preference for active or reactive power in that timeframe? In a response study by the TP/PC, perhaps guidance on
preference could be provided but it is unclear and NOT required in TPL Standards to this point. Clarity between the Tables and Figures in
Attachment one needs provided to avoid confusion.
Just to be clear, It appears that any new units after the effective date of this Standard have to meet all the criteria. Do the existing units with
limitations have six months after the effective date of Standard to submit equipment limitations. With PRC-024-3 and PRC-024-2 already
having a Requirement in place that requires limitations to be provided to the TP/PC and the industry already leaning on IRO-010 and TOP-003
for notifications, why is there a need to add an additional 6 months for Requirement R6? The RC already has communication capability with
GOs.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer
No
Document Name
Comment
See EEI Comments
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
Document Name
No
Comment
R1:
R1 should be revised to directly clarify, or include a footnote to clarify, the statement “that each IBR remains electrically connected and
continues to exchange current” with “electrically connected, i.e., shall not trip, and continue to exchange current, i.e., shall not enter
momentary cessation” that was provided in the Technical Rationale.
Attachment 1:
There is a discrepancy between the definition of the Term “Mandatory Operating Region” which states “≤ 1.2 per unit” and Table 1/Figure 1
or Table 2/Figure 2 which state “≥1.200” per unit “N/A”. Please clarify if Table 1/Figure 1 and Table 2/Figure 2 should state “>1200” or if
the definition of the Term “Mandatory Operating Region” should state “<1.2 per unit”.
Please clarify Figure 1 and Figure 2 to clearly show the “Continuous Operating Region”, “Mandatory Operating Region”, and “Permissive
Operating Region”, along with requirements beyond 10 seconds.
Please Clarify “9. The IBR may trip for more than four deviations of the applicable voltage….” In attachment 1.
R2.5:
This requirement is beyond the purpose of the standard, which is to establish Frequency and Voltage Ride-through Requirements for Inverter Based Generating Resources and should be removed.
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Dave Krueger - SERC Reliability Corporation - 10
Answer
No
Document Name
Comment
On behalf of the SERC Generator Working Group:
R2.4 does not take into consideration other dynamic system conditions as a result of the fault and the effects they can have on the PPC during
a fault recovery. An example of this is Primary Frequency Response due to system frequency excursions during fault recovery. The active
power recovery may be reduced or frozen during an over-frequency event while an IBR Resource is in recovery, thereby extending the time of
the full recovery.
R2.5: It is not practical for the GO to determine where every individual piece of equipment would be damaged, nor should the GO be required
to subject equipment to failure by trying to identify that point, run to it, and risk damaging it.
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
No
Document Name
Comment
OPG supports IESO’s comments.
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Glen Farmer - Avista - Avista Corporation - 5
Answer
No
Document Name
Comment
EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
EEI also does not support Requirement R2, subpart 2.5 because it contains unneeded language, which adds confusion and implies that GOs can
only trip outside of the trip zone if their equipment might become damaged. This has never been an obligation for synchronous generators,
and we do not agree that this should be an obligation for IBRs. If NERC or the SDT believe that the no-trip zone needs to be expanded, they
should justify such a change and present it for industry review and comment, otherwise, Requirement R2, subpart 2.5 should be deleted.
And while we support Requirement R6 and the provisions to notify PCs, TPs and RC about equipment limitations that would prevent an
applicable IBR from meeting ride‐through requirements as detailed in Requirements R1 and R2, the Requirement does not go far enough
because there may be technical reasons why an applicable IBR is unable to meet Requirement R3 through R5, as well. To address this concern,
R6 should be expanded to include Requirement R1 through R5.
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David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
No
Document Name
Comment
Vistra agrees with Invenergy
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
No
Document Name
Comment
Minnesota Power (MP) agrees with the MRO NSRF’s comments on R1, R2, and R6, and the associated graphics from Attachment 1.
Additionally, MP notes that language from the Technical Rationale document specifies that R2.1, R2.3, and R2.4 are intended to apply when
system conditions return to the Continuous Operation Region from the Mandatory or Permissive Operation regions. This should be specified in
the standard.
Finally, MP proposes the following language changes to eliminate any possible uncertainty:
Section 2.1: “current or apparent power limit” to “current limit or apparent power limit”
Section 2.4: “pre-disturbance or available level” to “pre-disturbance level or available level, whichever is lesser”
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Alison MacKellar - Constellation - 5
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Document Name
Comment
No
Constellation does not agree and feels the HVRT times are very high. Many wind turbines/inverters won't be able to meet those times,
equipment in general and these systems have not been designed to withstand that much overvoltage.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
For R6, R3,R4,R5 should be included as well for the documented limitation communication (see R6 comments below)
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Daniel Gacek - Exelon - 1
Answer
No
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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Imane Mrini - Austin Energy - 6, Group Name Austin Energy
Answer
Document Name
Comment
No
AE supports comments provided by Texas RE and the NAGF
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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
EEI also does not support Requirement R2, subpart 2.5 because it contains unneeded language, which adds confusion and implies that GOs can
only trip outside of the trip zone if their equipment might become damaged. This has never been an obligation for synchronous generators,
and we do not agree that this should be an obligation for IBRs. If NERC or the SDT believe that the no-trip zone needs to be expanded, they
should justify such a change and present it for industry review and comment, otherwise, Requirement R2, subpart 2.5 should be deleted.
And while we support Requirement R6 and the provisions to notify PCs, TPs and RC about equipment limitations that would prevent an
applicable IBR from meeting ride‐through requirements as detailed in Requirements R1 and R2, the Requirement does not go far enough
because there may be technical reasons why an applicable IBR is unable to meet Requirement R3 through R5, as well. To address this concern,
R6 should be expanded to include Requirement R1 through R5.
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Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
No
Document Name
Comment
R1/R2: Recommend that Attachment 1 have a chart to include the Continuous Operation Region, Mandatory Operation Region, and Permissive
Operation Region or have those regions specified on existing Voltage Ride -through Requirements Figure 1 and Figure 2.
Requests the SDT review and align the data in Attachment 1 so the data in Tables 1 and 2 aligns with what is shown in Figures 1 and 2.
Currently, the graphs in Figures 1 and 2 do not match what is indicated in the Tables.
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
No
Document Name
Comment
Duke Energy recommends the implementation of EEI and NAGF comments.
Duke Energy does not agree that the language is clear. The language seems close to but not completely in alignment with IEEE 2800-2022. It is
not clear that the -029 requirements align with the IEEE 2800 requirements, especially given that most would want to comply with both. Many
times the Continuous Operation Region is associated with the voltage regulation function and the Mandatory Operation Region is associated
with LVRT. This separation is not maintained in various statements within 2.1 and 2.2. It is not clear how the plant or inverters can be
configured to operate as specified in R2. Overall the language seems overly prescriptive and the DT may consider less specificity and possibly
even a reference to IEEE 2800 rather than trying to restate it. Voltage regulation functions are typically based on POI voltage while LVRT
functions are based on inverter terminal voltage. It is not clear that the requirements recognize this difference.
Also, there are multiple references in R1 and R2 to Attachment 1 containing or representing the various Regions, but they are not graphically
represented. The DT may consider revising the Att. 1 Figures (and moving the vertical axis crossing to 0.1 sec).
tt seems the industry has often misinterpreted the area outside of the No-trip Zone as an area where the plant must trip. The DT may consider
specifically addressing and emphasizing in the text and on the Figure that the plant is not required to trip in this area. For example, it may be
labeled May Trip Zone. To that end, it would also be helpful for the GO to submit equipment ride through limits. That is the actual equipment
limits, not the various voltage protection settings. With that information, plants would have the bases to provide the maximum ride-through
beyond the No-Trip Zone and still not exceed plant main and BOP equipment limits.
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Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
Document Name
Comment
No
WEC Energy Group does not agree that the language in R1, R2, and R6 is clear for the following reasons:
R1.:
WEC disagrees with text “… shall ensure that each IBR remains connected…”. How else can an entity “ensure” to remain connected other than
to set voltage protection outside the no-trip zone? The requirement must state what must be done. Based on Attachment 1, this is clearly
voltage protection settings function so R1 should try and match PRC-024 R1. Otherwise, this requirement is open-ended as IBR could
potentially be disconnected due to other reasons and the entity will be deemed non-compliant.
The “main power transformer” should be defined in a footnote, similar to what’s proposed in PRC-028. It’s unclear if main power transformer
represents individual IBR step-up transformer or the site step-up transformer.
The phrase “exchange current” should be listed and defined in Terms section. Confusion exists in understanding if “exchange current” applies
to BESS while charging, real/reactive current components, or something else. An exception should be added to exclude BESS from the PRC-029
requirements while charging.
WEC also disagrees with M1. The only means for an entity to “ensure IBR remains connected” is to set voltage protection and voltage ridethrough protection according to Attachment 1. Making sure that the settings are applied should be the measure. The “recorded data” is an
inconclusive statement. If the entity applied settings outside the no-trip zone and it still tripped, which could be for various other reasons,
does that mean then entity is non-compliant? What needs to be recorded and where? Does this measure now mandate additional recording
capabilities in addition to PRC-030? (Same comment applies to M2, M3, and M4).
R2.:
WEC disagrees with text “…. shall ensure that each IBR remains connected…”. The requirement must state what TO and GO must do.
Otherwise, this requirement is open-ended without a measurable statement.
2.1: Term “Continuous Operating Region” as defined conflicts with equipment design limitations. Power transformers may not be designed for
continuous operations from 0.9 and 1.1 pu. Please refer to IEEE C57.12.00, sections 4.1.6.1, 4.1.6.2 and 5.5, and ANSI C84.1. Without some
specific maximum time applied, the continuous operating region will conflict with equipment limitations. Due to this wide range, entities will
simply take exception to R2 and R2 will not have any positive benefit for BES reliability. There is a reason PRC-024-3 has a 4 second limit. This
limitation should clearly be introduced in PRC-029. Finally, the proposed “Continuous Operating Region” range conflicts with acceptable
continuous operating ranges by Transmission Operators. Many Transmission Operators classify continuous operating range from 0.95 and 1.05
pu, and consider voltage ranges from 0.9 to 0.95 pu and 1.05 to 1.1 pu as abnormal voltage ranges.
2.1.2: There is nothing that governs a TP, PC, RC or TO to specify active/reactive power prioritization.
2.3: This requirement is inconclusive. The requirement must state what TO and GO must do. Otherwise, this requirement is open-ended
without a measurable statement. Something regarding “IBR gain” was briefly mentioned during the PRC-029 webinar. A wide spectrum of
gains and tuning parameters exist within the IBR controls. The requirement must state what parameters are to be addressed and how to set
them. Gains and tuning parameters are covered in MOD-026 and MOD-027 standards and shall not be introduced here. Another potential
issue could be with AVR function within the power plant controller. AVR/PPC failure could potentially cause higher voltage outputs. AVR
failure, or any equipment failure, should not be the criteria to violate the standard. WEC recommends this requirement be removed.
2.4: WEC owns and operates multiple IBR sites and it is in our experience that the limitation to the 1 second requirement will come from the
power plant controller. The ramp rate capabilities of the power plant controllers are far slower than inverter ramp rates and are typically in
minutes range. WEC also had an instance where the power plant controller ramp rate increase was denied by the Transmission
Operator/Planner.
2.5: This requirement contradicts the meaning of established No-Trip zone. If the No-Trip zone is inadequate, then SDT should evaluate and
adjust it accordingly. In addition, having protection settings applied right at the equipment damage curve is not a standard protection practice,
especially if events such as voltage excursions have a cumulative effect on insulation degradation that could lead to premature failures. WEC
recommends this requirement be removed.
R6.: This requirement should include and cover equipment limitations associated with R3, R4, and R5.
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF provides the following comments:
a.
Requirement R1 - the NAGF request clarification on the term “exchange” being used in the proposed language for Requirement R1.
b. Requirement R2 – the Terms section identified the terms: Continuous Operating Region, Mandatory Operating Region, and Permissive
Operating Region but these terms are not specifically referenced in the tables for Attachment 1. The NAGF believes that the regions should be
included in Attachment 1 for clarity.
c. The PRC-029-1 draft remains silent on the network condition, so it is unclear how to model the transmission system to test compliance with
these requirements. One option is to assume that the transmission grid at the point of interconnection may be modeled as an ideal voltage
source. Another option is to model the transmission grid as a voltage with a Thevenin impedance based on a short circuit ratio (minimum and
maximum), which would consider the network condition at the point of interconnection. The NAGF requests clarity on this topic regarding
testing compliance.
d. The requirement stated in R2.4 for IBRs to restore active power to the pre-disturbance or available level within 1.0 second when voltage at
high-side of the main power transformer returns to Continuous Operation Region. Based on the TO studies or requirements, it is recommended
that flexibility be allowed in the recovery time requirement. For example, if studies indicate that a slower ramp-rate and/or pause in the power
ramp-up is beneficial then that should be allowed. The NAGF also recommends an active power recovery threshold of 90% of pre-disturbance
level to account for measurement and IBR unit control uncertainties and tolerances.
e. The requirement stated in R2.1.1 must allow IBRs apparent power to be limited if the voltage is outside the normal operating range and the
IBR units have reached their maximum current limit.
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Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
No
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of its members:
EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
EEI also does not support Requirement R2, subpart 2.5 because it contains unneeded language, which adds confusion and implies that GOs can
only trip outside of the trip zone if their equipment might become damaged. This has never been an obligation for synchronous generators,
and we do not agree that this should be an obligation for IBRs. If NERC or the SDT believe that the no-trip zone needs to be expanded, they
should justify such a change and present it for industry review and comment, otherwise, Requirement R2, subpart 2.5 should be deleted.
And while we support Requirement R6 and the provisions to notify PCs, TPs and RC about equipment limitations that would prevent an
applicable IBR from meeting ride‐through requirements as detailed in Requirements R1 and R2, the Requirement does not go far enough
because there may be technical reasons why an applicable IBR is unable to meet Requirement R3 through R5, as well. To address this concern,
R6 should be expanded to include Requirement R1 through R5.
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Joy Brake - Nova Scotia Power Inc. - NA - Not Applicable - NPCC
Answer
Document Name
Comment
Concerns are covered other commenters.
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No
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Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3 - WECC
Answer
No
Document Name
Comment
PNM agrees with the comments of EEI.
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
No
Document Name
Comment
R2.1/2.2
This states that the TO is who decides whether Active or Reactive Power is prioritized when a limit is reached. IBR sites will curtail real power to
meet the reactive power request from the controllers.
R2.4
This section would depend on the ramp rate of the units, 1.0 seconds seems extreme
M2
Will the PC's be communicating in writing to the Generator Owner every time there is a disturbance with the request for this data. How long
will the data need to be held?
R4
5 hz/second is not a reasonable rate
M4
Will the PC's be communicating in writing to the Generator Owner every time there is a disturbance with the request for this data. The
retention period for data is not defined.
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
No
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and North American Generator Forum
(NAGF) on question 2
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
No
Document Name
Comment
Dominion Energy supports EEI comments. In addition, Dominion Enetgy has the following comments:
R2, Section 2.1 refers to the Continuous Operation Region as specified in Attachment 1; however the definition of Continuous Operating
Region at the beginning of the standard is only applicable to voltages, measured at the high-side of the MPT that are between 0.9 PU and 1.1
PU. Does this mean that the definition of Continuous Operation Region is different from Continuous Operating Region? Or is the intent the
same as the definition at the front of the standard and the “tion” should be changed to “ting”? Please clarify. This disconnect also exists in R2
and in R2.2.
R2, Section 2.1.2 and R2.4 both allude to a requirement for either the Transmission Planner, Planning Coordinator, Reliability Coordinator or
Transmission Operator to provide a preference of active or reactive power if an IBR cannot deliver both due to a current or apparent power
limit. The standard is not applicable to any of these listed entities and thus puts an administrative burden on the Generator Owner to contact
each to determine a preference. Four entities determining the preference is three too many. A new requirement should be written directing
one of the four entities to be the lead point of contact for the GO. Additionally, the standard should specify that the lead entity charged with
determining the preference of active of reactive power should communicate the preference a minimum of 6 months prior to the effective date
for the GO. The GO cannot put controls in place and ensure compliance until the TP, PC, RC or TOP has documented the compliance
requirement.
R6, Section 6.2 is confusing since the Technical Rationale and FERC Order 901 Directives, Paragraph 193 states that “when the existing
equipment is replaced, the exemption would no longer apply, and the new equipment must comply with the appropriate IBR performance
requirements”. Further, FAC-002-5 considers replacement of inverters / converters or Power Plant Controllers to be “qualified changes” and
would require a study before implementation. This section seems to be an unnecessary administrative step, since the FAC-002 process would
require submittal of “as-built settings” for the qualified change study.
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George E Brown - Pattern Operators LP - 5
Answer
No
Document Name
Comment
Pattern Energy supports GRE’s comments for this question.
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Kimberly Turco - Constellation - 6
Answer
No
Document Name
Comment
Constellation does not agree and feels the HVRT times are very high. Many wind turbines/inverters won't be able to meet those times,
equipment in general and these systems have not been designed to withstand that much overvoltage.
Kimberly Turco on behalf of Constellation Segments 5 and 6
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Ruchi Shah - AES - AES Corporation - 5
Answer
No
Document Name
Comment
1 The language “continues to exchange current” in R1 is not clear, please explain.
OEMs have not been forthcoming with operating limit data/equipment trip capabilities. Due to the lack of information from OEMs, we are
2
concerned that the following language in R2.5 will be difficult to comply with: “Each IBR shall only trip to prevent equipment damage, when the
voltage at the high‐side of the main power transformer is outside of the no‐trip zone as specified in Attachment 1”.
3 The SDT should consider equipment where the manufacturer is not able to provide the limits where equipment damage can occur. For
legacy equipment, this information may not be available or may be available at a very high cost to the GO. These scenarios should be included
as limitations.
4·
Charts in Attachment 1 should be updated to graphically show the performance regions
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Rhonda Jones - Invenergy LLC - 5
Answer
No
Document Name
Comment
No, Invenergy disagrees that the language within PRC-029-1 requirements R1, R2, and R6 is clear. Specifically, we offer the below comments
regarding these requirements:
R2.1.1.: As currently drafted, R2.1.1. seems to ignore the changes to apparent power limits that could occur during a System disturbance. We
recommended the following language:
“R2.1.1. Continue to deliver the pre-disturbance level of active power or available active power, whichever is less, and continue to deliver
active power and reactive power up to the total aggregated current rating of the IBR Units in the plant.”
R2.1.2.: Invenergy is concerned that the language in R2.1.2. regarding the active power or reactive power preferences of TPs, PCs, RCs, or TOPs
may lead to increased confusion and unintended consequences. In its place, we recommend adopting something similar to the p/q/v capability
curve demonstrated in Figure 8 of IEEE 2800-2022.
R2.3.: It is unclear to us what R2.3. is requiring. Please clarify or remove.
R2.4.: The ramp rate should be based on System needs; in weaker grid conditions such rapid ramping of active power could lead to poweroscillations or small-signal instability.
R2.5.: This requirement is not auditable and is beyond the scope of the standard, which is to establish certain minimum ride-through
requirements. As written, R2.5. suggests GOs should push their equipment as near to its breaking point as possible, even after the minimum
ride-through requirements have been met. Thus, we ask R2.5. and similar statements throughout the draft standard be removed.
R6.: Given the technical limitations of many legacy IBRs, R6 must be thoroughly amended to allow exemptions for limitations related to
frequency, rate-of-change-of-frequency, and phase angle change ride-through requirements. Consider that there are a range of possible
concerns with legacy equipment and equipment already in commercial operation. At one end of the spectrum there exists legacy equipment
where the manufacturer is no longer in business, or no longer produces the given IBR unit technology. In these cases, it is often infeasible to
either truly document all aspects of the equipment limitations or to attempt to make any software or hardware modifications. At the other end
of the spectrum there exists equipment that has been installed in recent years where software modifications may be enough to bring the units
into compliance with the proposed requirements, after proper due-diligence and analyses have been performed. In between these two ends of
the spectrum there is a range of possibilities.
Where available, software-only modifications are the most likely to yield meaningful reliability improvements where they are most needed
while being technically and financially feasible for legacy IBRs to deploy. Indeed, the vast majority of performance issues identified with solar
PV resources involved in the 2021 and 2022 Odessa disturbances (and other solar PV resources with the same inverter make/model that were
not involved in the Odessa events) are being addressed in ERCOT with software-based modifications (see
https://www.ercot.com/files/docs/2024/03/06/Odessa%20Update_03082024.pptx).
Thus, R6 needs a thorough rewrite to give due consideration, and acknowledgement, to these various nuances. Invenergy proposes the below
modifications:
R6. Each Generator Owner and Transmission Owner with an applicable IBR that is in commercial operation prior to the effective date of this
standard that is unable to meet the ride-through performance requirements detailed in Requirements R1 through R5 shall document the
limitation, communicate each equipment limitation to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability
Coordinator(s), and provide a plan for making reasonable software and settings modifications that reduce or remove the limitation, if available
and feasible.
6.1. Each Generator Owner and Transmission Owner shall include in its documentation, in each case as is available or can be
reasonably obtained:
6.1.1. Identifying information of the IBR (name, facility #, other)
6.1.2. Current ride-through capability
6.1.3. Known ride-through limitations and documentation of such limitations
6.1.4. Reasonable software and settings modifications
6.1.5. Expected post-modification ride-through capability and documentation of any expected remaining limitations following
implementation of such modifications
6.1.6. A schedule for implementing the modifications
6.2. Each Generator Owner and Transmission Owner with a previously communicated equipment limitation that makes a
modification that reduces or removes such limitation shall document and communicate such modification to the associated Planning
Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s) within 30 days of the modification.
To supplement the language regarding reasonable software and settings modifications, the following language could be added to the Technical
Rationale: Reasonable software and settings modifications are any available technically feasible modifications involving only software,
firmware, settings, or parameterization changes that do not require physical modification of the IBR equipment and are reasonably priced.
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0
Response
David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
No
Document Name
Comment
Ameren agrees with EEI's comments.
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0
Response
Colin Chilcoat - Invenergy LLC - 6
Answer
No
Document Name
Comment
No, Invenergy disagrees that the language within PRC-029-1 requirements R1, R2, and R6 is clear. Specifically, we offer the below comments
regarding these requirements:
R2.1.1.: As currently drafted, R2.1.1. seems to ignore the changes to apparent power limits that could occur during a System disturbance. We
recommended the following language:
“R2.1.1. Continue to deliver the pre-disturbance level of active power or available active power, whichever is less, and continue to deliver
active power and reactive power up to the total aggregated current rating of the IBR Units in the plant.”
R2.1.2.: Invenergy is concerned that the language in R2.1.2. regarding the active power or reactive power preferences of TPs, PCs, RCs, or TOPs
may lead to increased confusion and unintended consequences. In its place, we recommend adopting something similar to the p/q/v capability
curve demonstrated in Figure 8 of IEEE 2800-2022.
R2.3.: It is unclear to us what R2.3. is requiring. Please clarify or remove.
R2.4.: The ramp rate should be based on System needs; in weaker grid conditions such rapid ramping of active power could lead to poweroscillations or small-signal instability.
R2.5.: This requirement is not auditable and is beyond the scope of the standard, which is to establish certain minimum ride-through
requirements. As written, R2.5. suggests GOs should push their equipment as near to its breaking point as possible, even after the minimum
ride-through requirements have been met. Thus, we ask R2.5. and similar statements throughout the draft standard be removed.
R6.: Given the technical limitations of many legacy IBRs, R6 must be thoroughly amended to allow exemptions for limitations related to
frequency, rate-of-change-of-frequency, and phase angle change ride-through requirements. Consider that there are a range of possible
concerns with legacy equipment and equipment already in commercial operation. At one end of the spectrum there exists legacy equipment
where the manufacturer is no longer in business, or no longer produces the given IBR unit technology. In these cases, it is often infeasible to
either truly document all aspects of the equipment limitations or to attempt to make any software or hardware modifications. At the other end
of the spectrum there exists equipment that has been installed in recent years where software modifications may be enough to bring the units
into compliance with the proposed requirements, after proper due-diligence and analyses have been performed. In between these two ends of
the spectrum there is a range of possibilities.
Where available, software-only modifications are the most likely to yield meaningful reliability improvements where they are most needed
while being technically and financially feasible for legacy IBRs to deploy. Indeed, the vast majority of performance issues identified with solar
PV resources involved in the 2021 and 2022 Odessa disturbances (and other solar PV resources with the same inverter make/model that were
not involved in the Odessa events) are being addressed in ERCOT with software-based modifications (see
https://www.ercot.com/files/docs/2024/03/06/Odessa%20Update_03082024.pptx).
Thus, R6 needs a thorough rewrite to give due consideration, and acknowledgement, to these various nuances. Invenergy proposes the below
modifications:
R6. Each Generator Owner and Transmission Owner with an applicable IBR that is in commercial operation prior to the effective date of this
standard that is unable to meet the ride-through performance requirements detailed in Requirements R1 through R5 shall document the
limitation, communicate each equipment limitation to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability
Coordinator(s), and provide a plan for making reasonable software and settings modifications that reduce or remove the limitation, if available
and feasible.
6.1. Each Generator Owner and Transmission Owner shall include in its documentation, in each case as is available or can be
reasonably obtained:
6.1.1. Identifying information of the IBR (name, facility #, other)
6.1.2. Current ride-through capability
6.1.3. Known ride-through limitations and documentation of such limitations
6.1.4. Reasonable software and settings modifications
6.1.5. Expected post-modification ride-through capability and documentation of any expected remaining limitations following
implementation of such modifications
6.1.6. A schedule for implementing the modifications
6.2. Each Generator Owner and Transmission Owner with a previously communicated equipment limitation that makes a
modification that reduces or removes such limitation shall document and communicate such modification to the associated Planning
Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s) within 30 days of the modification.
To supplement the language regarding reasonable software and settings modifications, the following language could be added to the Technical
Rationale: Reasonable software and settings modifications are any available technically feasible modifications involving only software,
firmware, settings, or parameterization changes that do not require physical modification of the IBR equipment and are reasonably priced.
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0
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Brittany Millard - Lincoln Electric System - 5
Answer
No
Document Name
Comment
A review of the data in Attachment 1 and Tables 1 and 2 should be performed so that they align. Currently, the graphs in Figures 1 and 2 do not
match what is indicated in the Tables.
We would recommend a part be added to the standard to directly address the Permissive Operating Region, similar to what is done in Part 2.1
(for Continuous Operation Region) and Part 2.2 (for Mandatory Operation Region) as, if left unaddressed, is unclear. For example, there should
be some linkage between the body of the standard and Attachment 1, item 10. The following language is provided for consideration (new Part
2.3):
2.3 While voltage at the high‐side of the main power transformer is within the Permissive Operation Region as specified in Attachment 1, an
IBR may operate in current block mode only if necessary to protect the equipment. Otherwise, each IBR shall follow the requirements for the
Mandatory Operation Region in Requirement R2.2.
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0
Response
Ben Hammer - Western Area Power Administration - 1
Answer
No
Document Name
Comment
Plese review and align the data in Attachement 1 so that data in Tables 1 & 2 align with Figures 1 & 2.
Also, it is recommended a part be added to the standard to directly address the Permissive Operating Region, similar to what is done in Part 2.1
(for Continuous Operation Region) and Part 2.2 (for Mandatory Operation Region) as, if left unaddressed, is unclear. For example, there should
be some linkage between the body of the standard and Attachment 1, item 10. See the following proposed language for consideration (new
Part 2.3):
2.3 While voltage at the high‐side of the main power transformer is within the Permissive Operation Region as specified in Attachment 1, an
IBR may operate in current block mode only if necessary to protect the equipment. Otherwise, each IBR shall follow the requirements for the
Mandatory Operation Region in Requirement R2.2.
OPTION A.
Requirement R6 provides an overly broad exemption as written as the standard is silent as to what criteria must be met. Only notification to
other reliability entities is required with no requirement to develop and implement a Corrective Action Plan. The SDT should consider:
•
•
Develop more specific criteria as to what qualifies as an equipment limitation[1], OR
Require exemptions be submitted to NERC and/or the Regional Entities for approval in order to qualify for the exemption.
OPTION B.
Leave R6 as written, apply R6 to R1 through R5.
it is recommended that there be no requirement to document limitations on legacy equipment and that this standard focuses on equipment
brought into service after the implementation date.
R2: We agree with the present flexibility that some of the IBR VRT performance could be modified to meet the individual system needs by the
applicable Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator. However, some clarity may be
required on how this process is initiated and what type is evidence is required to demonstrate request is received and implemented. This may
be an additional requirement assigned to the Transmission Planner. Each Transmission Planner, Planning Coordinator, and Transmission
Operator that jointly specifies the following voltage ride-through performance requirements within their area(s) different than those specified
under R2, shall make those requirements available to each associated applicable IBR Generator Owner and Transmission Owner
[1] See Implementation Plan (page 4), i.e. “only those IBR that are unable to meet voltage ride-through requirements due to their inability to
modify their coordinated protection and control settings may be considered for potential exemption.” See Technical Rationale (page 9); i.e.
specify which voltage band(s) and associated duration(s) cannot be satisfied or specific as to the number of cumulative voltage deviations within
a ten‐second time period that the equipment can ride‐through if less than four… identify the specific equipment and explain the characteristic(s)
of that equipment that prevent ride‐through.
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
We believe that language needs to be added to M1, similar to that provided in the other Measures, to specify the initiating event that triggers
the requirement for R1 evidence of compliance.
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0
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0
Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
No
Document Name
Comment
Black Hills Corporation supports EEI’s and NAGF’s comments. Additionally, Black Hills Corporation has concerns regarding event-based
“Measures” for Requirement R2, R3, R4 and R5 as GO will likely not have immediate knowledge of “System disturbance” or other transmission
system events (transient overvoltage due to switching, frequency excursion, instantaneous positive sequence voltage phase angle changes)
when they occur and data collection systems have a limited amount of storage capacity (i.e. data overwrite happens over time, in our case,
data is retained for a rolling 12 months). If available data remains the “Measure” for demonstrating compliance, then consideration needs to
be given to when and how GO are notified of an event, so data can be reviewed and archived for future demonstration of compliance.
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0
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0
Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
No
Document Name
Comment
FirstEnergy finds 2.4 requesting the return to of the Active Power is restrictive and needs to be inclusive of Reactive Power due to voltage
response.
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0
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0
Response
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
No
Document Name
Comment
AECI supports comments provided by the NAGF
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0
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0
Response
Brian Lindsey - Entergy - 1
Answer
No
Document Name
Comment
•
2.1.2 refers to requirements specified by the TP, TOP, PC, RC. It is unclear what the expectation is if those requirements have not been
defined.
•
Is 2.2.2 is stating that the IBR shall maintain reactive power per default setpoints unless a new reactive setpoint has been requested or
it’s been requested to maintain a certain active power? Why wouldn’t this be worded similarly to the sub-bullets in 2.1?
•
2.3: if the IBR is already responding to Mandatory or Permissive Operation regions (exceedances of Attachment 1 Table 1 or Table 2),
how could it then cause an exceedance?
•
R2.4 There is concern that the controls will be either unable to respond within the 1 second timeframe, or that the historical records
to prove the response would not have the resolution to be meaningful.
•
R 2.5: How would someone prove that an IBR tripped only to prevent equipment damage? This sub-bullet cannot be enforced.
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0
Response
Helen Lainis - Independent Electricity System Operator - 2
Answer
No
Document Name
Proposed change to table Q2.PNG
Comment
The IESO recommends the following modifications to the text improve clarity or to better convey intent.
With regards to R1:
“…as specified in Attachment 1 unless not doing so is needed to clear a fault or a documented and communicated equipment limitation exists
in accordance with Requirement R6.”
With regards to M1:
“…demonstrating adherence to ride‐through requirements, as specified in Requirement R1, or shall have evidence of a documented and
communicated equipment limitation, as specified in Requirement R6.”
With regards to R2:
“…each IBR’s voltage performance adheres to the following, unless a documented and communicated equipment limitation exists…”
With regards to 2.1: (and Tables 1 & 2, Figures 1 & 2):
There appears to be inconsistency between the definition of ‘Continuous Operation Region’, the Minimum Ride-Through Time values stated in
Tables 1 & 2, and the plots in Figures 1 & 2.
It seems the intent is to have ‘continuous’ operation between 95% and 105% voltage, and a minimum ride-through time of at least 1800
seconds (half an hour) when voltage is above 105% and not exceeding 110%. If it is really required that equipment must be able to operate
continuously at voltages up to 110%, then the tables and plots should be labelled with a descriptor that implies indefinite operation is required
(i.e., continuous) rather than a minimum time (1800 seconds). For example, a version of Table 2 that achieves what seems to be intent could
look like the following:
See file attached - Proposed change to table Q2
With regards to 2.5:
The IESO believes the principle of tripping only when necessary (i.e., to clear faults and to prevent equipment damage during disturbances) is
important enough that it warrants a dedicated requirement. With regards to tripping during over-voltages, this principle of only tripping for
equipment protection purposes may apply equally to system disturbances discussed in R2 and to switching transients as discussed in R3
(tripping for equipment protection is not presently addressed in R3, though is acknowledged in the Technical Rationale document).
With regards to R6:
The IESO suggests there should be explicit requirements to both ‘document equipment limitations’ and to ‘communicate’ those documented
limitations to the appropriate parties. The following modifications are proposed:
“Each Generator Owner and Transmission Owner with a known equipment limitation that would prevent an applicable IBR that is in‐service by
the effective date of this standard from meeting voltage ride‐through requirements as detailed in Requirements R1 and R2 shall document
each equipment limitation and communicate it to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability
Coordinator(s).
With regards to M6:
Each Generator Owner and Transmission Owner shall have evidence of known equipment
limitations, as specified in Requirement R6, having been documented and communicated to each associated Planning Coordinator,
Transmission Planner, and Reliability Coordinator prior to the effective date of PRC‐029‐1.
Each Generator Owner and Transmission Owner with changes to equipment shall have evidence of communication to each associated Planning
Coordinator, Transmission Planner, and Reliability Coordinator.
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1
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Ontario Power Generation Inc., 5, Chitescu Constantin
0
Response
Jennie Wike - Jennie Wike On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma
Power
Answer
No
Document Name
Comment
Tacoma Power does not agree that the language in the applicability section of PRC-029-1 is clear. The applicable facilities language in Section 4
is vague and difficult for entities to understand what is in scope of the Standard. Specifically, the term "BPS IBR" is broad and would encompass
all transmission connected IBRs, regardless of size or interconnection voltage. Additionally, the language and formatting of the applicability
sections in PRC-028, PRC-029 and PRC-030 are not consistent. These three Standards apply to the same facilities, and therefore, should use the
same language. Tacoma Power recommends that Section 4 of PRC-029 and PRC-030 should be revised to align with the language proposed in
Section 4 of PRC-028, as follows:
4.1. Functional Entities:
4.1.1. Transmission Owner that owns equipment as identified in section 4.2
4.1.2. Generator Owner that owns equipment as identified in section 4.2
4.2. Facilities: The Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or
contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
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1
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JEA, 1, McClung Joseph
0
Response
Leah Gully - Madison Fields Solar Project, LLC - 5 - RF
Answer
No
Document Name
Comment
See "additional comments" for details
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0
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0
Response
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
2020-02_EPRI Comments on Draft NERC PRC-029 (IBR ride-through) Reliability
Standard.pdf
Comment
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0
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Response
0
Michael Goggin - Grid Strategies LLC - 5
Answer
No
Document Name
Comment
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0
Dislikes
0
Response
David Campbell - David Campbell On Behalf of: Natalie Johnson, Enel Green Power, 5; - David Campbell
Answer
No
Document Name
Comment
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0
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0
Response
Carey Salisbury - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer
No
Document Name
Comment
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0
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0
Response
Ryan Quint - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable, Group Name Elevate Energy Consulting
Answer
Document Name
Comment
Yes
Yes. The SDT should consider citing IEEE 2800-2022 directly in the standard and consider using the IEEE 2800-2022 ride-through requirements
as a means to comply with Requirements R1-R5 instead of using Attachment 1 of the standard.
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0
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0
Response
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Yes
Document Name
Comment
Remove from R1 "and operation regions" since this is already required in R2.
Move R2.5 to a sub-requirement of R1, since R1 is the no-trip requirement not R2.
R2.5 should read be rearranged to be more clear, "When the voltage at the high-side of the main power transformer is outside of the no-trip
zone as specified in Attachment 1, each IBR shall only trip to prevent equipment damage."
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0
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0
Response
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer
Yes
Document Name
Comment
SRP believes the language in R1 and R2 provides clear expectations of how IBR controls should behave during short circuit events.
Likes
0
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Response
0
Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst
Ballot Body Member and Proxies
Answer
Yes
Document Name
Comment
While the language is clear, the SDT explains in the draft PRC-029-1 Technical Rationale that “An IBR becomes noncompliant with PRC‐029 only
when an event in the field occurs that shows that one or more requirements were not satisfied.” See Question 4 comment for RF’s concerns
with this approach.
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0
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0
Response
Stefanie Burke - Portland General Electric Co. - 6
Answer
Yes
Document Name
Comment
PGE supports EEI’s comments
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0
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0
Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
Since the evidence needed is the actual recorded data, we only need it when there’s an actual event that happened in the system. What if after
the event, we found out that we are not compliant? What can we do to ensure compliance? Please add more clarification about the evidence
requirements.
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0
0
Response
Wesley Yeomans - New York State Reliability Council - 10
Answer
Yes
Document Name
Comment
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0
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0
Response
Katrina Lyons - Georgia System Operations Corporation - 4
Answer
Yes
Document Name
Comment
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0
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0
Response
Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
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0
Dislikes
0
Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Yes
Comment
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0
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0
Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District,
3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Tim Kelley, Group Name SMUD and BANC
Answer
Yes
Document Name
Comment
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0
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0
Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
Likes
0
Yes
Dislikes
0
Response
Wendy Kalidass - U.S. Bureau of Reclamation - 5
Answer
Document Name
Comment
Not Applicable to Reclamation.
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0
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0
Response
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer
Document Name
Comment
BC Hydro appreciates the drafting team’s efforts and the opportunity to comment, and offers the following:
1. Requirement R2 Part 2.1.2 appears to set an additional Requirement for TP, PC, RC, or TOP to specify requirements for scenarios where an
IBR cannot deliver both active and reactive power when the voltage is within the Continuous Operating Region and below 95%. BC Hydro
recommends that if these are intended as mandatory or deemed as a necessary input for the IBR Owner/Operator, then these should be
codified as standalone Requirement(s) against the appropriate functional entities (TP, PC, RC, or TOP suggested by the current draft).
2. The VSL Table for Requirement R1 does not reflect the allowance of a documented limitation. As drafted, it implies that a Severe VSL will be
assessed in spite of a preexisting and documented equipment limitation. BC Hydro recommends that the wording be revised to clarify the
compliance expectations when evaluating IBR performance.
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0
3. Do you agree with the drafting team’s proposals for including IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage
phase-angle jump ride-through performance criteria in PRC-029-1 Requirements R3, R4, and R5?
Thomas Foltz - AEP - 5
Answer
No
Document Name
Comment
Designing an IBR plant for transient over-voltage ride-through compliance is complicated by separation of the IBR Units from MPT high side by
the non-aggregated collector system including the MPT itself, frequency dependence of the collector system, GSU (i.e., pad mount
transformers) and MPT transformer saturation, and surge arrestors on the collector system. DFRs triggered on TOV are essential for
monitoring compliance.
Assessing IBR plant phase jump ride-through is dependent on being able to trigger DFR records on non-fault line switching events. Also, as the
standard is now written, phase angle jump of any magnitude during a fault must be ridden through and it does not seem possible to determine
if a ride-through failure is caused by a fault-caused phase jump exceeding 25 degrees (in which case the IBR could be compliant), or if instead
there is a true non-conformity with R1. AEP is not aware if anything can be done about this, but it may be a minor point in most practical
situations.
Regarding R4, the technical rationale supporting the standard seems to neglect the possibility of torsional interaction between the wind
facilities where sub-synchronous control interaction could exist that can result in possible damage to the wind turbine generator shaft.
Therefore, a blanket statement that an inverter-based resource is not affected by off-nominal frequencies may be an assumption that should
warrant further considerations when establishing inverter-based resource, frequency ride through requirements. We believe this is supported
by page 6 of the technical rationale which states “In the case of the non-hydraulic turbine synchronous resources, the turbine is usually
considered to be more restrictive than generator in limiting IBR frequency ride‐through because of possible mechanical resonances in the many
stages of turbine blades. Off‐nominal frequencies may bring blade vibrational frequencies closer to a mechanical resonate frequency and cause
damage due to the vibration stresses. However, inverter‐ interfaced‐IBR does not share this vibrational failure mode.” Furthermore, how should
phase jump be considered in R5 where synch check relay settings are greater than 25 degrees?
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0
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0
Response
Leah Gully - Madison Fields Solar Project, LLC - 5 - RF
Answer
Document Name
No
Comment
See "additional comments" for details
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0
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0
Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
No
Document Name
Comment
Tri-State is concerned with the big jump from 61.8 to 64 under Attachment 3, Table 4. We would like to suggest the ride-through requirement
be at 62 or 63.
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0
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0
Response
Brian Lindsey - Entergy - 1
Answer
No
Document Name
Comment
•
R3:
o
Technical Rationale “High Voltage Ride Through and Low Voltage Ride Through” modes were not clearly defined. “Mode”
implies a specific, programmed, set of actions within controls which may not be real for solar sites.
A GO may not know if a switching event occurs. In that case, how would a GO be expected to determine if the event in
question is a switching event or not? While R6 addresses exemptions for R1 and R2 in the case that equipment or the ability to
record doesn’t exist in an existing site, the same may be of concern for the sub-second requirements listed in R3, 4 and 5. The
same exclusions should be for the entire standard, if applicable.
o
If the Rate of Change of Frequency is 5 Hz/second, there’s concern that the level of calculation needed on parameters that may
not have more than a 1/second resolution would net little reaction.
o
•
•
R4:
R5:
o
Likes
While R6 addresses exemptions for R1 and R2 in the case that equipment or the ability to record doesn’t exist in an existing
site, the same may be of concern for the sub-second requirements listed in R3, 4 and 5. The same exclusions should be for the
entire standard, if applicable.
0
Dislikes
0
Response
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
No
Document Name
Comment
AECI supports comments provided by the NAGF
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0
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0
Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
No
Document Name
Comment
Black Hills Corporation supports NAGF’s and EEI’s comments. Additionally, see “Measures” concern noted above in Q2.
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0
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0
Response
Colin Chilcoat - Invenergy LLC - 6
Answer
Document Name
Comment
No
No, Invenergy disagrees with the proposals for including IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle
jump ride-through performance criteria in Requirements R3, R4, and R5. We offer the below comments regarding these Requirements:
R3: Can the drafting team provide data that demonstrates observed overvoltages during recent System events were of the TOV magnitudes
and durations defined in Attachment 2 Table 3? TOVs of such scale are primarily due to the following three scenarios: 1) a lightning strike on
the nearby transmission system, 2) transmission line switching transients, and 3) resonant phenomena like voltage magnification due to shunt
capacitor switching on the transmission system. Measures are already in place to mitigate such events, including but not limited to proper
insulation coordination and substation design, metal oxide varistors, and proper capacitor bank switching of transmission level shunt
capacitors (e.g. synchronous switching or use of pre-insertion resistors to mitigate voltage magnification to the extent possible).
To support our statement above, consider an often-quoted document to support these TOV requirements in the NERC Odessa Disturbance
Texas Events: May 9, 2021 and June 26, 2021 Joint NERC and Texas RE Staff Report, Dated September 2021. A detailed read of the section that
is entitled Inverter Transient AC Overvoltage Tripping Persists identifies poor coordination of controls and protection as the primary driver of
these events, rather than TOV conditions at the point of measurement due to switching transients or any type of resonance. What the report
explains is that in some cases the IBR units force maximum reactive power output during a fault to push the network voltages up, then once
the fault clears they do not pull back on the reactive power injection quickly enough, which leads to an RMS over-voltage (not switching event
TOV) at the terminals of the IBR unit, and thus the IBR units tripped. This is solved by 1) proper controls and protection coordination, 2) proper
IBR plant design, and 3) proper evaluation of the LVRT and HVRT ride-through capabilities of the IBR plant during the design phase of the plant.
R3 should be removed, and the focus placed on low voltage ride-through and high voltage ride-through, with an emphasis that both LVRT and
HVRT performance should be tested during the design phase of a facility using validated IBR unit models based on type-testing.
R4: In the Technical Rationale, the drafting team explains that due to lower system inertia “a wider frequency ride-through capability for IBR
may be required to avoid the risk of widespread tripping.” Can the drafting team cite more specific reasoning or data to support the expansion
of the frequency ride-through capability requirement to the range of 64Hz to 56Hz, well beyond the IEEE 2800-2022 standard frequency ridethrough requirement and the capabilities of many legacy IBRs?
The proposed 6-second frequency ride-through capability requirement for the ranges of 61.8Hz to 64Hz and 57Hz to 56Hz does not align with
the requirements on the rest of the BES. For the foreseeable future, synchronous generators will continue to be a significant part of the grid. It
is a well-established fact that such large electric machinery, which are directly connected to the grid, cannot be exposed to such large
variations in frequency. Therefore, it does not seem reasonable to ask IBRs to go to such extremes.
R5: We fail to see the value of requirement R5 given the other ride-through requirements, and it’s unclear to us how an entity is to determine
if the subject switching event is initiated by a fault or not. Additionally, we don’t believe the language in R5.1. regarding equipment tripping to
prevent equipment damage is reasonable or auditable. We recommend Requirement R5 is removed.
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Rhonda Jones - Invenergy LLC - 5
Answer
No
Document Name
Comment
No, Invenergy disagrees with the proposals for including IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle
jump ride-through performance criteria in Requirements R3, R4, and R5. We offer the below comments regarding these Requirements:
R3: Can the drafting team provide data that demonstrates observed overvoltages during recent System events were of the TOV magnitudes
and durations defined in Attachment 2 Table 3? TOVs of such scale are primarily due to the following three scenarios: 1) a lightning strike on
the nearby transmission system, 2) transmission line switching transients, and 3) resonant phenomena like voltage magnification due to shunt
capacitor switching on the transmission system. Measures are already in place to mitigate such events, including but not limited to proper
insulation coordination and substation design, metal oxide varistors, and proper capacitor bank switching of transmission level shunt
capacitors (e.g. synchronous switching or use of pre-insertion resistors to mitigate voltage magnification to the extent possible).
To support our statement above, consider an often-quoted document to support these TOV requirements in the NERC Odessa Disturbance
Texas Events: May 9, 2021 and June 26, 2021 Joint NERC and Texas RE Staff Report, Dated September 2021. A detailed read of the section that
is entitled Inverter Transient AC Overvoltage Tripping Persists identifies poor coordination of controls and protection as the primary driver of
these events, rather than TOV conditions at the point of measurement due to switching transients or any type of resonance. What the report
explains is that in some cases the IBR units force maximum reactive power output during a fault to push the network voltages up, then once
the fault clears they do not pull back on the reactive power injection quickly enough, which leads to an RMS over-voltage (not switching event
TOV) at the terminals of the IBR unit, and thus the IBR units tripped. This is solved by 1) proper controls and protection coordination, 2) proper
IBR plant design, and 3) proper evaluation of the LVRT and HVRT ride-through capabilities of the IBR plant during the design phase of the plant.
R3 should be removed, and the focus placed on low voltage ride-through and high voltage ride-through, with an emphasis that both LVRT and
HVRT performance should be tested during the design phase of a facility using validated IBR unit models based on type-testing.
R4: In the Technical Rationale, the drafting team explains that due to lower system inertia “a wider frequency ride-through capability for IBR
may be required to avoid the risk of widespread tripping.” Can the drafting team cite more specific reasoning or data to support the expansion
of the frequency ride-through capability requirement to the range of 64Hz to 56Hz, well beyond the IEEE 2800-2022 standard frequency ridethrough requirement and the capabilities of many legacy IBRs?
The proposed 6-second frequency ride-through capability requirement for the ranges of 61.8Hz to 64Hz and 57Hz to 56Hz does not align with
the requirements on the rest of the BES. For the foreseeable future, synchronous generators will continue to be a significant part of the grid. It
is a well-established fact that such large electric machinery, which are directly connected to the grid, cannot be exposed to such large
variations in frequency. Therefore, it does not seem reasonable to ask IBRs to go to such extremes.
R5: We fail to see the value of requirement R5 given the other ride-through requirements, and it’s unclear to us how an entity is to determine
if the subject switching event is initiated by a fault or not.
Additionally, we don’t believe the language in R5.1. regarding equipment tripping to prevent equipment damage is reasonable or auditable.
We recommend Requirement R5 is removed.
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Ruchi Shah - AES - AES Corporation - 5
Answer
No
Document Name
Comment
1 AES CE agrees that such performance criteria in R3, R4, and R5 needs to be included, but requests modifications and clarifications as
requested below:
2·
The language in R3 and R5 relating to “switching events” is difficult to track from the GO perspective. If such an event occurs at the
Transmission Operator (TOP), we may not be aware of the need to track and assess our IBR performance as applicable to PRC-029 unless
notified by the TOP. If a performance issue with an IBR is identified we would need to be informed by the TOP that a switching event occurred
to assess applicability to PRC-029.
3
Please update the technical rationale to clearly state that the 5 Hz/second criteria in R4 aligns with IEEE2800.
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Kimberly Turco - Constellation - 6
Answer
No
Document Name
Comment
These requirements would be a huge expense for sites that currently don't have frequency response capabilities and there is a strong
possibility that many would not be capable of meeting based on manufactures. It will not be financially feasible for all project owners to
support this change.
Kimberly Turco on behalf of Constellation Segments 5 and 6
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George E Brown - Pattern Operators LP - 5
Answer
No
Document Name
Comment
Pattern Energy supports Invenergy’s comments for this question.
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1,
6; Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
No
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and North American Generator Forum
(NAGF) on question 3
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
No
Document Name
Comment
R5 ,
First time seeing this type of protective setting, unsure as to whether or not any documentation exists or protective settings currently exist in
our fleet for this.
M5 ,
Will the PC's be communicating in writing to the Generator Owner every time there is a disturbance with the request for this data. How long
will the data need to be held?
The values for ride through are different from PRC-24. All current generation sites have targeted to comply with the curve given in PRC24. The basis of moving these protective curves are unclear.
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Joy Brake - Nova Scotia Power Inc. - NA - Not Applicable - NPCC
Answer
No
Document Name
Comment
Yes, they are needed but the understanding of what those criteria should be is not evolved sufficiently at this time. Also, large scale EMT
network models are not of sufficient quality to assess the criteria in the design phase.
For example, if RoCoF is for a time period of greater than or equal to 0.1 second, it leaves the choice of sample time to the user. The plant can
take the 100ms for calculations and meet the criteria. The System Operator criteria may calculate RoCoF over 500ms (as we do) and would see
the plant as not meeting criteria for the same event.
The proposed RoCoF of 5Hz/s is higher than IEEE1547 Category I, II and III. Transmission Wind turbines and their capabilities are often the
same as DER plants. A transmission facility just has a lot more of them. That said, we are looking to introduce higher RoCoF for DER as they
may be vulnerable as we transition to a very high IBR grid.
RoCoF is not calculated during the fault occurrence and clearance? The standard would only apply for loss of a source of generation without a
fault? For loss of our tieline for a fault it would not apply but loss of tieline for neighbouring RAS action it would? It is most needed when there
is a fault. For a fault, we are also losing the older wind MW as they go into momentary cessation during the fault making the generation loss
greater. For simple loss of supply, a high IBR grid is stronger than for a loss of supply due to fault. We apply RoCoF criteria during a fault. Our
current criteria for transmission design is 2.4 Hz/s calculated over 500ms. Our current design criteria for generation facilities ride through is
4Hz/s. But it is under review in EMT studies. We do not use rolling average at this time as it is difficult to accurately calculate in PSSE. We hope
to be able to move to rolling average as we increase our use of PSCAD study results for operational studies.
How does it align with the RoCoF criteria for synchronous plants? We are surveying our existing thermal plants and it is still a bit of an
unknown in some areas. Our current criteria of 4Hz/s applies to all generating facilities.
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF provides the following comments:
a. Requirement R3 – the NAGF notes that GOs do not have knowledge of BPS/BES “switching events” and requests that the Drafting Team
(DT) consider adding a requirement for the TO/TOP to notify the GOs of such events.
b.
Requirement R4:
i.
The term “applicable IBR” needs clarification.
ii.
Request additional clarification/justification regarding the proposed 5 Hz/second threshold.
iii.
The NAGF requests clarity on how to test compliance with the TOV Ride-Through requirement during study or plant IBR design phase.
c.
Requirement R5:
i.
Same concern as identified for R3
ii.
The requirements for phase angle shift of 25 degrees should allow IBR tripping if the post-fault system condition is drastically changed
and the device protection is activated.
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Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Comment
•
WEC Energy Group disagrees with R3. FERC Order 901 calls for addressing system disturbances. A switching event does not qualify as
a system disturbance. In addition, disturbance events summarized this as an anti-islanding protection issue and therefore it should be
stated in R3 to reduce confusion. If the SDT decides to keep R3, then R3 should include following text, “unless a documented
equipment limitation exists in accordance with Requirement R6.”
•
•
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WEC Energy Group agrees with inclusion of R4 with following exception: R4 should include following text, “unless a documented
equipment limitation exists in accordance with Requirement R6.”
WEC Energy Group agrees with inclusion of R5 with following exceptions:
o R5 should include following text, “unless a documented equipment limitation exists in accordance with Requirement R6.”
o The industry term is known as PLL Loss of Synchronism and is identified as such in disturbance reports. Therefore, R5 should
adopt the same to reduce the confusion.
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
No
Document Name
Comment
Duke Energy recommends the implementation of EEI and NAGF comments.
Duke Energy also recommends, if not already considered, to verify with OEMs that the inverters can satisfy Att 2. Figure 3 does not align with
IEEE 2800 Figure 14; again, making compliance with both requirements more complicated.
The controls only respond to voltage and therefore will have no context of the initiating event as could be implied by the statements in R3 and
R5. Recommend adding an exception to R3 worded in a similar format to the exception stated in 5.1.
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Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
No
Document Name
Comment
R3-5: R6 should apply to R1-R5 to account for equipment limitations that may also apply to R3-R5. Recommend similar language included in R1
and R2 is added to R3-5:
“…unless a documented equipment limitation exists in accordance with Requirement R6.”
Recommend that there be no requirement to document limitations on legacy equipment and that this standard focuses on equipment brought
into service after the implementation date.
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Alison MacKellar - Constellation - 5
Answer
No
Document Name
Comment
These requirements would be a huge expense for sites that currently don't have frequency response capabilities and there is a strong
possibility that many would not be capable of meeting based on manufactures. It will not be financially feasible for all project owners to
support this change.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer
No
Document Name
Comment
No technical expertise to comment.
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David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
No
Document Name
Comment
Vistra agrees with AEP.
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Dave Krueger - SERC Reliability Corporation - 10
Answer
No
Document Name
Comment
On behalf of the SERC Generator Working group:
Apply the R1 and R2 phrase “…unless a documented equipment limitation exists in accordance with Requirement R6” to R3, R4, and R5 in
addition to what is currently proposed in R1 and R2.
For R3 and R5, the GO will not know an over-voltage or phase jump is the result of a non-fault switching event, so is the GO expected to treat
all over voltage and phase jump events as non-fault events.
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
No
Document Name
Comment
R5.1:
This requirement is beyond the purpose of the standard, which is to establish Frequency and Voltage Ride-through Requirements for Inverter Based Generating Resources and should be removed.
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Carey Salisbury - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer
No
Document Name
Comment
For R3 and R5, the GO will not know an over-voltage or phase jump is the result of a non-fault switching event, so is the GO expected to treat
all over voltage and phase jump events as non-fault events.
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Michael Goggin - Grid Strategies LLC - 5
Answer
No
Document Name
Comment
There are several concerns with the equipment limitation exemption language in the draft of R6, and such exemptions not being allowed for
R3 and R5. To justify R6 only allowing an equipment limitation exemption for existing resources to R1 and R2, and not the other requirements
of PRC-029, the NERC drafting team’s technical rationale document points to FERC Order 901:
The objective of Requirement R5 [sic] is to ensure legacy IBR may need to obtain an exemption to the voltage ride‐through requirements if
hardware replacements or other costly upgrades would be necessary to comply with Requirements R1 or Requirement R2… FERC Order No. 901
states that this provision would be limited to exempting “certain registered IBRs from voltage ride‐through performance requirements.” This is
the reason that no similar provisions are included for exemptions for frequency, rate‐of‐change‐of‐frequency (ROCOF), phase angle change ride‐
through requirements.
First, the R6 equipment limitation exemption should also apply to R3, which requires ride-through for “a transient overvoltage as a result of a
switching event whereby instantaneous voltage at the high‐side of the main power transformer exceeds 1.2 per unit.” As NERC notes, FERC
Order 901 directed NERC that existing resources can have equipment limitation exemptions from voltage ride-through requirements, and
remaining online during transient over-voltage is clearly a voltage ride-through requirement. Transient over-voltage can damage equipment,
so allowing IBRs to protect against this damage is consistent with FERC’s intent in Order 901 to only allow tripping that is necessary to protect
equipment. Moreover, in many cases making existing equipment better able to withstand transient overvoltages would require replacing or
modifying hardware.
For similar reasons, an equipment limitation exemption for existing resources should also apply to R5, which requires ride-through for voltage
phase angle changes of less than 25 degrees. FERC Order 901 directed NERC that existing resources can have equipment limitation exemptions
from voltage ride-through requirements, and remaining online during voltage phase angle changes should be interpreted as part of voltage
ride-through requirements. Remaining online during phase angle changes of less than 25 degrees could be a problem for existing generators,
particularly wind generators as phase angle changes can impose mechanical stresses on the wind turbine’s rotating equipment. Not allowing
an equipment limitation exemption for existing generators under R5 is particularly problematic as it is not typically feasible to retrofit existing
wind turbines to increase their ability to withstand mechanical stresses due to phase angle changes. In such cases, making existing equipment
better able to withstand voltage phase angle changes would require replacing or modifying hardware. Phase angle changes can damage
equipment, so allowing IBRs to protect against this damage is consistent with FERC’s intent in Order 901 to only allow tripping that is necessary
to protect equipment.
Moreover, a contextual reading of Order 901 indicates FERC was mostly focused on limiting equipment limitation exemptions to existing
generators that would have to physically replace or modify hardware, and not strictly limiting such exemptions to a narrow reading of what
constitutes voltage ride-through requirements. Paragraph 193 in its entirety, and particularly the first sentence, explain that FERC’s intent was
focused on exempting existing resources that would have to physically replace or modify hardware: “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.” FERC continued by directing that “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.”{C}[1] As explained above, equipment limitation exemptions for R3 and R5 are likely necessary to ensure some existing
generators do not have to physically replace or modify hardware, and thus such exemptions are consistent with FERC’s directive in Order 901.
Finally, R6 equipment limitation exemptions should be allowed for resources with signed interconnection agreements as of the effective date
of the Standard, instead of resources that are in-service as of that date. Resource equipment decisions are typically locked down at the time
the interconnection agreement is signed, and a change in requirements after that point can require a costly change in equipment or settings
that may also trigger a material modification and resulting interconnection restudies. The implementation plan for PRC-029 indicates that the
effective date for the Standard will be the first day of the first quarter six months after FERC approval. Many resources take significantly longer
than that to move from a signed interconnection agreement to being placed in service, so it makes more sense to allow R6 equipment
limitation exemptions for resources that have a signed interconnection agreement as of the effective date of the Standard.
{C}[1]{C} Order 901, https://www.ferc.gov/media/e-1-rm22-12-000, at paragraph 193
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Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
No
A premise of R3 is knowing of a transient OV, due to a switching event on the transmission system. The Generator Owner is not going to have
the intelligence to know if a transient OV is due to a switching event. So, is the GO expected to treat all OV events as non-switching events?
1. Requirement R3: The Transient Overvoltage Ride-Through requirement is just not ready to be included in a regulatory standard. The
measure for this requirement is based on actual recorded data. The existing facilities may not even have recording equipment in place
to measure switching transients. The IEEE P2800.2 WG has also struggled to come up with a Design Evaluation procedure to show that
the plant would be able to ride-through the specified TOV ride-through requirements.
2. Requirement R4:
o The intent of “continue to exchange current” is understood, however, the requirement is vague. During frequency excursion
events, it is necessary that IBR adjusts active power output in response to frequency deviation. But these details are not
necessary in NERC standards, currently. The IBR that “continues to exchange current” but not based on frequency deviation,
would comply with the standard requirements, which is not ideal. The TP/PC is expected to specify IBR performance during
abnormal system frequency. Hence, the requirement should read as following: Each GO or TO of an applicable IBR shall ensure
each IBR remains electrically connected and continues to exchange current as specified by TP or PC during a frequency
excursion event……
o Why is there no exception for Volts/Hz limit? This could be an issue for type III WTG and transformer within the plant. The
frequency ride-through requirement in the IEEE Std 2800 recognizes Volts/Hz limitation.
3. Requirement R5:
o Consider revising to read as follows: Each GO or TO of an applicable IBR facility shall ensure that each IBR remains electrically
connected and continues to exchange current during non-fault switching events where the instantaneous change in positive
sequence voltage phase angle is less than or equal to 25 electrical degrees at the high-side of the main power transformer.
o Has the SDT discussed how to measure “instantaneous” phase angle jump based on recorded data?
o Part 5.1 is not necessary. The IBR may not trip because it measured phase angle jump of greater than 25 electrical degrees but
may trip due to affects of such a jump in phase angle. Not sure how to even prove that equipment was at risk or not.
o For R5, the GO will not know if a phase jump is the result of a non-fault switching event, so is the GO expected to treat all phase
jump events as non-fault switching events?
o In R5, what happens if an IBR trips due to phase angle jump while the frequency and voltage remain in the continue to operate
range? IBRs will not know whether the system has experienced a fault or not.
4. Attachment 3:
o Why does the SDT require more stringent ride-through capability compared to the IEEE Std 2800? If a certain interconnection
requires stringent ride-through requirement then it should only be required for that interconnection. There is no need to
extend the stringent requirements of one interconnection to all interconnections. Such an approach is implemented in the PRC024, PRC-006, etc. Additionally, the PRC-006 specifies boundaries between which the frequency needs to remain while
simulating and designing UFLS scheme. The IBR frequency ride-through coordinated with boundaries in PRC-006 should be
enough.
o Table 4:
Not sure what is implied by “average system frequency”. The term “average” makes sense when associated with
ROCOF but not with frequency.
≥64 should be >64
≥61.8 should be >61.8
o Note 1 is not necessary. Which measurement is taken on each phase?
o Note 2: Consider replacing with following: Frequency is measured over a period of time, typically 3-6 cycles.
o
o
Note 3: not sure which “control settings” are referred here. Consider the following from PRC-024: Instantaneous trip settings
based on instantaneously calculated frequency measurement is not permissible.
Note 5: Why did the SDT specify 15-min time period instead of 10-min time period in the IEEE Std 2800.
ROCOF and phase angle jumps:
•
•
Some legacy IBRs have technical limitations that will prevent them from riding through ROCOF less than or equal to 5 hz / second or
phase angle jumps less than 25 electrical degrees. Such IBRs need the ability to seek an exemption for these requirements.Note:
ERCOT has questioned the validity of how ROCOF and phase angle jumps are measured, and whether the 5 hz / second and 25 electric
degree values are accurate.
R5 specifies that IBRs must ride through phase angle jumps initiated by non-fault switching events and are changes of less than 25
electrical degrees. There is an issue Southern Company has encountered on NOGRR245. ERCOT has proposed that IBRs not trip for
any ROCOF or phase angle jumps during fault conditions. It is an understanding that IBRs should ignore ROCOF and phase angle jump
values during fault conditions. Southern Company would support similar fault language in PRC-029-1, but a technical exemption would
be required because some legacy IBRs are unable to distinguish between a fault and non-fault condition.
R6.1.2 discusses “aspects of VRT requirements that the IBR would be unable to meet”. This language could be clearer by requesting the IBR to
identify actual VRT capabilities.[A1]
M6 requires evidence of equipment limitations prior to the effective date of the standard. This could be extremely challenging to meet.
Finally, Southern Company supports NAGF comments.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company, 3,
1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
No
Document Name
Comment
Rwquirement 3
PG&E believes specific requirements for the inverter capabilities should be removed from the NERC standard and left to the IEEE 2800-22
standard for inverter specifications. The utility relies on RMS measurements and does not have a means to accurately measure transient overvoltage conditions for protective relays; therefore, it would be extremely difficult for the entity to prove its compliance.
Requirement 4
Frequency ride-through limits have been raised considering that IBRs can continue to generate. For synchronous machines, it is not possible to
have such a wide frequency range (as per attachment 3 copied below). When the system has majority of IBRs, the effect on synchronous
machines with such wide frequency variations is unknown. Also, it would affect the underfrequency load shedding schemes.
PG&E has the following questions for the SDT to consider: Should there be separate ride through limits for Grid Forming inverters and Grid
Following inverters? Would higher penetration of IBRs affect the allowable frequency ranges?
Requirement 5
PG&E believes specific requirements for the inverter capabilities should be removed from the NERC standard and left to the IEEE 2800-22
standard for inverter specifications.
PG&E has the following question for the SDT: how do we set relays or trigger a DFR for a switching/non-fault event to show compliance with
the requirement?
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Mark Flanary - Midwest Reliability Organization - 10
Answer
No
Document Name
Comment
See comments below under question 4.
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Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
2020-02_EPRI Comments on Draft NERC PRC-029 (IBR ride-through) Reliability
Standard.pdf
Comment
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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
We agree that PRC-024 standard should remain (enforced) because this will also help in ensuring the reliability of the Bulk Power System.
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Helen Lainis - Independent Electricity System Operator - 2
Answer
Yes
Document Name
Comment
The IESO recommends the following modifications to the text improve clarity or to better convey intent.
With regards to R4:
“…continues to exchange current during a frequency excursion event whereby the system frequency remains within the “no trip zone”
according to…”
This suggestion would differentiate the actual system frequency from, say, the frequency measurement as ‘seen’ by the PLL or other parts of
the controls.
With regards to 5.1
As commented above, IESO believes ‘not tripping except to provide equipment protection’ warrants a dedicated Requirement, which may be
referred to the context of other requirements, such as performance during phase angle jumps.
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Ontario Power Generation Inc., 5, Chitescu Constantin
0
Response
Michael Brytowski - Great River Energy - 3
Answer
Yes
Document Name
Comment
Comments: Initial review indicates the proposed requirements R3, R4 and R5 align with IEEE 2800 which we support.
R3: we suggest adding to attachment 2 how the instantaneous transient overvoltage should be calculated (such as what the pu base? and the
minimum sampling rate?)
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Yes
Document Name
Comment
FirstEnergy has no issue for the direction of these requirements.
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Stefanie Burke - Portland General Electric Co. - 6
Answer
Yes
Document Name
Comment
PGE supports EEI’s comments but in addition would add clarification: For the requirement to say “may trip, but shall only trip to prevent
equipment damage” does not provide clear direction. If the IBR can stand a 30 electrical degree change, is it acceptable to trip at 25.0 to
prevent equipment damage? It would be preferrable to provide a safety margin before reaching the damage point. Or, is this stating that the
IBR wait until 30.0 electrical degrees is reached before taking action? What is the measure for making sure an IBR does not trip at 25.0 or
above except to protect the equipment? If there is nothing particularly harmful about tripping an IBR above 25.0, why not indicate that above
25.0 is not a “Must Trip Zone/Criteria”?
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Ben Hammer - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
R3: we suggest adding to attachment 2 how the instantaneous transient overvoltage should be calculated (such as what the pu base? and the
minimum sampling rate?)
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David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
Yes
Document Name
Comment
Ameren agrees with EEI's comments.
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Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Yes
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of its members:
EEI supports the proposal to include IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle jump ride-through
performance criteria in PRC-029-1 Requirements R3, R4, and R5. However, the following phrase “of an applicable IBR” should be removed
from R3, R4 and R5. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
EEI supports the proposal to include IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle jump ride-through
performance criteria in PRC-029-1 Requirements R3, R4, and R5. However, the following phrase “of an applicable IBR” should be removed
from R3, R4 and R5. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
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Daniel Gacek - Exelon - 1
Answer
Yes
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Yes
Comment
But we need to consider old units, please see the additional comments below.
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Yes
Document Name
Comment
R3: MP agrees with the NSRF’s comments on defining the transient overvoltage calculation method. MP also suggests defining the term
“current block mode.”
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
OPG supports IESO’s comments.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
Yes
See EEI Comments
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Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
Yes
Document Name
Comment
However, please verify the ROCOF with regards to how FR data at the IBR Unit level (per the definitions proposed by 2020-06) is required to be
captured (Per proposed PRC-028-1). Note that PRC-002-4 and -5 have ROCOF triggers for recording that are significantly different than 5
Hz/second. Measure 4 of PRC-029-1 has a reference to a Planning Coordinator’s area but Requirement 4 has no such limitation or uses
Planning Coordinator within the language. It appears that the stated ROCOF is high based on IRPT reports
(https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/Fast_Frequency_Response_Conce
pts_and_BPS_Reliability_Needs_White_Paper.pdf ). And the ROCOF definition is different from said report by the IRPTF.
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Richard Vendetti - NextEra Energy - 5
Answer
Yes
Document Name
Comment
NextEra aligns with EEI's comments:
EEI supports the proposal to include IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle jump ride-through
performance criteria in PRC-029-1 Requirements R3, R4, and R5. However, the following phrase “of an applicable IBR” should be removed
from R3, R4 and R5. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Yes
Document Name
Comment
ERCOT joins the comments of the IRC SRC and adopts them as its own in addition to the following comments, except to the extent of any
specific differences between the SRC comments and the following comments from ERCOT.
Footnote 2 is not clear as to whether RoCoF measurement should begin immediately or upon fault clearing. IEEE 2800.2 discussions are
heading in a direction that would indicate that during fault occurrence, clearance, and recovery back to a steady-state operating point, failure
to ride through should only be allowed if the voltage is beyond the requirement (i.e., the unit should not trip due to any perceived RoCoF
during the entire disturbance and recovery period). This is similar for phase angle jump.
Requirement R4 may need to include language similar to that found in Requirement R5, Part 5.1 to ensure RoCoF is set to the equipment
capability and is not arbitrarily set at 5 Hz/s. ERCOT also notes that the IEEE 2800-2 drafting team is identifying that there should be
agreement between unit owners and planners/operators on how to measure RoCoF (at what time points, greater than or equal to .1 second)
to ensure consistency in testing, model validation, application, and performance evaluation. Otherwise, such a requirement may create
confusion or otherwise be unenforceable. IEEE 2800-2 also identifies the potential need for higher RoCoF requirements, which may be
appropriate in smaller Interconnections.
The current language in Requirement R5 excludes voltage phase angle change of exactly 25 degrees, which is included in IEEE2800
requirements:
SDT’s proposed language:
“Each Generator Owner or Transmission Owner of an applicable IBR shall ensure each IBR remains electrically connected and continues to
exchange current during instantaneous positive sequence voltage phase angle changes that are initiated by non‐fault switching events on the
transmission system and are changes of less than 25 electrical degrees at the high‐side of the main power transformer.”
ERCOT’s proposed language:
Each Generator Owner or Transmission Owner of an applicable IBR shall ensure each IBR remains electrically connected and continues to
exchange current during instantaneous positive sequence voltage phase angle changes of 25 electrical degrees or less at the high-side of the
main power transformer that are initiated by non‐fault switching events on the transmission system.
Finally, ERCOT believes that under the Violation Risk Factor guidelines, Requirements R3, R4, and R5 should have a VRF of High as they are
requirements “that, if violated, could directly cause or contribute to Bulk-Power System instability, separation, or a cascading sequence of
failures, or could place the Bulk-Power System at an unacceptable risk of instability, separation, or cascading failures . . . .”
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Kinte Whitehead - Exelon - 3
Answer
Yes
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Yes
Document Name
Comment
See EEI comments
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Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
See comments submitted by Edison Electric Institute
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Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Yes
Document Name
Comment
Overall, we at ACES support Requirements R3 through R5; however, we have a minor concern with the wording of Requirement R3, Option 2.
Specifically, we have concerns with the requirement to “restart current exchange within 5 cycles of the instantaneous voltage falling below
(and remaining below) 1.2 per unit.” For how long of a duration should the instantaneous voltage remain below 1.2 p.u. to trigger the 5 cycles
wherein the IBR must resume current exchange? We recommend that the SDT consider adding a time component to the return from the
transient overvoltage condition.
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Joshua Phillips - Southwest Power Pool, Inc. (RTO) - 2
Answer
Yes
Document Name
Comment
Southwest Power Pool joins the ISO/RTO Council Standards Review Committee comments.
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Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
Answer
Yes
Document Name
Comment
Initial review indicates the proposed requirements R3, R4, and R5 align with IEEE 2800, which the SRC supports.
The SRC recommends the following modifications to the text to improve clarity and to better convey the intent of the standard.
Recommended changes to R4:
“…continues to exchange current during a frequency excursion event whereby the system frequency remains within the “no trip zone”
according to…”
This revision would clarify that the actual system frequency is the relevant measurement instead of the frequency measurement as ‘seen’ by
the PLL or other parts of the IBR control system.
Recommended changes to R5.1
As noted above, the SRC believes ‘not tripping except to provide equipment protection’ warrants a dedicated Requirement, which may be
referred to in the context of other requirements, such as performance during phase angle jumps.
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Ryan Quint - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable, Group Name Elevate Energy Consulting
Answer
Yes
Document Name
Comment
Yes. The SDT should consider citing IEEE 2800-2022 directly in the standard and consider using the IEEE 2800-2022 ride-through requirements
as a means to comply with Requirements R1-R5 instead of using Attachment 1 of the standard.
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Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District,
3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Tim Kelley, Group Name SMUD and BANC
Answer
Yes
Document Name
Comment
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Brittany Millard - Lincoln Electric System - 5
Answer
Yes
Document Name
Comment
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Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst
Ballot Body Member and Proxies
Answer
Yes
Document Name
Comment
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Yes
Document Name
Comment
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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Yes
Document Name
Comment
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Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3 - WECC
Answer
Yes
Document Name
Comment
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Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
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Glen Farmer - Avista - Avista Corporation - 5
Answer
Yes
Document Name
Comment
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Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Yes
Document Name
Comment
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David Campbell - David Campbell On Behalf of: Natalie Johnson, Enel Green Power, 5; - David Campbell
Answer
Yes
Document Name
Comment
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Shonda McCain - Omaha Public Power District - 6
Answer
Yes
Document Name
Comment
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Katrina Lyons - Georgia System Operations Corporation - 4
Answer
Document Name
Yes
Comment
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John Pearson - ISO New England, Inc. - 2
Answer
Yes
Document Name
Comment
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Yes
Document Name
Comment
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Wesley Yeomans - New York State Reliability Council - 10
Answer
Yes
Document Name
Comment
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0
Wendy Kalidass - U.S. Bureau of Reclamation - 5
Answer
Document Name
Comment
Not Applicable to Reclamation.
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Imane Mrini - Austin Energy - 6, Group Name Austin Energy
Answer
Document Name
Comment
N/A
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0
4. Provide any additional comments for the Drafting Team to consider, if desired.
Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1
Answer
Document Name
Comment
The proposed PRC-029 seems vague and does not specify what size IBR would applicable. If it is below the 75MVA aggregate, then I believe that
would cause undue burden on utilities to meet.
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Ryan Quint - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable, Group Name Elevate Energy Consulting
Answer
Document Name
Comment
Attachment 1 needs a few corrections.
•
•
Figures 1 and 2 use a logarithmic time scale for the Time x-axis. This should be updated to be a regular non-logarithmic time scale.
There are numerous inconsistencies in this standard language and Attachment 1 when compared to IEEE 2800. These should be
considered and reviewed for clarity and completeness in the standard. The option to cite IEEE 2800-2022 and use the requirements in
the IEEE 2800-2022 directly should be allowed over just the use of Attachment 1 (give each GO/TO the ability to use either of these
guides to base their performance off of).
o IEEE 2800 identifies the following items, but the standard does not support. Clarification/review should occur for each of these
items:
Exceptions for Negative-sequence voltage exceeding thresholds
IEEE 2800 recognizes Volts/Hz limitations, but the standard does not.
IEEE 2800 recognizes 500kV system voltages are actually operated in the range of 525kV and therefore has equipment
rated to 550kV. These 500kV operating conditions should be considered in the standard.
In IEEE 2800 the frequency ride-through criteria defines 10-minute time periods whereas the standard defines them in a
15 minute time period (Table 4 of Attachment 3). This should be clarified and identified.
The standard is quite vague in terms of technical limitations and documentation exemptions to the requirements. Experience has shown that
this is a highly nuanced and difficult consideration. There is no language focused on software versus hardware limitations and what is
allowed/expected. This could lead to inconsistent, subjective auditing practices rather than clear objective requirements and auditing.
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Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
Answer
Document Name
Comment
The SRC requests several enhancements to PRC-029.
1. Clarify and emphasize that documented equipment limitations under Requirement R6 must not be construed to be complete
2.
3.
4.
5.
6.
7.
8.
9.
exemptions from the Requirements of PRC-029. If entities are unable to ride-through portions of the ride-through curve, this should
not automatically exempt them from complying with the balance of the ride-through curve as described in the Technical Rationale.
While this is clearly expressed in the Technical Rationale for Requirement R6 (page 9), this point needs to be brought out more clearly in
the PRC-029 standard itself.
Expand PRC-029 to require that Corrective Action Plans be developed and implemented to remove equipment limitations within a
specified timeline or require a technical justification that addresses why corrective actions will not be applied nor implemented.
PRC-029 will need to explicitly require any new inverter/controller replacing older equipment to be compliant with PRC-029 rather than
set to original equipment specification.
Applicability:In Introduction, Section 4.2.2, it is not obvious what aspect of ‘IBR Registration Criteria’ makes an IBR an ‘applicable’ IBR –
is it simply that an IBR meets NERC Registration Criteria? This bullet point should be elaborated upon to ensure clarity.
Event-Based Standard: The SRC has concerns that this standard is an event-based standard that does not necessarily provide an
assurance of reliability before events occur, such as would be provided by having an engineering analysis or results from bench-testing
and real-time simulations of control equipment that indicate that successful ride through of prescribed disturbances is expected.
Without disturbance events that show whether IBRs perform properly, there is no way to determine if an IBR is compliant with the
standard. At a minimum, the measures (e.g, M2-M5) should be extended to indicate that a statement that no such events are known to
have occurred will qualify as evidence of compliance.
Presentation of Ride-Through Ranges: The intended ride-through requirements would be made more clear if the ‘minimum ridethrough times’ were associated with precisely stated, non-overlapping ranges of voltages or frequencies, such as in the example ‘Table
2’ provided by the SRC in its comments above.
Nominal Voltages: Note #4 of Attachment 1 would be clearer if the 'nominal' system voltage values were listed as they are in
Attachment 2 of PRC-024-3, i.e., “(e.g., 100 kV, 115 kV, 138 kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.)”
Harmonize Tables, Figures, Requirements: The voltage/frequency excursion levels and the associated minimum ride-through times for
all tables, figures, and any associated performance requirements that modify the requirements should be carefully reviewed and
harmonized. There are presently some conflicting entries in the tables/figures.
10. PRC-029 introduces new terms. The drafting team should consider using these new terms in PRC-024 for consistency. The ranges in
these definitions may be specific to IBRs due to their unique performance characteristics, but these regions serve the same purpose for
synchronous generators.
i. Term(s):
ii. Continuous Operating Region – The range of voltages, measured at the high‐side of the main power transformer, that are ≥
0.9 per unit and ≤ 1.1 per unit.
iii. Mandatory Operating Region – The range of voltages, measured at the high‐side of the main power transformer, that are > 0.1
per unit and < 0.9 per unit – or – > 1.1 and ≤ 1.2 per unit.
iv. Permissive Operating Region – The range of voltages, measured at the high‐side of the main power transformer, that is ≤ 0.1
per unit.
11. There does not seem to be a direct explanation of how these new terms used in the Requirements are applied in Attachment 1, where
the ranges for “No-Trip” and “Must-trip” are shown. the only mention of these terms in Attachment 1 appears to be in bullets 8, 9, and
10 where one or two Regions are mentioned and assumed to be understood. Additionally, these terms are not used consistently
throughout the standard, as these terms are defined as “Operating Regions,” but frequently appear in the standard as “Operation
Regions.” The SRC recommends that the SDT standardize on a consistent format for these terms.
R1. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that each IBR remains electrically connected and continues
to exchange current in accordance with the no‐trip zones and operation regions as specified in Attachment 1
Attachment 1
8. The specified duration of the Mandatory Operation Regions and the Permissive Operation Regions in Tables 1 and 2 is cumulative over one or
more disturbances within a 10 second time period.
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Mark Flanary - Midwest Reliability Organization - 10
Answer
Document Name
Comment
Requirements R1, R2, R3, R4, and R5 and associated Measures do not make it clear whether equipment settings or configurations that render a
facility unable to meet the performance requirements constitute a non-compliance prior to the occurrence of an event where the facility fails
to meet the performance requirements. An understanding of these requirements as event-based (as described in the current draft of the PRC029-1 Technical Rationale) would only partially accomplish the risk objectives described in the SAR and in FERC order 901 as many events would
not be prevented. This is particularly concerning for frequency excursion events (R4) as these events are relatively infrequent and yet
widespread, potentially resulting in the failure of a multitude of IBRs to meet the performance requirements if frequency trip settings are not
evaluated preemptively. As such, these requirements should make it clear that facilities are to be configured to meet performance
requirements and that the relevant equipment settings should be available as evidence to show compliance.
If there are portions of the performance criteria in this standard that equipment owners cannot be expected to meet through assessment of
equipment settings in the absence of an event, those portions should be addressed in separate requirements that specify corrective actions to
be performed following an event rather than identify non-compliance at the time of the event.
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
Attachment 1, Part 2b. I assume that “ESS” means Energy Storage System? Please document or clarify.
Part 7 “ … trip …” again. Same question as in comment 2 above. The second sentence is also unclear. What is “the 10-second time period”? Is
this phrase identified in Parts 8 and 9? If so, please define it before first use and use the same phrase subsequently.
Attachment 2 Part 3 “ … trip …” again. Same question as in comment 2 and Attachment 1 Part 2b above.
Attachment 3, Table 4 Part 2. I agree with averaging frequency over a set time period. But 3 cycles seems rather short to assure a reasonable
frequency value, especially during fault conditions. IEEE 2800 says “… at least 0.1 sec” [6 cycles] for ROCOF, and that is probably a good target
for frequency also.
Table 4 and Part 4 “ … trip …” again. Same question as in comment 2 and Attachment 1 Part 2b and 3 above.
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John Pearson - ISO New England, Inc. - 2
Answer
Document Name
Comment
The new or modified terms should define what the “voltage” is, RMS, Positive Sequence? Instantaneous? Etc. for Continuous Operating Region,
Mandatory Operating Region and Permissive Operating Region.
In Attachment 1, bullet 3 is problematic, basing the applicable table based on direction by the Transmission Planner needs to have a specific
requirement describing how that would be done. Bullet 4 is also problematic for the same reason. Bullet 8 – Mandatory Operation Regions
should conform with IEEE 2800 7.2.2.4 for consecutive disturbances, and differentiate from dynamic voltage oscillations. Bullet 9 should also
conform to IEEE 2899 7.2.2.4.
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Joshua Phillips - Southwest Power Pool, Inc. (RTO) - 2
Answer
Document Name
Comment
Southwest Power Pool joins the ISO/RTO Council Standards Review Committee comments.
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Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Document Name
Comment
•
It is the opinion of ACES that Section 4.2 should be modified to utilize the registration criteria as defined in the latest revision of the
NERC Rules of Procedure.
Thus, we recommend the following revisions to Section 4.2:
4. Applicability:
4.1 Functional Entities:
4.1.1 Generator Owner that owns an applicable facility in Section 4.2.1.
4.1.2 Transmission Owner that owns an applicable facility in Section 4.2.3.
4.2 Facilities:
4.2.1 Either of the following Inverter-Based Resource (IBR)1 types:
4.2.1.1 BES IBR
4.2.1.2 non-BES IBR that is:
4.2.1.2.1 Connected to the Bulk Power System, and
4.2.1.2.2 Meets the criteria for a Category 2 GO facility.
4.2.2 High-voltage Direct Current (VSC-HVDC) Transmission facilities that serve as a dedicated connection for an Inverter-Based Resource
meeting the criteria of 4.2.1.1
•
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Transmission is a defined term in the NERC Glossary of Terms. As it is currently defined, this term does not specify a voltage threshold
for its applicability; therefore, we recommend capitalizing all uses of the word “transmission” within PRC-029-1 for the sake of clarity.
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Katrina Lyons - Georgia System Operations Corporation - 4
Answer
Document Name
Comment
GSOC supports Georgia Transmission Corporation (GTC) Comments.
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Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Document Name
Comment
See comments submitted by Edison Electric Institute
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI comments
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Kinte Whitehead - Exelon - 3
Answer
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT joins the comments of the IRC SRC and adopts them as its own in addition to the following comments, except to the extent of any
specific differences between the SRC comments and the following comments from ERCOT.
The proposed changes to PRC-024 create a reliability gap, as Type 1 and Type 2 wind turbines are not synchronous machines and would
therefore no longer be required to comply with PRC-024 but are not included in PRC-029 because they are not IBRs. The SDT should consider
including a specific requirement in PRC-024 or PRC-029 that addresses this technology and requires these types of units to try to meet
requirements up to their equipment limitations, to notify their PC/TP/RC/TOP of such limitations, and to reflect any such limitations in their
dynamic models. This will ensure that the PC/TP/RC/TOP can incorporate the expected performance of these units in their studies.
ERCOT agrees with the SDT’s overall approach of ensuring that PRC-029 is clearly a performance-based standard. However, the standard is not
entirely clear on this point, as the Time Horizon is “operations assessment” instead of “Real-time Operations.” Additionally, the standard
generally uses a structure of ‘owners…shall… ensure that’ instead of an ‘owners….shall.. perform’ structure. Structures found in other
standards, such as BAL-001’s ‘entity…shall.. operate such that…’ structure or BAL-001-TRE’s ‘entity….shall….meet (or exceed)’ structure may
also work well for PRC-029.
ERCOT notes that FERC Order 901 states, “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 support during a Bulk-Power System disturbance” (emphasis added). To
meet this directive, it may be important to clearly specify that partial failures (individual IBR unit trips or abnormal responses) also fall under
PRC‑029.
ERCOT therefore recommends modifying the Purpose statement for PRC-029 as follows: “To ensure that Inverter-Based Resources, and their
IBR Units, remain connected and perform operationally as expected to support the Bulk-Power System during and after defined frequency and
voltage excursions.”
The figures in Attachments 1, 2, and 3 appear to be intended to be graphical representations of the tables. To that extent, they are redundant
(and potentially contradict what is in the tables). They may be valuable in visualizing the requirements, but they are also ambiguous in that the
lines are not precisely defined, and it is not clear if ride-through is required on the lines themselves. ERCOT recommends that these figures be
moved to the Technical Rationale or that Attachments 1, 2, and 3 include a clarification that the plots are for visualization purposes only and
that the tables define what is actually enforceable
Item 7 in Attachment 1 should not imply that the IBR shall trip beyond the minimum duration. While the inclusion of the term "minimum"
helps clarify item 7, the "shall not trip until…" language implies that the IBR shall trip once the minimum ride-through time duration has
elapsed.
SDT’s proposed language:
“At any given voltage value, each IBR shall not trip until the time duration at that voltage exceeds the specified minimum ride‐through time
duration. If the voltage is continuously varying over time, it is necessary to add the duration within each band of Tables 1 and 2 over the 10‐
second time period to determine compliance.”
ERCOT’s proposed language:
"The IBR shall ride through voltage conditions beyond those specified in Tables 1 and 2 above to the maximum extent the equipment allows. If
the voltage is continuously varying over time, it is necessary to add the duration within each band of Tables 1 and 2 over the 10‐second time
period to determine compliance.”
Similar wording should also be applied in item 3 of Attachment 2 and item 4 of Attachment 3.
ERCOT is concerned that item 10 in Attachment 1 (“If the positive sequence voltage at the high‐side of the main power transformer enters the
Permissive Operation Region, an IBR may operate in current block mode if necessary to protect the equipment”) is inconsistent with the
following directive from paragraph 190 of FERC Order 901 (as cited in the technical rationale): “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.”
The proposed defined terms do not seem to be appropriate for the NERC glossary, especially if they are intended to be used exclusively for
IBRs. If the SDT keeps these proposed terms, the definitions should be improved to include durations in addition to voltage ranges and to note
that they are only valid for application to IBRs. Furthermore, there are inconstancies between these terms and Tables 1 and 2 in Attachment
1. For example, the Continuous Operating Region is defined as 0.9-1.1 pu (inclusive), but the tables specify only a one second ride-through time
for 1.1pu voltage and an 1800 second ride-through time for voltages greater than or equal to 1.05pu, which is not consistent with the concept
of continuous operations. Additionally, the terms are used inconsistently in PRC-029, as the terms are defined as “Operating Regions,” but
frequently appear in PRC-029 as “Operation Regions.”
The Technical Rationale includes the following language:
“The proposed PRC‐029 must be understood as an event‐based standard. Compliance with PRC‐029 is determined from IBR ride‐through
performance during transmission system events in the field and not from interconnection studies, transmission planning studies, operational
planning studies, or from IBR models.”
ERCOT recommends that the SDT add basic expectations to the Technical Rationale instead of simply stating that compliance is not determined
by studies. For example, GOs should design and/or test their facilities to help ensure they won’t be non-compliant during an actual
event. Furthermore, it would be helpful to offer advice or SDT opinions on how ride-through should be evaluated during design,
interconnection, planning, and operational studies. Even though deficient performance in such studies may not be a violation of PRC-029, it
makes little sense to proceed with or allow an interconnection of a plant whose simulation models indicate that it will be unable to comply with
PRC-029. Such guidance in the Technical Rationale would be beneficial for industry even if the Requirements in the standard do not contain a
corresponding mandate.
The Technical Rationale should describe the basis for the “6‐second frequency ride‐through capability requirement for frequencies in the
ranges of 61.8Hz to 64Hz or 57.0Hz to 56.0Hz range,” as it is unclear why this approach was chosen instead of an approach that goes all the way
up to 65 Hz and down to 55 Hz for 10 seconds or only up to 63.5 Hz and down to 56.5 Hz for 5 seconds.
It is also unclear how the SDT addressed the phase lock loop (PLL) loss of synchronism concerns discussed in FERC Order 901. While there is
certainly an interrelationship, certain protection systems like PLL loss of synch may not need to be enabled. Even if enabled, these systems
may, if not correctly configured, require additional tuning to ensure the PLL circuit properly controls and prevents some of the other
parameters from tripping the unit offline (e.g. phase angle, RoCoF, and overvoltage). The SDT should consider adding additional language to
PRC-029 to clarify that phase lock loss of synchronism trips (whether directly or indirectly involved) are not allowed.
The SDT should also consider adding the following items to Attachment 1 for clarity:
11. To the extent possible, IBRs should not use these curves as the absolute voltage or frequency protection set points but should strive to
exceed them up to their equipment capabilities while still ensuring adequate equipment protection.
12. IBRs are not required to trip when voltage and frequency are in the may-trip or permissive operation regions.
Additionally, ERCOT has overall concerns with the work plan pushing the planner and operator requirement changes to the final phases. FERC
Order 901 states, “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, 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 [sic] 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.”
Due to the interrelationship between these factors, the allowance for limited exemptions should be linked to the need to mitigate the impact of
such exemptions, which will take time in and of itself. In addition, Order 901 directs NERC to consider the reliability impacts of such an
exemption. If the SDT does not have identified quantities or models of likely exemptions to assess the impact of allowing exemptions, it is
unclear how NERC is considering the reliability impacts of allowing exemptions. There must be guardrails in place to ensure that exemptions
are truly limited, not open-ended, and there should be verification by means of accurate models and studies that the system can withstand the
impacts of exemptions. If such studies demonstrate unreliable operations (i.e. Instability, Cascading Outages, and uncontrolled separation)
would result from granting exemptions, then the exemptions should not be accepted. While ERCOT understands the impacts to generator
owners, such assessment and determination should be made under FERC’s direction to ensure that the limited exemptions and risk posed by
such exemptions are balanced in such a way that the system maintains Reliable Operation.
Finally, regarding the implementation plan, ERCOT does not agree with how the FERC Order 901 excerpt quoted under "Equipment Limitations
and Process for Requirement R6" has been applied. The FERC Order 901 excerpt refers to "typically older IBR technology," which would exclude
a majority of IBRs that are in operation today. Aligning eligibility for PRC-029-1 exemptions based on documented equipment limitations under
Requirement R6 with the effective date of PRC-029-1 would allow potentially hundreds of GWs of newer IBRs to qualify for exemptions. Such
an allowance could result in a failure to realize the reliability benefits FERC intended to capture, as it would allow legacy IBRs to claim
exemptions even if they are ultimately capable of complying with the requirements of PRC-029. Unless there is assurance, based on validated
and accurate models, that planners and operators can verify that the System can withstand the impact of allowing these exemptions, this
allowing this level of potential exemptions may not allow for Reliable Operations. In such instances where exemptions may not allow for
Reliable Operations, there should be additional evaluation of available physical modifications (e.g. upgrade kits, new power plant controllers,
new controller cards/circuits, control communication networks, component upgrades) for IBR technology that is not approaching its end of life
and or an upcoming replacement/refurbishment cycle like "typically older IBR technology" is. Additionally, IBRs that make physical
modifications to achieve compliance or that have to make software changes at multiple sites may need additional implementation time when
such changes require changes at each individual inverter or turbine.
ERCOT expresses appreciation for all of the SDT’s hard work in meeting an expedited timeline for developing a technically complex set of
Requirements that attempts to balance elements from IEEE 2800, FERC Orders, NERC recommendations, and vast amounts of stakeholder
input. The SDT is to be commended for its progress thus far on this critical standard.
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Shonda McCain - Omaha Public Power District - 6
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Document Name
Comment
OPPD supports comments provided by GRE: Michael Brytowski, Great River Energy, 3, 4/17/2024
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company, 3,
1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Document Name
Comment
For PRC-029-1
PG&E asks the SDT the following question: Does Table 1 or 2 apply to Type 4 Wind IBRs? It is unclear which table it would apply to and should
be clarified since Table 1 specifies “Wind IBR” but not which types of Wind IBRs.
PG&E suggests reconsidering the use of the term “trip” or “no-trip.” Per IEEE 2800-22, “trip” for IBRs may not mean the same as has been
traditionally used for synchronous machines and other electric elements.
For PRC-024-4
PG&E has the following question for the SDT to clarify: For Transmission Owners, does new language in sections 4.1.2 & 4.2.2 only apply to
Synchronous Condensers?
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Richard Vendetti - NextEra Energy - 5
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Document Name
Comment
NextEra aligns with EEI's comments:
PRC-029-1 (Applicability Section) Comments: EEI does not support the Applicability Section of PRC-029-1 for the following reasons:
{C}1.
Applicability details should not be contained in footnotes. Please remove footnote 1 from the Applicability Section.
{C}2. Voltage Source Converter – High-voltage Direct Current (VSC-HVDC) are not defined or justified within the Technical Rationale as to
why these resources need to be added PRC-029.
{C}3.
Without a justification of a need to include VSC-HVDC systems, TOs should be removed from PRC-029-1.
{C}4. EEI does not support the use of the term “BPS IBRs” because no such term exists in the NERC Glossary of Terms that might provide
entities with the knowledge to know definitively which IBRs are applicable.
{C}5.
EEI also does not support language that points to the registration criteria.
To address our concerns, we suggest the following changes to the Applicability Section of PRC-029-1, noting the Facilities portion of our
comments utilize the recommendations from the Project 2020-06 SDT (see boldface changes below):
{C}4.
Applicability:
{C}4.1
Functional Entities:
{C}4.1.1
Generator Owner
{C}4.1.2
{C}Transmission Owner (and footnote 1)
Facilities: (1) BES Inverter-Based Resources; and (2) Non-BES Inverter Based Resources (IBRs) that that either have or contribute to
{C}4.2
an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such
capacity to a common point of connection at a voltage greater than or equal to 60 kV. For purposes of this standard, the term “applicable
Inverter‐Based Resource” or “applicable Inverter‐Based Resources” refers to the following:
{C}4.2.1
{C}BPS IBRs
{C}4.2.2
{C}IBR Registration Criteria
PRC-024 Comments: While there were no questions related to the proposed modifications to PRC-024-4, EEI does not support all of the
proposed changes made to PRC-024-4. Note the following:
Applicability Section of PRC-024-4
EEI does not support changing the intent of 4.2.1.4 (Previously 4.2.1.5) to include multiple synchronous generators connecting to a common
bus under the BES Definition, Inclusion I4. Since the development of the BES definition, Inclusion I4 did not include or intend to include
synchronous generators. Had that been the intent, the SDT could have included synchronous generator resources in I4. Furthermore, the BES
Reference Document states in Chapter I4: BES Inclusion the following:
Dispersed power producing resources are small-scale power generation technologies that use a system designed primarily for aggregating
capacity providing an alternative to, or an enhancement of, the traditional electric power system. Examples could include, but are not limited
to: solar, geothermal, energy storage, flywheels, wind, microturbines, and fuel cells.
While EEI is open to making modifications to the BES Definition, trying to provide interpretations within individual Applicability Sections of
proposed NERC Reliability Guidelines is not the proper method to make such a change. For this reason, and since 4.2.1.4 (previously 4.2.1.5)
was intended to address IBRs; this part of the Applicability Section of PRC-024-4 should be deleted.
Comments on the proposed New Definitions
EEI has no concerns with the proposed new definitions, but we do have some non-substantive comments on their usage throughout PRC-029,
Implementation Plan and Technical Rationale. (See below)
{C}·
Usage of the newly defined terms deviated from the defined term within PRC-029 and the Technical Rational. (i.e., Operating vs.
Operations)
{C}·
Incorrectly stating in the Implementation Plan that there were no newly defined terms. Please correct this error.
Continuous Operating Region – Only used once in Requirement 2.3.
{C}·
Continuous Operation Region used in Requirements 2.1, 2.1.2, 2.4, & once in Attachment 1 (i.e., suggest changing the defined term to
Continuous Operation Region or correct to Continuous Operating Region throughout)
{C}·
Continuous Operation Region used twice in the Technical Rationale; Continuous Operating Region never used in the Technical
Rationale.
Mandatory Operating Region – Never used in PRC-029
{C}·
Mandatory Operation Region used in PRC-029 in Requirements 2.2, 2.3, 2.4 & once in Attachment 1 (i.e., suggest changing the defined
term to Mandatory Operation Region or correct to Mandatory Operating Region throughout)
{C}·
Mandatory Operation Region was used twice in Technical Rationale; Mandatory Operating Region was never used in the Technical
Rational.
Permissive Operating Region – Never used in PRC-029
{C}·
Permissive Operation Region used in PRC-029 in Requirements 2.3, 2.4, & used twice in Attachment 1 (i.e., suggest changing the
defined term to Permissive Operation Region or correct to Permissive Operating Region throughout)
{C}·
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Permissive Operation Region used once in the Technical Rationale; Permissive Operating Region never used in the Technical Rationale.
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Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Has the MPT Volts/Hz capability been considered when considering the high voltage/low frequency curves?
For R6, the use of "repair" seems inappropriate - an equipment limitation is not equivalent to a broken part in need of repair. We suggest that
"repair(s) or replace the limiting element" in R6.1.4 and R6.2 be changed to "remedy the equipment limitation".
The standard requires IBR to ride-through regardless of operating condition of the transmission system. The IBR is typically designed to ridethrough for planning events, most likely defined in TPL-001 standard. Considering 24 hour/365 day operation, the transmission system may be
experiencing outages beyond planning events. During such an abnormal operating condition, the IBR may not be able ride-through system
disturbances as specified. The same could also be true as the transmission system changes over time, as new transmission lines are added to
the transmission system and generating plants are added to or removed from the transmission system. The IBR which is designed to ridethrough certain transmission network and operating conditions at the time of entering commercial operation may not be able to do so if
transmission network and operating conditions change significantly over time. The standard needs to recognize such issues and grant an
exception if IBR fails to ride-through.
The SDT proposes to add continuous operating region, mandatory operating region, and permissive operating region terms to the Glossary of
Terms. However, these terms are specific to voltage ride-through requirements. There is no reason to limit those terms to voltage ride-through
capability only. The continuous and mandatory operation region terms could be applied to frequency ride-through capability as well. Refer to
IEEE 2800 to see how these terms are used for both voltage and frequency ride-through capabilities.
Continuous/mandatory/permissive operating region terms:
1. The SDT uses continuous/mandatory/permissive “operating” region as well as continuous/mandatory/permissive “operation” region.
Be consistent with either “operating” or “operation” throughout the standard.
2. Following comments to align voltage ranges in Attachment 1, Tables 1 & 2:
o Mandatory Operating Region term should read like following: The range of voltages, measured at the high-side of main power
o
transformer, that are ≥ 0.1 per unit and < 0.9 per unit OR > 1.1 per unit and ≤ 1.2 per unit.
Permissive Operating Region term should read like the following: The range of voltages, measured at the high-side of main
power transformer, that is ≤< 0.1 per unit.
3. These terms specify voltage threshold, but which voltage is used in these terms is in the Attachment 1. Per attachment 1, the
continuous and mandatory operating regions are based on phase-to-ground or phase-to-phase voltages. But the permissive operating
region is based on positive-sequence voltage. The defined terms should also make it clear which voltage thresholds are defined.
Consider revising the purpose statement as following: To ensure that Inverter-Based Resources (IBRs) remain connected and support the Bulk
Power System (BPS) during and after frequency and voltage excursions events.
Transmission Owner is included as a Functional Entity in section 4. However, footnote 1 makes it confusing. Would standard only apply to
Transmission Owner when it owns the VSC-HVDC transmission facility connecting isolated IBR with BPS?
Currently, PRC-029-1 allows for a GO or TO to seek an exemption from meeting voltage-ride through requirements in R1 and R2.
Southern Company believes that GOs and TOs should be able to seek exemptions from meeting frequency and voltage ride-through
requirements in R1 – R5.
The proposed standard only provides for VRT exemptions. Any consideration for FRT, ROCOF, phase angle?
Comment to PRC-024-4:
Facilities section 4.2.1.1 should include I2 of the BES definition and section 4.2.1.4 be removed or reference I2 in place of I4. I4 of the BES
definition was intended to point to IBRs at the time of the latest BES definition adoption in 2018 as dispersed power resources and was not
intended to point to synchronous generation resources.
Opportunity to clarify that legacy IBRs must maximize capabilities:
1. For NOGRR245, it has been advocated that legacy IBRs should make software / settings changes to maximize capabilities to meet or
approach the new ride-through requirements, unless such changes are unreasonably priced.
2. Southern’s experience is that software / settings changes are commercially reasonable. The “unreasonably priced” language is
intended to protect against price gauging from OEMs.
3. The current PRC-029-1 draft requires legacy IBRs to meet the new voltage ride-through requirements unless a documented technical
limitation exists. So a legacy IBR can document an exemption and have performance capabilities less than new VRT standard. But what
happens if that legacy IBR owner later learns there is an available software / setting change that would reduce or remove the
limitation? The current draft need clarity to address this.
4. Southern Company supports such a software / setting deployment requirement and believes it would (1) be commercially reasonable
and (2) more clearly require ride-through capability maximization.
Finally, Southern Company supports EEI and NAGF comments.
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Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
Document Name
Comment
While inclusive, is PRC-024-4 Facility Section Part 4.2.1.4 applicable to synchronous generators? Inclusion 4, when written, was designed to
catch the wind/solar aspects of the generation fleet. Inclusion 2 seems to be more appropriate (if not already covered in 4.2.1.1). The MPT
footnote appears to be limited to Quebec TO synchronous generators and does not include a reference to synchronous condensers (4.2.2
synchronous condenser applicable facilities simply says “step-up transformer(s)”). In PRC-024-4 Requirement 2 there is a reference to “MPT”
and the introduction of Transmission Owner within Requirement. It is not clear if applicable to TOs outside of Quebec based on the language
provided (from Requirement R2---“…a voltage excursion at the high-side of the GSU or MPT…” which the GSU/MPT is not mentioned in
applicable Facilities for synchronous condensers Section 4.2.2). In Attachment 1 there is a similar issue in that footnote 8 on page 21 mentions
the high-side of the GSU or MPT—Also should be noted that Footnote 8 does not appear to have an anchor (location within document to
reference the footnote). On page 22 of Attachment 2A there are references to the GSU/MPT as well. Just seeking clarification to avoid an
entity having a synchronous condenser indicating no applicability because of the language. This inconsistency in language does not appear to
follow items 8 (“Clear Language”) and 10 (“Consistent Terminology”) of the Ten Benchmarks of an Excellent Reliability Standard as referenced
in the Guideline for Quality Review of NERC Reliability Standards Project Documents.
PRC-029-1- SDTs need to use the same IBR terms and not add additional descriptors. Even the title of the Standard is not consistent. Should
use the proposed definitions in 2020-06 Verifications of Models and Data for Generators for clarity and consistency. There is no such Facility as
“IBR Registration Criteria”. Footnote 1 contains undefined terms which should be defined within this Standard if used. Because of the
inconsistency in definition use, it is not clear whether this applies to the IBR or IBR Unit locations (even when stated that it does not apply to
“individual inverter units or measurements takes at individual inverter unit terminals.” If looking at Project 2020-06, the inverters in a “common
IBR Unit configuration’ as shown in Figure 2.2 and 2.3 of the Technical Rational are exactly at the individual IBR Units (see link 202006_IBR_Definitions_Technical_Rationale_02222024.pdf (nerc.com). Is “exchange current” considered the same as “inject current” which is
used (various ways) in other Standards being proposed? The new terms introduced address range of voltages that may not correlate to the
Tables effectively. The Continuous Operating Region definition shows to include 1.1 per unit and should reflect the 1800 seconds in Table 1
and Table 2 but the 1.1 voltage per unit in the Tables show only a 1 second capability (Mathemataical expression includes 1.1 per unit in the
Table which it should not). Furthermore the 1.2 voltage per unit is shown to be included in the Mandatory Operating Region but NOT in the
Tables. Please clarify the expectations as entities had an issue in PRC-024 setting protection on the curves when initially mandatory. With
conflicting information, and Figures that are not as explicit or appear to match the Tables, WECC is concerned there may be confusion. This
language does not appear to follow Item 8 (“Clear Language”) and 10 of the Ten Benchmarks of an Excellent Reliability Standard as referenced
in the Guideline for Quality Review of NERC Reliability Standards Project Documents.
At a minimum, bullet 2 under Attachment 1 Table 2 should mention all the types of IBR as listed in other Standards (Type 3 and type 4 of wind
is covered in bullet 1, “Isolated IBR” is undefined, and 2.b. simply says “Other IBR plants” and limits hybrid to PV and “ESS” (possible typo that
should be “BESS”?). The “not limited to” should remain and the SDT may say all are covered with said language but clarity could be provided by
adding consistent language as used in other Standards. This inconsistency in language does not appear to follow items 10 (“Consistent
Terminology”) of the Ten Benchmarks of an Excellent Reliability Standard as referenced in the Guideline for Quality Review of NERC Reliability
Standards Project Documents.
Attachment 1 Table 2 Bullet 3 leaves the applicability to the TP but the TP is not called out as an applicable entity and this is an Operations
Assessment time horizon. In the Technical Rationale it clearly states “Compliance with PRC‐029 is determined from IBR ride‐through
performance during transmission system events in the field and not from interconnection studies, transmission planning studies, operational
planning studies, or from IBR models.” So, if IBRs in a hybrid plant have issues, the TP is to blame for calling out the incorrect Table? TPs may
very well have the studies to determine how long a ride-through should be sustained by IBRs, but there is no compliance responsibility (not
saying there should be—should be responsibility properly assigned through the Standards process). Bullet 4 allows the PC or TP to change the
Requirement criteria but there is no accountability if done (furthermore no notifications for awareness to those entities in the Operations side
of business). The apparent responsibility does not appear to follow items 1 (“Applicability”) of the Ten Benchmarks of an Excellent Reliability
Standard as referenced in the Guideline for Quality Review of NERC Reliability Standards Project Documents.
“MPT” is not defined in the Standard yet used repeatedly. Clarity can be provided with a footnote or addition of a definition (not that
synchronous condenser use in PRC-024-4 was unclear for MPT).
There are only Severe VSLs for Requirements R1 through R5. Clarity on where the inverter is (based on the 2020-06 drawings provided and
language in this Standards Technical Rational) will be important to understand. Failure of individual IBR units (as defined in 2020-06) appears to
not be addressed9unless it is intended to be addressed by the Sever VSL) and will have an impact on being complaint at the IBR level.
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Romel Aquino - Edison International - Southern California Edison Company - 3
Answer
Document Name
Comment
See comments submitted by the Edison Electric Institute
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
See EEI Comments
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Carey Salisbury - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer
Document Name
Comment
For each of the measures M1-M5, what “other evidence” can demonstrate compliance with R1-R5 other than recorded data? How does the
drafting team believe that generator owners can assure this performance expectation can be achieved prior to an actual event? There is no
test verification that can be performed to confirm the expected performance that considers every type of system disturbance that can occur.
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Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Document Name
Comment
Many references in the requirements point toward Continuous Operating Region, Mandatory Operating Region, and Permissive Operating
Region "as specified in Attachment 1", yet Attachment 1 does not specify any of these regions. Operating Regions should be added to
Attachment 1 tables and figures.
No-trip zone Figures 1 & 2 don't match the tables.
Is there a point or distinction being made by using capitalized "Systen" instead of undefined "system" in requirements?
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
Document Name
Comment
The Implementation Plan should be extended to 36 months to allow for monitoring equipment to be installed at sites completed before PRC029 becomes enforceable, to demonstrate performance and compliance with the standard.
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Dave Krueger - SERC Reliability Corporation - 10
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Document Name
Comment
On behalf of the SERC Generator Working Group:
Consider allowing for some period of time beyond the effective date of PRC-029 to document limitations per (R6) – contemplate the real
impact to BES reliability of limitation documentation.
Consider synchronizing the phase in of PRC-028 with the measures such as M1 stating “shall have evidence of actual recorded data...”.
For each of the measures M1-M5, what “other evidence” can demonstrate compliance with R1-R5 other than recorded data? How does the
drafting team believe that generator owners can assure this performance expectation can be achieved prior to an actual event? There is no
test verification that can be performed to confirm the expected performance that considers every type of system disturbance that can occur.
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Constantin Chitescu - Ontario Power Generation Inc. - 5
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Document Name
Comment
OPG supports IESO, HQ, and NPCC Regional Standards Committee’s comments.
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
MP agrees with the NSRF’s suggestions to enhance PRC-029, especially regarding limiting the power of equipment limitations from exempting
applicable entities from compliance, expanding the applicable facilities to include IBRs of 20MVA and above, and more precisely defining
applicable entities and facilities within the text of the standard.
MP also suggests that a formal definition of “Inverter-Based Resources” precede the adoption of the standard.
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Junji Yamaguchi - Hydro-Quebec (HQ) - 1,5
Answer
Document Name
Comment
We are concerned that the standard refers to a defined term for IBR which has yet to be adopted in project 2020-06.
We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
2021-04 (PRC-028) and 2023-02(PRC-030). Section 4.2.2 refers to IBR Registration criteria, however it is our understanding that section 4.2.1
would refer to GOs and TOs “that own equipment as identified in section 4.2” and where section 4.2 would indicate “the Elements associated
with (1) BES Inverter‐Based Resources; and (2) Non‐BES Inverter‐Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of
connection at a voltage greater than or equal to 60 kV.” .
We question why “attachment 1” and “Requirement R6” are written in bold.
Attachment 1: should the “including, but not limited to” in table 2 include the same list (or minimally the same wording) that is found in the
technical rationale of the IBR definition in project 2020-0?. For example, the IBR list in 2020-06 refers to “solar photovoltaic” whereas table 2
refers to “photovoltaic (PV)”.
In what standard does the PC/TP define the applicable table in point 3 of section 2 in attachment 1? Same question for the voltage base for per
unit calculation in both Attachment 1 and 2. Is there a corresponding requirement in another standard that requires the PC/TP to do this?
·
Terms : Mandatory and permissive operation should be defined based on the attachment figures allowing for interconnections to use
different requirements
·
A-4.2.2 What is the IBR registration criteria? Add a clear reference and make sur the user understands what the IBR registration criteria is.
·
B-R2-2.1 Attachment 1 only uses "no-trip zone". Define continuous operating region more clearly in the table (similar to what is done in
PRC-024-4)
·
B-R2-2.1.2 Can the TP ask for a mix of active/reactive power based on a predetermined ratio (currently only indicated as active or
reactive).
·
B-R2-2.2 Attachment 1 only uses "no-trip zone". Define "mandatory operation region" in Attachment 1.
·
B-R2-2.4 Permissive operation region is not used or defined in attachment 1.
·
B-R3. The document refers to an overvoltage value of 1.2pu. It should refer to a voltage exceeding the mandatory operating region in
order for Interconnections to set their own overvoltage table.
·
B-R3. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through these overvoltages ? An
exemption clause is required for existing IBR that cannot be modified or upgraded.
·
B-R4. The 5Hz/s value should be moved to Attachment 3 and B-R4 should only refer to the value in the Attachment.
·
B-R4. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through these frequencies and
ROCOF ? (for instance, for all the HQ connected projects, the ROCOF requirement was 4Hz/s) An exemption clause is required for existing IBR
that cannot be modified or upgraded.
·
B-R5. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through this phase angle jump ? An
exemption clause is required for existing IBR that cannot be modified or upgraded.
·
Attachment 1. Tables 1 and 2: Indicate what is considered as “continuous operation”, “mandatory operation” and “permissive operation”
in an additional column.
·
Attachment 1. HQ needs a Quebec regional variance since the Québec Interconnection has its own requirements in this regard.
·
Attachment 2. Bullet 3: This sentence is hard to read. Proposed replacement: "Each IBR shall not trip unless the cumulative time of one or
more instances in which the instantaneous voltage exceeds the respective voltage threshold over a 1-minute time window exceeds the
minimum ride-through time"
·
Attachment 2. HQ needs a Quebec regional variance since the Québec Interconnection has its own requirements in this regard.
·
Attachment 3. This attachment should also include the maximum absolute ROCOF value.
·
Attachment 3. HQ needs a Quebec regional variance (or the equivalent through the “regie de l’energie” approval process).
·
B-R2-2.1.2 Which entity between Transmission Planner, Planning Coordinator, Reliability Coordinator and Transmission Operator has
priority to specify those requirements?
·
B-R2-2.4 Which entity between Transmission Planner, Planning Coordinator, Reliability Coordinator and Transmission Operator has
priority to specify those requirements?
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Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
The implementation plan is also very aggressive and for some generators may be impossible to meet.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Overall comments:
1. Implementation date: 6 months is not sufficient for IBR manufacturers to meet the new standard. Instead we propose 2yrs to
accommodate product development/adequacy and appropriate validation.
2.
For R6, R3,R4,R5 should be included as well for the documented limitation communication (see R6 comments below).
3. For Attachment 1, for VSC-HVDC connected IBRs, it is not clear if Table 2 is applicable at the MPT on grid side or on the IBR side of HVDC
(see Attachment 1 comments below)
4.
For MFRT, GEV suggests to align to IEEE2800-2022 7.2.2.4 for consistency (see Attachment 1 comments below).
GEV comments to R6: The language in R6 only allows documented limitations for Requirements R1 and R2. The standard must allow for
documentation of limitations for Requirements R3, R4, and R5, as some existing site equipment was not designed to these requirements
originally.
GEV comments to Table 2 in Attachment 1: For VSC-HVDC connected IBRs, please clarify if Table 2 is applicable at the MPT on grid side or on
the IBR side.
GEV comments to MFRT: For MFRT requirements, GE Vernova strongly suggests that this language should align to IEEE2800-2022 7.2.2.4.
Exceptions from the IEEE standard that are relevant were not included, making these requirements inconsistent with 2800-2022.
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Daniel Gacek - Exelon - 1
Answer
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Document Name
Comment
PRC-24-4 mentined BPS in the Purpose section. We believe it is typo becuase the rest of the standard the applicabilty is for BES elements.
The implemetation plan to to strict to allow cost effect implementation.
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Imane Mrini - Austin Energy - 6, Group Name Austin Energy
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Document Name
Comment
AE supports comments provided by Texas RE and the NAGF
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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI offers the following additional comments on both PRC-024 & PRC-029:
PRC-029-1 (Applicability Section) Comments: EEI does not support the Applicability Section of PRC-029-1 for the following reasons:
1. Applicability details should not be contained in footnotes. Please remove footnote 1 from the Applicability Section.
2. Voltage Source Converter – High-voltage Direct Current (VSC-HVDC) are not defined or justified within the Technical Rationale as to why
these resources need to be added PRC-029.
3. Without a justification of a need to include VSC-HVDC systems, TOs should be removed from PRC-029-1.
4. EEI does not support the use of the term “BPS IBRs” because no such term exists in the NERC Glossary of Terms that might provide
entities with the knowledge to know definitively which IBRs are applicable.
5. EEI also does not support language that points to the registration criteria.
To address our concerns, we suggest the following changes to the Applicability Section of PRC-029-1, noting the Facilities portion of our
comments utilize the recommendations from the Project 2020-06 SDT (see removals (i.e., TOs, registration criteria, etc. and other text) and
boldface changes below:
4.
Applicability:
4.1
Functional Entities:
4.1.1
Generator Owner
Facilities:
(1) BES Inverter-Based Resources; and (2) Non-BES Inverter Based Resources (IBRs) that that either have or contribute to an aggregate
nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.
PRC-024 Comments: While there were no questions related to the proposed modifications to PRC-024-4, EEI does not support all of the
proposed changes made to PRC-024-4. Note the following:
Applicability Section of PRC-024-4
EEI does not support changing the intent of 4.2.1.4 (Previously 4.2.1.5) to include multiple synchronous generators connecting to a common
bus under the BES Definition, Inclusion I4. Since the development of the BES definition, Inclusion I4 did not include or intend to include
synchronous generators. Had that been the intent, the SDT could have included synchronous generator resources in I4. Furthermore, the BES
Reference Document states in Chapter I4: BES Inclusion the following:
Dispersed power producing resources are small-scale power generation technologies that use a system designed primarily for aggregating
capacity providing an alternative to, or an enhancement of, the traditional electric power system. Examples could include, but are not limited
to: solar, geothermal, energy storage, flywheels, wind, microturbines, and fuel cells.
While EEI is open to making modifications to the BES Definition, trying to provide interpretations within individual Applicability Sections of
proposed NERC Reliability Guidelines is not the proper method to make such a change. For this reason, and since 4.2.1.4 (previously 4.2.1.5)
was intended to address IBRs; this part of the Applicability Section of PRC-024-4 should be deleted.
Comments on the proposed New Definitions
EEI has no concerns with the proposed new definitions, but we do have some non-substantive comments on their usage throughout PRC-029,
Implementation Plan and Technical Rationale. (See below)
•
•
Usage of the newly defined terms deviated from the defined term within PRC-029 and the Technical Rational. (i.e., Operating vs.
Operations)
Incorrectly stating in the Implementation Plan that there were no newly defined terms. Please correct this error.
Continuous Operating Region – Only used once in Requirement 2.3.
•
•
Continuous Operation Region used in Requirements 2.1, 2.1.2, 2.4, & once in Attachment 1 (i.e., suggest changing the defined term to
Continuous Operation Region or correct to Continuous Operating Region throughout)
Continuous Operation Region used twice in the Technical Rationale; Continuous Operating Region never used in the Technical
Rationale.
Mandatory Operating Region – Never used in PRC-029
•
•
Mandatory Operation Region used in PRC-029 in Requirements 2.2, 2.3, 2.4 & once in Attachment 1 (i.e., suggest changing the defined
term to Mandatory Operation Region or correct to Mandatory Operating Region throughout)
Mandatory Operation Region was used twice in Technical Rationale; Mandatory Operating Region was never used in the Technical
Rational.
Permissive Operating Region – Never used in PRC-029
•
Permissive Operation Region used in PRC-029 in Requirements 2.3, 2.4, & used twice in Attachment 1 (i.e., suggest changing the defined
term to Permissive Operation Region or correct to Permissive Operating Region throughout)
•
Permissive Operation Region used once in the Technical Rationale; Permissive Operating Region never used in the Technical Rationale.
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Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
Document Name
Comment
1. Implementation should align with PRC-028-1 proposed implementation to ensure data collecting information is available to adhere to PRC029-1.
2. PRC-024-4 Applicability and Purpose should include asynchronous type 1 and type 2 wind since these are not IBRs and therefore not
applicable to PRC-029:
4.2.1.4 Elements that are designed primarily for the delivery of capacity from the multiple synchronous generators or asynchronous type 1 or
type 2 wind generators, connecting to a common bus identified in the BES Definition, Inclusion I4, to the point where those resources
aggregate to greater than 75 MVA.
4.2.1.6 Type I and type II asynchronous wind generation identified in the BES Definition, Inclusion I4.
3. Suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggested the following language be included in the applicability section. Facilities: The
Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment
Please consider using the risk-based approach when drafting standards.
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Duke Energy recommends the implementation of EEI and NAGF comments.
For clarification, expand the following subparts as stated below:
4.1. Functional Entities:
4.1.1. Transmission Owner that owns equipment as identified in section 4.2.
4.1.2. Generator Owner that owns equipment as identified in section 4.2.
4.2. Facilities: The Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or
contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
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Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
Document Name
Comment
The applicability section should match applicability sections of other IBR standards under development, PRC-030 and PRC-028.
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
Comment
The NAGF provides the following additional comments for consideration:
PRC-024:
a.
Section 4.2.1.2 – Consider adding the language “Main Power Transformer (MPT)”.
b. Section 4.2.1.4 and 4.2.1.5 - Recommend that the proposed language be modified to reference BES Definition – Inclusion I2 instead of
Inclusion I4 – Dispersed Power Producing Resources. The proposed new PRC-029 standard’s focus is on Frequency and Voltage Ride‐through
Requirements for Inverter‐Based Generating Resources and therefore should include a reference BES I4 resources.
PRC-029:
a. Terms – the NAGF requests additional clarification on how the proposed defined terms work with the proposed PRC-030. Will analysis be
required for an event under the proposed PRC-029 and under PRC-030? Potential double jeopardy issue. Alternatively, if tripping is allowed
under PRC-029, would an analysis still be required under PR-030?
b.
Section 4.2 - Facilities:
i.
Use of the capitalized term “Bulk Power System (BPS) Inverter-Based Resources (IBR)” should be reviewed as it is not a defined term in the
NERC Glossary of Terms. In addition, it is very likely that not all Bulk Power System Inverter-Based Resources will be registered even under
NERC’s modified Rules of Procedure. Until the definition of Inverter-Based Resources is approved, the SDT should only use the term “inverterbased resource” if needed.
ii.
c.
The NAGF requests clarification if IBR plants that include synchronous condensers should meet the PRC-029 requirements.
Comments Related to Attachments:
i.
Attachment 1 – Recommend adding to the table a column that species what area is the Continuous Operating Region, Mandatory
Operating Region and Permissive Operating Region. As currently structured, it is not clear where the different regions begin or end. If possible,
the NAGF recommends a graph showing the different areas for clarity.
ii.
The abbreviations “MPT” and “ESS” are not defined within the standard/attachment. Please ensure all acronyms/initializations are fully
defined for use.
iii.
If the term ESS is intended to mean Energy Storage Systems, does this also apply to water storage systems, or only Battery Energy
Storage Systems? If the intent is to refer to Battery Energy Storage Systems, please modify the term used.
iv.
Attachment 1, note 3 – There does not appear to be a requirement proposed for the Transmission Planner (TP) to provide direction as
stated in note 3. Request clarification on how the TP will provide such guidance/direction on the applicable table to be used.
v.
Attachment 1, Note 7 – These notes appear to state that no unit should trip in a 10 second period if voltage is fluctuating, but the
summation of time interval does not appear to be 10 seconds in most instances. As an example, assuming that the SDT intends for a generator
to follow the voltage for 10 seconds when it is fluctuating between .7 and .5, the unit should be allowed to trip when voltage is below the .5 level
for 1.2 seconds. However, note 7 appears to state that there is a 10 second limit if voltage were to be below .7 for 1 second, then goes below .5
for 3 seconds, then returns to the .7 for 6 seconds. Please verify this interpretation is correct, or how this language should be understood.
vi.
Attachment 1, Notes 7 and 8 – Both of these items discuss cumulative numbers in Tables 1 and 2. As worded, it is unclear if the intent is
to add the numbers in Table 1 to the numbers in Table 2, or if the intent is to add the numbers in the second column of Table 1 for those
resources that are considered Table 1 entities, and similar for Table 2 entities. Please clarify the wording so the intent of the standard is clear.
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Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of its members:
PRC-029-1 (Applicability Section) Comments: EEI does not support the Applicability Section of PRC-029-1 for the following reasons:
1.
Applicability details should not be contained in footnotes. Please remove footnote 1 from the Applicability Section.
2. Voltage Source Converter – High-voltage Direct Current (VSC-HVDC) are not defined or justified within the Technical Rationale as to why
these resources need to be added PRC-029.
3.
Without a justification of a need to include VSC-HVDC systems, TOs should be removed from PRC-029-1.
4. EEI does not support the use of the term “BPS IBRs” because no such term exists in the NERC Glossary of Terms that might provide entities
with the knowledge to know definitively which IBRs are applicable.
5.
EEI also does not support language that points to the registration criteria.
To address our concerns, we suggest the following language in the Applicability Section of PRC-029-1, noting the Facilities portion of our
comments utilize the recommendations from the Project 2020-06 SDT):
4.
4.1
Applicability:
Functional Entities:
4.1.1 Generator Owner
4.2
Facilities: (1) BES Inverter-Based Resources; and (2) Non-BES Inverter Based Resources (IBRs) that that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
PRC-024 Comments: While there were no questions related to the proposed modifications to PRC-024-4, EEI does not support all of the
proposed changes made to PRC-024-4. Note the following:
Applicability Section of PRC-024-4
EEI does not support changing the intent of 4.2.1.4 (Previously 4.2.1.5) to include multiple synchronous generators connecting to a common
bus under the BES Definition, Inclusion I4. Since the development of the BES definition, Inclusion I4 did not include or intend to include
synchronous generators. Had that been the intent, the SDT could have included synchronous generator resources in I4. Furthermore, the BES
Reference Document states in Chapter I4: BES Inclusion the following:
Dispersed power producing resources are small-scale power generation technologies that use a system designed primarily for aggregating
capacity providing an alternative to, or an enhancement of, the traditional electric power system. Examples could include, but are not limited
to: solar, geothermal, energy storage, flywheels, wind, microturbines, and fuel cells.
While EEI is open to making modifications to the BES Definition, trying to provide interpretations within individual Applicability Sections of
proposed NERC Reliability Guidelines is not the proper method to make such a change. For this reason, and since 4.2.1.4 (previously 4.2.1.5)
was intended to address IBRs; this part of the Applicability Section of PRC-024-4 should be deleted.
Comments on the proposed New Definitions
EEI has no concerns with the proposed new definitions, but we do have some non-substantive comments on their usage throughout PRC-029,
Implementation Plan and Technical Rationale. (See below)
•
Usage of the newly defined terms deviated from the defined term within PRC-029 and the Technical Rational. (i.e., Operating vs.
Operations)
•
Incorrectly stating in the Implementation Plan that there were no newly defined terms. Please correct this error.
Continuous Operating Region – Only used once in Requirement 2.3.
•
•
Continuous Operation Region used in Requirements 2.1, 2.1.2, 2.4, & once in Attachment 1 (i.e., suggest changing the defined term to
Continuous Operation Region or correct to Continuous Operating Region throughout)
Continuous Operation Region used twice in the Technical Rationale; Continuous Operating Region never used in the Technical
Rationale.
Mandatory Operating Region – Never used in PRC-029
•
•
Mandatory Operation Region used in PRC-029 in Requirements 2.2, 2.3, 2.4 & once in Attachment 1 (i.e., suggest changing the defined
term to Mandatory Operation Region or correct to Mandatory Operating Region throughout)
Mandatory Operation Region was used twice in Technical Rationale; Mandatory Operating Region was never used in the Technical
Rational.
Permissive Operating Region – Never used in PRC-029
•
•
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Permissive Operation Region used in PRC-029 in Requirements 2.3, 2.4, & used twice in Attachment 1 (i.e., suggest changing the defined
term to Permissive Operation Region or correct to Permissive Operating Region throughout)
Permissive Operation Region used once in the Technical Rationale; Permissive Operating Region never used in the Technical Rationale.
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Joy Brake - Nova Scotia Power Inc. - NA - Not Applicable - NPCC
Answer
Document Name
Comment
If using ALL CAPS, consider RCF as the acronym. It is not that significant a metric to require capitalization of “of”.
RoCoF is also used in many other jurisdictions.
FERC order:
“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. “ Yes, but PRC-024 now prohibits this. In some cases, settings in the older plants can be tweaked to improve performance but we
are having trouble getting good models from the GOs. To address NERC concerns we need requirements for better models.
“some models and simulations incorrectly predict that some IBRs will ride through disturbances, i.e., maintain real power output at predisturbance levels and provide voltage and frequency support consistent with Reliability Standard PRC-024-3”. Only if incorrectly modelled.
Require better modelling to identify issues and determine mitigations. PRC-029 will not stop the problem of simulating a system that works
great in the virtual world but will not perform when called upon.
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Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3 - WECC
Answer
Document Name
Comment
PNM agrees with EEI's comments.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has the following additional comments for PRC-029-1:
1. Texas RE recommends the new terms included in PRC-029-1 clearly state the voltage measurements included are at the high-side of the
main transformer connecting to the BPS transmission system. Texas RE suggests the following changes (in bold):
Term(s): Continuous Operating Region – The range of voltages, measured at the high‐side of the BPS main power transformer, that are ≥ 0.9
per unit and ≤ 1.1 per unit.
Mandatory Operating Region – The range of voltages, measured at the high‐side of the BPS main power transformer, that are > 0.1 per unit and
< 0.9 per unit – or – > 1.1 and ≤ 1.2 per unit.
Permissive Operating Region – The range of voltages, measured at the high‐side of the BPS main power transformer, that is ≤ 0.1 per unit.
2.
Consider changing ‘each IBR’ to ‘each IBR Facility’ for all the requirements.
3.
For consistency, consider modifying the title of the standard to (in bold):
Title: Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
4. Consider changing 4.2.1 to BES IBRs (instead of BPS IBRs) to be consistent with other PRC standards such as proposed reliability standards
PRC-028-1 and PRC-024-4.
5. Consider changing voltage (per unit) in Attachment 1 (third row) to greater than 1.05 pu only (i.e. remove the equal 1.05 criterion). Typical
BES and BPS systems are expected to operate continuously for voltage levels 0.95 – 1.05 pu.
Attachment 1 - changes
In Table 1 & Table 2 change > 1.05 to >1.05
Add the following to Table 1 and 2:
Voltage (per unit):
> 0.9 Minimum Ride-Through: Continuous
Voltage (per unit):
< 1.05
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Minimum Ride-Through: Continuous
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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Comment
•
GTC recommends increasing the implementation timeline to be 12 to 18 months after the effective date of the applicable
governmental authority’s order approving for both the PRC-024-4 and PRC-029-1 standards.
•
There were no balloting questions provided for the language changes in the PRC-024-4 standard. GTC recommends providing balloting
questions for the industry to respond to the changes in the PRC-024-4 standard.
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name
Comment
NERC should remain consistent with their revised Rules of Procedure by avoiding the use of “BPS IBR” terminology in the applicable facilities.
This is overly broad and can lead to misinterpretation for Generator Owners who own IBRs that do and do not fit the 60 kV and 20 MVA
thresholds. The third question in the Project 2020-06 comment form, copied below, is a clearer definition of IBR which NERC has determined
has a material impact to the BPS. NERC should consider adopting this terminology in PRC-029
Section 4. Applicability:
4.1 Functional Entities: Generator Owner, Generator Operator
4.2 Facilities: (1) BES Inverter-Based Resources; and (2) Non-BES Inverter Based Resources (IBRs) that that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and North American Generator Forum
(NAGF) on question 4
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Dominion Energy supports EEI comments. In addition, we have the following coments:
The term BPS IBRs and IBR Registration Criteria are not clear-cut Facilities. The standard should reference terms available for use in the NERC
Glossary of Terms to determine applicability, such as the BES defintion. As stated in the EEI comments, the BES defintion would be the
appropriate place to address defintions of this type.
The Effective Date of 6 months following approval by FERC is too short for Generator Owners and Transmission Owners that own numerous IBR
generating sites, to develop internal controls and processes; and perform the necessary compliance evaluations and possible settings changes
to meet the ride-through criteria. Conversely, 6 months after the effective date is too long for documenting Limitations per Requirement R6.
The documentation of limitations is typically done during the compliance analysis and study. A staggered implementation plan, that takes into
account the registration and requirements for Level 2 GO registrations should be designed and implemented.
The Implementation Plan should also consider those IBRs that are approved to be built and have had their Interconnection Studies approved.
The contracts for building these sites are signed years in advance with the inverters ordered. A staggered applicability for R6 should be
considered that allow for projects in service prior to 2027 or 2028 to be eligible for equipment limitations and those in service after to meet the
performance criteria without limitations.
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George E Brown - Pattern Operators LP - 5
Answer
Document Name
Comment
Pattern Energy supports GRE’s comments for this question.
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Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer
Document Name
Comment
The SDT explains in the draft PRC-029-1 Technical Rationale that “An IBR becomes noncompliant with PRC‐029 only when an event in the field
occurs that shows that one or more requirements were not satisfied.” This, coupled with the removal of IBRs from PRC-024 applicability, would
result in a lack of accountability until actual harm (i.e., failure to adequately support the reliability of the BES during a system event) occurs for
IBRs not prepared to meet the performance requirements. There would not be auditable and enforceable requirements for owners of IBRs to
proactively take action to reasonably ensure the performance requirements will be met. Reliability standards exist to prevent potential harm,
which minimizes actual harm.
While RF acknowledges the observed limitations of the existing PRC-024 standard in preventing the undesirable responses of IBRs to the system
disturbance events cited in the SAR, RF does not support the whole-sale elimination of frequency and voltage protection settings verification
requirements for IBRs. Generator frequency protection settings verification is critical in ensuring UFLS programs are adequately coordinated
with generator capabilities, and RF does not wish to rely on self-revealing events to determine where miscoordination exists between IBR
frequency protection and UFLS. Unless additional verification requirements are added to PRC-029, RF believes PRC-024 should remain
applicable to IBRs.
RF notes that the range of system conditions in which PRC-029 would require IBRs to remain online appear to be significantly larger than those
established in PRC-024 (which would remain applicable to synchronous generators). Although the unique capabilities of IBRs may support such
a large expansion for only IBR resource types, additional discussion of the technical justification for this expansion would be useful.
Regarding implementation, RF finds a 12-month implementation period acceptable.
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Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
The implementation plan is also very aggressive and for some generators may be impossible to meet.
Kimberly Turco on behalf of Constellation Segments 5 and 6
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Ruchi Shah - AES - AES Corporation - 5
Answer
Document Name
Comment
•
The new performance-based approach opens us up to a lot of issues with other tripping/cessation besides basic overvoltage/under
voltage/frequency that our operations team has seen during events.
o
This protection is not modeled in basic models right now and will require substantial effort to ensure we can perform as
required. AES CE requests that the Implementation Plan be modified to use a phased-in approach for existing sites to allow
adequate time to prepare for these performance requirements.
Additionally, the standard and rationale is absent of language on studies/assessments that should be performed. AESCE believes
that providing examples of the types of studies and assessments that should be run to ensure that resources would perform as
expected is necessary for reliability and adequate implementation of this standard by GOs.
•
•
•
•
•
Please provide additional clarification on acceptable limitations under R6. Language such as “hardware replacements or other costly
upgrades” from the Technical rationale document is vague and open to interpretation.
AESCE would like the SDT to consider the challenges with ensuring plants, particularly legacy operational plants, can ride through per
the requirements. To ensure this or identify equipment limitations, studies and equipment information is necessary and is not available
for most legacy equipment.
First, EMT studies and RMS model studies are necessary to study plant ride-through capabilities specified in the standard. However,
there are significant challenges with these models today that should be considered in the implementation and equipment limitations.
Quality EMT models including all equipment information needed are not available for legacy equipment (inverters, PPCs). Many legacy
inverters do not have an EMT model, and those that do have models that are not adequately validated against equipment performance.
Creation of models is either not supported or can be developed at a very high cost. Models created after the inverters were initially
released are of inadequate quality because the equipment is no longer able to be in a lab environment.
o To consider this, AESCE suggests that the SDT include exceptions for legacy equipment where the performance may not be
predictable due to a lack of modeling or inverter information.
Second, not all current models are of the level of quality that they can be used to ensure that the plant will ride-through as specified in
the standard. The implementation of this standard should consider the significant resources and cost to implement.
Third, manufacturer support for GOs to ensure that IBRs only trip to prevent equipment damage as noted in R2.5 is limited for existing
equipment and is unavailable for some legacy equipment. Additionally, this support has been very costly for us to obtain and will strain
manufacturer resources to provide.
Considering these limitations, AESCE suggests that the SDT include exceptions for legacy equipment where 1. The performance may not be
predictable due to a lack of accurate models at a reasonable cost, 2. Equipment limits may not be known or where the cost may be egregious to
provide.
•
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Expectations for demonstrating and checking performance are unclear, please add language or examples to illustrate how the SDT
believes this will happen.
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Rhonda Jones - Invenergy LLC - 5
Answer
Document Name
Comment
Invenergy thanks the drafting team for their work and the opportunity to provide comments.
Regarding the proposed Implementation Plan for R6, six months may not be enough time to gather all applicable documentation regarding
equipment limitations. There are a limited number of vendors of IBR technology that have serviced the industry, and they will be inundated
with requests for documentation once the standard becomes effective.
On a final note, NERC appears to have borrowed from some of the requirements within IEEE 2800-2022 and brought them into this standard
(e.g. the phase-angle jump requirement, etc.). Invenergy believes it would be incorrect to adopt such requirements until the work of IEEE
Working Group p2800.2 has been completed and their recommended practice standard published. Without such an approved recommended
practice standard, there is no industry-wide accepted set of procedures for verifying conformity to the borrowed requirements in PRC-029-1.
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David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
Document Name
Comment
Ameren agrees with EEI's comments.
In addition, Ameren believes that ride-through requirements should be in a MOD standard instead of a PRC standard. Protection relay
engineers do not have access to the necessary IBR equipment and do not have the expertise to determine the root cause of why an IBR
behaved in an unexpected manner. Thus, evaluating and establishing a CAP to correct a reduction in power following a disturbance will not be
performed by a relay engineer.
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Colin Chilcoat - Invenergy LLC - 6
Answer
Document Name
Comment
Invenergy thanks the drafting team for their work and the opportunity to provide comments.
Regarding the proposed Implementation Plan for R6, six months may not be enough time to gather all applicable documentation regarding
equipment limitations. There are a limited number of vendors of IBR technology that have serviced the industry, and they will be inundated
with requests for documentation once the standard becomes effective.
On a final note, NERC appears to have borrowed from some of the requirements within IEEE 2800-2022 and brought them into this standard
(e.g. the phase-angle jump requirement, etc.). Invenergy believes it would be incorrect to adopt such requirements until the work of IEEE
Working Group p2800.2 has been completed and their recommended practice standard published. Without such an approved recommended
practice standard, there is no industry-wide accepted set of procedures for verifying conformity to the borrowed requirements in PRC-029-1.
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Brittany Millard - Lincoln Electric System - 5
Answer
Document Name
Comment
With regards to PRC-029 we woulkd ask:
1. Clarify and emphasize that limitations must not be construed as complete exemptions. If entities are unable to ride-through portions of
the ride-through curve, this does not automatically exempt them from complying with the balance of the ride-through curve as described in the
Technical Rationale. While this is clear in the Technical Rationale for Requirement R6 (page 9), this point needs to be brought out more clearly
in the PRC-029 standard itself.
2. Expand PRC-029 to require Corrective Action Plans be implemented to remove equipment limitations within a specified timeline.
3.
we recommend modifying Section 4 of PRC-029-1 as follows:
4. Applicability:
4.1 Functional Entities: 4.1.1 Generator Owner that owns equipment identified in section 4.2, 4.1.2 Transmission Owner that owns equipment
as identified in section 4.2 Generator Owner that owns equipment identified in section 4.2.
4.2 Facilities: to include 4.2.3 Shunt static or dynamic reactive device(s) associated with IBR that either have or contribute to meeting the
performance requirements.
4. The standard is event-based compliance that requires installing recorded equipment data with higher sampling rates at all applicable
legacy IBR Facilities. Therefore, we suggest that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC-028-1) for
the legacy IBR. Also, we suggest having a different implementation plan for the legacy IBR from IBR connected after the approval date of
PRC-029.
5. Some clarity on how these requirements would be enforced in the location where no data recording is available at the IBR
facility during system events.
6. M1-M5 required GO to maintain the evidence of actual recorded data or other evidence for each applicable IBR demonstrating
adherence to ride‐through requirements, as specified in Requirement R1-R5. What are the criteria for selecting the event(s) that should be
analyzed to demonstrate compliance with the VRT, FRT, and VRT performance requirement(s)? If the performance does not meet the
requirement(s), do Generator Owner needs to present a correction action plan and provide it to each applicable Reliability Coordinator. We
suggest coordinate this project 2020-02 (PRC-029) with project 2023-02(PRC-030) regarding the IBR ride‐through performance analysis.
7.
We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggested the following language be included in the applicability section. Facilities: The
Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
8. The title of the standard calls out “Inverter-Based Generating Resources”, should “Generating” be removed to be consistent?
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Ben Hammer - Western Area Power Administration - 1
Answer
Document Name
Comment
Several enhansments to PRC-029 are requested:
1. Clarify and emphasize that limitations must not be construed as complete exemptions. If entities are unable to ride-through portions
of the ride-through curve, this does not automatically exempt them from complying with the balance of the ride-through curve as
described in the Technical Rationale. While this is clear in the Technical Rationale for Requirement R6 (page 9), this point needs to be
brought out more clearly in the PRC-029 standard itself.
2. Expand PRC-029 to require Corrective Action Plans be implemented to remove equipment limitations within a specified timeline.
3. we recommend modifying Section 4 of PRC-029-1 as follows:
4. Applicability:
4.1 Functional Entities: 4.1.1 Generator Owner that owns equipment identified in section 4.2, 4.1.2 Transmission Owner that owns
equipment as identified in section 4.2 Generator Owner that owns equipment identified in section 4.2.
4.2 Facilities: to include 4.2.3 Shunt static or dynamic reactive device(s) associated with IBR that either have or contribute to meeting the
performance requirements.
4. The standard is event-based compliance that requires installing recorded equipment data with higher sampling rates at all applicable
legacy IBR Facilities. Therefore, we suggest that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC028-1) for the legacy IBR. Also, we suggest having a different implementation plan for the legacy IBR from IBR connected after the
approval date of PRC-029.
5. Some clarity on how these requirements would be enforced in the location where no data recording is available at the IBR
facility during system events.
6. M1-M5 required GO to maintain the evidence of actual recorded data or other evidence for each applicable IBR demonstrating
adherence to ride‐through requirements, as specified in Requirement R1-R5. What are the criteria for selecting the event(s) that
should be analyzed to demonstrate compliance with the VRT, FRT, and VRT performance requirement(s)? If the performance does
not meet the requirement(s), do Generator Owner needs to present a correction action plan and provide it to each applicable
Reliability Coordinator. We suggest coordinate this project 2020-02 (PRC-029) with project 2023-02(PRC-030) regarding the IBR ride‐
through performance analysis.
7. We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects
such as Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggested the following language be included in the applicability
section. Facilities: The Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that
either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system
designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
New terms are introduced on page 2 (Continuous Operating Region, Mandatory Operating Region, Permissive Operating
Region). Requirement R1 includes the words “operation regions” and R2 includes the terms “Continuous Operation Region” (Part 2.1) and
“Mandatory Operation Region” (Part 2.2). We recommend the drafting team review all instances of “operation region” within the standard
and determine if it should be changed to “operating region” to align with the proposed terms. Or conversely, consider if the word “Operating”
within the defined terms should be changed to “Operation”.
For Requirement R2:
How will the Generator Owner or Transmission Owner of an applicable IBR be made aware that a PRC-029-1 applicable “System disturbance”
has occurred within their associated Planning Coordinator(s) area(s)?
Part 2.1.2 refers to “requirements [for active or reactive power preference] specified by the Transmission Planner, Planning Coordinator,
Reliability Coordinator, or Transmission Operator”.
Part 2.2.2 refers to a “certain magnitude of reactive power response to voltage changes” or a preference for “active power priority instead of
reactive power priority” that can be specified by the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission
Operator.
Part 2.4 refers to a “lower post‐disturbance active power level requirement” or “different post‐disturbance active power restoration time”
specified by the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
With up to four registered entity types being able to provide these preferences (spanning the operations and planning time horizons), is there a
chance the Generator Owner or Transmission Owner of an applicable IBR will receive conflicting requirements? Is there a corresponding
standard(s) that includes a requirement(s) for the TP, PC, RC or TOP to specify these preferences?
For Requirement R3, how will the Generator Owner or Transmission Owner of an applicable IBR know that a PRC-029-1 applicable transient
overvoltage period has occurred within their associated Planning Coordinator(s) area(s)?
For Requirement R4, how will the Generator Owner or Transmission Owner of an applicable IBR know that a PRC-029-1 applicable frequency
excursion event has occurred within their associated Planning Coordinator(s) area(s)?
Requirement R6 requires that a Generator Owner or Transmission Owner of an applicable IBR that has a documented equipment limitation,
that prevents it from meeting voltage ride‐through requirements as detailed in Requirements R1 and R2, communicate each equipment
limitation to their associated Planning Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s). Since the Transmission Operator
is also identified in R2, it seems strange to omit the TOP from R6.
With regard to the Implementation Plan, having PRC-024-4 becoming effective six months after approval is reasonable, since this Standard’s
changes are primarily to limit its applicability to synchronous generators / condensers, and they should already be compliant with the existing
version.
However, having PRC-029-1 become effective six months after approval is not reasonable. The technical rationale doesn't provide guidance on
how to provide evidence of compliance. It can take considerable time to develop and perform the required analyses, generate potential design
changes to make the required setting changes, and implement them.
We recommend providing implementation guidance or technical data showing how to demonstrate performance.
We also recommend allowing at least 24 months to achieve full compliance with the proposed requirements in PRC-029-1.
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Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name
Comment
Black Hills Corporation supports EEI’s and NAGF’s additional comments.
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
FirstEnergy finds inconsistency in how these newly created standards are applying IBR applicability in the Applicable Section – leading to
confusion from one project and standard to another. We request these Drafting Teams align these Applicable Sections.
FE cannot support the Implementation Plan until it is clear how R2 will be clarified toward requirement responsibility.
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Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by the NAGF
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Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District,
3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Tim Kelley, Group Name SMUD and BANC
Answer
Document Name
Comment
The language proposed in the Applicability section of PRC-029-1 is inadequate to define what IBR Facilities this Standard would apply to. The
terms “BPS IBRs” and “IBR Registration Criteria” are too broad, vague, and undefined, and could include all IBRs interconnected to the Bulk
Power System at any voltage level.
SMUD recommends the Standards Drafting Team use similar language to that proposed in NERC Standards Project 2021-04 Modifications to
PRC-002 - Phase II, PRC-028-1 draft #2. If modified accordingly, the Applicability section would state:
“4.1. Functional Entities:
4.1.1. Generator Owner that owns equipment as identified in section 4.2
4.1.2. Transmission Owner that owns equipment as identified in section 4.2
4.2. Facilities: The Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or
contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.”
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Brian Lindsey - Entergy - 1
Answer
Document Name
Comment
No Comment
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
NA
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Michael Brytowski - Great River Energy - 3
Answer
Document Name
Comment
1. Clarify and emphasize that limitations must not be construed as complete exemptions. If entities are unable to ride-through portions of
the ride-through curve, this does not automatically exempt them from complying with the balance of the ride-through curve as described in the
Technical Rationale. While this is clear in the Technical Rationale for Requirement R6 (page 9), this point needs to be brought out more clearly
in the PRC-029 standard itself.
2. Expand PRC-029 to require Corrective Action Plans be implemented to remove equipment limitations within a specified timeline.
3.. we recommend modifying Section 4 of PRC-029-1 as follows:
4. Applicability:
4.1 Functional Entities: 4.1.1 Generator Owner that owns equipment identified in section 4.2, 4.1.2 Transmission Owner that owns equipment
as identified in section 4.2 Generator Owner that owns equipment identified in section 4.2.
4.2 Facilities: to include 4.2.3 Shunt static or dynamic reactive device(s) associated with IBR that either have or contribute to meeting the
performance requirements.
4. The standard is event-based compliance that requires installing recorded equipment data with higher sampling rates at all applicable
legacy IBR Facilities. Therefore, we suggest that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC-028-1) for
the legacy IBR. Also, we suggest having a different implementation plan for the legacy IBR from IBR connected after the approval date of
PRC-029.
5. Some clarity on how these requirements would be enforced in the location where no data recording is available at the IBR facility during
system events.
6. M1-M5 required GO to maintain the evidence of actual recorded data or other evidence for each applicable IBR demonstrating
adherence to ride‐through requirements, as specified in Requirement R1-R5. What are the criteria for selecting the event(s) that should be
analyzed to demonstrate compliance with the VRT, FRT, and VRT performance requirement(s)? If the performance does not meet the
requirement(s), do Generator Owner needs to present a correction action plan and provide it to each applicable Reliability Coordinator. We
suggest coordinate this project 2020-02 (PRC-029) with project 2023-02(PRC-030) regarding the IBR ride‐through performance analysis.
7. We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggested the following language be included in the applicability section. Facilities: The
Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
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Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer
Document Name
Comment
BC Hydro appreciates the drafting team’s efforts and the opportunity to comment, and offers the following:
1. The Applicability section (A.4.2 Facilities) of PRC-029-1 references BPS IBR and IBR Registration Criteria. BC Hydro suggests that the
Facilities section instead use wording reflective of the proposed Category 2 GO as included in the recent revisions to the NERC Rules of
Procedure.
2. BC Hydro suggests that the use of “shall” in the language of the Measures may not be appropriate as it could imply a new Requirement
or expansion on the existing Requirement. The obligation of having evidence is adequately established and enforceable via the CMEP.
3. The Measure M3 of PRC-029-1 references "the associated Planning Coordinator". The associated Requirement R3 does not. BC Hydro
suggests that this is not needed as there may be switching events within a PC's area that do not create overvoltage conditions to trigger
R3 for certain IBRs within the PC area.
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Helen Lainis - Independent Electricity System Operator - 2
Answer
Document Name
Comment
Applicability:
In Introduction, Section 4.2.2, it is not obvious what aspect of ‘IBR Registration Criteria’ makes an IBR an ‘applicable’ IBR – is it simply that an
IBR meets NERC Registration Criteria? This bullet point should be elaborated to ensure clarity.
Event-Based Standard:
The IESO has concerns with this standard being an event-based standard, in that it does not necessarily provide an assurance of reliability
before events occur, such as would be provided by having an engineering analysis, or bench-testing/real-time simulations of controls
equipment that indicates successful ride through of prescribed disturbances is expected.
Without disturbance events that challenge the IBRs to perform properly it would be unknown if the IBR is compliant. At a minimum, the
measures (e.g, M2-M5) should be extended to allow a statement that no such events are known to have occurred to ‘count’ as evidence of
compliance.
Presentation of Ride Through Ranges:
The intended ride through requirements could be made more clear if the ‘minimum ride through times’ were associated with precisely stated,
non-overlapping ranges of voltages or frequencies, such as in the example ‘Table 2’ provided by the IESO in the comments above, for Section
2.1.
Nominal Voltages:
To ensure clarity of intent in note #4 of Attachment 1, the 'nominal' system voltage values should be listed as they are in the existing PRC-024,
i.e., “(e.g., 100 kV, 115 kV, 138 kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.)”
Harmonize Tables, Figures, Requirements:
The levels of voltage/frequency excursion and the minimum ride through times for all tables, figures, and any associated performance
requirements that modify the requirements at given times should be carefully reviewed and harmonized. There are presently some conflicting
entries in the tables/figures.
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Ontario Power Generation Inc., 5, Chitescu Constantin
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Chantal Mazza - Hydro-Quebec (HQ) - 1 - NPCC
Answer
Document Name
Comment
We are concerned that the standard refers to a defined term for IBR which has yet to be adopted in project 2020-06.
We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
2021-04 (PRC-028) and 2023-02(PRC-030). Section 4.2.2 refers to IBR Registration criteria, however it is our understanding that section 4.2.1
would refer to GOs and TOs “that own equipment as identified in section 4.2” and where section 4.2 would indicate “the Elements associated
with (1) BES Inverter‐Based Resources; and (2) Non‐BES Inverter‐Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of
connection at a voltage greater than or equal to 60 kV.” .
We question why “attachment 1” and “Requirement R6” are written in bold.
Attachment 1: should the “including, but not limited to” in table 2 include the same list (or minimally the same wording) that is found in the
technical rationale of the IBR definition in project 2020-0?. For example, the IBR list in 2020-06 refers to “solar photovoltaic” whereas table 2
refers to “photovoltaic (PV)”.
In what standard does the PC/TP define the applicable table in point 3 of section 2 in attachment 1? Same question for the voltage base for per
unit calculation in both Attachment 1 and 2. Is there a corresponding requirement in another standard that requires the PC/TP to do this?
·
Terms : Mandatory and permissive operation should be defined based on the attachment figures allowing for interconnections to use
different requirements
·
A-4.2.2 What is the IBR registration criteria? Add a clear reference and make sur the user understands what the IBR registration criteria is.
·
B-R2-2.1 Attachment 1 only uses "no-trip zone". Define continuous operating region more clearly in the table (similar to what is done in
PRC-024-4)
·
B-R2-2.1.2 Can the TP ask for a mix of active/reactive power based on a predetermined ratio (currently only indicated as active or
reactive).
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B-R2-2.2 Attachment 1 only uses "no-trip zone". Define "mandatory operation region" in Attachment 1.
·
B-R2-2.4 Permissive operation region is not used or defined in attachment 1.
·
B-R3. The document refers to an overvoltage value of 1.2pu. It should refer to a voltage exceeding the mandatory operating region in
order for Interconnections to set their own overvoltage table.
·
B-R3. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through these overvoltages ? An
exemption clause is required for existing IBR that cannot be modified or upgraded.
·
B-R4. The 5Hz/s value should be moved to Attachment 3 and B-R4 should only refer to the value in the Attachment.
·
B-R4. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through these frequencies and
ROCOF ? (for instance, for all the HQ connected projects, the ROCOF requirement was 4Hz/s) An exemption clause is required for existing IBR
that cannot be modified or upgraded.
·
B-R5. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through this phase angle jump ? An
exemption clause is required for existing IBR that cannot be modified or upgraded.
·
Attachment 1. Tables 1 and 2: Indicate what is considered as “continuous operation”, “mandatory operation” and “permissive operation”
in an additional column.
·
Attachment 1. HQ needs a Quebec regional variance since the Québec Interconnection has its own requirements in this regard.
·
Attachment 2. Bullet 3: This sentence is hard to read. Proposed replacement: "Each IBR shall not trip unless the cumulative time of one or
more instances in which the instantaneous voltage exceeds the respective voltage threshold over a 1-minute time window exceeds the
minimum ride-through time"
·
Attachment 2. HQ needs a Quebec regional variance since the Québec Interconnection has its own requirements in this regard.
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Attachment 3. This attachment should also include the maximum absolute ROCOF value.
·
Attachment 3. HQ needs a Quebec regional variance
·
B-R2-2.1.2 Which entity between Transmission Planner, Planning Coordinator, Reliability Coordinator and Transmission Operator has
priority to specify those requirements?
·
B-R2-2.4 Which entity between Transmission Planner, Planning Coordinator, Reliability Coordinator and Transmission Operator has
priority to specify those requirements?
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Ontario Power Generation Inc., 5, Chitescu Constantin
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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name
Comment
- Evidence Retention: We would suggest that the evidence retention period for both Standards should be changed from five years to three
years, to be consistent with other NERC Standards.
- The standard is event-based compliance that required installing recorded equipment data with higher sampling rates at all applicable legacy
IBR Facilities. Therefore, we recommend that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC-028-1) for the
legacy IBR. Also, we suggest have different implementation plan for the legacy IBR from IBR connected after the approval date of PRC-029.
- Some clarity how these requirements would be enforced in a location where no data recording is available at an IBR facility during system
events.
- M1-M5 required the GO to maintain the evidence of actual recorded data or other evidence for each applicable IBR demonstrating adherence
to ride‐through requirements, as specified in Requirement R1-R5. What are the criteria for selecting the event(s) that should be analyzed to
demonstrate compliance with the VRT, FRT and VRT performance requirement(s)? If the performance does not meet the requirement(s), do
Generator Owner need to present a corrective action plan and provide it to each applicable Reliability Coordinator. We suggest coordinating
this project 2020-02 (PRC-029) with project 2023-02(PRC-030) regarding the IBR ride‐through performance analysis.
- R2: We agree with the present flexibility that some of the IBR VRT performance could be modified to meet the individual system needs by the
applicable Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator. However, some clarity may be
required on how this process is initiated and what type of evidence is required to demonstrate the request is received and implemented. This
may be an additional requirement assigned to the Transmission Planner. Each Transmission Planner, Planning Coordinator, and Transmission
Operator that jointly specifies the following voltage ride-through performance requirements within their area(s) different than those specified
under R2, shall make those requirements available to each associated applicable IBR Generator Owner and Transmission Owner.
- We suggest that the drafting team ensures consistent language is used in the section 4.2 “Facilities” section with the other projects such as
Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggest the following language be included in the applicability section. Facilities: The
Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
- R3: we suggest adding to the attachment 2 how the instantaneous transient overvoltage should be calculated (such as what is the pu based
on? and the minimum sampling rate?)
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Leah Gully - Madison Fields Solar Project, LLC - 5 - RF
Answer
Document Name
Comment
1. The proposed Standard refers to four different operating regions (no-trip zone, Continuous Operation Region, Mandatory Operation
2.
3.
4.
5.
Region, and Permissive Operating Region). The different zones require Generator Owners to take different actions based on the number
of disturbances and deviations that occur within in a 10 second period as well as the positive sequence voltage on the high side of the
MPT. The ability of plant operators or inverter controls to identify, track, and respond effectively to all these variables is unrealistic.
Why are these requirements not applied to non-IBR owners?
In R1, GOs are required to ensure that IBRs continue to “exchange current in accordance with the no-trip zones and operation regions
as specified in Attachment 1.” The Standard does not define the term “exchange current”. Please define this term.
Measure 1 requires the Generator Owner and Transmission Owner to have actual recorded data for each applicable IBR demonstrating
ridethrough adherence. This measure needs a timeframe for retention of the data.
The second half of the sentence in 2.1.1 doesn’t appear to add any value to the sub-requirement. Please clarify what added operational
requirement is meant by, “…and continue to deliver active power and reactive power up to its apparent power limit.”
Requirement R2.1.2 allows four different entities to dictate each IBR’s operating mode. This contradicts the requirements of VAR-001
which states that GOs must operate in voltage control mode unless exempted by the TOP. Recommend selecting one of these entities
to determine the preference.
6. For overvoltage conditions greater than 140% Attachment 2 requires Generator Owners to distinguish and respond with different time
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
Likes
delays, all less than or equal to 3 ms. Recommend requiring IBRs to delay their response to voltage excursions and program their IBRs to
match the responses of synchronous machines.
Clarify Requirement 2.2.1 to address the expected operational response to close-in faults. Recommend the Standard specify separate
performance requirements for close-in faults and more distant faults.
Requirement 2.2 appears to mandate that IBRs who operate in active power priority mode in the continuous operating region would be
required to switch to the reactive power mode if a voltage disturbance occurs. What criteria are IBRs expected to use to determine
when this switch should occur? What are IBRs expected to do if their inverters cannot be switched without software modifications?
The ride through requirements should all be specified in the same units of time.
Couldn’t the voltage overshoot concerns addressed by Requirement 2.3 be addressed more reliably by slowing the response time of the
IBR plant controllers to match that of synchronous generation?
Measure 2 requires the GO and TO to have actual recorded data during each system disturbance. Recommend establishing a timeframe
for the retention of this data.
Measure 3 requires the GO and TO to have actual recorded data during each transient voltage event. Recommend establishing a
timeframe for the retention of this data.
Measure 4 requires the GO and TO to have actual recorded data during each frequency excursion event. Recommend establishing a
timeframe for the retention of this data.
Measure 5 requires the GO and TO to have actual recorded data during each positive sequence voltage phase angle changes that are
less than 25 electrical degrees at the high side of the main transformer. Recommend establishing a timeframe for the retention of this
data.
Requirement 6 has more specific requirements for an equipment limitation than is being proposed for the synchronous generators.
Recommend PRC-029 reflect the wording proposed for PRC-024-4.
PRC-029 frequency ride-through is a single graph for all regions. The graph no trip zone is larger than the existing PRC-024 frequency notrip zone for Eastern, Western, and ERCOT zones. The wording in the rationale is very soft (may be required). The change will cause the
LFRT and HFRT settings to be updated as well as collector and transformer frequency settings. Recommend the frequency settings
remain consistent with PRC-024 until the time that it is justified from grid events.
0
Dislikes
0
Response
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
In some cases, the initial 6-month implementation period to develop a technical rationale for an exemption may be too short. This is
attributable to the necessary input from the original OEM and in some cases due to the complexity associated with facilities comprised of new
and old equipment. One example where this may exist are plants where a repower project may have taken place that does not replace all
inverters. In a case such as this, the new equipment may meet the requirements, but the remaining existing equipment may not. This may
require a detailed study to verify compliance, or perhaps instead, require some form of hybrid exemption for the site. Unlike the stated
technical goal of the standard where this is a “performance based” standard, the justification for a technical exemption will require some form
of a study to justify that exemption. This could lead to a greater than 6-month period in developing the exemption request. To accommodate
these situations, AEP recommends an implementation period of 18 months.
PRC-029 requires that IBR’s shall ride through 110%-120% overvoltage from 0-1 seconds as seen at the high side of the main power step-up
transformer. Due to voltage drop, the voltage seen at the equipment terminals can be another 5% higher leading to potential equipment
damage from overvoltage. AEP suggests that the SDT consider lowering the ride through to 110% at the high side of the main step-up
transformer.
Likes
0
Dislikes
0
Response
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Likes
0
Dislikes
Response
0
2020-02_EPRI Comments on Draft NERC PRC-029 (IBR ride-through) Reliability Standard.pdf
Consideration of Comments
Project Name:
2020-02 Modifications to PRC-024 (Generator Ride-through) | Draft 1
Comment Period Start Date:
3/27/2024
Comment Period End Date:
4/22/2024
Associated Ballot(s):
2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan IN 1 OT
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 | Non-binding Poll IN 1 NB
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 IN 1 ST
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 | Non-binding Poll IN 1 NB
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 IN 1 ST
There were 79 sets of responses, including comments from approximately 180 different people from approximately 111 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, let us know immediately. Our goal is to give every comment serious consideration in this
process. If you feel there has been an error or omission, contact Director, Standards Development Latrice Harkness (via email) or at (404) 8588088.
RELIABILITY | RESILIENCE | SECURITY
Questions
1. Do you agree with the need for creating a new Standard (PRC-029-1) to address gaps the Inverter-Based Resource Performance
Subcommittee (IRPSC) identified within the PRC-024-3 Project 2020-02 SAR and to address the expectations of FERC Order No. 901?
2. Do you agree that the language within PRC-029-1 requirements R1, R2, and R6 regarding IBR plant-level performance during grid voltage
disturbances is clear?
3. Do you agree with the drafting team’s proposals for including IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage
phase-angle jump ride-through performance criteria in PRC-029-1 Requirements R3, R4, and R5?
4. Provide any additional comments for the Drafting Team to consider, if desired.
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
2
Organization
Name
Name
BC Hydro and Adrian
Power
Andreoiu
Authority
Segment(s)
1
Santee
Cooper
Carey
Salisbury
1,3,5,6
WEC Energy
Group, Inc.
Christine
Kane
3
Southern
Colby
Company Galloway
Southern
Company
Services, Inc.
1,3,5,6
Region
WECC
Group Member Group Member
Group Name
Name
Organization
BC Hydro
Group
Member
Segment(s)
Group
Member
Region
Hootan Jarollahi BC Hydro and
Power
Authority
3
WECC
Helen Hamilton BC Hydro and
Harding
Power
Authority
5
WECC
Adrian
Andreoiu
1
WECC
BC Hydro and
Power
Authority
Santee
Cooper
Lachelle Brooks Santee Cooper 1,3,5,6
SERC
Paul Camilletti
Santee Cooper 1,3,5,6
SERC
WEC Energy
Group
Christine Kane
WEC Energy
Group
3
RF
Matthew
Beilfuss
WEC Energy
Group, Inc.
4
RF
Clarice Zellmer WEC Energy
Group, Inc.
5
RF
David Boeshaar WEC Energy
Group, Inc.
6
RF
Matt Carden
1
SERC
3
SERC
MRO,RF,SERC,Texas Southern
RE,WECC
Company
Southern
Company Southern
Company
Services, Inc.
Joel Dembowski Southern
Company Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
3
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member Group Member
Name
Organization
Group
Member
Segment(s)
Group
Member
Region
Alabama Power
Company
California ISO Darcy
O'Connell
2
WECC
Ron Carlsen
Southern
Company Southern
Company
Generation
6
SERC
Leslie Burke
Southern
Company Southern
Company
Generation
5
SERC
California ISO
2
WECC
New York
Independent
System
Operator
2
NPCC
John Pearson
ISO New
England, Inc.
2
NPCC
Helen Lainis
Independent
Electricity
System
Operator
2
NPCC
ISO/RTO
Ali Miremadi
Council (IRC) Gregory
Standards
Campoli
Review
Committee
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
Elizabeth Davis PJM
2
Interconnection
RF
Charles Yeung
MRO
Southwest
Power Pool,
Inc.
2
4
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member Group Member
Name
Organization
Bobbi Welch
Midcontinent
ISO, Inc.
Jennie Wike
Jennie Wike
RF
2
Texas RE
Austin Energy
6
Texas RE
Michael Dillard Austin Energy
5
Texas RE
Lovita Griffin
Austin Energy
3
Texas RE
Tony Hua
Austin Energy
4
Texas RE
Thomas
Standifur
Austin Energy
1
Texas RE
Jennie Wike
Tacoma Public 1,3,4,5,6
Utilities
WECC
John Merrell
Tacoma Public 1
Utilities
(Tacoma, WA)
WECC
John
Nierenberg
Tacoma Public 3
Utilities
(Tacoma, WA)
WECC
Hien Ho
Tacoma Public 4
Utilities
(Tacoma, WA)
WECC
Terry Gifford
Tacoma Public 6
Utilities
(Tacoma, WA)
WECC
Austin Energy Imane Mrini
WECC
Tacoma
Power
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
Group
Member
Region
2
Kennedy Meier Electric
Reliability
Council of
Texas, Inc.
Austin Energy Imane Mrini 6
Group
Member
Segment(s)
5
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member Group Member
Name
Organization
Ozan Ferrin
ACES Power
Marketing
Jodirah
Green
FirstEnergy - Mark Garza
FirstEnergy
Corporation
1,3,4,5,6
4
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
Group
Member
Region
Tacoma Public 5
Utilities
(Tacoma, WA)
WECC
Hoosier Energy 1
Electric
Cooperative
RF
Jason Procuniar Buckeye Power, 4
Inc.
RF
Scott Brame
North Carolina 3,4,5
Electric
Membership
Corporation
SERC
Bill Pezalla
Old Dominion
Electric
Cooperative
SERC
Sara Orr
Golden Spread 5
Electric
Cooperative,
Inc.
Texas RE
Kris Carper
Arizona Electric 1
Power
Cooperative,
Inc.
WECC
Julie Severino
FirstEnergy FirstEnergy
Corporation
RF
MRO,RF,SERC,Texas ACES
Bob Soloman
RE,WECC
Collaborators
FE Voter
Group
Member
Segment(s)
3,4
1
6
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member Group Member
Name
Organization
Rachel
Schuldt
Northeast
Ruida Shu
Power
Coordinating
Council
6
1,2,3,4,5,6,7,8,9,10 NPCC
Group
Member
Region
Aaron
Ghodooshim
FirstEnergy FirstEnergy
Corporation
3
RF
Robert Loy
FirstEnergy FirstEnergy
Solutions
5
RF
Mark Garza
FirstEnergyFirstEnergy
1,3,4,5,6
RF
6
RF
Stacey Sheehan FirstEnergy FirstEnergy
Corporation
Black Hills
Corporation
Group
Member
Segment(s)
Black Hills
Micah Runner
Corporation All Segments Josh Combs
Black Hills
Corporation
1
WECC
Black Hills
Corporation
3
WECC
Rachel Schuldt
Black Hills
Corporation
6
WECC
Carly Miller
Black Hills
Corporation
5
WECC
Sheila
Suurmeier
Black Hills
Corporation
5
WECC
Gerry Dunbar
Northeast
Power
Coordinating
Council
10
NPCC
1
NPCC
NPCC RSC
Deidre Altobell Con Edison
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
7
Organization
Name
Name
Segment(s)
Region
Group Name
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
Group Member Group Member
Name
Organization
Group
Member
Segment(s)
Group
Member
Region
Michele
Tondalo
United
1
Illuminating Co.
NPCC
Stephanie
Ullah-Mazzuca
Orange and
Rockland
1
NPCC
Michael
Ridolfino
Central Hudson 1
Gas & Electric
Corp.
NPCC
Randy Buswell
Vermont
Electric Power
Company
1
NPCC
James Grant
NYISO
2
NPCC
Dermot Smyth
Con Ed Consolidated
Edison Co. of
New York
1
NPCC
David Burke
Orange and
Rockland
3
NPCC
Peter Yost
Con Ed Consolidated
Edison Co. of
New York
3
NPCC
Salvatore
Spagnolo
New York
Power
Authority
1
NPCC
Sean Bodkin
Dominion 6
Dominion
Resources, Inc.
NPCC
8
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member Group Member
Name
Organization
Group
Member
Region
David Kwan
Ontario Power 4
Generation
NPCC
Silvia Mitchell
NextEra Energy 1
- Florida Power
and Light Co.
NPCC
Sean Cavote
PSEG
4
NPCC
5
NPCC
Tracy MacNicoll Utility Services 5
NPCC
Shivaz Chopra
New York
Power
Authority
6
NPCC
Vijay Puran
New York State 6
Department of
Public Service
NPCC
David Kiguel
Independent
7
NPCC
Joel Charlebois AESI
7
NPCC
Joshua London Eversource
Energy
1
NPCC
Jason Chandler Con Edison
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
Group
Member
Segment(s)
Emma Halilovic Hydro One
1,2
Networks, Inc.
NPCC
Emma Halilovic Hydro One
1,2
Networks, Inc.
NPCC
Chantal Mazza
Hydro Quebec 1,2
NPCC
Emma Halilovic Hydro One
1,2
Networks, Inc.
NPCC
9
Organization
Name
Name
Segment(s)
Elevate
Energy
Consulting
Ryan Quint
NA - Not
Applicable
Dominion Dominion
Resources,
Inc.
Sean Bodkin 6
Region
Group Name
NA - Not Applicable Elevate
Energy
Consulting
Dominion
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
Group Member Group Member
Name
Organization
Group
Member
Segment(s)
Group
Member
Region
Chantal Mazza
Hydro Quebec 1,2
NPCC
Nicolas
Turcotte
Hydro-Quebec 1
(HQ)
NPCC
Jeffrey Streifling NB Power
Corporation
1,4,10
NPCC
Jeffrey Streifling NB Power
Corporation
1,4,10
NPCC
Jeffrey Streifling NB Power
Corporation
1,4,10
NPCC
Joel Charlebois AESI
7
NPCC
Ryan Quint
Elevate Energy
Consulting
NA - Not
Applicable
N/A
N/A
NA - Not
Applicable
Connie Lowe
Dominion 3
Dominion
Resources, Inc.
NA - Not
Applicable
Lou Oberski
Dominion 5
Dominion
Resources, Inc.
NA - Not
Applicable
Larry Nash
Dominion 1
Dominion
Virginia Power
NA - Not
Applicable
Rachel Snead
Dominion 5
Dominion
Resources, Inc.
NA - Not
Applicable
10
Organization
Name
Stephen
Whaite
Tim Kelley
Name
Segment(s)
Stephen
Whaite
RF
Tim Kelley
Associated
Todd
Electric
Bennett
Cooperative,
Inc.
Region
WECC
3
Group Name
Group Member Group Member
Name
Organization
Group
Member
Segment(s)
Group
Member
Region
ReliabilityFirst Lindsey
ReliabilityFirst
Ballot Body Mannion
Member and Stephen Whaite ReliabilityFirst
Proxies
10
RF
10
RF
SMUD and
BANC
Sacramento
Municipal
Utility District
3
WECC
Charles Norton Sacramento
Municipal
Utility District
6
WECC
Wei Shao
Sacramento
Municipal
Utility District
1
WECC
Foung Mua
Sacramento
Municipal
Utility District
4
WECC
Nicole Goi
Sacramento
Municipal
Utility District
5
WECC
Kevin Smith
Balancing
Authority of
Northern
California
1
WECC
Michael Bax
Central Electric 1
Power
Cooperative
(Missouri)
AECI
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
Nicole Looney
SERC
11
Organization
Name
Name
Segment(s)
Region
Group Name
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
Group Member Group Member
Name
Organization
Group
Member
Segment(s)
Group
Member
Region
Adam Weber
Central Electric 3
Power
Cooperative
(Missouri)
SERC
Gary Dollins
M and A
Electric Power
Cooperative
3
SERC
William Price
M and A
Electric Power
Cooperative
1
SERC
Olivia Olson
Sho-Me Power 1
Electric
Cooperative
SERC
Mark Ramsey
N.W. Electric
Power
Cooperative,
Inc.
1
SERC
Heath Henry
NW Electric
Power
Cooperative,
Inc.
3
SERC
Tony Gott
KAMO Electric
Cooperative
3
SERC
Micah
Breedlove
KAMO Electric
Cooperative
1
SERC
Brett Douglas
Northeast
Missouri
1
SERC
12
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member Group Member
Name
Organization
Group
Member
Segment(s)
Group
Member
Region
Electric Power
Cooperative
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
Skyler
Wiegmann
Northeast
Missouri
Electric Power
Cooperative
3
SERC
Mark Riley
Associated
Electric
Cooperative,
Inc.
1
SERC
Brian
Ackermann
Associated
Electric
Cooperative,
Inc.
6
SERC
Chuck Booth
Associated
Electric
Cooperative,
Inc.
5
SERC
Jarrod
Murdaugh
Sho-Me Power 3
Electric
Cooperative
SERC
13
1. Do you agree with the need for creating a new Standard (PRC-029-1) to address gaps the Inverter-Based Resource Performance Subcommittee
(IRPSC) identified within the PRC-024-3 Project 2020-02 SAR and to address the expectations of FERC Order No. 901?
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
We recommend adding these IBR related requirements to PRC-024, rather than creating a new Standard.
Likes
0
Dislikes
0
Response
Thank you for your comment.
The need for a separate standard, PRC-029, is a consequence of both the different natures of synchronous and inverter‐based generation and
several recent events exhibiting significant IBR ride‐through deficiencies and failures the causes of which are not relevant to synchronous
generators. Due to the differences in the requirements between these types of generation, PRC-024 is focused on equipment settings, and PRC-029
includes performance based requirements to “ride-through” events. Please refer to the technical rationale for additional information.
Kimberly Turco - Constellation - 6
Answer
No
Document Name
Comment
Constellation does not agree with creating a new IBR specific standard (PRC-29) to address the gaps in the Inverter-Based Resource. While
Constellation recognizes that there has been some grid disturbance in the Odessa/California/Utah regions in the past couple years as a result of
some IBRs not performing as intended, the creation of a new standard is a quick reaction without ensuring existing equipment's are capable to fully
comply.
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
14
Kimberly Turco on behalf of Constellation Segments 5 and 6
Likes
0
Dislikes
0
Response
Thank you for your comment.
The scope of PRC-029 is consistent with the SAR assigned to this team and the regulatory directives from FERC Order No. 901 that were assigned to
this team. The need for a separate standard, PRC-029, is a consequence of both the different natures of synchronous and inverter‐based generation
and several recent events exhibiting significant IBR ride‐through deficiencies and failures the causes of which are not relevant to synchronous
generators. We cannot take the approach of PRC-024 for IBRs because there are too many other factors and causes of IBR ride-through failure not
directly related to voltage and frequency protection settings that may, and have caused ride-through deficiencies and failures.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
No
Document Name
Comment
Texas RE supports creating a new standard to address Inverter-Based Resources (IBR) gaps identified. Texas RE is concerned, however, with the
structure of the standard as it is presently proposed.
As currently drafted, the proposed PRC-029-1 would wholly eliminate existing frequency and voltage protection setting verification requirements
for IBR resources. Texas RE submits that this is contrary to FERC’s intent in directing NERC to develop a comprehensive ride-through standard for
IBR resources. FERC Order No. 901 explicitly directs NERC to draft a standard “that require[s] IBR generator owners and operators to use
appropriate settings (i.e., inverter, plant controller, and protection) to ride through frequency and voltage system excursions and that permit IBR
tripping only to protect IBR equipment in scenarios similar to when synchronous generation resources use tripping as protection from internal
faults.” (Order No, 901, paragraph 190). FERC’s intent behind the order was to expand the scope of applicable devices beyond protection system
equipment subject to the current PRC-024 requirements to embrace a range of devices that can trip an IBR facility (inverters, plant controller,
etc.). The ultimate goal is to better ensure that IBRs provide reliable performance during voltage and frequency excursions.
Texas RE submits, however, that FERC did not intent to exclude IBR entities from the existing verification processes or significant limit the ability of
the ERO to review protection system settings prior to an actual disturbance event. In its order, FERC specifically referenced the 2021 Odessa
Disturbance Report jointly prepared by NERC and Texas RE staff (“2021 Odessa Disturbance Report”). The 2021 Odessa Disturbance Report in turn
called for the development of a ride-through standard to replace PRC-024-3 because “the events analyzed by NERC regarding fault-induced
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
15
reductions in solar PV output and wind output have identified issues with controls and protections unrelated to voltage and frequency.” (2021
Odessa Report, at 29). While calling for a more comprehensive standard, however, the report simultaneously identified pervasive issues with
protection system settings within the scope of the current PRC-024 standards. The report noted: “Numerous plant owner/operators have stated
that they do not have sufficient technical staff on hand to interpret the results and will simply install what the consultant recommends. This is
leading to poorly coordinated protection systems within the facility, causing unreliable performance from BPS-connected solar PV facilities in
multiple interconnections.” (2021 Odessa Report, at 17 (emphasis added)). In short, while acknowledging that the current PRC-024 standard is
overly narrow, FERC and the various reports FERC references make clear that protection system verification failures remain an important
contributing factor in the numerous disturbance events involving IBRs over the past few years.
As proposed, PRC-029-1 would result in a reliability gap by requiring that protection system settings no longer require verification. The Standard
Drafting Team (SDT) explains in the draft PRC-029-1 Technical Rationale that “[a]n IBR becomes noncompliant with PRC‐029 only when an event in
the field occurs that shows that one or more requirements were not satisfied.” Under the SDT’s proposed approach, therefore, the existing PRC024 protection system setting verification requirements would be eliminated and the sole mechanism to verify performance would be an IBR’s
failure to perform during a disturbance event. Texas RE posits that this approach is inconsistent with the intent of FERC’s order to expand the
applicable devices and settings that an IBR-entity must ensure are properly set to avoid unnecessary tripping during events. It is also inconsistent
with findings that entities continue to experience issues properly setting (and verifying) existing protection systems within the scope of the current
PRC-024 requirements.
Rather than pursue this approach, Texas RE suggests that the SDT consider retaining the existing protection system verification requirements as a
foundational step, but augment those requirements with a general performance standard. Moreover, while Texas RE does not believe the SDT
needs or should develop a comprehensive and prescriptive list of devices that must be appropriate set and coordinated to ensure IBR performance,
the SDT should consider which measures and evidence would be appropriate for the GO and TO to demonstrate that its settings meet the various
no-trip zone parameters described in Attachment 1. This should include sufficient evidence to show that protection system settings are properly set
to not trip within appropriate no trip zones, as well as that other settings for inverters, plant controllers, and other devices are properly
coordinated. Such clarity will ensure that at least minimum performance can be audited and verified prior to a disturbance event – the goal of the
standards process.
Additionally, Texas RE noticed during the webinar, SDT stated that the requirements do not apply to individual IBR units. Requirement R1 seems to
indicate that each IBR unit needs to remain electrically connected and continue to exchange current in accordance with the no-trip zones and
operation regions.
Lastly, Texas RE recommends the SDT consider changing ‘each IBR’ to ‘each IBR Facility’ for all the Requirements.
Likes
0
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
16
Dislikes
0
Response
Thank you for your comment.
The team agrees that the ability to validate the capability of each applicable IBR was not clear from the initial draft. Changes have been made to
ensure the design/capability of each IBR can be validated prior to an event – in addition to retaining the event and performance-based
requirements. The team does intend for each requirement to only apply at the plant/facility level; consistent with the disturbance monitoring
equipment requirements within draft PRC-028. Also, the specific term identifying the applicable IBR facilities will have to await the completion of
the IBR definition(s) by Project 2020-06. Changes have been made throughout the requirements and the applicability section to use only currently
enforceable language.
Joy Brake - Nova Scotia Power Inc. - NA - Not Applicable - NPCC
Answer
No
Document Name
Comment
A performance standard should be based on function not technology type which is always changing. An IBR generation facility should meet the
same performance threshold as traditional generation, with additional support devices as necessary incorporated into the facility design to meet
the same level of performance as a traditional unit.
Likes
0
Dislikes
0
Response
Thank you for your comment.
The need for a separate standard, PRC-029, is a consequence of both the different natures of synchronous and inverter‐based generation and
several recent events exhibiting significant IBR ride‐through deficiencies and failures the causes of which are not relevant to synchronous
generators. Due to the differences in the requirements between these types of generation, PRC-024 is focused on equipment settings, and PRC-029
includes performance based requirements to “ride-through” events. Please refer to the technical rationale for additional information.
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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17
Comment
PRC-024-3 has not been in effect long enough to be deemed inadequate to address “gaps” and issues described in IBR disturbance reports. It
became effective on 10/1/2022, which was long after major disturbances occurred, and as written, covers major causes of IBR disturbances such as
voltage, frequency, and momentary cessation. Most importantly, the Standard clearly stated applicability to individual IBR units and it clearly stated
no-trip zones. The Standard could have been modified to include and cover other recommendations from the disturbance report such as PLL
protection and ramp rate mis-coordination.
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The scope of PRC-029 is consistent with the SAR assigned to this team and the regulatory directives from FERC Order No. 901 that were assigned to
this team. The need for a separate standard, PRC-029, is a consequence of both the different natures of synchronous and inverter‐based generation
and several recent events exhibiting significant IBR ride‐through deficiencies and failures the causes of which are not relevant to synchronous
generators. We cannot take the approach of PRC-024 for IBRs because there are too many other factors and causes of IBR ride-through failure not
directly related to voltage and frequency protection settings that may, and have caused ride-through deficiencies and failures. Lastly, PRC-029 is
plant/facility level based requirements and is not applicable at the individual inverter unit level.
Alison MacKellar - Constellation - 5
Answer
No
Document Name
Comment
Constellation does not agree with creating a new IBR specific standard (PRC-29) to address the gaps in the Inverter-Based Resource. While
Constellation recognizes that there has been some grid disturbance in the Odessa/California/Utah regions in the past couple years as a result of
some IBRs not performing as intended, the creation of a new standard is a quick reaction without ensuring existing equipment's are capable to fully
comply.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Response
Thank you for your comment.
The scope of PRC-029 is consistent with the SAR assigned to this team and the regulatory directives from FERC Order No. 901 that were assigned to
this team. The need for a separate standard, PRC-029, is a consequence of both the different natures of synchronous and inverter‐based generation
and several recent events exhibiting significant IBR ride‐through deficiencies and failures the causes of which are not relevant to synchronous
generators. We cannot take the approach of PRC-024 for IBRs because there are too many other factors and causes of IBR ride-through failure not
directly related to voltage and frequency protection settings that may, and have caused ride-through deficiencies and failures.
Michael Goggin - Grid Strategies LLC - 5
Answer
No
Document Name
Comment
A major concern with the separate Standards, as drafted, is that ride through performance is not required for synchronous generators under PRC024-4, but it is for IBRs under PRC-029. PRC-02-4 simply requires protective relays to be set so they do not trip the generator within specified
bounds, but it allows a resource to trip offline for other reasons. PRC-024-4 also allows a plant to trip if protection systems trip auxiliary plant
equipment, per section 4.2.3. In contrast, PRC-029 requires IBRs to remain electrically connected and to continue to exchange current within the
specified voltage and frequency bounds. Said another way, an IBR and a synchronous resource could both trip during the same disturbance, and the
IBR would be in violation of PRC-029 but the synchronous generator would not be in violation of PRC-024-4, as long as the synchronous generator
did not trip due to the settings of its protection system.
To ensure grid reliability and resilience, all resources including IBRs and synchronous resources should ride through grid disturbances. The failure of
synchronous generators to ride through grid disturbances threatens grid reliability as much or more than the failure of IBRs, as synchronous
resources are often producing at a higher level of output, are more typically relied on as capacity resources, and often take longer to come back
online and ramp up to full output if they trip due to a disturbance.
FERC Order 901 directed NERC to treat IBR resources similarly to how NERC Standards treat synchronous generators, writing that the IBR Standard
should “permit IBR tripping only to protect the IBR equipment in scenarios similar to when synchronous generation resources use tripping as
protection from internal faults.”{C}[1] Allowing synchronous generators to trip but requiring IBRs to ride through the same or similar disturbance
could be challenged at FERC as undue discrimination.
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Not requiring ride-through performance from synchronous generators is also at odds with the intent for this project that NERC stated in its February
2023 comments on the FERC proposed rulemaking that led to Order 901: “A comprehensive, performance-based ride-through standard is needed to
assure future grid reliability. To that end, NERC re-scoped an existing project, 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 generating
resources.”[2] FERC’s Order 901 also noted NERC’s statement that this project would require ride-through performance from all generating
resources,[3] so a failure to require ride-through performance from synchronous generators may be contrary to both NERC and FERC’s intent.
The drafting team should make PRC-024-4 a ride-through performance requirement like PRC-029, or alternatively create a single standard that
applies to both types of resources (with any necessary clarifications or minor differences in requirements to reflect the differences in IBR and
synchronous generator technologies).
{C}[1]{C} Order 901, https://www.ferc.gov/media/e-1-rm22-12-000, at paragraph 190
{C}[2]{C}https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Comments_IBR%20Standards%20NOPR.pdf, at 21-22
{C}[3]{C} Order 901, https://www.ferc.gov/media/e-1-rm22-12-000, at paragraph 185
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The team intends to continue evaluation of synchronous generators within the scope of the project. The team is seeking to meet regulatory
timelines for IBR within FERC Order No. 901 and to address changes for IBR with the proposed PRC-029. Further, the team wants to assure that the
physical differences between the technology types are fully represented in any new or modified requirements for synchronous machines and that
such new or modified requirements are reasonable.
Carey Salisbury - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer
No
Document Name
Comment
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Response
David Campbell - David Campbell On Behalf of: Natalie Johnson, Enel Green Power, 5; - David Campbell
Answer
No
Document Name
Comment
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Thomas Foltz - AEP - 5
Answer
Yes
Document Name
Comment
While AEP agrees with creating PRC-029-1 to address the identified gaps, AEP recommends the SDTs for PRC-028, PRC-029 and PRC-030 review each
proposed standard obligations to ensure there is a consistent, integrated plan across these projects and standards to achieve the goal of correcting
the past performance of Invertor-Based Resources and IBR units. Having a coherent strategy document that explains how these three standards
complement each other (and not be duplicative) would be beneficial.
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Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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NERC will post updated information on the response to FERC Order No. 901. The three projects associated with Milestone 2 are meeting together to
review draft changes at this time.
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
Synchronous generation and Inverter-based resources should have separate standards due to their unique differences. Presently, behavior of
Synchronous generation during disturbances and faults is very well understood compared to IBR technology.
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Helen Lainis - Independent Electricity System Operator - 2
Answer
Yes
Document Name
IESO Comments for PRC-024 PRC-029 Draft 1.docx
Comment
Complete set of comments for all Qs attached in file: IESO Comments for PRC-024 and PRC-029 Draft 1
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Ontario Power Generation Inc., 5, Chitescu Constantin
0
Response
The team confirmed that these comments are included under other questions below and will be addressed there.
Brian Lindsey - Entergy - 1
Answer
Yes
Document Name
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Comment
Yes, we need a separate a standard. The technologies are different enough that a separate standard will reduce confusion.
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Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Yes
Document Name
Comment
AECI supports comments provided by the NAGF
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Yes
Document Name
Comment
FirstEnergy supports the need for the new standard (PRC-029-1).
In addition, FE supports EEI’s comments which state:
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
Additionally, Requirement R2, subpart 2.5 could be understood to mean that IBRs whenever the voltage at the high-side of the main power
transformer is within the no-trip zone, as specified in Attachment 1, must not trip even if it might lead to equipment damage. We offer the
following proposed edits in boldface to Requirement R2, subpart 2.5 to clarify the requirement. NERC Reliability Standards should never mandate
that equipment run to failure.
2.5 Each IBR shall only trip to prevent equipment damage, Whenever the voltage at the high‐side of the main power transformer is within of the
no‐trip zone, as specified in Attachment 1, each IBR shall continue to operate except when the continued operation of the IBR would lead to
equipment damage.
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Terminology: The team has removed the word “applicable” and include a reference to the applicability section of the Standard. Any IBR that cannot
meet voltage ride-through requirements, and may need to trip within the no-trip zone to protect equipment, would be covered under the
documented equipment limitations as covered within Requirement R4 (previous R6).
R2.5: The team agrees with removing requirements on operation outside the no-trip zone and has removed R2.5.
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Yes
Document Name
Comment
Black Hills Corporation agrees that there is a gap in PRC-024-3 regarding performance of inverter-based resources (IBR). However, more
consideration should be given to creating “protection-based” Standards for IBR, whether as an update to existing Standard PRC-024-3 or new
Standard PRC-029-1 rather than the “event-based” approach currently being taken in PRC-029-1.
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Response
Thank you for your comment.
The SDT wants to avoid the complexities of OEM-specific IBR controls and protection by avoiding the protection settings issues altogether. We
believe that a settings-based approach to the determination of compliance would become impractical if not impossible because of the varability of
OEM designs. We cannot take the approach of PRC-024 for IBRs because there are too many other factors and causes of IBR ride-through failure not
directly related to voltage and frequency protection settings that may, and have caused ride-through deficiencies and failures. A settings-based
approach cannot practically address all factors and causes inherent to the various OEM designs of IBR units and plants. Some revisions were made
to add clarity to capability-based requirements which require a demonstration of verified design/capability to ride-through.
Stefanie Burke - Portland General Electric Co. - 6
Answer
Yes
Document Name
Comment
PGE requests that the Standard Drafting Team (SDT) add clarity regarding Attachment A: Voltage Boundary Clarifications, Section: Evaluating
Protection Settings, a. The most probable real and reactive loading conditions for the unit under study.
Loading conditions vary depending on the type of unit, location, time of year, etc. How should an entity assess “most probable” loading conditions?
Are entities being required to account for the worst case scenarios providing the greatest voltage change(s), not just a probable condition that may
represent little to no significant voltage difference?
PGE also notes that the Table References and Figure References are not aligned
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The attachment describes an approach to translating per unit voltage between the low and high sides of GSUs. This is something that needs to be
done if voltage protection is applied at the generator terminal. It is only a recommendation. The protection setting no-trip zone references the POI
voltage.
The table and figure numbers in PRC-024-4 are now corrected.
Colin Chilcoat - Invenergy LLC - 6
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Answer
Yes
Document Name
Comment
Yes, the technological differences warrant separate standards for IBRs and synchronous generation.
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David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
Yes
Document Name
Comment
Ameren agrees with EEI's comments.
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Rhonda Jones - Invenergy LLC - 5
Answer
Yes
Document Name
Comment
Yes, the technological differences warrant separate standards for IBRs and synchronous generation.
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Thank you for your comment.
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Yes
Document Name
Comment
None
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Yes
Document Name
Comment
Duke Energy recommends the implementation of EEI comments.
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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Answer
Yes
Document Name
Comment
EEI supports the development of a new Reliability Standard to address gaps in Inverter-Based Resource Performance and while the SAR does not
include any language that specifically addresses FERC Order No. 901, EEI has no concerns with the SDT adjusting PRC-029 in line with the directives
contained in this Order.
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Imane Mrini - Austin Energy - 6, Group Name Austin Energy
Answer
Yes
Document Name
Comment
AE supports comments provided by Texas RE and the NAGF
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Daniel Gacek - Exelon - 1
Answer
Yes
Document Name
Comment
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Exelon supports the comments submitted by the EEI for this question.
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Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
But we have additional comments.
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Thank you for your comment. Please see responses to the other comments below.
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer
Yes
Document Name
Comment
SRP believes that there is a huge lack of oversight in regard to inverter-based resources. Regulation on IBR controls is somewhat late but we are glad
is happening.
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Response
Thank you for your comment.
David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
Yes
Document Name
Comment
Vistra agrees with AEP.
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
OPG supports IESO’s comments.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Yes
Document Name
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
June 18, 2024
30
Comment
See EEI Comments
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Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Southern Company believes that separating synchronous machine facilities from IBR facilities simplifies the complication that would exist by
addressing both types of facilities in the same standard. While the existing "legacy" facilities have demonstrated imperfect ride-through
performance (reactions) during system initiated disturbances, Southern believes that the application of ride-through requirements should only be
applicable to facilities designed, built, and commissioned after the development of such a standard. The existing "legacy" facilities were not
designed or built to achieve the desired ride-through performance that is specified in PRC-029-1, requirements R1-R5 of this proposed standard,
and should not be subject to those requirements. The demonstrated performance, while not matching the ideal performance dictated by this
proposed standard, is not catastrophic to the interconnection. The notion that generator owners have not taken any actions to improve the
reaction of the legacy facilities to system disturbances is false. Southern Company has reviewed and modified control and protection settings for
inverter operations at multiple facilities since the issuance of the first two NERC Alerts on the Loss of Solar facilities and during the multiple
disturbance analysis evaluations. Addressing the desired performance with new facilities which will have the component design and control
strategies sufficient to meet the desired performance should be a measure adequate to address the frequency control, voltage control, and stability
needs and concerns of the interconnection.
Perhaps a more reasonable approach towards achieving better IBR facility ride through performance during system disturbance events, is to require
evaluations with every instance of a plant output hiccup. The proposed required evaluation process in PRC-030, requiring corrective action plans to
minimize/eliminate/eradicate the reason for the hiccup, would address, where possible, action taken through control or protection system setting
changes, or through hardware changes - for equipment placed in service after the effective date of this draft standard).
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Southern would offer general concerns with synchronizing language across all draft standards. For example, M1 states: “shall have evidence of
actual recorded data or other evidence for each applicable IBR demonstrating adherence to ride-through requirements”. This seems like an
opportunity to clarify by explicitly referencing standard(s) addressing data collection. This example repeats in some form in each “M” paragraph.
Should the evidence of actual recorded data in M1 and other measures synch up with the phased in approach to PRC-028?
Finally, Southern Company supports EEI and NAGF comments.
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Scope of legacy IBR and approach by the team: The scope of PRC-029 is consistent with the SAR assigned to this team and the regulatory directives
from FERC Order No. 901 that were assigned to this team. There is some potential for documented limitations within Requirement R6 and the
Implementation Plan for legacy equipment that cannot meet any voltage ride-through requirements (R1 and R2). Some revisions were made to
clarify design capabilities would still be required.
Coordination between PRC-029 and PRC-030 drafting teams: these team have implemented changes to those drafts that triggers within PRC-030 to
initiate an analysis will be evaluated against PRC-029 ride through criteria. PRC-029 established the criteria and PRC-030 includes requirements for
conducting the analysis of performance after a disturbance.
Performance Measures: The compliance measures for demonstration of performance were revised from “actual recorded data” to “actual
disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data”.
Richard Vendetti - NextEra Energy - 5
Answer
Yes
Document Name
Comment
NextEra aligns with EEI's comments:
EEI supports the development of a new Reliability Standard to address gaps in Inverter-Based Resource Performance and while the SAR does not
include any language that specifically addresses FERC Order No. 901, EEI has no concerns with the SDT adjusting PRC-029 in line with the directives
contained in this Order.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company, 3, 1, 5;
Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Yes
Document Name
Comment
PG&E agrees with creating the new Standard PRC-029-1 to address IBRs.
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Kinte Whitehead - Exelon - 3
Answer
Yes
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Answer
Yes
Document Name
Comment
See EEI comments
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Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
See comments submitted by Edison Electric Institute
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Yes
Document Name
Comment
Thank you for leaning heavily on IEEE 2800.
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Ryan Quint - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable, Group Name Elevate Energy Consulting
Answer
Yes
Document Name
Comment
Yes, generator ride-through is an essential reliability service and the changing generation technology to inverter-based has led to the need for
improved, applicable, appropriate, and technically accurate requirements that suit IBRs. However, it is critically important that the implementation
of these requirements consider all stakeholder needs and capture important technical considerations so that the requirements sufficiently mitigate
risks without causing unnecessary costs or burdens on any responsible entity.
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Jennie Wike - Jennie Wike On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma
Power
Answer
Yes
Document Name
Comment
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Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer
Yes
Document Name
Comment
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Michael Brytowski - Great River Energy - 3
Answer
Yes
Document Name
Comment
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0
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0
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Yes
Document Name
Comment
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0
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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0
Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal Utility
District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3, 6, 4, 1, 5;
Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim Kelley, Group
Name SMUD and BANC
Answer
Yes
Document Name
Comment
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Ben Hammer - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Brittany Millard - Lincoln Electric System - 5
Answer
Yes
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Document Name
Comment
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0
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0
Response
Ruchi Shah - AES - AES Corporation - 5
Answer
Yes
Document Name
Comment
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0
Response
Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer
Yes
Document Name
Comment
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Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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George E Brown - Pattern Operators LP - 5
Answer
Yes
Document Name
Comment
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Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Yes
Document Name
Comment
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0
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0
Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Yes
Document Name
Comment
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Yes
Document Name
Comment
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0
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0
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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Yes
Document Name
Comment
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0
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Wendy Kalidass - U.S. Bureau of Reclamation - 5
Answer
Yes
Document Name
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Comment
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Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3 - WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Yes
Document Name
Comment
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0
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0
Response
Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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Answer
Yes
Document Name
Comment
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0
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Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
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0
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0
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Yes
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Glen Farmer - Avista - Avista Corporation - 5
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Yes
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Comment
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Dave Krueger - SERC Reliability Corporation - 10
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Yes
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
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Yes
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Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
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Yes
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Comment
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Steven Rueckert - Western Electricity Coordinating Council - 10
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Yes
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Comment
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Shonda McCain - Omaha Public Power District - 6
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Yes
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Comment
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
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Yes
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Katrina Lyons - Georgia System Operations Corporation - 4
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Yes
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Comment
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Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Yes
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Joshua Phillips - Southwest Power Pool, Inc. (RTO) - 2
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Yes
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John Pearson - ISO New England, Inc. - 2
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Yes
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Mark Flanary - Midwest Reliability Organization - 10
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Yes
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Comment
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Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
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Yes
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Comment
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Wesley Yeomans - New York State Reliability Council - 10
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Yes
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Comment
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0
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Response
Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1
Answer
Yes
Document Name
Comment
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Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
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Yes
Document Name
2020-02_EPRI Comments on Draft NERC PRC-029 (IBR ride-through) Reliability Standard.pdf
Comment
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Thank you for your comments. The team believes these comments have been sufficiently addressed through the response to other comments.
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2. Do you agree that the language within PRC-029-1 requirements R1, R2, and R6 regarding IBR plant-level performance during grid voltage
disturbances is clear?
Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
Answer
No
Document Name
Comment
The ISO/RTO Council (IRC) Standards Review Committee (SRC) recommends the following modifications to improve the clarity and better convey the
intent of the standard.
Recommended changes to R1:
“…as specified in Attachment 1 except when needed to clear a fault or a documented and communicated equipment limitation exists in accordance
with Requirement R6.”
Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that each IBR remains electrically connected and continues to
exchange current in accordance with the no‐trip zones and operation regions as specified in Attachment 1 unless needed to clear a fault or a
documented equipment limitation exists in accordance with Requirement R6.
Recommended changes to M1:
“…demonstrating adherence to ride‐through requirements, as specified in Requirement R1, or shall have evidence of a documented and
communicated equipment limitation, as specified in Requirement R6.”
Recommended changes to R2:
“…each IBR’s voltage performance adheres to the following, unless a documented and communicated equipment limitation exists…”
The SRC recommends that the SDT to review and align the data in Attachment 1 to ensure that the data in Tables 1 and 2 aligns with what is shown
in Figures 1 and 2. Currently, the graphs in Figures 1 and 2 do not match what is indicated in the Tables. For example, rows 1-3 in Tables 1 and 2 are
identical, yet Figure 2 does not match Figure 1 by indicating a Voltage Ride-Through Requirement of 1.0.
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It appears that the SDT’s intent is to require continuous operation between 95% and 105% voltage with a minimum ride-through time of at least
1800 seconds (half an hour) when voltage is above 105% and not exceeding 110%. If the intent is actually that equipment must be able to operate
continuously at voltages up to 110%, then the tables and plots should be labelled with a descriptor that clearly indicates that indefinite or
continuous operation is required rather than operation for a minimum ride-through time (1800 seconds). For example, a version of Table 2 that
achieves the SDT’s apparent intent could look like the following:
Voltage (per unit)
Minimum Ride-Through Time (sec)
>1.2
N/A
<=1.2 and >1.1
1.0
<=1.1 and >1.05
1800
<=1.05 and >=0.95
Continuous
<0.95 and >=0.90
Continuous*
*current limitation permitted, with active or reactive power preference as specified
<0.90 and >=0.70
6
<0.70 and >=0.50
3
<0.50 and >=0.25
1.2
<0.25
0.32
While the above comments point out areas of ambiguity in the draft standard that need to be clarified, the SRC recommends that Table 1 and Table
2 be modified to require IBR plants remain connected indefinitely when the voltage is between 1.05 and 1.1 pu. The current draft standard requires
units to remain online for 1800 seconds in this range, and the logic behind this threshold is not clear. The current PRC-024 standard requires units to
remain on-line indefinitely for the above range. [All SRC entities support the comments in this paragraph except MISO].
In addition, the SRC recommends a part be added to the standard to directly address the Permissive Operating Region, similar to what is done in
Part 2.1 (for the Continuous Operation Region) and Part 2.2 (for the Mandatory Operation Region) as, the rules surrounding the Permissive
Operating Region are unclear if this is not addressed. For example, there should be some linkage between the body of the standard and Attachment
1, item 10. The SRC proposes the following language for consideration (new Part 2.3):
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2.3 While voltage at the high‐side of the main power transformer is within the Permissive Operation Region as specified in Attachment 1, an IBR
may operate in current block mode only if necessary to protect the equipment. Otherwise, each IBR shall follow the requirements for the
Mandatory Operation Region in Requirement R2, Part 2.2.
Recommended changes to R6:
The SRC is concerned that Requirement R6 as proposed provides an overly broad exemption, as the standard is silent as to what criteria must be
met to qualify for an exemption and contains no requirement that a Corrective Action Plan be developed or that the equipment limitations be
resolved or addressed. Only notification to other entities is required. The SRC recommends that the SDT:
•
•
Develop more specific criteria as to what qualifies as an equipment limitation[1], OR A technical justification that addresses why corrective
actions will not be applied nor implemented.
Require exemptions be submitted to NERC and/or the Regional Entities for pre-approval in order to qualify for the exemption.
The SRC suggests there should be explicit requirements to both ‘document equipment limitations’ and to ‘communicate’ those documented
limitations to the appropriate parties. The SRC proposes the following modifications to address this issue:
“Each Generator Owner and Transmission Owner with a known equipment limitation that would prevent an applicable IBR that is in‐service by the
effective date of this standard from meeting voltage ride‐through requirements as detailed in Requirements R1 and R2 shall document each
equipment limitation, develop a Corrective Action Plan to address the limitation, and communicate both the limitation and the Corrective Action
Plan to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s).
Recommended changes to M6:
Each Generator Owner and Transmission Owner shall have evidence of known equipment Limitations accompanied by a Corrective Action Plan, as
specified in Requirement R6, having been documented and communicated to each associated Planning Coordinator, Transmission Planner, and
Reliability Coordinator prior to the effective date of PRC‐029‐1.
Each Generator Owner and Transmission Owner with changes to equipment shall have evidence of communication to each associated Planning
Coordinator, Transmission Planner, and Reliability Coordinator.
[1] See Implementation Plan (page 4), “only those IBR that are unable to meet voltage ride-through requirements due to their inability to modify
their coordinated protection and control settings may be considered for potential exemption.” See Technical Rationale (page 9); i.e. specify which
voltage band(s) and associated duration(s) cannot be satisfied or specific as to the number of cumulative voltage deviations within a ten‐second time
period that the equipment can ride‐through if less than four… identify the specific equipment and explain the characteristic(s) of that equipment that
prevent ride‐through.
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Response
Thank you for your comment.
R1 and R2: The team revised R1 and R2 to state “an equipment limitation in accordance with Requirement R6.” R6 includes requirement language
to document and communicate. Measure M4 (previous M6) was revised to include “known” as well as “and communicate” with the initial
documentation of an equipment limitation.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of Tables
1 and 2 to clarify the continuous operation region.
R2: The team added requirement subpart 2.3 to provide clarity on the operation within the Permissive Operation Region.
R4 (Previous R6): The team added clarity to Requirement R4 and the Implementation Plan to align the documentation and communication of
known equipment limitations and exemptions with Requirement R3 of PRC-024-4.
Michael Brytowski - Great River Energy - 3
Answer
No
Document Name
Attachment 1 figures 1 and 2 .pdf
Comment
Comments: GRE requests the SDT review and align the data in Attachment 1 so the data in Tables 1 and 2 aligns with what is shownin Figures 1 and
2. Currently, the graphs in Figures 1 and 2 do not match what is indicated in the Tables. (uploaded)
GRE recommends a part be added to the standard to directly address the Permissive Operating Region, similar to what is done in Part 2.1 (for
Continuous Operation Region) and Part 2.2 (for Mandatory Operation Region) as, if left unaddressed, is unclear. For example, there should be some
linkage between the body of the standard and Attachment 1, item 10. MRO NSRF proposes the following language for consideration (new Part 2.3):
2.3 While voltage at the high‐side of the main power transformer is within the Permissive Operation Region as specified in Attachment 1, an IBR
may operate in current block mode only if necessary to protect the equipment. Otherwise, each IBR shall follow the requirements for the
Mandatory Operation Region in Requirement R2.2.
GRE is concerned that requirement R6 provides an overly broad exemption as written as the standard is silent as to what criteria must be met. Only
notification to other reliability entities is required with no requirement to develop and implement a Corrective Action Plan. MRO NSRF recommends
the SDT:
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Develop more specific criteria as to what qualifies as an equipment limitation[1], OR
Require exemptions be submitted to NERC and/or the Regional Entities for approval in order to qualify for the exemption.
[1] See Implementation Plan (page 4), i.e. “only those IBR that are unable to meet voltage ride-through requirements due to their inability to modify
their coordinated protection and control settings may be considered for potential exemption.” See Technical Rationale (page 9); i.e. specify which
voltage band(s) and associated duration(s) cannot be satisfied or specific as to the number of cumulative voltage deviations within a ten‐second time
period that the equipment can ride‐through if less than four… identify the specific equipment and explain the characteristic(s) of that equipment that
prevent ride‐through.
R2: GRE agrees with the present flexibility that some of the IBR VRT performance could be modified to meet the individual system needs by the
applicable Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator. However, some clarity may be required
on how this process is initiated and what type is evidence is required to demonstrate request is received and implemented. This may be an
additional requirement assigned to the Transmission Planner. Each Transmission Planner, Planning Coordinator, and Transmission Operator that
jointly specifies the following voltage ride-through performance requirements within their area(s) different than those specified under R2, shall
make those requirements available to each associated applicable IBR Generator Owner and Transmission Owner.
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Response
Thank you for your comment.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of Tables
1 and 2 to clarify the continuous operation region.
R2: The team added requirement subpart 2.3 to provide clarity on the operation within the Permissive Operation Region.
R4 (Previous R6): The team added clarity to Requirement R4 and the Implementation Plan to align the documentation and communication of
known equipment limitations and exemptions with Requirement R3 of PRC-024-4.
Mark Flanary - Midwest Reliability Organization - 10
Answer
No
Document Name
Comment
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See comments below under question 4.
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Thank you for your comments.
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
No
Document Name
Comment
R2.5 & R5.1, et al. Each IBR shall only trip … “Trip” may be ambiguous. Does this mean disconnecting from the system to de-energize the IBR
equipment, as in opening a circuit breaker? Or does it mean cease exchanging current? Or something else?
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Thank you for your comment.
The team believes that “trip” is an industry term that is generally accepted when a plant/facility disconnects and electrically isolates itself.
R2: The team agrees with removing requirements on operation outside the no-trip zone and has removed R2.5.
R5: Requirement R5 has also been removed.
John Pearson - ISO New England, Inc. - 2
Answer
No
Document Name
Comment
For R1, We recommend adding language to refer to plants that were previously exchanging current before the disturbance. For example, A BESS
that is fully charged would be connected to the BES, but would not be exchanging current. For R2, change “each IBR’s voltage performance” to
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voltage ride through performance. For R6, exemptions should not be automatically allowed. This would allow for bad designs relying on an
exemption. Exemptions should only be for existing or legacy units. New units should not have the option for exemption.
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Thank you for your comment.
Terminology: That the requirement states “continues to exchange” implies that the facility was exchanging current prior to the disturbance.
R2: R2 states that the voltage performance must meet the requirements within Attachment 1. Also, ride-through is not currently defined.
R4 (Previous R6): R4 only applies for legacy units that have already documented known equipment limitations. Refer to the Implementation Plan for
additional information.
Joshua Phillips - Southwest Power Pool, Inc. (RTO) - 2
Answer
No
Document Name
Comment
Southwest Power Pool joins the ISO/RTO Council Standards Review Committee comments.
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0
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0
Response
Thank you for your comment. Please see response to the ISO/RTO Council Standards Review Committee.
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
No
Document Name
Comment
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In the opinion of ACES, the newly proposed Glossary Terms are unnecessary and seemingly incongruous terms. For example, if the Mandatory
Operating Region is required, should it not also be continuous? It is our opinion that these terms add little to no value and instead only create
confusion where none was previously present. We recommend striking these new terms from the standard.
In ACES’ opinion, R1 appears to be overly broad so as to require an applicable IBR to be operational at all times. This does not appear to allow for
full facility outages without first having a “documented equipment limitation” per R6. Thus, as written, the GO will run the risk of non-compliance
with either R1, R6, or both whenever a full facility outage of an IBR is required. Furthermore, it is unclear how R1 differs from R2 other than seeming
to requiring the GO to ensure the GOP always keeps the unit online during to normal operation. We recommend striking R1 from the standard.
Additionally, we do not agree with the language of Requirement R2, Part 2.1.1. As written, R2 does not define what type of System disturbance is
applicable and Part 2.1.1 requires the GO to continue producing active power at the pre-disturbance levels or its maximum capability; whichever is
less. We have concerns with this approach. Namely, during an over frequency deviation event wherein the high side MPT voltage remains ≥ 0.9
p.u. and ≤ 1.1 p.u. In this instance, the frequency response algorithm within the IBR would attempt to reduce active power output. Due to the
fast-acting nature of IBRs, it is likely that an IBR facility(ies) would respond to and correct such an event before a synchronous generating
resource(s). However, in the aforementioned hypothetical example, to comply with R2.1.1, the IBR frequency response control would need to be
either disabled or limited in its response to an over frequency System disturbance. In our opinion, this is not beneficial to the reliability of the BES.
While possibly unlikely at the current time, this hypothetical scenario becomes increasingly likely as conventional synchronous generating resources
are retired in favor of IBRs.
Furthermore, it is the opinion of ACES that R6 should be modified to include any potential regulatory limitations. This suggested approach is in line
with the approach taken in PRC-024-4 R3. We recommend the modifying R6 as follows:
R6. Each Generator Owner and Transmission Owner shall document each known regulatory or equipment limitation that prevents an applicable IBR
that is in‐service by the effective date of this standard from meeting voltage or frequency ride‐through requirements as detailed in Requirements R1
through R5.
6.1 Each Generator Owner and Transmission Owner shall include in its documentation:
6.1.1 Identifying information of the IBR (name, facility #, other)
6.1.2 Which aspects of voltage ride‐through requirements that the IBR would be unable to meet
6.1.3 Identify the specific piece(s) of equipment causing the limitation.
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6.2 The Generator Owner and Transmission Owner shall communicate the documented regulatory or equipment limitation, or the removal of a
previously documented regulatory or equipment limitation, to its Planning Coordinator and Transmission Planner, and Reliability Coordinator within
30 calendar days of any of the following:
6.2.1 Identification of a regulatory or equipment limitation.
6.2.2 Repair of the equipment causing the limitation that removes the limitation.
6.2.3 Replacement of the equipment causing the limitation with equipment that removes the limitation.
Lastly, the values specified in Table 1 and Table 2 in Attachment 1 do not align with the graphs shown in Figure 1 and Figure 2, respectively.
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Thank you for your comments.
Definitions: The team removed the terms for operating regions.
R1: Requirement R1 requires that the plant/facility must be electrically connected and exchanging current prior to the disturbance. R1 is needed to
define clear boundaries for ride-through and R2 is needed to define performance for the different operation regions within the no-trip zone.
R1 and R2: The team used the defined term “voltage excursion” to align with language in PRC-024.
R2: The team added a footnote to 2.1.1 and other relevant footnotes to resolve the frequency excursion scenario.
R4 (Previous R6): The team included the regulatory limitation to align with PRC-024. R4 was also modied to clarify that changes to equipment that
remedy the equipment limitation, that would remove the exemption.
Attachment 1: The tables and figures have been adjusted.
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
No
Document Name
Comment
See comments submitted by Edison Electric Institute
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0
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Dislikes
0
Response
Thank you for your comment. See response to EEI.
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI comments
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0
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0
Response
Thank you for your comment. See response to EEI.
Kinte Whitehead - Exelon - 3
Answer
No
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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0
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0
Response
Thank you for your comment. See response to EEI.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
No
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Document Name
Comment
Electric Reliability Council of Texas, Inc. (ERCOT) joins the comments of the ISO/RTO Council (IRC) Standards Review Committee (SRC) and adopts
them as its own in addition to the following comments, except to the extent of any specific differences between the SRC comments and the
following comments from ERCOT.
As detailed below, the currently proposed language for Requirement R1 is not clear. Additionally, ERCOT believes that plant‑level requirements are
insufficient because individual IBR unit performance failures continue to occur and could, in aggregate, be just as impactful or more impactful than
the complete loss of an IBR plant. The performance threshold should be coordinated with the threshold in PRC-030, and ERCOT believes a
reasonable threshold would be the lesser of either 20% of the plant’s gross nameplate rating, or 20 MW. In an IBR-dominated electric system, these
aggregated losses could cause unreliable operations if not corrected. The past 8-10 years have demonstrated that IBR owners will not voluntarily
correct these performance issues in the absence of a mandatory reliability standard.
SDT’s proposed language (ERCOT finds the bold portions unclear):
“Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that each IBR remains electrically connected and continues to
exchange current in accordance with the no‐trip zones and operation regions as specified in Attachment 1 unless needed to clear a fault or a
documented equipment limitation exists in accordance with Requirement R6.”
ERCOT’s proposed language:
“Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that each IBR, and its IBR units, remains electrically connected and
continues to exchange current in accordance with the no‐trip zones and operation regions as specified in Attachment 1 unless the IBR, or its IBR
units, needs to be tripped to clear a fault or a documented equipment limitation exists in accordance with Requirement R6.”
In addition to the concerns with Requirement R1 noted above, ERCOT is concerned that Requirement R2 does not clarify the timeframe
encompassed by the term “System disturbance.” Without further clarification, “System disturbance” may be interpreted to only describe the fault
itself, even though control instability may manifest itself immediately after the fault clears or during the milliseconds or seconds after the fault
clears, during which time frequency and voltage support are still critical. While IEEE 2800 defines the disturbance period, and there is an
expectation that an IBR will perform acceptably in the continuous operation region, Requirement R2 is not clear that “riding-through” a disturbance
includes both the fault and the non-fault portions of the disturbance along with the transition from ride-through mode to a new steady-state (i.e.,
the post-disturbance period). ERCOT suggests a 10-second window as a bright-line criterion.
SDT's proposed language for Requirement R2.
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“R2. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that during a System disturbance, each IBR’s voltage
performance adheres to the following, unless a documented equipment limitation exists in accordance with Requirement R6.”
ERCOT’s proposed language for Requirement R2:
“R2. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that during, and up to ten seconds after, a System disturbance,
each IBR’s voltage performance and its associated IBR units’ voltage performance adheres to the following, unless a documented equipment
limitation exists in accordance with Requirement R6.”
For Requirement R2, Part 2.2.2, ERCOT agrees that location-specific flexibility may be needed and defined by the TP, PC, RC, and or TOP; however,
the language should clearly mandate that in such instances, the established performance requirements must also be met. Additionally, the current
wording does not address the possibility that reactive current “response” could be in the wrong direction if not properly configured, and the
language should be clarified to address this issue. ERCOT proposes the following language for Part 2.2.2 to capture the full spectrum of current
priority modes from full aggressive reactive priority mode, to a de‑tuned reactive response while in reactive priority mode, to an active priority
mode.
“Adjust reactive current injection at the high-side of the main power transformer so that the magnitude of the reactive current properly responds
to changes in voltage at the high-side of the main power transformer in accordance with default reactive prioritization or as required by any
applicable Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator that specifies a certain magnitude and
timeliness of reactive power response to voltage changes, that specifies a maximum allowed active current reduction to provide reactive current,
or that specifies active power priority instead of reactive power priority.”
ERCOT also recommends including the following language to help prevent unnecessary misoperations due to the use of unfiltered measurements or
instantaneous (no time delay) settings for protection systems, consistent with NERC recommendations for addressing easily preventable
performance failures.
R2.2.3 “Utilize sufficient time delays or filtering methods for any voltage measurements utilized by its protection equipment to prevent unnecessary
trips due to calculation errors or transients.”
ERCOT finds the bolded portions of the SDT’s proposed language for Requirement R2, Part 2.3 to be unclear:
“The IBR shall not itself cause voltage at the high‐side of the main power transformer to exceed the applicable Attachment 1 Table 1 or Table 2 no‐
trip zone voltage thresholds and time durations in its response from Mandatory or Permissive Operation Regions to the Continuous Operating
Region.”
ERCOT proposes the following language to clarify the issue:
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“The IBR shall not itself cause voltage at the high‐side of the main power transformer to exceed the applicable Attachment 1 Table 1 or Table 2 no‐
trip zone voltage thresholds and time durations in its response as it transitions from Mandatory or Permissive Operation Regions to the Continuous
Operating Region.”
ERCOT would also point out that the last clause may not be necessary because the IBR should not cause high voltage at any time, and the SDT could
consider the following alternative language:
“The IBR shall not itself cause voltage at the high‐side of the main power transformer to exceed the applicable Attachment 1 Table 1 or Table 2 no‐
trip zone voltage thresholds and time durations.”
Consistent with the comments above on Requirement R2, Part 2.2.2, Requirement R2, Part 2.4 should be revised as follows to clarify that the other
requirements or specifications from the RC/PC/TP/TOP must still be met:
“Each IBR shall restore active power output to the pre‐disturbance or available level within 1.0 second when the voltage at the high‐side of the main
power transformer returns to the Continuous Operation Region from the Mandatory Operation Region or Permissive Operation Region (including
operation in current block mode) as specified in Attachment 1, or as required by any applicable Transmission Planner, Planning Coordinator,
Reliability Coordinator, or Transmission Operator that specifies a lower post‐disturbance active power level requirement or that specifies a
different post‐disturbance active power restoration time.”
Requirement R2, Part 2.5 may not be clear, in light of the new defined terms, that partial trips (including trips of individual IBR units) should not be
allowed. While this topic should be coordinated with PRC-030, it goes to the heart of momentary cessation in that staying connected but not
supporting frequency and voltage can, in aggregate, be just as detrimental to reliability as a full trip. The SDT should consider revising Part 2.5 to
ensure that it is clear that there would be a violation at a particular level (e.g., the lesser of 20% of the unit’s rated output, or 20 MW) of IBR unit
trips. This could be graduated in severity level starting at the 20% or 20 MW level and increasing thereafter (e.g., 20%, 40%, 60%, 80%, and above).
ERCOT’s proposed language for Part 2.5: “Each IBR, or its IBR units, shall only trip to prevent equipment damage, when the voltage at the high‐side
of the main power transformer is outside of the no‐trip zone as specified in Attachment 1.”
ERCOT also has concerns with the SDT’s proposed Requirement R6 language:
“Each Generator Owner and Transmission Owner with a documented equipment limitation that would prevent an applicable IBR that is in‐service
by the effective date of this standard from meeting voltage ride‐through requirements as detailed in Requirements R1 and R2 shall communicate
each equipment limitation to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s).”
More specifically, the first bolded phrase (“a documented equipment limitation”) appears to allow complete GO/TO discretion to declare a
limitation with no process for review, approval, or acceptance of the limitation by any other entity. Only a communication to the PC, TP, and RC is
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required. It is unclear if the SDT’s intention is that at some point these documented limitations would be reviewed or evaluated under the NERC
CMEP (and it is unclear what standard the limitation documentation would be held to under such a review). At a minimum, Measure M6 and/or the
Technical Rationale should provide more information about what an acceptable limitation might be and guidance for CMEP staff to use in evaluating
the validity of limitations and the associated documentation.
The second bolded portion (“shall communicate each equipment limitation to the associated Planning Coordinator(s), Transmission Planner(s), and
Reliability Coordinator(s)”) is necessary, but may not be effective from a reliability perspective. A mere description of a limitation sent in an email
or letter would not be useful for the PC/TP/RC but would meet the letter of Requirement R6. If the purpose of the communication is for PCs, TPs,
and RCs to be able to assess the limitation and incorporate it into system studies, either Requirement R6 or the Technical Rationale should clarify
that the communication needs to be in a format that is acceptable and useful to the PC/TP/RC (most likely in the form of an updated model that
reflects the limitation). Additional burdensome administrative requirements to cover this communication process are not suggested, but at the very
least the Technical Rationale should include guidance and set expectations to ensure that the communication will be useful to ensure the reliability
of the grid. Additionally, ERCOT notes that FERC Order 901 recognized 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.” ERCOT recommends that Requirement R6 be clarified to indicate
that the equipment limitation process is only available to the limited subset of IBRs described in Order 901.
Additionally, ERCOT notes that Requirement R6, Part 6.2 does not require the TO/GO to actually improve ride-through capability even when
equipment is replaced:
“Each Generator Owner and Transmission Owner with a previously communicated equipment limitation that repairs or replaces the equipment
causing the limitation shall document and communicate such equipment changes to the associated Planning Coordinator(s), Transmission
Planner(s), and Reliability Coordinator(s) within 30 days of the equipment change.”
Rather than focusing on communication of changes, Part 6.2 should require the TO/GO to comply with all PRC-029 requirements and should not
allow any documented limitations whenever equipment is changed or replaced; this approach would better align with FERC Order 901. PRC-029
should also include a requirement that mandates the implementation of software settings changes and upgrades (that do not require replacement
of physical equipment) that improve ride-through capability. This is referenced in the implementation plan, but is absent from the actual
requirements in PRC-029.
Equipment limitations may also not be currently captured in dynamic models, and the list of requirements should be updated to reflect this
issue. The MOD standards may not accurately account for the provision of this information to all entities that perform studies (including stability
limit and IROL determination studies that RCs perform); this would constitute a reliability gap. RCs and PC/TPs must be able to assess the impact of
these exemptions to be able address the reliability impact under FERC Order 901.
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Finally, ERCOT notes that FERC Order 901 requires NERC 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.” While it is clear that the SDT has determined that the standard
should allow for documented exemptions for equipment limitations, the requirement language is unclear as to how or whether this exemption
process is truly “limited” as required in Order 901, especially in light of the explicit reference to IBRs “that are unable to modify their coordinated
protection and control settings to meet the requirements without physical modification of the IBRs’ equipment.” As ERCOT notes below,
exemptions should be limited to scenarios where a responsible entity cannot otherwise achieve the necessary ride-through performance without
physical equipment changes (inability to meet ride-through requirements that can be addressed simply by making software- or parameterizationtype changes should not be grounds for an exemption) OR to scenarios where, even without making the remaining physical changes, the loss of a
contingency would not cause instability, Cascading Outages, or uncontrolled separation that adversely impact the BPS.
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Thank you for your comments.
Evaluation of plant performance: The team is establishing plant/facility level ride-through requirements, consistent with the availability of
disturbance monitoring data established within PRC-028. Further, Requirement R2 requires that the plant/facility must return to pre-disturbance
values. Should the plant experience tripping of a portion of it’s individual inverters, the overall plant would not be able to achieve compliance with
R2. PRC-030 also include mechanisms for the entities with a wider-area view to request data, analyze performance, and establish corrective action
plans.
Terminology used: The team has replaced the terms “disturbance” and “event” to use the type of excursion that is occurring. This change allows
Requirement R1 to cover the time after a fault.
R2: The team agrees to some revised language in 2.2.2 to clarify the current response desired to improve performance.
R2.4 (Previous R2.3): The team clarified language in as suggested and added clarity on the voltage recovering as part of the change state.
R2.5 (Previous R2.4): Revisions included.
Previous R2.5: R2: The team agrees with removing requirements on operation outside the no-trip zone and has removed R2.5.
R4 (Previous R6): The team did add clarity to R4 and the implementation plan to specify what is allowable to an exemption that is consistent with
the regulatory directives and assures adequate reliability can be evaluated.
Shonda McCain - Omaha Public Power District - 6
Answer
No
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Document Name
Comment
OPPD supports comments provided by GRE: Michael Brytowski, Great River Energy, 3, 4/17/2024
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Thank you for your comments. See response to Great River Energy.
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company, 3, 1, 5;
Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
No
Document Name
Comment
Requirement 1 and 2
These requirements mention that the IBRs should respond to the voltage changes with reactive current injection during a system disturbance,
however, the magnitude of this response is not identified. The magnitude and expectation of the response should be clarified due to the fact that it
can vary by unit and unit capabilities.
Measures 1, 2, 3, 4, and 5
With regards to data recording, it is unclear what counts as recording? If the expectation is the same as contained in PRC-028-01 Draft 2, that
should be specified; or otherwise identify alternate means of data recording.
What if an entity does not have a recorded event to show compliance with the standard and prove its ability to ride through a system event?
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Thank you for your comments.
R1 and R2: R2.2.2 allows for TP/PC/RC/TOP to require specific reactive current and active current magnitude as needed. The team does not intend
to provide specificity of magnitude in R1 nor R2.
Measures: The team specific language in the measures to tie disturbance monitoring data language to PRC-028-1. The team added specificity for
demonstration of capability/design as well as performance.
Coordination between projects: The team will work with the implementation plan to reflect the reality of the PRC-028 implementation.
Richard Vendetti - NextEra Energy - 5
Answer
No
Document Name
Comment
NextEra aligns with EEI's comments:
EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
EEI also does not support Requirement R2, subpart 2.5 because it contains unneeded language, which adds confusion and implies that GOs can only
trip outside of the trip zone if their equipment might become damaged. This has never been an obligation for synchronous generators, and we do
not agree that this should be an obligation for IBRs. If NERC or the SDT believe that the no-trip zone needs to be expanded, they should justify such
a change and present it for industry review and comment, otherwise, Requirement R2, subpart 2.5 should be deleted.
And while we support Requirement R6 and the provisions to notify PCs, TPs and RC about equipment limitations that would prevent an applicable
IBR from meeting ride‐through requirements as detailed in Requirements R1 and R2, the Requirement does not go far enough because there may
be technical reasons why an applicable IBR is unable to meet Requirement R3 through R5, as well. To address this concern, R6 should be expanded
to include Requirement R1 through R5.
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Applicability: The team has removed the word “applicable” and include a reference to the applicability section of the Standard. Any IBR that cannot
meet voltage ride-through requirements, and may need to trip within the no-trip zone to protect equipment, would be covered under the
documented equipment limitations as covered within Requirement R4 (Previous R6).
R2: The team agrees with removing requirements on operation outside the no-trip zone and has removed R2.5.
R4 (Previous R6): The scope of allowable exemptions within R4 is consistent with the regulatory directives of Order No. 901. Requirements R3-R5
cannot apply.
Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
No
Document Name
Comment
In regard to R1:
Does M1 imply that actual recorded data must be kept as evidence of ride-thru compliance for every in-scope IBR, for every system disturbance?
Thesame question applies to R2-M2, R3-M3, R4-M4, and R5-M5.
The disturbance characteristic must be specified in order to trigger captures of performance information for every disturbance at every IBR facility the characteristic which defines each type of disturbance must be defined in order to capture the record.
For each of the Measures M1 - M5, what "other evidence" can demonstrate compliance with R1-R5 other than recorded data? How does the
drafting team believe that generator owners can assure this performance expectation can be achieved prior to an actual event? There is no test
verification that can be performed to confirm the expected performance. Consider providing some examples of what is acceptable as “other
evidence”.
R1 mentions “operation regions specified in Attachment 1. R2, Part 2.1 mentions “continuous operation region as specified in Attachment 1” and
Part 2.2 mentions “mandatory operation regions as specified in Attachment 1”. However, nowhere in attachment 1, is there mention of
"continuous, mandatory, or permissive" operation regions.
In regard to R2:
For R2, Continuous Operation Region is not specified in Att. 1; it is merely a defined term in the draft standard. Southern Company suggests that
the referenced region be shown on the graph of Att.1, or that the words from the defined term simply be placed in the sub-requirement directly
rather than creating a defined term. The term region implies an area (volt-time). If the definition is simply specifying voltage level magnitude,
simply state that. The definition labels are confusing; does permissive operation mean the IBR has permission to trip if the voltage is less than
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0.1pu? It is observed that the values in the "mandatory operating region" match some of the borders of the "no trip zone" in Attachment 1, yet
there is a time element that must be accounted for in determining if a trip is in compliance or not with the curve of Att. 1. For example, how can a
long term (1-9 second) event where the voltage is 0.4pu be a Mandatory Operating Region? The voltage ride-thru curve does not specify this (for
example).
Regarding the R2.2 and R2.3 requirement specifications, IBR facilities do not have per phase voltage regulation in their current designs, so the
feasibility of successfully reacting to low system voltage (R2.2) with rapid reactive power injection while not possibly causing high voltage locally
(R2.3) is questionable.
Regarding R2.1.1 & R2.1.2, it should also reference Interconnection Agreements (IA) limits since some IBR facilities have both solar and battery
storage with an IA limit less than the aggregate sum.
Regarding R2.1.1 and R2.1.2, the idea that IBR Facility Power Plant Controllers operate to apparent power limits, is not in line with normal
practices. Most PPC interfaces do not provide an apparent power reading or control function option. PPCs communicate separate MW and MVAR
setpoints to all the of the site IBR Units and they follow or provide as capable the MWs and deliver MVARs up to the inverter reactive power limit.
Southern Company recommends changing wording to:
R2.1.1:Continue to deliver the predisturbance level of active power or available active power, whichever is less, and continue to deliver active powe
r and reactive power up to its reactive power limit.
R2.1.2:If the IBR cannot deliver both active and reactive power due to a current or reactive power limit, when the applicable voltage is below 95% a
nd still within the Continuous Operation Region, then preference shall be given to active or reactive power according to requirements specified by t
he Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
R2.1.2 discusses giving preference to either active or reactive power based on requirements specified by transmission entities. There is some
concern that this could be interpreted as a fluid preference that could require IBRs to actively configure active vs reactive capabilities.
Regarding R2.3, what happens if TOP has several lines down for maintenance in the area, which causes the part of the system the IBR facility is
located, go from a strong system to a weak system?
R2.4 does not take into consideration other dynamic system conditions as a result of the fault and the effects on the PPC during a fault recovery. An
example of this is Primary Frequency Response due to system frequency excursions during fault recovery. The active power recovery may be
reduced or frozen during an underfrequency event while an IBR Resource is in recovery, thereby extending the time of the recovery.
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R2 specifies performance for continuous and mandatory operation region, but not for permissive operation region. The performance during
permissive operation region is in Attachment 1. Performance for all regions should be in Requirement R2.
Regarding R2.1.1, the first part, where IBR is required to continue to deliver the pre-disturbance level of active power or available active power,
whichever is less is fine. However, the second part (and continue to deliver active power and reactive power up to its apparent power limit) is
conflicting with the first part of this requirement. If the IBR plant’s available active power was 50% of nameplate rating due availability of wind, solar
irradiance, etc., then the second part of the requirement is stating that plant is required to produce reactive power to its apparent power limit given
its available active power equal to 50% of nameplate rating. This is not correct.
In regard to R2.1, the clause 7.2.2.2 of the IEEE Std 2800 includes an exception when negative-sequence voltage is higher than certain threshold for
a given time duration. Why the SDT not include this exception in the PRC-029?
In regard to R2.2, it appears the intent is to require that inject balanced current, during symmetrical faults, and unbalanced current during
asymmetrical faults. However, the language is confusing. First, there is no plant level voltage regulation during a fault condition. Second, during
unbalanced faults, what does a voltage regulation mean? One option is replace both Part 2.2.1 and Part 2.2.2 with following: The IBR shall inject
current based on voltage deviation on high-side of main power transformer and as specified by the TP, PC, RC, or TOP.
In regard to R2.3,this requirement is confusing. Table 1 and 2 in Attachment 1 includes both low- and high-voltage thresholds. One meaning could
be that the IBR shall not cause voltage to exceed LVRT threshold for a specified time duration. The true meaning is unclear. Is it correct that the
intent is to focus on HVRT thresholds and time duration? The time duration for voltage > 1.2 per unit is not specified. Does this mean that IBR shall
not cause overvoltage > 1.2 per unit whatsoever? If so, it needs to be written clearly.
In regard toR2.5, if there is no expectation for IBR to ride-through disturbance outside of no-trip zone, then there is no need for this requirement.
For example, if voltage is zero for greater than specified time duration in Tables 1 and 2, say 1 second, then what is the point in staying connected
and feeding into fault unless there is a risk of equipment damage? Additionally, there is no such expectation for frequency ride-through
requirement R4.
R2.5 is not practical for the GO to determine where every individual piece of equipment would be damaged. There is no need to require tripping
just before equipment damage if IEEE 2800 is guidance for equipment manufacturers.
In regard to Attachment 1:
1. There is no mention of continuous, mandatory, or permissive operation region in tables 1 and 2. Consider adding a column in tables 1 and 2
to show these operation regions.
2. For Table 1 and 2:
o ≥1.20 should be >1.2
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3.
4.
5.
6.
≥1.1 should be >1.1
≥1.05 should be >1.5
In IEEE Std 2800, the cumulative ride-through duration of 1800 second when voltage is > 1.05 is applicable to all nominal voltages except for
500kV nominal operating voltage. For 500kV nominal operating voltage, the equipment rated to 550kV (1.10 per unit) is available per ANSI
C84.1. In IEEE Std 2800, see Note 1 under Table 12. Consider clarifying this in the PRC-029.
Note 7: A time window of 10-second is mentioned. However, when V>1.05, the ride-through duration is 1800 second, which is over a 3600second time window in IEEE 2800.
Note 10: The purpose of current blocking in IEEE 2800 was not to protect the equipment but to rather to avoid tripping due to consequences
of injecting current and hence, failure of ride-through.
Figures 1 & 2: why does the X-axis start at 0.1 second and not zero?
o
o
Finally, Southern Company supports EEI and NAGF comments.
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Thank you for your comments
Measures (events): The evidence of compliance for disturbance monitoring that are associated with voltage and frequency excursions that were
System disturbances and would be identified for analysis or another trigger by an applicable entity within draft PRC-030. Evidence of disturbance
monitoring of IBR associated with those disturbances would be triggered by compliance under the requirements for PRC-030.
Measures (data): The team agrees and the measures for R1 through R3 have been adjusted to include design/capability based requirements as well
as the demonstration of performance during disturbances.
Attachment 1: The team agrees and has made changes to the tables and figures to include clear references to the operation regions. Explanation of
the permissive operation region was added to Requirement 2. The definitions for the regions were also removed.
Exemptions: Voltage requirements R1 and R2 may have the capability for exemption of an known hardware-based limitation as detailed in the
Implementation and Requirement R4 (Previous R6). The requirements include the flexibility for the IBR response based on the communication
between the GO and the TP/PC.
R2 – use of reactive power: The team agrees that changes to clarify reaction power support in 2.1 was needed and made some adjustments to
specify reactive power. This was broken into 2.1.1 and 2.1.2.
R2- -dynamic switching: Requirement 2.1.3 (previously 2.1.2) does not require dynamic switching between these two modes of operation.
However, if that capability already exists, the operating mode would need to be specified by the TP, PC, RC, or TOP.
General operation expectations: IBR must adhere to ride through requirements and any direction as specified by their TOP(s) under any system
operating condition.
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R2 – clarification on frequency and voltage excursions: Requirement 2.5 (previously 2.4) now includes a footnote to add an exception for IBR
response during a frequency excursion. Language was also changed to voltage/frequency excursions throughout to add clarity on this point.
Permissive Opertion Region: The team added new 2.3 to include performance requirements during the permissive operation region.
R2 – use of reactive power: Language was clarified in 2.1.1 and new 2.1.2 to address apparent vs reactive power limits per above.
General operation expectations: Any additional operation for specific conditions such as the negative sequence overvoltage conditions, should be
directed by the TOP as needed.
R2 General operation expectations: Requirement 2.2. was clarified to allow for operating instructions from the TOP/PC/RC/TP to be followed but
only if specified. Further usage of AVR was removed from the requirement.
R2 overvoltage clarification: Revisions were made to R2.4 (previously 2.3) to specify exceedances above the high voltage thresholds.
R2.5: The team has removed the previous 2.5.
Attachment 1 - corrections: Attachment 1 tables and figures have been adjusted to correct some values and to include clear references to the
operation regions.
Attachment 1 clarification on 500kv: Attachment 1 sets the minimum expectation for operation regardless of voltage class. Expanding the no trip
zone for 500kV may still be done based on the system need.
Attachment 1 clarification of accumulation Note: The 10-second window is not used to define the thresholds within a particular operating region
but it’s the reset of the accumulation of the excursions into the mandatory and permissive operating regions.
Attachment 1 revision to Previous Note 10: The team agrees on the details of note 10 in attachment 1 and have made this a new requirement in
R2.3.
Attachment 1 - corrections: The figures have been adjusted and now starts as zero.
Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
No
Document Name
Comment
In 2.1.1 the “apparent power limit” is what is capable during the System disturbance correct? What is the “applicable voltage” to determine 95% in
2.1.2 (and why is per unit not used)? Where are the “requirements specified” by the TP/PC/RC/TOP and how does a GO or TO determine which one
to use? If in the Planning world, the requirements should be specified in the TPL Standards. It is unclear what actions a TO/GO will take and be
consistently applied. Since this is an event driven compliance review in the Operations Assessment time horizon, why would a TP or PC provide
preference for active or reactive power in that timeframe? In a response study by the TP/PC, perhaps guidance on preference could be provided
but it is unclear and NOT required in TPL Standards to this point. Clarity between the Tables and Figures in Attachment one needs provided to avoid
confusion.
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Just to be clear, It appears that any new units after the effective date of this Standard have to meet all the criteria. Do the existing units with
limitations have six months after the effective date of Standard to submit equipment limitations. With PRC-024-3 and PRC-024-2 already having a
Requirement in place that requires limitations to be provided to the TP/PC and the industry already leaning on IRO-010 and TOP-003 for
notifications, why is there a need to add an additional 6 months for Requirement R6? The RC already has communication capability with GOs.
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Thank you for your comments.
R2 – use of reactive power: The team agrees and has clarified the language in 2.1. to use reactive power limit instead of “apparent power”. Also,
the reference to “applicable voltage” was changed to “voltage”. The parent requirement states which voltage already. The team has also changed
the 95% to per unit values to be consistent throughout the standard.
R2 – dynamic switching The language of 2.1 and 2.2 was changed to clarify default preferences unless preference for active/reactive power support
was established by the TP/PC/RC/TOP and based on system needs. Requirements do not require dynamic switching between these two modes of
operation. A footnote was added that clarified that if a operation mode was specified by the TP/PC/RC/TOP, then that operation mode shall be
followed instead.
Attachment 1 – corrections: Attachment 1 tables and figures have been revised to clarify the operating regions and no-trip zones.
Implementation Plan: The additional six month time frame is provided during the implementation plan for R4 (previous R6) to allow entities to
verify documentation and cross check with the criteria within the new Standard. The required data to provide to qualify for an exemption must
provide documentation stating which aspect of the voltage ride-through requirements cannot be met. Additionally, the criteria within PRC-029 is
not one-to-one with criteria within PRC-024-4.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
No
Document Name
Comment
See EEI Comments
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Response
Thank you for your comment.
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
No
Document Name
Comment
R1:
R1 should be revised to directly clarify, or include a footnote to clarify, the statement “that each IBR remains electrically connected and continues to
exchange current” with “electrically connected, i.e., shall not trip, and continue to exchange current, i.e., shall not enter momentary cessation” that
was provided in the Technical Rationale.
Attachment 1:
There is a discrepancy between the definition of the Term “Mandatory Operating Region” which states “≤ 1.2 per unit” and Table 1/Figure 1 or
Table 2/Figure 2 which state “≥1.200” per unit “N/A”. Please clarify if Table 1/Figure 1 and Table 2/Figure 2 should state “>1200” or if the
definition of the Term “Mandatory Operating Region” should state “<1.2 per unit”.
Please clarify Figure 1 and Figure 2 to clearly show the “Continuous Operating Region”, “Mandatory Operating Region”, and “Permissive Operating
Region”, along with requirements beyond 10 seconds.
Please Clarify “9. The IBR may trip for more than four deviations of the applicable voltage….” In attachment 1.
R2.5:
This requirement is beyond the purpose of the standard, which is to establish Frequency and Voltage Ride-through Requirements for Inverter Based Generating Resources and should be removed.
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R1: The team finds the current language of R1 does not need additional language and the TR provides the clarity.
Attachment 1: The tables and figures in Attachment 1 have been updated for consistency. The continuous operating region applies for beyond 10
seconds. Note 9 in Attachment 1 is an exception of the overall requirement.
Requirement R2.5: The team has removed R2.5.
Dave Krueger - SERC Reliability Corporation - 10
Answer
No
Document Name
Comment
On behalf of the SERC Generator Working Group:
R2.4 does not take into consideration other dynamic system conditions as a result of the fault and the effects they can have on the PPC during a
fault recovery. An example of this is Primary Frequency Response due to system frequency excursions during fault recovery. The active power
recovery may be reduced or frozen during an over-frequency event while an IBR Resource is in recovery, thereby extending the time of the full
recovery.
R2.5: It is not practical for the GO to determine where every individual piece of equipment would be damaged, nor should the GO be required to
subject equipment to failure by trying to identify that point, run to it, and risk damaging it.
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Requirement 2.5 (previously R2.4): now includes a footnote to add an exception for IBR response during a frequency excursion. Language was also
changed to voltage/frequency excursions throughout to add clarity on this point.
Previous Requirement 2.5: has been removed.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
No
Document Name
Comment
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OPG supports IESO’s comments.
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Glen Farmer - Avista - Avista Corporation - 5
Answer
No
Document Name
Comment
EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
EEI also does not support Requirement R2, subpart 2.5 because it contains unneeded language, which adds confusion and implies that GOs can only
trip outside of the trip zone if their equipment might become damaged. This has never been an obligation for synchronous generators, and we do
not agree that this should be an obligation for IBRs. If NERC or the SDT believe that the no-trip zone needs to be expanded, they should justify such
a change and present it for industry review and comment, otherwise, Requirement R2, subpart 2.5 should be deleted.
And while we support Requirement R6 and the provisions to notify PCs, TPs and RC about equipment limitations that would prevent an applicable
IBR from meeting ride‐through requirements as detailed in Requirements R1 and R2, the Requirement does not go far enough because there may
be technical reasons why an applicable IBR is unable to meet Requirement R3 through R5, as well. To address this concern, R6 should be expanded
to include Requirement R1 through R5.
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Terminology: The team has removed the word “applicable” and include a reference to the applicability section of the Standard.
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Exemptions: Any IBR that cannot meet voltage ride-through requirements, and may need to trip within the no-trip zone to protect equipment,
would be covered under the documented equipment limitations as covered within Requirement R4 (Previous R6).
R2.5: The team agrees with removing requirements on operation outside the no-trip zone and has removed R2.5.
Exemptions: The scope of allowable exemptions within Requirement R4 (Previous R6) is consistent with the regulatory directives of Order No. 901.
Previous Requirements R3 and R5 have been removed.
David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
No
Document Name
Comment
Vistra agrees with Invenergy
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Response
Thank you for your comment. See response to Invenergy.
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
No
Document Name
Comment
Minnesota Power (MP) agrees with the MRO NSRF’s comments on R1, R2, and R6, and the associated graphics from Attachment 1.
Additionally, MP notes that language from the Technical Rationale document specifies that R2.1, R2.3, and R2.4 are intended to apply when system
conditions return to the Continuous Operation Region from the Mandatory or Permissive Operation regions. This should be specified in the
standard.
Finally, MP proposes the following language changes to eliminate any possible uncertainty:
Section 2.1: “current or apparent power limit” to “current limit or apparent power limit”
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Section 2.4: “pre-disturbance or available level” to “pre-disturbance level or available level, whichever is lesser”
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Thank you for your comment:
Attachment 1: The tables and figures in Attachment 1 have been updated for consistency. The continuous operating region applies for beyond 10
seconds. Note 9 in Attachment 1 is an exception of the overall requirement.
R2 - clarity on language: Language has been added to 2.4 (previously 2.3) to specify response as voltage recovers to the continuous operating
region.
R2 – use of reactive power: Language was clarified in 2.1.1 and new 2.1.2 to address apparent vs reactive power limits per above and other
comments.
R2.5 (previous R2.4): R2.4 was revised to include the language as suggested.
Alison MacKellar - Constellation - 5
Answer
No
Document Name
Comment
Constellation does not agree and feels the HVRT times are very high. Many wind turbines/inverters won't be able to meet those times, equipment in
general and these systems have not been designed to withstand that much overvoltage.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Response
Thank you for your comment.
The transient overvoltage requirement (previous R3) has been removed.
Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
No
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Document Name
Comment
For R6, R3,R4,R5 should be included as well for the documented limitation communication (see R6 comments below)
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Response
Thank you for your comment.
The scope of allowable exemptions within R6 is consistent with the regulatory directives of Order No. 901. Previous requirement R3 and R5 have
also been removed.
Daniel Gacek - Exelon - 1
Answer
No
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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Thank you for your comment.
Imane Mrini - Austin Energy - 6, Group Name Austin Energy
Answer
No
Document Name
Comment
AE supports comments provided by Texas RE and the NAGF
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Thank for your comment.
See response to Texas RE and NAGF.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
EEI also does not support Requirement R2, subpart 2.5 because it contains unneeded language, which adds confusion and implies that GOs can only
trip outside of the trip zone if their equipment might become damaged. This has never been an obligation for synchronous generators, and we do
not agree that this should be an obligation for IBRs. If NERC or the SDT believe that the no-trip zone needs to be expanded, they should justify such
a change and present it for industry review and comment, otherwise, Requirement R2, subpart 2.5 should be deleted.
And while we support Requirement R6 and the provisions to notify PCs, TPs and RC about equipment limitations that would prevent an applicable
IBR from meeting ride‐through requirements as detailed in Requirements R1 and R2, the Requirement does not go far enough because there may
be technical reasons why an applicable IBR is unable to meet Requirement R3 through R5, as well. To address this concern, R6 should be expanded
to include Requirement R1 through R5.
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Thank you for your comments.
Terminology: The team has removed the word “applicable” and include a reference to the applicability section of the Standard. Any IBR that cannot
meet voltage ride-through requirements, and may need to trip within the no-trip zone to protect equipment, would be covered under the
documented equipment limitations as covered within Requirement R4 (previous R6).
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Equipment protection: Any IBR that cannot meet voltage ride-through requirements, and may need to trip within the no-trip zone to protect
equipment, would be covered under the documented equipment limitations as covered within Requirement R4.
Previous R2.5: The team agrees with removing requirements on operation outside the no-trip zone and has removed R2.5.
Excemptions: The scope of allowable exemptions within Requirement R4 Previous R6 is consistent with the regulatory directives of Order No. 901.
Requirement R3 (Previous R4) cannot apply. Previous Requirement R3 and R5 has also been removed.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1.
Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
No
Document Name
Comment
R1/R2: Recommend that Attachment 1 have a chart to include the Continuous Operation Region, Mandatory Operation Region, and Permissive
Operation Region or have those regions specified on existing Voltage Ride -through Requirements Figure 1 and Figure 2.
Requests the SDT review and align the data in Attachment 1 so the data in Tables 1 and 2 aligns with what is shown in Figures 1 and 2. Currently,
the graphs in Figures 1 and 2 do not match what is indicated in the Tables.
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Thank you for your comment.
The tables and figures in Attachment 1 have been updated for consistency.
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
No
Document Name
Comment
Duke Energy recommends the implementation of EEI and NAGF comments.
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Duke Energy does not agree that the language is clear. The language seems close to but not completely in alignment with IEEE 2800-2022. It is not
clear that the -029 requirements align with the IEEE 2800 requirements, especially given that most would want to comply with both. Many times the
Continuous Operation Region is associated with the voltage regulation function and the Mandatory Operation Region is associated with LVRT. This
separation is not maintained in various statements within 2.1 and 2.2. It is not clear how the plant or inverters can be configured to operate as
specified in R2. Overall the language seems overly prescriptive and the DT may consider less specificity and possibly even a reference to IEEE 2800
rather than trying to restate it. Voltage regulation functions are typically based on POI voltage while LVRT functions are based on inverter terminal
voltage. It is not clear that the requirements recognize this difference.
Also, there are multiple references in R1 and R2 to Attachment 1 containing or representing the various Regions, but they are not graphically
represented. The DT may consider revising the Att. 1 Figures (and moving the vertical axis crossing to 0.1 sec).
tt seems the industry has often misinterpreted the area outside of the No-trip Zone as an area where the plant must trip. The DT may consider
specifically addressing and emphasizing in the text and on the Figure that the plant is not required to trip in this area. For example, it may be labeled
May Trip Zone. To that end, it would also be helpful for the GO to submit equipment ride through limits. That is the actual equipment limits, not the
various voltage protection settings. With that information, plants would have the bases to provide the maximum ride-through beyond the No-Trip
Zone and still not exceed plant main and BOP equipment limits.
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Thank you for your comments.
Outside references: Requirements within the NERC PRC-029 address the scope of the SAR and draw from IEEE2800 but are mandatory and
enforceable requirements; in contrast to IEEE2800. NERC Standards cannot refer to outside sources for the purposes of requirement language, per
the Rules of Procedure.
R2: Language was clarified in 2.1.1 and new 2.1.2 to address apparent vs reactive power limits per above and other comments.
Attachment 1: Figures and tables in attachment 1 have been updated to include the operation regions. The figures have been updated to cross at 0
seconds. The area outside of the no-trip zone is now labeled “may trip or may ride-through zone”.
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Comment
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WEC Energy Group does not agree that the language in R1, R2, and R6 is clear for the following reasons:
R1.:
WEC disagrees with text “… shall ensure that each IBR remains connected…”. How else can an entity “ensure” to remain connected other than to
set voltage protection outside the no-trip zone? The requirement must state what must be done. Based on Attachment 1, this is clearly voltage
protection settings function so R1 should try and match PRC-024 R1. Otherwise, this requirement is open-ended as IBR could potentially be
disconnected due to other reasons and the entity will be deemed non-compliant.
The “main power transformer” should be defined in a footnote, similar to what’s proposed in PRC-028. It’s unclear if main power transformer
represents individual IBR step-up transformer or the site step-up transformer.
The phrase “exchange current” should be listed and defined in Terms section. Confusion exists in understanding if “exchange current” applies to
BESS while charging, real/reactive current components, or something else. An exception should be added to exclude BESS from the PRC-029
requirements while charging.
WEC also disagrees with M1. The only means for an entity to “ensure IBR remains connected” is to set voltage protection and voltage ride-through
protection according to Attachment 1. Making sure that the settings are applied should be the measure. The “recorded data” is an inconclusive
statement. If the entity applied settings outside the no-trip zone and it still tripped, which could be for various other reasons, does that mean then
entity is non-compliant? What needs to be recorded and where? Does this measure now mandate additional recording capabilities in addition to
PRC-030? (Same comment applies to M2, M3, and M4).
R2.:
WEC disagrees with text “…. shall ensure that each IBR remains connected…”. The requirement must state what TO and GO must do. Otherwise,
this requirement is open-ended without a measurable statement.
2.1: Term “Continuous Operating Region” as defined conflicts with equipment design limitations. Power transformers may not be designed for
continuous operations from 0.9 and 1.1 pu. Please refer to IEEE C57.12.00, sections 4.1.6.1, 4.1.6.2 and 5.5, and ANSI C84.1. Without some specific
maximum time applied, the continuous operating region will conflict with equipment limitations. Due to this wide range, entities will simply take
exception to R2 and R2 will not have any positive benefit for BES reliability. There is a reason PRC-024-3 has a 4 second limit. This limitation should
clearly be introduced in PRC-029. Finally, the proposed “Continuous Operating Region” range conflicts with acceptable continuous operating ranges
by Transmission Operators. Many Transmission Operators classify continuous operating range from 0.95 and 1.05 pu, and consider voltage ranges
from 0.9 to 0.95 pu and 1.05 to 1.1 pu as abnormal voltage ranges.
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2.1.2: There is nothing that governs a TP, PC, RC or TO to specify active/reactive power prioritization.
2.3: This requirement is inconclusive. The requirement must state what TO and GO must do. Otherwise, this requirement is open-ended without a
measurable statement. Something regarding “IBR gain” was briefly mentioned during the PRC-029 webinar. A wide spectrum of gains and tuning
parameters exist within the IBR controls. The requirement must state what parameters are to be addressed and how to set them. Gains and tuning
parameters are covered in MOD-026 and MOD-027 standards and shall not be introduced here. Another potential issue could be with AVR function
within the power plant controller. AVR/PPC failure could potentially cause higher voltage outputs. AVR failure, or any equipment failure, should
not be the criteria to violate the standard. WEC recommends this requirement be removed.
2.4: WEC owns and operates multiple IBR sites and it is in our experience that the limitation to the 1 second requirement will come from the power
plant controller. The ramp rate capabilities of the power plant controllers are far slower than inverter ramp rates and are typically in minutes range.
WEC also had an instance where the power plant controller ramp rate increase was denied by the Transmission Operator/Planner.
2.5: This requirement contradicts the meaning of established No-Trip zone. If the No-Trip zone is inadequate, then SDT should evaluate and adjust
it accordingly. In addition, having protection settings applied right at the equipment damage curve is not a standard protection practice, especially
if events such as voltage excursions have a cumulative effect on insulation degradation that could lead to premature failures. WEC recommends
this requirement be removed.
R6.: This requirement should include and cover equipment limitations associated with R3, R4, and R5.
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Thank you for your comments.
Performance and capability: Assigned regulatory directives from Order 901 to this team necessitate the inclusion of performance-based
requirements that an entity would be required to demonstrate using actual measured data. Additional language has been added to require entities
to demonstrate their capability to meet the requirements; including the protection and controller settings. Additional clarity on what recorded data
has been included in the measures to align with new disturbance monitoring data requirements in PRC-028. There are many causes of ride-through
failure beyond just over- and undervoltage protection settings that are encompassed within PRC-029.
MPT: The team has added a footnote as suggested.
Terminology: BESS are applicable to ride-through if they are electrically connected at the time of a fault. The phrase “continue to exchange current”
is consistent if a BESS is charging prior to a fault and providing voltage support after the fault. However, the team agrees that a definition for Ridethrough is preferable and has replaced usage of “continue to exchange current”.
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R2: R2 wording is consistent with expectations for performance-based requirements and how a GO or TO plant/facilities must performance during a
voltage excursion.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of Tables
1 and 2 to clarify the continuous operation region. Language has been added to R2 to clarify that if such specification has provided to the GO/TO
that the GO/TO shall follow those specifications.
Measurement: PRC-029 is not an equipment setting standard. Both the SAR and the assigned Order 901 direct the team to include capability and
performance-based requirements for ride-through. The criteria does not cover any equipment failure during a disturbance.
R2.5 (previously 2.4): R2.5 requires that a GO/TO follow any RC/PC/TOP/TP specified operation in response to a voltage excursion, including a
specified ramping time. For legacy equipment, R6 covers any known regulatory or hardware-based limation.
Previous Requirement R2.5 has been removed.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901. Frequency
or phase-jump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the ordered directives.
Previous R3: Previous requirement R3 has been removed.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1.
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF provides the following comments:
a.
Requirement R1 - the NAGF request clarification on the term “exchange” being used in the proposed language for Requirement R1.
b. Requirement R2 – the Terms section identified the terms: Continuous Operating Region, Mandatory Operating Region, and Permissive Operating
Region but these terms are not specifically referenced in the tables for Attachment 1. The NAGF believes that the regions should be included in
Attachment 1 for clarity.
c. The PRC-029-1 draft remains silent on the network condition, so it is unclear how to model the transmission system to test compliance with
these requirements. One option is to assume that the transmission grid at the point of interconnection may be modeled as an ideal voltage source.
Another option is to model the transmission grid as a voltage with a Thevenin impedance based on a short circuit ratio (minimum and maximum),
which would consider the network condition at the point of interconnection. The NAGF requests clarity on this topic regarding testing compliance.
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d. The requirement stated in R2.4 for IBRs to restore active power to the pre-disturbance or available level within 1.0 second when voltage at highside of the main power transformer returns to Continuous Operation Region. Based on the TO studies or requirements, it is recommended that
flexibility be allowed in the recovery time requirement. For example, if studies indicate that a slower ramp-rate and/or pause in the power ramp-up is
beneficial then that should be allowed. The NAGF also recommends an active power recovery threshold of 90% of pre-disturbance level to account
for measurement and IBR unit control uncertainties and tolerances.
e. The requirement stated in R2.1.1 must allow IBRs apparent power to be limited if the voltage is outside the normal operating range and the IBR
units have reached their maximum current limit.
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Thank you for your comments.
Terminology: The phrase “continue to exchange current” is consistent if a BESS is charging prior to a fault and providing voltage support after the
fault. However, the team agrees that a definition for Ride-through is preferable and has replaced usage of “continue to exchange current”.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of Tables
1 and 2 to clarify the continuous operation region.
Testing Conditions: The drafting team declines to address testing system conditions used to evaluate capability.
R2.5 (previous R2.4): R2.5 requires that a GO/TO follow any RC/PC/TOP/TP specified operation in response to a voltage excursion, including a
specified ramping time. For legacy equipment, R6 covers any known regulatory or hardware-based limation.
R2 – use of reactive power: The team agrees that changes to clarify reaction power support in 2.1 was needed and made some adjustments to
specify reactive power. This was broken into 2.1.1 and 2.1.2.
R2- -dynamic switching: Requirement 2.1.3 (previously 2.1.2) does not require dynamic switching between these two modes of operation.
However, if that capability already exists, the operating mode would need to be specified by the TP, PC, RC, or TOP.
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
No
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of its members:
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EEI agrees with most of the proposed language in Requirements R1, R2 and R6; however, the phrase “of an applicable IBR” should be
removed. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
EEI also does not support Requirement R2, subpart 2.5 because it contains unneeded language, which adds confusion and implies that GOs can only
trip outside of the trip zone if their equipment might become damaged. This has never been an obligation for synchronous generators, and we do
not agree that this should be an obligation for IBRs. If NERC or the SDT believe that the no-trip zone needs to be expanded, they should justify such
a change and present it for industry review and comment, otherwise, Requirement R2, subpart 2.5 should be deleted.
And while we support Requirement R6 and the provisions to notify PCs, TPs and RC about equipment limitations that would prevent an applicable
IBR from meeting ride‐through requirements as detailed in Requirements R1 and R2, the Requirement does not go far enough because there may
be technical reasons why an applicable IBR is unable to meet Requirement R3 through R5, as well. To address this concern, R6 should be expanded
to include Requirement R1 through R5.
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Thank you for your comments.
Terminology: The team has removed the word “applicable” and include a reference to the applicability section of the Standard. Any IBR that cannot
meet voltage ride-through requirements, and may need to trip within the no-trip zone to protect equipment, would be covered under the
documented equipment limitations as covered within Requirement R4 (previous R6).
Previous R2.5: The team agrees with removing requirements on operation outside the no-trip zone and has removed R2.5.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901. Frequency
or phase-jump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the ordered directives.
Joy Brake - Nova Scotia Power Inc. - NA - Not Applicable - NPCC
Answer
No
Document Name
Comment
Concerns are covered other commenters.
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Thank you for your comment.
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3 - WECC
Answer
No
Document Name
Comment
PNM agrees with the comments of EEI.
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Thank you for your comment. See response to EEI.
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
No
Document Name
Comment
R2.1/2.2
This states that the TO is who decides whether Active or Reactive Power is prioritized when a limit is reached. IBR sites will curtail real power to
meet the reactive power request from the controllers.
R2.4
This section would depend on the ramp rate of the units, 1.0 seconds seems extreme
M2
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Will the PC's be communicating in writing to the Generator Owner every time there is a disturbance with the request for this data. How long will the
data need to be held?
R4
5 hz/second is not a reasonable rate
M4
Will the PC's be communicating in writing to the Generator Owner every time there is a disturbance with the request for this data. The retention
period for data is not defined.
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Thank you for your comments.
R2 – use of reactive power: The team agrees that changes to clarify reaction power support in 2.1 was needed and made some adjustments to
specify reactive power. This was broken into 2.1.1 and 2.1.2.
R2- -dynamic switching: Requirement 2.1.3 (previously 2.1.2) does not require dynamic switching between these two modes of operation.
However, if that capability already exists, the operating mode would need to be specified by the TP, PC, RC, or TOP.
Requirement 2.5 (previously 2.4) requires the GO/TO to follow provided TP/PC/RC/TOP restoration time or active power recovery threshold
requirements – if different than default values in the sub-requirement.
M2 and M4: Coordination between PRC-029 and PRC-030 drafting teams have implemented changes to those drafts that triggers within PRC-030 to
initiate an analysis will be evaluated against PRC-029 ride through criteria. PRC-029 establishes the criteria and PRC-030 includes requirements for
conducting the analysis of performance after a disturbance. Data retention for R2 will be aligned with data retention requirements within PRC-030.
R4: Please refer to other comment responses in Question 3 below.
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
No
Document Name
Comment
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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and North American Generator Forum (NAGF) on
question 2
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Thank you for your comments. See response to EEI and NAGF.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
No
Document Name
Comment
Dominion Energy supports EEI comments. In addition, Dominion Enetgy has the following comments:
R2, Section 2.1 refers to the Continuous Operation Region as specified in Attachment 1; however the definition of Continuous Operating Region at
the beginning of the standard is only applicable to voltages, measured at the high-side of the MPT that are between 0.9 PU and 1.1 PU. Does this
mean that the definition of Continuous Operation Region is different from Continuous Operating Region? Or is the intent the same as the definition
at the front of the standard and the “tion” should be changed to “ting”? Please clarify. This disconnect also exists in R2 and in R2.2.
R2, Section 2.1.2 and R2.4 both allude to a requirement for either the Transmission Planner, Planning Coordinator, Reliability Coordinator or
Transmission Operator to provide a preference of active or reactive power if an IBR cannot deliver both due to a current or apparent power limit.
The standard is not applicable to any of these listed entities and thus puts an administrative burden on the Generator Owner to contact each to
determine a preference. Four entities determining the preference is three too many. A new requirement should be written directing one of the four
entities to be the lead point of contact for the GO. Additionally, the standard should specify that the lead entity charged with determining the
preference of active of reactive power should communicate the preference a minimum of 6 months prior to the effective date for the GO. The GO
cannot put controls in place and ensure compliance until the TP, PC, RC or TOP has documented the compliance requirement.
R6, Section 6.2 is confusing since the Technical Rationale and FERC Order 901 Directives, Paragraph 193 states that “when the existing equipment is
replaced, the exemption would no longer apply, and the new equipment must comply with the appropriate IBR performance requirements”.
Further, FAC-002-5 considers replacement of inverters / converters or Power Plant Controllers to be “qualified changes” and would require a study
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before implementation. This section seems to be an unnecessary administrative step, since the FAC-002 process would require submittal of “as-built
settings” for the qualified change study.
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Thank you for your comment.
Attachment 1: The definitions for the operation regions have been removed. Additionally, the tables and figures in Attachment 1 have been
updated for consistency. Also the continuous operation region have been labeled within the tables and figures.
Requirement R2: R2 subparts require the GO/TO to follow provided TP/PC/RC/TOP restoration time or active power recovery threshold
requirements – if different than default values in the sub-requirement. R2 does not intend that values other than the default values must be
specified, only that performance for the plant/facility will be evaluated in accordance with those values if provided. Language has been added to M2
to clarify what evidence is expected if the TP/PC/RC/TOP provide other performance requirements.
Limitations: Language has been added in R4 (previously R6) has been clarified that such a replacement would remove the limitation; consistent with
the FERC Order 901. This is retained in PRC-029 to be consistent with new performance based requirements established in PRC-029 and the Order.
George E Brown - Pattern Operators LP - 5
Answer
No
Document Name
Comment
Pattern Energy supports GRE’s comments for this question.
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Kimberly Turco - Constellation - 6
Answer
No
Document Name
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Comment
Constellation does not agree and feels the HVRT times are very high. Many wind turbines/inverters won't be able to meet those times, equipment in
general and these systems have not been designed to withstand that much overvoltage.
Kimberly Turco on behalf of Constellation Segments 5 and 6
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Thank you for your comment.
The transient overvoltage requirement, R3, has been removed. Any qualifying R1 or R2 limitation is covered within R4 (previously R6).
Ruchi Shah - AES - AES Corporation - 5
Answer
No
Document Name
Comment
1 The language “continues to exchange current” in R1 is not clear, please explain.
OEMs have not been forthcoming with operating limit data/equipment trip capabilities. Due to the lack of information from OEMs, we are
2
concerned that the following language in R2.5 will be difficult to comply with: “Each IBR shall only trip to prevent equipment damage, when the
voltage at the high‐side of the main power transformer is outside of the no‐trip zone as specified in Attachment 1”.
3 The SDT should consider equipment where the manufacturer is not able to provide the limits where equipment damage can occur. For legacy
equipment, this information may not be available or may be available at a very high cost to the GO. These scenarios should be included as
limitations.
4·
Charts in Attachment 1 should be updated to graphically show the performance regions
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Response
Thank you for your comments.
Terminology: The phrase “continue to exchange current” is consistent if a BESS is charging prior to a fault and providing voltage support after the
fault. However, the team agrees that a definition for Ride-through is preferable and has replaced usage of “continue to exchange current”.
R2.5: The team agrees with removing requirements on operation outside the no-trip zone and has removed R2.5.
R2.5: The team agrees with removing requirements on setting limits operation outside the no-trip zone and has removed R2.5.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of Tables
1 and 2 to clarify the continuous operation region.
Rhonda Jones - Invenergy LLC - 5
Answer
No
Document Name
Comment
No, Invenergy disagrees that the language within PRC-029-1 requirements R1, R2, and R6 is clear. Specifically, we offer the below comments
regarding these requirements:
R2.1.1.: As currently drafted, R2.1.1. seems to ignore the changes to apparent power limits that could occur during a System disturbance. We
recommended the following language:
“R2.1.1. Continue to deliver the pre-disturbance level of active power or available active power, whichever is less, and continue to deliver active
power and reactive power up to the total aggregated current rating of the IBR Units in the plant.”
R2.1.2.: Invenergy is concerned that the language in R2.1.2. regarding the active power or reactive power preferences of TPs, PCs, RCs, or TOPs may
lead to increased confusion and unintended consequences. In its place, we recommend adopting something similar to the p/q/v capability curve
demonstrated in Figure 8 of IEEE 2800-2022.
R2.3.: It is unclear to us what R2.3. is requiring. Please clarify or remove.
R2.4.: The ramp rate should be based on System needs; in weaker grid conditions such rapid ramping of active power could lead to poweroscillations or small-signal instability.
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R2.5.: This requirement is not auditable and is beyond the scope of the standard, which is to establish certain minimum ride-through requirements.
As written, R2.5. suggests GOs should push their equipment as near to its breaking point as possible, even after the minimum ride-through
requirements have been met. Thus, we ask R2.5. and similar statements throughout the draft standard be removed.
R6.: Given the technical limitations of many legacy IBRs, R6 must be thoroughly amended to allow exemptions for limitations related to frequency,
rate-of-change-of-frequency, and phase angle change ride-through requirements. Consider that there are a range of possible concerns with legacy
equipment and equipment already in commercial operation. At one end of the spectrum there exists legacy equipment where the manufacturer is
no longer in business, or no longer produces the given IBR unit technology. In these cases, it is often infeasible to either truly document all aspects
of the equipment limitations or to attempt to make any software or hardware modifications. At the other end of the spectrum there exists
equipment that has been installed in recent years where software modifications may be enough to bring the units into compliance with the
proposed requirements, after proper due-diligence and analyses have been performed. In between these two ends of the spectrum there is a range
of possibilities.
Where available, software-only modifications are the most likely to yield meaningful reliability improvements where they are most needed while
being technically and financially feasible for legacy IBRs to deploy. Indeed, the vast majority of performance issues identified with solar PV resources
involved in the 2021 and 2022 Odessa disturbances (and other solar PV resources with the same inverter make/model that were not involved in the
Odessa events) are being addressed in ERCOT with software-based modifications (see
https://www.ercot.com/files/docs/2024/03/06/Odessa%20Update_03082024.pptx).
Thus, R6 needs a thorough rewrite to give due consideration, and acknowledgement, to these various nuances. Invenergy proposes the below
modifications:
R6. Each Generator Owner and Transmission Owner with an applicable IBR that is in commercial operation prior to the effective date of this
standard that is unable to meet the ride-through performance requirements detailed in Requirements R1 through R5 shall document the limitation,
communicate each equipment limitation to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s), and
provide a plan for making reasonable software and settings modifications that reduce or remove the limitation, if available and feasible.
obtained:
6.1. Each Generator Owner and Transmission Owner shall include in its documentation, in each case as is available or can be reasonably
6.1.1. Identifying information of the IBR (name, facility #, other)
6.1.2. Current ride-through capability
6.1.3. Known ride-through limitations and documentation of such limitations
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6.1.4. Reasonable software and settings modifications
6.1.5. Expected post-modification ride-through capability and documentation of any expected remaining limitations following
implementation of such modifications
6.1.6. A schedule for implementing the modifications
6.2. Each Generator Owner and Transmission Owner with a previously communicated equipment limitation that makes a modification
that reduces or removes such limitation shall document and communicate such modification to the associated Planning Coordinator(s),
Transmission Planner(s), and Reliability Coordinator(s) within 30 days of the modification.
To supplement the language regarding reasonable software and settings modifications, the following language could be added to the Technical
Rationale: Reasonable software and settings modifications are any available technically feasible modifications involving only software, firmware,
settings, or parameterization changes that do not require physical modification of the IBR equipment and are reasonably priced.
Likes
0
Dislikes
0
Response
Thank you for your comments.
R2.1.1: Language was clarified in 2.1.2 (previously 2.1.1) to address apparent vs reactive power limits per above and other comments.
R2.1.2: R2.1.3 (previously R2.1.2) has been clarified that the GO/TO shall follow provided TP/PC/RC/TOP requirements if those are provided. The
team has clarified that the GO/TO shall follow provided TP/PC/RC/TOP requirements only if those are provided.
R2.3: Language has been added to 2.4 (previously 2.3) to specify response as voltage recovers to the continuous operation region.
R2.4: R2.5 (previously R2.4) does not intend that values other than the default values must be specified, only that performance for the plant/facility
will be evaluated in accordance with those values if provided. Language has been added to M2 to clarify what evidence is expected if the
TP/PC/RC/TOP provide other performance requirements.
R2.5: What was previously R2.5 has been removed.
R4 (previously R6): The scope of allowable exemptions within R4 is consistent with the regulatory directives of Order No. 901. Frequency or phasejump requirements cannot apply for exemption. Software-limitation also cannot apply for exemption. This is consistent with the ordered directives.
David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
No
Document Name
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Comment
Ameren agrees with EEI's comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. See response to EEI.
Colin Chilcoat - Invenergy LLC - 6
Answer
No
Document Name
Comment
No, Invenergy disagrees that the language within PRC-029-1 requirements R1, R2, and R6 is clear. Specifically, we offer the below comments
regarding these requirements:
R2.1.1.: As currently drafted, R2.1.1. seems to ignore the changes to apparent power limits that could occur during a System disturbance. We
recommended the following language:
“R2.1.1. Continue to deliver the pre-disturbance level of active power or available active power, whichever is less, and continue to deliver active
power and reactive power up to the total aggregated current rating of the IBR Units in the plant.”
R2.1.2.: Invenergy is concerned that the language in R2.1.2. regarding the active power or reactive power preferences of TPs, PCs, RCs, or TOPs may
lead to increased confusion and unintended consequences. In its place, we recommend adopting something similar to the p/q/v capability curve
demonstrated in Figure 8 of IEEE 2800-2022.
R2.3.: It is unclear to us what R2.3. is requiring. Please clarify or remove.
R2.4.: The ramp rate should be based on System needs; in weaker grid conditions such rapid ramping of active power could lead to poweroscillations or small-signal instability.
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R2.5.: This requirement is not auditable and is beyond the scope of the standard, which is to establish certain minimum ride-through requirements.
As written, R2.5. suggests GOs should push their equipment as near to its breaking point as possible, even after the minimum ride-through
requirements have been met. Thus, we ask R2.5. and similar statements throughout the draft standard be removed.
R6.: Given the technical limitations of many legacy IBRs, R6 must be thoroughly amended to allow exemptions for limitations related to frequency,
rate-of-change-of-frequency, and phase angle change ride-through requirements. Consider that there are a range of possible concerns with legacy
equipment and equipment already in commercial operation. At one end of the spectrum there exists legacy equipment where the manufacturer is
no longer in business, or no longer produces the given IBR unit technology. In these cases, it is often infeasible to either truly document all aspects
of the equipment limitations or to attempt to make any software or hardware modifications. At the other end of the spectrum there exists
equipment that has been installed in recent years where software modifications may be enough to bring the units into compliance with the
proposed requirements, after proper due-diligence and analyses have been performed. In between these two ends of the spectrum there is a range
of possibilities.
Where available, software-only modifications are the most likely to yield meaningful reliability improvements where they are most needed while
being technically and financially feasible for legacy IBRs to deploy. Indeed, the vast majority of performance issues identified with solar PV resources
involved in the 2021 and 2022 Odessa disturbances (and other solar PV resources with the same inverter make/model that were not involved in the
Odessa events) are being addressed in ERCOT with software-based modifications (see
https://www.ercot.com/files/docs/2024/03/06/Odessa%20Update_03082024.pptx).
Thus, R6 needs a thorough rewrite to give due consideration, and acknowledgement, to these various nuances. Invenergy proposes the below
modifications:
R6. Each Generator Owner and Transmission Owner with an applicable IBR that is in commercial operation prior to the effective date of this
standard that is unable to meet the ride-through performance requirements detailed in Requirements R1 through R5 shall document the limitation,
communicate each equipment limitation to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s), and
provide a plan for making reasonable software and settings modifications that reduce or remove the limitation, if available and feasible.
obtained:
6.1. Each Generator Owner and Transmission Owner shall include in its documentation, in each case as is available or can be reasonably
6.1.1. Identifying information of the IBR (name, facility #, other)
6.1.2. Current ride-through capability
6.1.3. Known ride-through limitations and documentation of such limitations
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6.1.4. Reasonable software and settings modifications
6.1.5. Expected post-modification ride-through capability and documentation of any expected remaining limitations following
implementation of such modifications
6.1.6. A schedule for implementing the modifications
6.2. Each Generator Owner and Transmission Owner with a previously communicated equipment limitation that makes a modification
that reduces or removes such limitation shall document and communicate such modification to the associated Planning Coordinator(s),
Transmission Planner(s), and Reliability Coordinator(s) within 30 days of the modification.
To supplement the language regarding reasonable software and settings modifications, the following language could be added to the Technical
Rationale: Reasonable software and settings modifications are any available technically feasible modifications involving only software, firmware,
settings, or parameterization changes that do not require physical modification of the IBR equipment and are reasonably priced.
Likes
0
Dislikes
0
Response
Thank you for your comments.
R2.1.1: Language was clarified in 2.1.2 (previously 2.1.1) to address apparent vs reactive power limits per above and other comments.
R2.1.2: R2.1.3 (previously R2.1.2) has been clarified that the GO/TO shall follow provided TP/PC/RC/TOP requirements if those are provided. The
team has clarified that the GO/TO shall follow provided TP/PC/RC/TOP requirements only if those are provided.
R2.3: Language has been added to 2.4 (previously 2.3) to specify response as voltage recovers to the continuous operation region.
R2.4: R2.5 (previously R2.4) does not intend that values other than the default values must be specified, only that performance for the plant/facility
will be evaluated in accordance with those values if provided. Language has been added to M2 to clarify what evidence is expected if the
TP/PC/RC/TOP provide other performance requirements.
R2.5: What was previously R2.5 has been removed.
R4 (previously R6): The scope of allowable exemptions within R5 is consistent with the regulatory directives of Order No. 901. Frequency or phasejump requirements cannot apply for exemption. Software-limitation also cannot apply for exemption. This is consistent with the ordered directives.
Brittany Millard - Lincoln Electric System - 5
Answer
No
Document Name
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Comment
A review of the data in Attachment 1 and Tables 1 and 2 should be performed so that they align. Currently, the graphs in Figures 1 and 2 do not
match what is indicated in the Tables.
We would recommend a part be added to the standard to directly address the Permissive Operating Region, similar to what is done in Part 2.1 (for
Continuous Operation Region) and Part 2.2 (for Mandatory Operation Region) as, if left unaddressed, is unclear. For example, there should be some
linkage between the body of the standard and Attachment 1, item 10. The following language is provided for consideration (new Part 2.3):
2.3 While voltage at the high‐side of the main power transformer is within the Permissive Operation Region as specified in Attachment 1, an IBR
may operate in current block mode only if necessary to protect the equipment. Otherwise, each IBR shall follow the requirements for the
Mandatory Operation Region in Requirement R2.2.
Likes
0
Dislikes
0
Response
Thank you for your comment.
The tables and figures in Attachment 1 have been updated for consistency.
The team agrees and has added a new requirement R2.3 for the permissive operation region.
Ben Hammer - Western Area Power Administration - 1
Answer
No
Document Name
Comment
Plese review and align the data in Attachement 1 so that data in Tables 1 & 2 align with Figures 1 & 2.
Also, it is recommended a part be added to the standard to directly address the Permissive Operating Region, similar to what is done in Part 2.1 (for
Continuous Operation Region) and Part 2.2 (for Mandatory Operation Region) as, if left unaddressed, is unclear. For example, there should be some
linkage between the body of the standard and Attachment 1, item 10. See the following proposed language for consideration (new Part 2.3):
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2.3 While voltage at the high‐side of the main power transformer is within the Permissive Operation Region as specified in Attachment 1, an IBR
may operate in current block mode only if necessary to protect the equipment. Otherwise, each IBR shall follow the requirements for the
Mandatory Operation Region in Requirement R2.2.
OPTION A.
Requirement R6 provides an overly broad exemption as written as the standard is silent as to what criteria must be met. Only notification to other
reliability entities is required with no requirement to develop and implement a Corrective Action Plan. The SDT should consider:
•
•
Develop more specific criteria as to what qualifies as an equipment limitation[1], OR
Require exemptions be submitted to NERC and/or the Regional Entities for approval in order to qualify for the exemption.
OPTION B.
Leave R6 as written, apply R6 to R1 through R5.
it is recommended that there be no requirement to document limitations on legacy equipment and that this standard focuses on equipment
brought into service after the implementation date.
R2: We agree with the present flexibility that some of the IBR VRT performance could be modified to meet the individual system needs by the
applicable Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator. However, some clarity may be required
on how this process is initiated and what type is evidence is required to demonstrate request is received and implemented. This may be an
additional requirement assigned to the Transmission Planner. Each Transmission Planner, Planning Coordinator, and Transmission Operator that
jointly specifies the following voltage ride-through performance requirements within their area(s) different than those specified under R2, shall
make those requirements available to each associated applicable IBR Generator Owner and Transmission Owner
[1] See Implementation Plan (page 4), i.e. “only those IBR that are unable to meet voltage ride-through requirements due to their inability to modify
their coordinated protection and control settings may be considered for potential exemption.” See Technical Rationale (page 9); i.e. specify which
voltage band(s) and associated duration(s) cannot be satisfied or specific as to the number of cumulative voltage deviations within a ten‐second time
period that the equipment can ride‐through if less than four… identify the specific equipment and explain the characteristic(s) of that equipment that
prevent ride‐through.
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0
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0
Response
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Thank you for your comment.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of Tables
1 and 2 to clarify the continuous operation region.
R2.3 (permissive region): The team agrees and has added a new requirement R2.3 for the permissive operation region.
R4 (previously R4): The scope of allowable exemptions within R4 is consistent with the regulatory directives of Order No. 901. Frequency or phasejump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the ordered directives.
Requirement R2 subparts require the GO/TO to follow provided TP/PC/RC/TOP restoration time or active power recovery threshold requirements –
if different than default values in the sub-requirement. R2 does not intend that values other than the default values must be specified, only that
performance for the plant/facility will be evaluated in accordance with those values if provided. Language has been added to M2 to clarify what
evidence is expected if the TP/PC/RC/TOP provide other performance requirements.
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
We believe that language needs to be added to M1, similar to that provided in the other Measures, to specify the initiating event that triggers the
requirement for R1 evidence of compliance.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Coordination between PRC-029 and PRC-030 drafting teams have implemented changes to those drafts that triggers within PRC-030 to initiate an
analysis will be evaluated against PRC-029 ride through criteria. PRC-029 established the criteria and PRC-030 includes requirements for conducting
the analysis of performance after a disturbance. The compliance measures were revised from “actual recorded data” to “actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data”.
Additions were made to the requirements to require demonstration of IBR capability and the measures were updated to include capability-based
evidence.
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
No
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Document Name
Comment
Black Hills Corporation supports EEI’s and NAGF’s comments. Additionally, Black Hills Corporation has concerns regarding event-based “Measures”
for Requirement R2, R3, R4 and R5 as GO will likely not have immediate knowledge of “System disturbance” or other transmission system events
(transient overvoltage due to switching, frequency excursion, instantaneous positive sequence voltage phase angle changes) when they occur and
data collection systems have a limited amount of storage capacity (i.e. data overwrite happens over time, in our case, data is retained for a rolling
12 months). If available data remains the “Measure” for demonstrating compliance, then consideration needs to be given to when and how GO are
notified of an event, so data can be reviewed and archived for future demonstration of compliance.
Likes
0
Dislikes
0
Response
Thank you for your comments. See response to EEI and NAGF.
Coordination between PRC-029 and PRC-030 drafting teams have implemented changes to those drafts that triggers within PRC-030 to initiate an
analysis will be evaluated against PRC-029 ride through criteria. PRC-029 established the criteria and PRC-030 includes requirements for conducting
the analysis of performance after a disturbance. The compliance measures were revised from “actual recorded data” to “actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data”.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
No
Document Name
Comment
FirstEnergy finds 2.4 requesting the return to of the Active Power is restrictive and needs to be inclusive of Reactive Power due to voltage response.
Likes
0
Dislikes
0
Response
Thank you for your comment.
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Requirement 2.5 (previously 2.4) now includes a footnote to add an exception for IBR response during a frequency excursion. Language was also
changed to voltage/frequency excursions throughout to add clarity on this point.
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
No
Document Name
Comment
AECI supports comments provided by the NAGF
Likes
0
Dislikes
0
Response
Thank you for your comment. See response to NAGF.
Brian Lindsey - Entergy - 1
Answer
No
Document Name
Comment
•
2.1.2 refers to requirements specified by the TP, TOP, PC, RC. It is unclear what the expectation is if those requirements have not been
defined.
•
Is 2.2.2 is stating that the IBR shall maintain reactive power per default setpoints unless a new reactive setpoint has been requested or it’s
been requested to maintain a certain active power? Why wouldn’t this be worded similarly to the sub-bullets in 2.1?
•
2.3: if the IBR is already responding to Mandatory or Permissive Operation regions (exceedances of Attachment 1 Table 1 or Table 2), how
could it then cause an exceedance?
•
R2.4 There is concern that the controls will be either unable to respond within the 1 second timeframe, or that the historical records to
prove the response would not have the resolution to be meaningful.
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•
Likes
R 2.5: How would someone prove that an IBR tripped only to prevent equipment damage? This sub-bullet cannot be enforced.
0
Dislikes
0
Response
Thank you for your comment.
R2.1.2 (previous R2.1.1) and R2.1.3 (previous 2.1.2): Language was clarified in R2.1.2 and R2.1.3 to address apparent vs reactive power limits per
above and other comments. R2.1.3 has been clarified that the GO/TO shall follow provided TP/PC/RC/TOP requirements if those are provided.
Requirement R2 subparts require the GO/TO to follow provided TP/PC/RC/TOP restoration time or active power recovery threshold requirements –
if different than default values in the sub-requirement. R2 does not intend that values other than the default values must be specified, only that
performance for the plant/facility will be evaluated in accordance with those values if provided. Language has been added to M2 to clarify what
evidence is expected if the TP/PC/RC/TOP provide other performance requirements.
R2.4 (previous R2.3) - recovery: Language has been added to R2.4 to specify response as voltage recovers to the continuous operating region.
1 second: Regarding the 1 second, R4 covers any known regulatory or hardware-based limitation for legacy equipment.
R2.5: The team agrees with removing requirements on operation outside the no-trip zone and has removed R2.5.
Helen Lainis - Independent Electricity System Operator - 2
Answer
No
Document Name
Proposed change to table Q2.PNG
Comment
The IESO recommends the following modifications to the text improve clarity or to better convey intent.
With regards to R1:
“…as specified in Attachment 1 unless not doing so is needed to clear a fault or a documented and communicated equipment limitation exists in
accordance with Requirement R6.”
With regards to M1:
“…demonstrating adherence to ride‐through requirements, as specified in Requirement R1, or shall have evidence of a documented and
communicated equipment limitation, as specified in Requirement R6.”
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With regards to R2:
“…each IBR’s voltage performance adheres to the following, unless a documented and communicated equipment limitation exists…”
With regards to 2.1: (and Tables 1 & 2, Figures 1 & 2):
There appears to be inconsistency between the definition of ‘Continuous Operation Region’, the Minimum Ride-Through Time values stated in
Tables 1 & 2, and the plots in Figures 1 & 2.
It seems the intent is to have ‘continuous’ operation between 95% and 105% voltage, and a minimum ride-through time of at least 1800 seconds
(half an hour) when voltage is above 105% and not exceeding 110%. If it is really required that equipment must be able to operate continuously at
voltages up to 110%, then the tables and plots should be labelled with a descriptor that implies indefinite operation is required (i.e., continuous)
rather than a minimum time (1800 seconds). For example, a version of Table 2 that achieves what seems to be intent could look like the following:
See file attached - Proposed change to table Q2
With regards to 2.5:
The IESO believes the principle of tripping only when necessary (i.e., to clear faults and to prevent equipment damage during disturbances) is
important enough that it warrants a dedicated requirement. With regards to tripping during over-voltages, this principle of only tripping for
equipment protection purposes may apply equally to system disturbances discussed in R2 and to switching transients as discussed in R3 (tripping for
equipment protection is not presently addressed in R3, though is acknowledged in the Technical Rationale document).
With regards to R6:
The IESO suggests there should be explicit requirements to both ‘document equipment limitations’ and to ‘communicate’ those documented
limitations to the appropriate parties. The following modifications are proposed:
“Each Generator Owner and Transmission Owner with a known equipment limitation that would prevent an applicable IBR that is in‐service by the
effective date of this standard from meeting voltage ride‐through requirements as detailed in Requirements R1 and R2 shall document each
equipment limitation and communicate it to the associated Planning Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s).
With regards to M6:
Each Generator Owner and Transmission Owner shall have evidence of known equipment
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limitations, as specified in Requirement R6, having been documented and communicated to each associated Planning Coordinator, Transmission
Planner, and Reliability Coordinator prior to the effective date of PRC‐029‐1.
Each Generator Owner and Transmission Owner with changes to equipment shall have evidence of communication to each associated Planning
Coordinator, Transmission Planner, and Reliability Coordinator.
Likes
1
Dislikes
Ontario Power Generation Inc., 5, Chitescu Constantin
0
Response
Thank you for your comment.
R1: Modifications have been made to R1 and M1 for clarity – please see the new draft for those changes.
Attachment 1: The tables and figures in Attachment 1 have been updated for consistency. The operation regions have been included on the figures.
R2: Previous requirement R2.5 has been removed.
R5: Previously R6 has been updated to include “known”, “regulatory”, and “communicated”.
Jennie Wike - Jennie Wike On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma
Power
Answer
No
Document Name
Comment
Tacoma Power does not agree that the language in the applicability section of PRC-029-1 is clear. The applicable facilities language in Section 4 is
vague and difficult for entities to understand what is in scope of the Standard. Specifically, the term "BPS IBR" is broad and would encompass all
transmission connected IBRs, regardless of size or interconnection voltage. Additionally, the language and formatting of the applicability sections in
PRC-028, PRC-029 and PRC-030 are not consistent. These three Standards apply to the same facilities, and therefore, should use the same language.
Tacoma Power recommends that Section 4 of PRC-029 and PRC-030 should be revised to align with the language proposed in Section 4 of PRC-028,
as follows:
4.1. Functional Entities:
4.1.1. Transmission Owner that owns equipment as identified in section 4.2
4.1.2. Generator Owner that owns equipment as identified in section 4.2
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4.2. Facilities: The Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or
contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering
such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
Likes
1
Dislikes
JEA, 1, McClung Joseph
0
Response
Thank you for your comments.
The drafts for PRC-028, PRC-029, and PRC-030 have been updated for consistency. The Facilities sections between these drafts will stay aligned
moving forward.
Leah Gully - Madison Fields Solar Project, LLC - 5 - RF
Answer
No
Document Name
Comment
See "additional comments" for details
Likes
0
Dislikes
0
Response
Thank you for your comments.
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
2020-02_EPRI Comments on Draft NERC PRC-029 (IBR ride-through) Reliability
Standard.pdf
Comment
Likes
0
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Dislikes
0
Response
Thank you for your comments. The team believes these comments have been sufficiently addressed in other comment responses.
Michael Goggin - Grid Strategies LLC - 5
Answer
No
Document Name
Comment
Likes
0
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0
Response
Thank you.
David Campbell - David Campbell On Behalf of: Natalie Johnson, Enel Green Power, 5; - David Campbell
Answer
No
Document Name
Comment
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Thank you.
Carey Salisbury - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer
No
Document Name
Comment
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Response
Thank you.
Ryan Quint - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable, Group Name Elevate Energy Consulting
Answer
Yes
Document Name
Comment
Yes. The SDT should consider citing IEEE 2800-2022 directly in the standard and consider using the IEEE 2800-2022 ride-through requirements as a
means to comply with Requirements R1-R5 instead of using Attachment 1 of the standard.
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Response
Thank you for your comment.
NERC Standards cannot refer to outside sources for the purposes of requirement language, per the Rules of Procedure. From the NERC Rules of
Procedure: “Reliability Standards shall be complete and self-contained. The Reliability Standards shall not depend on external information to
determine the required level of performance."
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Yes
Document Name
Comment
Remove from R1 "and operation regions" since this is already required in R2.
Move R2.5 to a sub-requirement of R1, since R1 is the no-trip requirement not R2.
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R2.5 should read be rearranged to be more clear, "When the voltage at the high-side of the main power transformer is outside of the no-trip zone
as specified in Attachment 1, each IBR shall only trip to prevent equipment damage."
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Response
Thank you for your comment.
Terminology: The team agrees and has defined a new term for Ride-through and replaced language in the requirements with this new term.
Attachments have also been updated to utilize this term as the “Must Ride-through Zone”.
R2.5: The team agrees with removing requirements on operation outside the Must Ride-through Zone and has removed R2.5.
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer
Yes
Document Name
Comment
SRP believes the language in R1 and R2 provides clear expectations of how IBR controls should behave during short circuit events.
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Thank you for your comment.
Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer
Yes
Document Name
Comment
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While the language is clear, the SDT explains in the draft PRC-029-1 Technical Rationale that “An IBR becomes noncompliant with PRC‐029 only
when an event in the field occurs that shows that one or more requirements were not satisfied.” See Question 4 comment for RF’s concerns with
this approach.
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Thank you for your comment.
Measures (data): The team agrees and the measures for R1 through R3 have been adjusted to include design/capability based requirements as well
as the demonstration of performance during disturbances.
Stefanie Burke - Portland General Electric Co. - 6
Answer
Yes
Document Name
Comment
PGE supports EEI’s comments
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0
Response
Thank you for your comments. See response to EEI.
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
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109
Since the evidence needed is the actual recorded data, we only need it when there’s an actual event that happened in the system. What if after the
event, we found out that we are not compliant? What can we do to ensure compliance? Please add more clarification about the evidence
requirements.
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Response
Thank you for your comment.
Capability and Performance Measures: The team agrees and the measures for R1 through R3 have been adjusted to include design/capability based
requirements as well as the demonstration of performance during disturbances.
Measures - data: The compliance measures for demonstration of performance were revised from “actual recorded data” to “actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data”.
Wesley Yeomans - New York State Reliability Council - 10
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Katrina Lyons - Georgia System Operations Corporation - 4
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal Utility
District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3, 6, 4, 1, 5;
Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim Kelley, Group
Name SMUD and BANC
Answer
Yes
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Document Name
Comment
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Response
Thank you.
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Thomas Foltz - AEP - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
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Wendy Kalidass - U.S. Bureau of Reclamation - 5
Answer
Document Name
Comment
Not Applicable to Reclamation.
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Thank you.
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer
Document Name
Comment
BC Hydro appreciates the drafting team’s efforts and the opportunity to comment, and offers the following:
1. Requirement R2 Part 2.1.2 appears to set an additional Requirement for TP, PC, RC, or TOP to specify requirements for scenarios where an IBR
cannot deliver both active and reactive power when the voltage is within the Continuous Operating Region and below 95%. BC Hydro recommends
that if these are intended as mandatory or deemed as a necessary input for the IBR Owner/Operator, then these should be codified as standalone
Requirement(s) against the appropriate functional entities (TP, PC, RC, or TOP suggested by the current draft).
2. The VSL Table for Requirement R1 does not reflect the allowance of a documented limitation. As drafted, it implies that a Severe VSL will be
assessed in spite of a preexisting and documented equipment limitation. BC Hydro recommends that the wording be revised to clarify the
compliance expectations when evaluating IBR performance.
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Thank you for your comment:
R2 does not intend that values other than the default values must be specified, only that performance for the plant/facility will be evaluated in
accordance with those values if provided. If the TP, PC, RC, or TOP require different criteria for system reliability then the flexibility to require
GO/TOs to follow those criteria is allowable. Requring planner/operators to provide values when different criteria are not needed was determined
to be unnecessary.
VSL: The VSL tables were adjusted to clarify if there is an exemption in place.
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3. Do you agree with the drafting team’s proposals for including IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage
phase-angle jump ride-through performance criteria in PRC-029-1 Requirements R3, R4, and R5?
Thomas Foltz - AEP - 5
Answer
No
Document Name
Comment
Designing an IBR plant for transient over-voltage ride-through compliance is complicated by separation of the IBR Units from MPT high side by
the non-aggregated collector system including the MPT itself, frequency dependence of the collector system, GSU (i.e., pad mount transformers)
and MPT transformer saturation, and surge arrestors on the collector system. DFRs triggered on TOV are essential for monitoring compliance.
Assessing IBR plant phase jump ride-through is dependent on being able to trigger DFR records on non-fault line switching events. Also, as the
standard is now written, phase angle jump of any magnitude during a fault must be ridden through and it does not seem possible to determine if
a ride-through failure is caused by a fault-caused phase jump exceeding 25 degrees (in which case the IBR could be compliant), or if instead there
is a true non-conformity with R1. AEP is not aware if anything can be done about this, but it may be a minor point in most practical situations.
Regarding R4, the technical rationale supporting the standard seems to neglect the possibility of torsional interaction between the wind facilities
where sub-synchronous control interaction could exist that can result in possible damage to the wind turbine generator shaft. Therefore, a
blanket statement that an inverter-based resource is not affected by off-nominal frequencies may be an assumption that should warrant further
considerations when establishing inverter-based resource, frequency ride through requirements. We believe this is supported by page 6 of the
technical rationale which states “In the case of the non-hydraulic turbine synchronous resources, the turbine is usually considered to be more
restrictive than generator in limiting IBR frequency ride‐through because of possible mechanical resonances in the many stages of turbine blades.
Off‐nominal frequencies may bring blade vibrational frequencies closer to a mechanical resonate frequency and cause damage due to the
vibration stresses. However, inverter‐ interfaced‐IBR does not share this vibrational failure mode.” Furthermore, how should phase jump be
considered in R5 where synch check relay settings are greater than 25 degrees?
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Thank you for your comments.
Previous R3: The team has removed Requirement R3.
Assessing phase jump: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to
trip within the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of
the MPT would include this information. The measure for R1 has been modified to reflect this change. The analysis is triggered by the plant
tripping which is an event included within an analysis required by PRC-030. At a minimum, the DFR should be configured to trigger when a trip or
a reduction in active power occurs for PRC-030.
R3 (Previous R4): R3 requires ride-through only during frequency deviations of the fundamental waveform as described in Attachment 2 (previously
Attachment 3) and is, as you correctly observe, the intent of the standard is currently only for the fundamental frequency and does not address
other superimposed frequencies including those resulting from sub-synchronous resonances. We expect that the actual phase jump seen at an IBR
POI or high side of MPT in the case of a sync-check supervised line reclosing would be substantially less than the pre-reclose angle across the open
breaker.“ In most cases and for most sync-check settings, we don’t believe the actual phase jump would be greater than 25 degrees.”
Leah Gully - Madison Fields Solar Project, LLC - 5 - RF
Answer
No
Document Name
Comment
See "additional comments" for details
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Response
Thank you for you comment
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
No
Document Name
Comment
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Tri-State is concerned with the big jump from 61.8 to 64 under Attachment 3, Table 4. We would like to suggest the ride-through requirement be
at 62 or 63.
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Response
Thank you for your comment. At this time, there is no change to the table ranges.
Brian Lindsey - Entergy - 1
Answer
No
Document Name
Comment
•
R3:
o
Technical Rationale “High Voltage Ride Through and Low Voltage Ride Through” modes were not clearly defined. “Mode” implies
a specific, programmed, set of actions within controls which may not be real for solar sites.
A GO may not know if a switching event occurs. In that case, how would a GO be expected to determine if the event in question
is a switching event or not? While R6 addresses exemptions for R1 and R2 in the case that equipment or the ability to record
doesn’t exist in an existing site, the same may be of concern for the sub-second requirements listed in R3, 4 and 5. The same
exclusions should be for the entire standard, if applicable.
o
If the Rate of Change of Frequency is 5 Hz/second, there’s concern that the level of calculation needed on parameters that may
not have more than a 1/second resolution would net little reaction.
o
While R6 addresses exemptions for R1 and R2 in the case that equipment or the ability to record doesn’t exist in an existing site,
the same may be of concern for the sub-second requirements listed in R3, 4 and 5. The same exclusions should be for the entire
standard, if applicable.
o
•
•
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R5:
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Thank you for your comment.
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Previous R3: Requirement R3 has been removed.
R3 (previous R4): The team is drafting PRC-029 to align with the proposed requirements for measurements within PRC-028. Additional
information on calculating ROCOF has been provided in the technical rationale.
R4 (previous R6): The scope of allowable exemptions within R5 is consistent with the regulatory directives of Order No. 901. Frequency or phasejump requirements cannot apply for exemption. New IBR cannot apply for exemption.
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
No
Document Name
Comment
AECI supports comments provided by the NAGF
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Response
Thank you for your comment. See response to NAGF.
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
No
Document Name
Comment
Black Hills Corporation supports NAGF’s and EEI’s comments. Additionally, see “Measures” concern noted above in Q2.
Likes
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Response
Thank you for your comment. See response to EEI and NAGF. The measures have been addressed per the response in Q2.
Colin Chilcoat - Invenergy LLC - 6
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Answer
No
Document Name
Comment
No, Invenergy disagrees with the proposals for including IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle
jump ride-through performance criteria in Requirements R3, R4, and R5. We offer the below comments regarding these Requirements:
R3: Can the drafting team provide data that demonstrates observed overvoltages during recent System events were of the TOV magnitudes and
durations defined in Attachment 2 Table 3? TOVs of such scale are primarily due to the following three scenarios: 1) a lightning strike on the
nearby transmission system, 2) transmission line switching transients, and 3) resonant phenomena like voltage magnification due to shunt
capacitor switching on the transmission system. Measures are already in place to mitigate such events, including but not limited to proper
insulation coordination and substation design, metal oxide varistors, and proper capacitor bank switching of transmission level shunt capacitors
(e.g. synchronous switching or use of pre-insertion resistors to mitigate voltage magnification to the extent possible).
To support our statement above, consider an often-quoted document to support these TOV requirements in the NERC Odessa Disturbance Texas
Events: May 9, 2021 and June 26, 2021 Joint NERC and Texas RE Staff Report, Dated September 2021. A detailed read of the section that is
entitled Inverter Transient AC Overvoltage Tripping Persists identifies poor coordination of controls and protection as the primary driver of these
events, rather than TOV conditions at the point of measurement due to switching transients or any type of resonance. What the report explains
is that in some cases the IBR units force maximum reactive power output during a fault to push the network voltages up, then once the fault
clears they do not pull back on the reactive power injection quickly enough, which leads to an RMS over-voltage (not switching event TOV) at the
terminals of the IBR unit, and thus the IBR units tripped. This is solved by 1) proper controls and protection coordination, 2) proper IBR plant
design, and 3) proper evaluation of the LVRT and HVRT ride-through capabilities of the IBR plant during the design phase of the plant.
R3 should be removed, and the focus placed on low voltage ride-through and high voltage ride-through, with an emphasis that both LVRT and
HVRT performance should be tested during the design phase of a facility using validated IBR unit models based on type-testing.
R4: In the Technical Rationale, the drafting team explains that due to lower system inertia “a wider frequency ride-through capability for IBR may
be required to avoid the risk of widespread tripping.” Can the drafting team cite more specific reasoning or data to support the expansion of the
frequency ride-through capability requirement to the range of 64Hz to 56Hz, well beyond the IEEE 2800-2022 standard frequency ride-through
requirement and the capabilities of many legacy IBRs?
The proposed 6-second frequency ride-through capability requirement for the ranges of 61.8Hz to 64Hz and 57Hz to 56Hz does not align with the
requirements on the rest of the BES. For the foreseeable future, synchronous generators will continue to be a significant part of the grid. It is a
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well-established fact that such large electric machinery, which are directly connected to the grid, cannot be exposed to such large variations in
frequency. Therefore, it does not seem reasonable to ask IBRs to go to such extremes.
R5: We fail to see the value of requirement R5 given the other ride-through requirements, and it’s unclear to us how an entity is to determine if
the subject switching event is initiated by a fault or not. Additionally, we don’t believe the language in R5.1. regarding equipment tripping to
prevent equipment damage is reasonable or auditable. We recommend Requirement R5 is removed.
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Thank you for your comment.
Previous R3: Requirement R3 has been removed. The poor coordination scenario described is covered within Requirement 2.4 (previously R2.3).
There was additional information regarding transient overvoltage within Note 10 of Attachment 1 which would be applicable to Requirements R1
and R2.
R3 (Previous R4):
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to trip within
the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of the MPT
would include this information. The measure for R1 has been modified to reflect this change.
Rhonda Jones - Invenergy LLC - 5
Answer
No
Document Name
Comment
No, Invenergy disagrees with the proposals for including IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle
jump ride-through performance criteria in Requirements R3, R4, and R5. We offer the below comments regarding these Requirements:
R3: Can the drafting team provide data that demonstrates observed overvoltages during recent System events were of the TOV magnitudes and
durations defined in Attachment 2 Table 3? TOVs of such scale are primarily due to the following three scenarios: 1) a lightning strike on the
nearby transmission system, 2) transmission line switching transients, and 3) resonant phenomena like voltage magnification due to shunt
capacitor switching on the transmission system. Measures are already in place to mitigate such events, including but not limited to proper
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120
insulation coordination and substation design, metal oxide varistors, and proper capacitor bank switching of transmission level shunt capacitors
(e.g. synchronous switching or use of pre-insertion resistors to mitigate voltage magnification to the extent possible).
To support our statement above, consider an often-quoted document to support these TOV requirements in the NERC Odessa Disturbance Texas
Events: May 9, 2021 and June 26, 2021 Joint NERC and Texas RE Staff Report, Dated September 2021. A detailed read of the section that is
entitled Inverter Transient AC Overvoltage Tripping Persists identifies poor coordination of controls and protection as the primary driver of these
events, rather than TOV conditions at the point of measurement due to switching transients or any type of resonance. What the report explains
is that in some cases the IBR units force maximum reactive power output during a fault to push the network voltages up, then once the fault
clears they do not pull back on the reactive power injection quickly enough, which leads to an RMS over-voltage (not switching event TOV) at the
terminals of the IBR unit, and thus the IBR units tripped. This is solved by 1) proper controls and protection coordination, 2) proper IBR plant
design, and 3) proper evaluation of the LVRT and HVRT ride-through capabilities of the IBR plant during the design phase of the plant.
R3 should be removed, and the focus placed on low voltage ride-through and high voltage ride-through, with an emphasis that both LVRT and
HVRT performance should be tested during the design phase of a facility using validated IBR unit models based on type-testing.
R4: In the Technical Rationale, the drafting team explains that due to lower system inertia “a wider frequency ride-through capability for IBR
may be required to avoid the risk of widespread tripping.” Can the drafting team cite more specific reasoning or data to support the expansion of
the frequency ride-through capability requirement to the range of 64Hz to 56Hz, well beyond the IEEE 2800-2022 standard frequency ridethrough requirement and the capabilities of many legacy IBRs?
The proposed 6-second frequency ride-through capability requirement for the ranges of 61.8Hz to 64Hz and 57Hz to 56Hz does not align with
the requirements on the rest of the BES. For the foreseeable future, synchronous generators will continue to be a significant part of the grid. It is
a well-established fact that such large electric machinery, which are directly connected to the grid, cannot be exposed to such large variations in
frequency. Therefore, it does not seem reasonable to ask IBRs to go to such extremes.
R5: We fail to see the value of requirement R5 given the other ride-through requirements, and it’s unclear to us how an entity is to determine if
the subject switching event is initiated by a fault or not.
Additionally, we don’t believe the language in R5.1. regarding equipment tripping to prevent equipment damage is reasonable or auditable. We
recommend Requirement R5 is removed.
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Thank you for your comment.
Previous R3: Requirement R3 has been removed. The poor coordination scenario described is covered within Requirement 2.4 (previously R2.3).
There was additional information regarding transient overvoltage within Note 10 of Attachment 1 which would be applicable to Requirements R1
and R2.
R3 (Previous R4):
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to trip within
the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of the MPT
would include this information. The measure for R1 has been modified to reflect this change
Ruchi Shah - AES - AES Corporation - 5
Answer
No
Document Name
Comment
1 AES CE agrees that such performance criteria in R3, R4, and R5 needs to be included, but requests modifications and clarifications as
requested below:
2·
The language in R3 and R5 relating to “switching events” is difficult to track from the GO perspective. If such an event occurs at the
Transmission Operator (TOP), we may not be aware of the need to track and assess our IBR performance as applicable to PRC-029 unless notified
by the TOP. If a performance issue with an IBR is identified we would need to be informed by the TOP that a switching event occurred to assess
applicability to PRC-029.
3
Please update the technical rationale to clearly state that the 5 Hz/second criteria in R4 aligns with IEEE2800.
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Thank you for your comment.
2. Previous requirement R3 has been removed. Previous R5 does not require to track all switching events. However, Previous R5 has been
removed and the non-fault exclusionary language has been added to R1. A requirement to notify the Generator Owner or Transmisson Owner
and to evaluate performance when the plant/facility tripped because of a switching event is in the current draft PRC-030.
3. Additional language has been added in the TR.
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Kimberly Turco - Constellation - 6
Answer
No
Document Name
Comment
These requirements would be a huge expense for sites that currently don't have frequency response capabilities and there is a strong possibility
that many would not be capable of meeting based on manufactures. It will not be financially feasible for all project owners to support this
change.
Kimberly Turco on behalf of Constellation Segments 5 and 6
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Response
Thank you for your comment.
Frequency response capability is not required by PRC-029.
George E Brown - Pattern Operators LP - 5
Answer
No
Document Name
Comment
Pattern Energy supports Invenergy’s comments for this question.
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0
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0
Response
Thank you for your comment. See response to Invenergy.
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
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Answer
No
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and North American Generator Forum (NAGF)
on question 3
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0
Response
Thank you for your comment. See responses to EEI and NAGF.
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
No
Document Name
Comment
R5 ,
First time seeing this type of protective setting, unsure as to whether or not any documentation exists or protective settings currently exist in our
fleet for this.
M5 ,
Will the PC's be communicating in writing to the Generator Owner every time there is a disturbance with the request for this data. How long will
the data need to be held?
The values for ride through are different from PRC-24. All current generation sites have targeted to comply with the curve given in PRC-24. The
basis of moving these protective curves are unclear.
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Response
Thank you for your comment.
R5: The requirements in PRC-029 are not protection or controller setting requirements. Revisions have been to made to include capability based
requirements along with performance based requirements. Phase jump protection would typically only be located within the inverter controller
and would not be part of requirements for evaluating performance of the full plant/facility; per PRC-030. The documentation could include
protection and control settings, manufacturer guidance, engineering analysis, or other guidance on why the trip settings were selected.
M5: PRC-030 dictates the requirements for entities to send/receive requests for disturbance monitoring data and specifies the retention rate for
compliance. The PRC-028 draft specifies data retention requirements for disturbance monitoring data outside of those requests.
Ride-through curves: The team identifies that there is reliability need to address IBR technologies with these wider range or ride-through
capability, which have demonstrated through multiple reports of wide-area disturbances.
Joy Brake - Nova Scotia Power Inc. - NA - Not Applicable - NPCC
Answer
No
Document Name
Comment
Yes, they are needed but the understanding of what those criteria should be is not evolved sufficiently at this time. Also, large scale EMT network
models are not of sufficient quality to assess the criteria in the design phase.
For example, if RoCoF is for a time period of greater than or equal to 0.1 second, it leaves the choice of sample time to the user. The plant can
take the 100ms for calculations and meet the criteria. The System Operator criteria may calculate RoCoF over 500ms (as we do) and would see
the plant as not meeting criteria for the same event.
The proposed RoCoF of 5Hz/s is higher than IEEE1547 Category I, II and III. Transmission Wind turbines and their capabilities are often the same
as DER plants. A transmission facility just has a lot more of them. That said, we are looking to introduce higher RoCoF for DER as they may be
vulnerable as we transition to a very high IBR grid.
RoCoF is not calculated during the fault occurrence and clearance? The standard would only apply for loss of a source of generation without a
fault? For loss of our tieline for a fault it would not apply but loss of tieline for neighbouring RAS action it would? It is most needed when there is
a fault. For a fault, we are also losing the older wind MW as they go into momentary cessation during the fault making the generation loss
greater. For simple loss of supply, a high IBR grid is stronger than for a loss of supply due to fault. We apply RoCoF criteria during a fault. Our
current criteria for transmission design is 2.4 Hz/s calculated over 500ms. Our current design criteria for generation facilities ride through is
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4Hz/s. But it is under review in EMT studies. We do not use rolling average at this time as it is difficult to accurately calculate in PSSE. We hope to
be able to move to rolling average as we increase our use of PSCAD study results for operational studies.
How does it align with the RoCoF criteria for synchronous plants? We are surveying our existing thermal plants and it is still a bit of an unknown
in some areas. Our current criteria of 4Hz/s applies to all generating facilities.
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Response
Thank you for your comment.
Models: PRC-029 is one part of many standard revisions that are being made to address poor performance. Modeling issues, inclusive of EMT,
will be addressed as part Milestone 3 projects (due to be filed Nov 2025).
RoCoF: The requirements within PRC-029 only state the calculation will be of at least 0.1s. Please refer to the Technical Rationale for more
information.
Measures - data: The compliance measures for demonstration of performance were revised from “actual recorded data” to “actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data”.
Clarification: The requirements to demonstrate ride-through performance are in relation to the response to a fault and include no-trip zones and
operation regions to require specific performance during the recovery period, immediately following a fault.
PRC-024 -RoCoF: PRC-024 does include criteria for calculating RoCoF for synchronous machines.
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF provides the following comments:
a. Requirement R3 – the NAGF notes that GOs do not have knowledge of BPS/BES “switching events” and requests that the Drafting Team (DT)
consider adding a requirement for the TO/TOP to notify the GOs of such events.
b.
i.
Requirement R4:
The term “applicable IBR” needs clarification.
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ii.
Request additional clarification/justification regarding the proposed 5 Hz/second threshold.
iii.
The NAGF requests clarity on how to test compliance with the TOV Ride-Through requirement during study or plant IBR design phase.
c.
Requirement R5:
i.
Same concern as identified for R3
ii.
The requirements for phase angle shift of 25 degrees should allow IBR tripping if the post-fault system condition is drastically changed and
the device protection is activated.
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Response
Thank you for your comments.
TOV (previous R3): Previous requirement R3 has been removed.
R3 (previous R4): the term “applicable IBR” has been replaced to refer the applicability section. Additionally, the team has aligned the usage of
the 5hz/second criterion with IEEE 2800 and additional clarity has been added to the TR.
R4 (previous R5): The evidence of compliance for disturbance monitoring that are associated with voltage and frequency excursions that were
System disturbances and would be identified for analysis or another trigger by an applicable entity within draft PRC-030. Evidence of disturbance
monitoring of IBR associated with those disturbances would be triggered by compliance under the requirements for PRC-030.
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Comment
•
•
•
WEC Energy Group disagrees with R3. FERC Order 901 calls for addressing system disturbances. A switching event does not qualify as a
system disturbance. In addition, disturbance events summarized this as an anti-islanding protection issue and therefore it should be
stated in R3 to reduce confusion. If the SDT decides to keep R3, then R3 should include following text, “unless a documented equipment
limitation exists in accordance with Requirement R6.”
WEC Energy Group agrees with inclusion of R4 with following exception: R4 should include following text, “unless a documented
equipment limitation exists in accordance with Requirement R6.”
WEC Energy Group agrees with inclusion of R5 with following exceptions:
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o
o
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R5 should include following text, “unless a documented equipment limitation exists in accordance with Requirement R6.”
The industry term is known as PLL Loss of Synchronism and is identified as such in disturbance reports. Therefore, R5 should
adopt the same to reduce the confusion.
0
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Response
Thank you for your comment.
Previous R3: Previous requirement R3 has been removed.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to trip within
the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of the MPT
would include this information. The measure for R1 has been modified to reflect this change.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901.
Frequency or phase-jump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the ordered
directives.
PLL loss of synchronism: A footnote has been added to R1 to clarify PLL loss of synchronism.
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
No
Document Name
Comment
Duke Energy recommends the implementation of EEI and NAGF comments.
Duke Energy also recommends, if not already considered, to verify with OEMs that the inverters can satisfy Att 2. Figure 3 does not align with
IEEE 2800 Figure 14; again, making compliance with both requirements more complicated.
The controls only respond to voltage and therefore will have no context of the initiating event as could be implied by the statements in R3 and
R5. Recommend adding an exception to R3 worded in a similar format to the exception stated in 5.1.
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Thank you for your comments. See response to EEI and NAGF.
TOV: Attachment 2 has been removed as well requirement R3.
IEEE 2800: PRC-029 and IEEE 2800 to not have any contradictory. Requirements within the NERC PRC-029 address the scope of the SAR and draw
from IEEE2800 but are mandatory and enforceable requirements; in contrast to IEEE2800.
Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
No
Document Name
Comment
R3-5: R6 should apply to R1-R5 to account for equipment limitations that may also apply to R3-R5. Recommend similar language included in R1
and R2 is added to R3-5:
“…unless a documented equipment limitation exists in accordance with Requirement R6.”
Recommend that there be no requirement to document limitations on legacy equipment and that this standard focuses on equipment brought
into service after the implementation date.
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Response
Thank you for your comment.
Previous R3: Previous requirement R3 has been removed.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901.
Frequency or phase-jump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the ordered
directives.
Alison MacKellar - Constellation - 5
Answer
No
Document Name
Comment
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These requirements would be a huge expense for sites that currently don't have frequency response capabilities and there is a strong possibility
that many would not be capable of meeting based on manufactures. It will not be financially feasible for all project owners to support this
change.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Response
Thank you for your comments.
The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901. Frequency or phasejump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the ordered directives.
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer
No
Document Name
Comment
No technical expertise to comment.
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Response
Thank you for your comment.
David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
No
Document Name
Comment
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Vistra agrees with AEP.
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Response
Thank you for your comment. See response to AEP.
Dave Krueger - SERC Reliability Corporation - 10
Answer
No
Document Name
Comment
On behalf of the SERC Generator Working group:
Apply the R1 and R2 phrase “…unless a documented equipment limitation exists in accordance with Requirement R6” to R3, R4, and R5 in
addition to what is currently proposed in R1 and R2.
For R3 and R5, the GO will not know an over-voltage or phase jump is the result of a non-fault switching event, so is the GO expected to treat all
over voltage and phase jump events as non-fault events.
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Response
Thank you for your comment.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901.
Frequency or phase-jump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the ordered
directives.
Previous R3: Previous requirement R3 has been removed.
R4 (previous R5): R4 does not require to track all switching events. The requirement to notify the Generator Owner or Transmisson owner and to
evaluate performance when the plant/facility tripped because of a switching event is in the current draft PRC-030. Coordination between PRC029 and PRC-030 drafting teams: these team have implemented changes to those drafts that triggers within PRC-030 to initiate an analysis will be
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evaluated against PRC-029 ride through criteria. PRC-029 established the criteria and PRC-030 includes requirements for conducting the analysis
of performance after a disturbance.
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
No
Document Name
Comment
R5.1:
This requirement is beyond the purpose of the standard, which is to establish Frequency and Voltage Ride-through Requirements for Inverter Based Generating Resources and should be removed.
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Response
Thank you for your comment.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to trip within
the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of the MPT
would include this information. The measure for R1 has been modified to reflect this change.
Carey Salisbury - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer
No
Document Name
Comment
For R3 and R5, the GO will not know an over-voltage or phase jump is the result of a non-fault switching event, so is the GO expected to treat all
over voltage and phase jump events as non-fault events.
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Response
Thank you for your comment.
Previous requirement R3 has been removed.
R4 (previous R5): R4 does not require to track all switching events. The requirement to notify the Generator Owner or Transmisson owner and to
evaluate performance when the plant/facility tripped because of a switching event is in the current draft PRC-030.
Michael Goggin - Grid Strategies LLC - 5
Answer
No
Document Name
Comment
There are several concerns with the equipment limitation exemption language in the draft of R6, and such exemptions not being allowed for R3
and R5. To justify R6 only allowing an equipment limitation exemption for existing resources to R1 and R2, and not the other requirements of
PRC-029, the NERC drafting team’s technical rationale document points to FERC Order 901:
The objective of Requirement R5 [sic] is to ensure legacy IBR may need to obtain an exemption to the voltage ride‐through requirements if
hardware replacements or other costly upgrades would be necessary to comply with Requirements R1 or Requirement R2… FERC Order No. 901
states that this provision would be limited to exempting “certain registered IBRs from voltage ride‐through performance requirements.” This is the
reason that no similar provisions are included for exemptions for frequency, rate‐of‐change‐of‐frequency (ROCOF), phase angle change ride‐
through requirements.
First, the R6 equipment limitation exemption should also apply to R3, which requires ride-through for “a transient overvoltage as a result of a
switching event whereby instantaneous voltage at the high‐side of the main power transformer exceeds 1.2 per unit.” As NERC notes, FERC Order
901 directed NERC that existing resources can have equipment limitation exemptions from voltage ride-through requirements, and remaining
online during transient over-voltage is clearly a voltage ride-through requirement. Transient over-voltage can damage equipment, so allowing
IBRs to protect against this damage is consistent with FERC’s intent in Order 901 to only allow tripping that is necessary to protect equipment.
Moreover, in many cases making existing equipment better able to withstand transient overvoltages would require replacing or modifying
hardware.
For similar reasons, an equipment limitation exemption for existing resources should also apply to R5, which requires ride-through for voltage
phase angle changes of less than 25 degrees. FERC Order 901 directed NERC that existing resources can have equipment limitation exemptions
from voltage ride-through requirements, and remaining online during voltage phase angle changes should be interpreted as part of voltage ridethrough requirements. Remaining online during phase angle changes of less than 25 degrees could be a problem for existing generators,
particularly wind generators as phase angle changes can impose mechanical stresses on the wind turbine’s rotating equipment. Not allowing an
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equipment limitation exemption for existing generators under R5 is particularly problematic as it is not typically feasible to retrofit existing wind
turbines to increase their ability to withstand mechanical stresses due to phase angle changes. In such cases, making existing equipment better
able to withstand voltage phase angle changes would require replacing or modifying hardware. Phase angle changes can damage equipment, so
allowing IBRs to protect against this damage is consistent with FERC’s intent in Order 901 to only allow tripping that is necessary to protect
equipment.
Moreover, a contextual reading of Order 901 indicates FERC was mostly focused on limiting equipment limitation exemptions to existing
generators that would have to physically replace or modify hardware, and not strictly limiting such exemptions to a narrow reading of what
constitutes voltage ride-through requirements. Paragraph 193 in its entirety, and particularly the first sentence, explain that FERC’s intent was
focused on exempting existing resources that would have to physically replace or modify hardware: “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.” FERC
continued by directing that “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.”{C}[1]
As explained above, equipment limitation exemptions for R3 and R5 are likely necessary to ensure some existing generators do not have to
physically replace or modify hardware, and thus such exemptions are consistent with FERC’s directive in Order 901.
Finally, R6 equipment limitation exemptions should be allowed for resources with signed interconnection agreements as of the effective date of
the Standard, instead of resources that are in-service as of that date. Resource equipment decisions are typically locked down at the time the
interconnection agreement is signed, and a change in requirements after that point can require a costly change in equipment or settings that
may also trigger a material modification and resulting interconnection restudies. The implementation plan for PRC-029 indicates that the
effective date for the Standard will be the first day of the first quarter six months after FERC approval. Many resources take significantly longer
than that to move from a signed interconnection agreement to being placed in service, so it makes more sense to allow R6 equipment limitation
exemptions for resources that have a signed interconnection agreement as of the effective date of the Standard.
{C}[1]{C} Order 901, https://www.ferc.gov/media/e-1-rm22-12-000, at paragraph 193
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Thank you for your comments.
Previous R3: The team agrees and previous requirement R3 has been removed.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to trip within
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the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of the MPT
would include this information. The measure for R1 has been modified to reflect this change.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901.
Frequency. Newly interconnecting IBR cannot apply for exemption and “legacy IBR” is generally understood to include those IBR that are “inservice”. This is consistent with the ordered directives.
Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
No
Document Name
Comment
A premise of R3 is knowing of a transient OV, due to a switching event on the transmission system. The Generator Owner is not going to have
the intelligence to know if a transient OV is due to a switching event. So, is the GO expected to treat all OV events as non-switching events?
1. Requirement R3: The Transient Overvoltage Ride-Through requirement is just not ready to be included in a regulatory standard. The
measure for this requirement is based on actual recorded data. The existing facilities may not even have recording equipment in place to
measure switching transients. The IEEE P2800.2 WG has also struggled to come up with a Design Evaluation procedure to show that the
plant would be able to ride-through the specified TOV ride-through requirements.
2. Requirement R4:
o The intent of “continue to exchange current” is understood, however, the requirement is vague. During frequency excursion
events, it is necessary that IBR adjusts active power output in response to frequency deviation. But these details are not necessary
in NERC standards, currently. The IBR that “continues to exchange current” but not based on frequency deviation, would comply
with the standard requirements, which is not ideal. The TP/PC is expected to specify IBR performance during abnormal system
frequency. Hence, the requirement should read as following: Each GO or TO of an applicable IBR shall ensure each IBR remains
electrically connected and continues to exchange current as specified by TP or PC during a frequency excursion event……
o Why is there no exception for Volts/Hz limit? This could be an issue for type III WTG and transformer within the plant. The
frequency ride-through requirement in the IEEE Std 2800 recognizes Volts/Hz limitation.
3. Requirement R5:
o Consider revising to read as follows: Each GO or TO of an applicable IBR facility shall ensure that each IBR remains electrically
connected and continues to exchange current during non-fault switching events where the instantaneous change in positive
sequence voltage phase angle is less than or equal to 25 electrical degrees at the high-side of the main power transformer.
o Has the SDT discussed how to measure “instantaneous” phase angle jump based on recorded data?
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Part 5.1 is not necessary. The IBR may not trip because it measured phase angle jump of greater than 25 electrical degrees but
may trip due to affects of such a jump in phase angle. Not sure how to even prove that equipment was at risk or not.
o For R5, the GO will not know if a phase jump is the result of a non-fault switching event, so is the GO expected to treat all phase
jump events as non-fault switching events?
o In R5, what happens if an IBR trips due to phase angle jump while the frequency and voltage remain in the continue to operate
range? IBRs will not know whether the system has experienced a fault or not.
4. Attachment 3:
o Why does the SDT require more stringent ride-through capability compared to the IEEE Std 2800? If a certain interconnection
requires stringent ride-through requirement then it should only be required for that interconnection. There is no need to extend
the stringent requirements of one interconnection to all interconnections. Such an approach is implemented in the PRC-024, PRC006, etc. Additionally, the PRC-006 specifies boundaries between which the frequency needs to remain while simulating and
designing UFLS scheme. The IBR frequency ride-through coordinated with boundaries in PRC-006 should be enough.
o Table 4:
Not sure what is implied by “average system frequency”. The term “average” makes sense when associated with ROCOF
but not with frequency.
≥64 should be >64
≥61.8 should be >61.8
o Note 1 is not necessary. Which measurement is taken on each phase?
o Note 2: Consider replacing with following: Frequency is measured over a period of time, typically 3-6 cycles.
o Note 3: not sure which “control settings” are referred here. Consider the following from PRC-024: Instantaneous trip settings
based on instantaneously calculated frequency measurement is not permissible.
o Note 5: Why did the SDT specify 15-min time period instead of 10-min time period in the IEEE Std 2800.
o
ROCOF and phase angle jumps:
•
•
Some legacy IBRs have technical limitations that will prevent them from riding through ROCOF less than or equal to 5 hz / second or
phase angle jumps less than 25 electrical degrees. Such IBRs need the ability to seek an exemption for these requirements.Note: ERCOT
has questioned the validity of how ROCOF and phase angle jumps are measured, and whether the 5 hz / second and 25 electric degree
values are accurate.
R5 specifies that IBRs must ride through phase angle jumps initiated by non-fault switching events and are changes of less than 25
electrical degrees. There is an issue Southern Company has encountered on NOGRR245. ERCOT has proposed that IBRs not trip for any
ROCOF or phase angle jumps during fault conditions. It is an understanding that IBRs should ignore ROCOF and phase angle jump values
during fault conditions. Southern Company would support similar fault language in PRC-029-1, but a technical exemption would be
required because some legacy IBRs are unable to distinguish between a fault and non-fault condition.
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R6.1.2 discusses “aspects of VRT requirements that the IBR would be unable to meet”. This language could be clearer by requesting the IBR to
identify actual VRT capabilities.[A1]
M6 requires evidence of equipment limitations prior to the effective date of the standard. This could be extremely challenging to meet.
Finally, Southern Company supports NAGF comments.
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Thank you for your comment.
Previously R3: Previous requirement R3 has been removed. Previous R5 does not require to track all switching events. However, Previous R5 has
been removed and the non-fault exclusionary language has been added to R1. A requirement to notify the Generator Owner or Transmission
Owner and to evaluate performance when the plant/facility tripped because of a switching event is in the current draft PRC-030.
Terminology: The phrase “continue to exchange current” is consistent if a BESS is charging prior to a fault and providing voltage support after the
fault. However, the team agrees that a definition for Ride-through is preferable and has replaced usage of “continue to exchange current”.
R3 (Previously R4): Previous requirement R4 does not require additional performance requirements beyond ride-through capability. Other 901
related Standards Projects are expected to address. The scope of allowable exemptions within R4 (previously R6) permits a Volts/Hz-related
exemption but in general the IBR should regulate voltage to avoid exceeding Volts/Hz limitations during an underfrequency event.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to trip within
the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of the MPT
would include this information. The measure for R1 has been modified to reflect this change. Previous R5 does not require to track all switching
events. Previous R5 has been removed and the non-fault exclusionary language has been added to R1. A requirement to notify the Generator
Owner or Transmission Owner and to evaluate performance when the plant/facility tripped because of a switching event is in the current draft
PRC-030.
Attachment 3: Please refer to the technical rationale for why the approach was taken for Regional variants. Other Regional variants are able to
be pursued by each Region as needed. Table 4: The word “averaged” has been removed from the title of Table 4. Note 1: The team agrees and
has removed the “each phase” language. Note 2: The language was modified as suggested. Note 3: PRC-029 is a performance-based Standard
and does not require specific equipment settings. Note 4: The 15 minutes was included to coincide with Table 4 as the maximum defined time
intervals is 11 minutes (660 seconds).
Phase Jump: The phase jump requirement (previously R5) has been removed and moved into the scope of R1. The scope of allowable
exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901. This is consistent with the ordered directives.
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ROCOF: Please refer to the Technical Rationale for more details on the team’s decisions for RoCoF and phase jump criteria. Similarly, this has
been brought into the scope of R1.
R4 (Previously R6): Requirement R4 has been revised to include additional clarity on equipment capability as requested information. Additionally,
the scope of allowable exemptions must be for known equipment limitations. The implementation plan for R4 does include an additional 6
month window to communicate those known limitations.
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company, 3, 1,
5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
No
Document Name
Comment
Rwquirement 3
PG&E believes specific requirements for the inverter capabilities should be removed from the NERC standard and left to the IEEE 2800-22
standard for inverter specifications. The utility relies on RMS measurements and does not have a means to accurately measure transient overvoltage conditions for protective relays; therefore, it would be extremely difficult for the entity to prove its compliance.
Requirement 4
Frequency ride-through limits have been raised considering that IBRs can continue to generate. For synchronous machines, it is not possible to
have such a wide frequency range (as per attachment 3 copied below). When the system has majority of IBRs, the effect on synchronous
machines with such wide frequency variations is unknown. Also, it would affect the underfrequency load shedding schemes.
PG&E has the following questions for the SDT to consider: Should there be separate ride through limits for Grid Forming inverters and Grid
Following inverters? Would higher penetration of IBRs affect the allowable frequency ranges?
Requirement 5
PG&E believes specific requirements for the inverter capabilities should be removed from the NERC standard and left to the IEEE 2800-22
standard for inverter specifications.
PG&E has the following question for the SDT: how do we set relays or trigger a DFR for a switching/non-fault event to show compliance with the
requirement?
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Thank you for your comment.
Previous R3: Previous requirement R3 has been removed.
R3 (previous R4): The team agrees with the comment regarding R4. The team does not propose including different requirements/standards for
forming/following type inverter technology.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to trip within
the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of the MPT
would include this information. The measure for R1 has been modified to reflect this change. Previous R5 does not require to track all switching
events. However, Previous R5 has been removed and the non-fault exclusionary language has been added to R1. A requirement to notify the
Generator Owner or Transmission Owner and to evaluate performance when the plant/facility tripped because of a switching event is in the
current draft PRC-030.
Mark Flanary - Midwest Reliability Organization - 10
Answer
No
Document Name
Comment
See comments below under question 4.
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Thank you for your comment.
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
2020-02_EPRI Comments on Draft NERC PRC-029 (IBR ride-through) Reliability Standard.pdf
Comment
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Response
Thank you for your comment. The team believes these comments have been sufficiently addressed in other comment responses.
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
We agree that PRC-024 standard should remain (enforced) because this will also help in ensuring the reliability of the Bulk Power System.
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Thank you for your comment.
Helen Lainis - Independent Electricity System Operator - 2
Answer
Yes
Document Name
Comment
The IESO recommends the following modifications to the text improve clarity or to better convey intent.
With regards to R4:
“…continues to exchange current during a frequency excursion event whereby the system frequency remains within the “no trip zone” according
to…”
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This suggestion would differentiate the actual system frequency from, say, the frequency measurement as ‘seen’ by the PLL or other parts of the
controls.
With regards to 5.1
As commented above, IESO believes ‘not tripping except to provide equipment protection’ warrants a dedicated Requirement, which may be
referred to the context of other requirements, such as performance during phase angle jumps.
Likes
1
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Ontario Power Generation Inc., 5, Chitescu Constantin
0
Response
Thank you for your comment.
R3 (Previous R4): R3 has been modified to include the revision as suggested.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to trip within
the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of the MPT
would include this information. The measure for R1 has been modified to reflect this change.
Michael Brytowski - Great River Energy - 3
Answer
Yes
Document Name
Comment
Comments: Initial review indicates the proposed requirements R3, R4 and R5 align with IEEE 2800 which we support.
R3: we suggest adding to attachment 2 how the instantaneous transient overvoltage should be calculated (such as what the pu base? and the
minimum sampling rate?)
Likes
0
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0
Response
Thank you for your comments.
Previous R3: Previous requirement R3 has been removed. Information on the TOV calculation has been added to Attachment 1.
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Yes
Document Name
Comment
FirstEnergy has no issue for the direction of these requirements.
Likes
0
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0
Response
Thank you for your comments.
Stefanie Burke - Portland General Electric Co. - 6
Answer
Yes
Document Name
Comment
PGE supports EEI’s comments but in addition would add clarification: For the requirement to say “may trip, but shall only trip to prevent
equipment damage” does not provide clear direction. If the IBR can stand a 30 electrical degree change, is it acceptable to trip at 25.0 to prevent
equipment damage? It would be preferrable to provide a safety margin before reaching the damage point. Or, is this stating that the IBR wait
until 30.0 electrical degrees is reached before taking action? What is the measure for making sure an IBR does not trip at 25.0 or above except to
protect the equipment? If there is nothing particularly harmful about tripping an IBR above 25.0, why not indicate that above 25.0 is not a “Must
Trip Zone/Criteria”?
Likes
0
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0
Response
Thank you for your comments. See response to EEI.
R2.5: The team agrees with removing requirements on operation outside the must Ride-through zone and has removed R2.5.
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Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. If there is a trip during non-fault
initiated switching events, measurement data taken from the high-side of the MPT would include this information. The measure for R1 has been
modified to reflect this change.
Capability and Performance Measures: The team agrees and the measures for R1 through R3 have been adjusted to include design/capability
based requirements as well as the demonstration of performance during disturbances.
Ben Hammer - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
R3: we suggest adding to attachment 2 how the instantaneous transient overvoltage should be calculated (such as what the pu base? and the
minimum sampling rate?)
Likes
0
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0
Response
Thank you for your comment.
Previous R3: Previous requirement R3 has been removed. Information on the TOV calculation has been added to Attachment 1.
David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
Yes
Document Name
Comment
Ameren agrees with EEI's comments.
Likes
0
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0
Response
Thank you for your comment. See response to EEI.
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Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Yes
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of its members:
EEI supports the proposal to include IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle jump ride-through
performance criteria in PRC-029-1 Requirements R3, R4, and R5. However, the following phrase “of an applicable IBR” should be removed from
R3, R4 and R5. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
Likes
0
Dislikes
0
Response
Thank you for your comment. See response to EEI.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
EEI supports the proposal to include IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle jump ride-through
performance criteria in PRC-029-1 Requirements R3, R4, and R5. However, the following phrase “of an applicable IBR” should be removed from
R3, R4 and R5. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
Likes
0
Dislikes
0
Response
Thank you for your comments.
The team agrees and has removed the word “applicable”.
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Daniel Gacek - Exelon - 1
Answer
Yes
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
Likes
0
Dislikes
0
Response
Thank you for your comment. See response to EEI.
Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
But we need to consider old units, please see the additional comments below.
Likes
0
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0
Response
Thank you for your comments.
The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901. New IBR cannot apply
for exemption. This is consistent with the ordered directives.
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Yes
Document Name
Comment
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145
R3: MP agrees with the NSRF’s comments on defining the transient overvoltage calculation method. MP also suggests defining the term “current
block mode.”
Likes
0
Dislikes
0
Response
Thank you for your comment.
Previous R3 has been removed. Information on the TOV calculation has been added to Attachment 1.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
OPG supports IESO’s comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. See response to IESO.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Yes
Document Name
Comment
See EEI Comments
Likes
Dislikes
0
0
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Response
Thank you for your comment. See response to EEI.
Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
Yes
Document Name
Comment
However, please verify the ROCOF with regards to how FR data at the IBR Unit level (per the definitions proposed by 2020-06) is required to be
captured (Per proposed PRC-028-1). Note that PRC-002-4 and -5 have ROCOF triggers for recording that are significantly different than 5
Hz/second. Measure 4 of PRC-029-1 has a reference to a Planning Coordinator’s area but Requirement 4 has no such limitation or uses Planning
Coordinator within the language. It appears that the stated ROCOF is high based on IRPT reports
(https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/Fast_Frequency_Response_Concepts
_and_BPS_Reliability_Needs_White_Paper.pdf ). And the ROCOF definition is different from said report by the IRPTF.
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Response
Thank you for your response.
Measurement Data: Per the current draft of PRC-028, FR data is not required to be collected below the plant level.
RoCoF: The team believes that the ROCOF and calculation are appropriate and consistent with other industry measures (e.g. IEEE 2800).
Additional information can be found in the technical rationale.
RoCoF - trigger levels: The team is aware of the trigger levels in PRC-002 are lower than 5 Volts/Hz, which is acceptable.
Terminology: The Requirement language for Requirements R1, R2, and R3 (previous R4) have been adjusted to “adhere to Ride-through
requirements” and no longer reference the PC.
Richard Vendetti - NextEra Energy - 5
Answer
Yes
Document Name
Comment
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147
NextEra aligns with EEI's comments:
EEI supports the proposal to include IBR transient overvoltage, frequency, ROCOF, and instantaneous voltage phase-angle jump ride-through
performance criteria in PRC-029-1 Requirements R3, R4, and R5. However, the following phrase “of an applicable IBR” should be removed from
R3, R4 and R5. Applicability is defined in the Applicability Section of the standard and anything more is unnecessary and redundant.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Previous R3: Previous requirement R3 has been removed. Information on the TOV calculation has been added to Attachment 1.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1.
The word “applicable” was also removed from the requirement language.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Yes
Document Name
Comment
ERCOT joins the comments of the IRC SRC and adopts them as its own in addition to the following comments, except to the extent of any specific
differences between the SRC comments and the following comments from ERCOT.
Footnote 2 is not clear as to whether RoCoF measurement should begin immediately or upon fault clearing. IEEE 2800.2 discussions are heading
in a direction that would indicate that during fault occurrence, clearance, and recovery back to a steady-state operating point, failure to ride
through should only be allowed if the voltage is beyond the requirement (i.e., the unit should not trip due to any perceived RoCoF during the
entire disturbance and recovery period). This is similar for phase angle jump.
Requirement R4 may need to include language similar to that found in Requirement R5, Part 5.1 to ensure RoCoF is set to the equipment
capability and is not arbitrarily set at 5 Hz/s. ERCOT also notes that the IEEE 2800-2 drafting team is identifying that there should be agreement
between unit owners and planners/operators on how to measure RoCoF (at what time points, greater than or equal to .1 second) to ensure
consistency in testing, model validation, application, and performance evaluation. Otherwise, such a requirement may create confusion or
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otherwise be unenforceable. IEEE 2800-2 also identifies the potential need for higher RoCoF requirements, which may be appropriate in smaller
Interconnections.
The current language in Requirement R5 excludes voltage phase angle change of exactly 25 degrees, which is included in IEEE2800 requirements:
SDT’s proposed language:
“Each Generator Owner or Transmission Owner of an applicable IBR shall ensure each IBR remains electrically connected and continues to
exchange current during instantaneous positive sequence voltage phase angle changes that are initiated by non‐fault switching events on the
transmission system and are changes of less than 25 electrical degrees at the high‐side of the main power transformer.”
ERCOT’s proposed language:
Each Generator Owner or Transmission Owner of an applicable IBR shall ensure each IBR remains electrically connected and continues to
exchange current during instantaneous positive sequence voltage phase angle changes of 25 electrical degrees or less at the high-side of the
main power transformer that are initiated by non‐fault switching events on the transmission system.
Finally, ERCOT believes that under the Violation Risk Factor guidelines, Requirements R3, R4, and R5 should have a VRF of High as they are
requirements “that, if violated, could directly cause or contribute to Bulk-Power System instability, separation, or a cascading sequence of
failures, or could place the Bulk-Power System at an unacceptable risk of instability, separation, or cascading failures . . . .”
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Response
Thank you for your comment.
ROCOF: Footnote 7 clarifies that ROCOF should not be measured during the fault or fault clearnce. The R3 (previous R4) requirement is only
applicable to frequency excursions. Ride-through during a voltage excursion would be covered under requirements R1 and R2. Ride-through
expectations within R1 and R2 are independent of ROCOF.
The technical rationale has been adjusted to include additional language on setting ROCOF trigger points appropriately and not arbitrarily. The
reference to prevent equipment damage (previous R2.5) has been removed from the Standard based on previous comments.
Previous R3: Previous requirement R3 has been removed. Information on the TOV calculation has been added to Attachment 1.
Severity Level: R3 (Previous R4) has been adjusted to a High as suggested.
Previous R5: This requirement has been removed and added as an exemption to Requirement R1.
Kinte Whitehead - Exelon - 3
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Answer
Yes
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
Likes
0
Dislikes
0
Response
Thank you for your comment. See response to EEI.
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Yes
Document Name
Comment
See EEI comments
Likes
0
Dislikes
0
Response
Thank you for your comment. See response to EEI.
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
See comments submitted by Edison Electric Institute
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Likes
0
Dislikes
0
Response
Thank you for your comment. See response to EEI.
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Yes
Document Name
Comment
Overall, we at ACES support Requirements R3 through R5; however, we have a minor concern with the wording of Requirement R3, Option 2.
Specifically, we have concerns with the requirement to “restart current exchange within 5 cycles of the instantaneous voltage falling below (and
remaining below) 1.2 per unit.” For how long of a duration should the instantaneous voltage remain below 1.2 p.u. to trigger the 5 cycles wherein
the IBR must resume current exchange? We recommend that the SDT consider adding a time component to the return from the transient
overvoltage condition.
Likes
0
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0
Response
Thank you for your comment.
Previous R3: Previous requirement R3 has been removed. Information on the TOV calculation has been added to Attachment 1.
Joshua Phillips - Southwest Power Pool, Inc. (RTO) - 2
Answer
Yes
Document Name
Comment
Southwest Power Pool joins the ISO/RTO Council Standards Review Committee comments.
Likes
0
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Dislikes
0
Response
Thank you for your comments. See response to ISO/RTO Council Standards Review Committee.
Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
Answer
Yes
Document Name
Comment
Initial review indicates the proposed requirements R3, R4, and R5 align with IEEE 2800, which the SRC supports.
The SRC recommends the following modifications to the text to improve clarity and to better convey the intent of the standard.
Recommended changes to R4:
“…continues to exchange current during a frequency excursion event whereby the system frequency remains within the “no trip zone” according
to…”
This revision would clarify that the actual system frequency is the relevant measurement instead of the frequency measurement as ‘seen’ by the
PLL or other parts of the IBR control system.
Recommended changes to R5.1
As noted above, the SRC believes ‘not tripping except to provide equipment protection’ warrants a dedicated Requirement, which may be
referred to in the context of other requirements, such as performance during phase angle jumps.
Likes
0
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0
Response
Thank you for your comments.
Previous R3: Previous requirement R3 has been removed. Information on the TOV calculation has been added to Attachment 1.
R3 (previous R4): The team agrees and has incorporated the change as suggested.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1.
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Ryan Quint - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable, Group Name Elevate Energy Consulting
Answer
Yes
Document Name
Comment
Yes. The SDT should consider citing IEEE 2800-2022 directly in the standard and consider using the IEEE 2800-2022 ride-through requirements as
a means to comply with Requirements R1-R5 instead of using Attachment 1 of the standard.
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Thank you for your comment.
Requirements within the NERC PRC-029 address the scope of the SAR and draw from IEEE2800 but are mandatory and enforceable requirements;
in contrast to IEEE2800. NERC Standards cannot refer to outside sources for the purposes of requirement language, per the Rules of Procedure.
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Brittany Millard - Lincoln Electric System - 5
Answer
Yes
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Document Name
Comment
Likes
0
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0
Response
Thank you.
Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Thank you.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
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Thank you.
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3 - WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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0
Response
Thank you.
Glen Farmer - Avista - Avista Corporation - 5
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Thank you.
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
David Campbell - David Campbell On Behalf of: Natalie Johnson, Enel Green Power, 5; - David Campbell
Answer
Yes
Document Name
Comment
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156
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0
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0
Response
Thank you.
Shonda McCain - Omaha Public Power District - 6
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Katrina Lyons - Georgia System Operations Corporation - 4
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Thank you.
John Pearson - ISO New England, Inc. - 2
Answer
Yes
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Document Name
Comment
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0
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0
Response
Thank you.
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Wesley Yeomans - New York State Reliability Council - 10
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
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Wendy Kalidass - U.S. Bureau of Reclamation - 5
Answer
Document Name
Comment
Not Applicable to Reclamation.
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0
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0
Response
Thank you.
Imane Mrini - Austin Energy - 6, Group Name Austin Energy
Answer
Document Name
Comment
N/A
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0
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0
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Thank you.
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4. Provide any additional comments for the Drafting Team to consider, if desired.
Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1
Answer
Document Name
Comment
The proposed PRC-029 seems vague and does not specify what size IBR would applicable. If it is below the 75MVA aggregate, then I believe that
would cause undue burden on utilities to meet.
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Response
Thank you for your comment.
The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be included as
part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of Procedure. These
are currently excluded from this draft.
Ryan Quint - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable, Group Name Elevate Energy Consulting
Answer
Document Name
Comment
Attachment 1 needs a few corrections.
•
•
Figures 1 and 2 use a logarithmic time scale for the Time x-axis. This should be updated to be a regular non-logarithmic time scale.
There are numerous inconsistencies in this standard language and Attachment 1 when compared to IEEE 2800. These should be
considered and reviewed for clarity and completeness in the standard. The option to cite IEEE 2800-2022 and use the requirements in
the IEEE 2800-2022 directly should be allowed over just the use of Attachment 1 (give each GO/TO the ability to use either of these
guides to base their performance off of).
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o
IEEE 2800 identifies the following items, but the standard does not support. Clarification/review should occur for each of these
items:
Exceptions for Negative-sequence voltage exceeding thresholds
IEEE 2800 recognizes Volts/Hz limitations, but the standard does not.
IEEE 2800 recognizes 500kV system voltages are actually operated in the range of 525kV and therefore has equipment
rated to 550kV. These 500kV operating conditions should be considered in the standard.
In IEEE 2800 the frequency ride-through criteria defines 10-minute time periods whereas the standard defines them in a
15 minute time period (Table 4 of Attachment 3). This should be clarified and identified.
The standard is quite vague in terms of technical limitations and documentation exemptions to the requirements. Experience has shown that
this is a highly nuanced and difficult consideration. There is no language focused on software versus hardware limitations and what is
allowed/expected. This could lead to inconsistent, subjective auditing practices rather than clear objective requirements and auditing.
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Thank you for your comment.
Attachment 1: The figures have been updated/corrected. The logarithmic scale has been removed.
IEEE 2800 – negative sequence: The PC/TOP/RC/TP are able to provide specific operational criteria beyond the requirements within R2.
Attachment 1 clarification on 500kv: Attachment 1 sets the minimum expectation for operation regardless of voltage class. Expanding the no
trip zone for 500kV may still be done based on the system need.
Attachment 1: The tables and figures in Attachment 1 have been updated for consistency. The continuous operating region applies for beyond
10 seconds. Note 9 in Attachment 1 is an exception of the overall requirement.
Attachment 3: Note 4: The 15 minutes was included to coincide with Table 4 as the maximum defined time intervals is 11 minutes (660
seconds); which 10 minute does not sufficiently cover.
Exemptions: Language has modified within the Requirement R4 (previous R6), Implementation Plan, as well as the Technical Rationale. Softwarebased limitations are not subject to potential exemption.
Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
Answer
Document Name
Comment
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The SRC requests several enhancements to PRC-029.
1. Clarify and emphasize that documented equipment limitations under Requirement R6 must not be construed to be complete
2.
3.
4.
5.
6.
7.
8.
9.
10.
exemptions from the Requirements of PRC-029. If entities are unable to ride-through portions of the ride-through curve, this should
not automatically exempt them from complying with the balance of the ride-through curve as described in the Technical Rationale.
While this is clearly expressed in the Technical Rationale for Requirement R6 (page 9), this point needs to be brought out more clearly in
the PRC-029 standard itself.
Expand PRC-029 to require that Corrective Action Plans be developed and implemented to remove equipment limitations within a
specified timeline or require a technical justification that addresses why corrective actions will not be applied nor implemented.
PRC-029 will need to explicitly require any new inverter/controller replacing older equipment to be compliant with PRC-029 rather than
set to original equipment specification.
Applicability:In Introduction, Section 4.2.2, it is not obvious what aspect of ‘IBR Registration Criteria’ makes an IBR an ‘applicable’ IBR –
is it simply that an IBR meets NERC Registration Criteria? This bullet point should be elaborated upon to ensure clarity.
Event-Based Standard: The SRC has concerns that this standard is an event-based standard that does not necessarily provide an
assurance of reliability before events occur, such as would be provided by having an engineering analysis or results from bench-testing
and real-time simulations of control equipment that indicate that successful ride through of prescribed disturbances is expected.
Without disturbance events that show whether IBRs perform properly, there is no way to determine if an IBR is compliant with the
standard. At a minimum, the measures (e.g, M2-M5) should be extended to indicate that a statement that no such events are known to
have occurred will qualify as evidence of compliance.
Presentation of Ride-Through Ranges: The intended ride-through requirements would be made more clear if the ‘minimum ridethrough times’ were associated with precisely stated, non-overlapping ranges of voltages or frequencies, such as in the example ‘Table
2’ provided by the SRC in its comments above.
Nominal Voltages: Note #4 of Attachment 1 would be clearer if the 'nominal' system voltage values were listed as they are in
Attachment 2 of PRC-024-3, i.e., “(e.g., 100 kV, 115 kV, 138 kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.)”
Harmonize Tables, Figures, Requirements: The voltage/frequency excursion levels and the associated minimum ride-through times for
all tables, figures, and any associated performance requirements that modify the requirements should be carefully reviewed and
harmonized. There are presently some conflicting entries in the tables/figures.
PRC-029 introduces new terms. The drafting team should consider using these new terms in PRC-024 for consistency. The ranges in
these definitions may be specific to IBRs due to their unique performance characteristics, but these regions serve the same purpose for
synchronous generators.
i. Term(s):
ii. Continuous Operating Region – The range of voltages, measured at the high‐side of the main power transformer, that are ≥
0.9 per unit and ≤ 1.1 per unit.
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iii. Mandatory Operating Region – The range of voltages, measured at the high‐side of the main power transformer, that are > 0.1
per unit and < 0.9 per unit – or – > 1.1 and ≤ 1.2 per unit.
iv. Permissive Operating Region – The range of voltages, measured at the high‐side of the main power transformer, that is ≤ 0.1
per unit.
11. There does not seem to be a direct explanation of how these new terms used in the Requirements are applied in Attachment 1, where
the ranges for “No-Trip” and “Must-trip” are shown. the only mention of these terms in Attachment 1 appears to be in bullets 8, 9, and
10 where one or two Regions are mentioned and assumed to be understood. Additionally, these terms are not used consistently
throughout the standard, as these terms are defined as “Operating Regions,” but frequently appear in the standard as “Operation
Regions.” The SRC recommends that the SDT standardize on a consistent format for these terms.
R1. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that each IBR remains electrically connected and continues
to exchange current in accordance with the no‐trip zones and operation regions as specified in Attachment 1
Attachment 1
8. The specified duration of the Mandatory Operation Regions and the Permissive Operation Regions in Tables 1 and 2 is cumulative over one or
more disturbances within a 10 second time period.
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Thank you for your comments.
Exemption: The team agrees that only specific ride-through limitations would be applied and there is no global exemption intended. Language
has modified within the Requirement R4 (previous R6) as well as the Technical Rationale to clarify this.
Removing Limitations: The team agrees that replacing equipment associated with the limitation also remove any exemption. This has been
clarified in Requirement R4 (previous R6).
Capability and Performance Measures: The team agrees and the measures for R1 through R3 have been adjusted to include design/capability
based requirements as well as the demonstration of performance during disturbances.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Measures - data: The compliance measures for demonstration of performance were revised from “actual recorded data” to “actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data”.
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Measures (events): The evidence of compliance for disturbance monitoring that are associated with voltage and frequency excursions that
were System disturbances and would be identified for analysis or another trigger by an applicable entity within draft PRC-030. Evidence of
disturbance monitoring of IBR associated with those disturbances would be triggered by compliance under the requirements for PRC-030.
CAPs: The analysis of voltage/frequency excursions as well as the development of CAPs are conducted within the PRC-030 draft (project 202302).
Ride-through Ranges: The tables in the Attachments have been adjusted to reflect this.
Nominal Voltage: The attachments apply to all system voltages as established by the TOP.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of
Tables 1 and 2 to clarify the continuous operation region.
Terminology – operating regions: These operating regions have been removed as defined terms. The language of the requirements has been
modified to reflect these changes.
Terminology- Ride-through: The team agrees and has defined a new term for Ride-through and replaced language the requirements with this
new term. Attachments have also been updated to utilize this term as the “Must Ride-through Zone”.
Attachment 1 – corrections: Attachment 1 tables and figures have been revised to clarify the operating regions and no-trip zones.
Mark Flanary - Midwest Reliability Organization - 10
Answer
Document Name
Comment
Requirements R1, R2, R3, R4, and R5 and associated Measures do not make it clear whether equipment settings or configurations that render a
facility unable to meet the performance requirements constitute a non-compliance prior to the occurrence of an event where the facility fails
to meet the performance requirements. An understanding of these requirements as event-based (as described in the current draft of the PRC029-1 Technical Rationale) would only partially accomplish the risk objectives described in the SAR and in FERC order 901 as many events would
not be prevented. This is particularly concerning for frequency excursion events (R4) as these events are relatively infrequent and yet
widespread, potentially resulting in the failure of a multitude of IBRs to meet the performance requirements if frequency trip settings are not
evaluated preemptively. As such, these requirements should make it clear that facilities are to be configured to meet performance
requirements and that the relevant equipment settings should be available as evidence to show compliance.
If there are portions of the performance criteria in this standard that equipment owners cannot be expected to meet through assessment of
equipment settings in the absence of an event, those portions should be addressed in separate requirements that specify corrective actions to
be performed following an event rather than identify non-compliance at the time of the event.
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Thank you for your comments.
Capability and Performance Measures: The team agrees and the measures for R1 through R3 have been adjusted to include design/capability
based requirements as well as the demonstration of performance during disturbances.
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
Attachment 1, Part 2b. I assume that “ESS” means Energy Storage System? Please document or clarify.
Part 7 “ … trip …” again. Same question as in comment 2 above. The second sentence is also unclear. What is “the 10-second time period”? Is
this phrase identified in Parts 8 and 9? If so, please define it before first use and use the same phrase subsequently.
Attachment 2 Part 3 “ … trip …” again. Same question as in comment 2 and Attachment 1 Part 2b above.
Attachment 3, Table 4 Part 2. I agree with averaging frequency over a set time period. But 3 cycles seems rather short to assure a reasonable
frequency value, especially during fault conditions. IEEE 2800 says “… at least 0.1 sec” [6 cycles] for ROCOF, and that is probably a good target
for frequency also.
Table 4 and Part 4 “ … trip …” again. Same question as in comment 2 and Attachment 1 Part 2b and 3 above.
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Thank you for your comment.
Attachment 1 – ESS correction: the note has been revised to “BESS”.
Attachment 1 and 3 – clarification 10 seconds: Notes 8, 9, and 10 (previous notes 7, 8, and 9) now state “any 10 second…”.
Previous Attachment 2: Previous Attachment 2 and previous requirement R3 have been removed.
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Attachment 2 (previous attachment 3): Notes and the table have been modified to remove reference to “averaging”.
RoCoF: The team aggrees that the calculation is for at least 0.1 seconds and is included in footnote 8.
John Pearson - ISO New England, Inc. - 2
Answer
Document Name
Comment
The new or modified terms should define what the “voltage” is, RMS, Positive Sequence? Instantaneous? Etc. for Continuous Operating Region,
Mandatory Operating Region and Permissive Operating Region.
In Attachment 1, bullet 3 is problematic, basing the applicable table based on direction by the Transmission Planner needs to have a specific
requirement describing how that would be done. Bullet 4 is also problematic for the same reason. Bullet 8 – Mandatory Operation Regions
should conform with IEEE 2800 7.2.2.4 for consecutive disturbances, and differentiate from dynamic voltage oscillations. Bullet 9 should also
conform to IEEE 2899 7.2.2.4.
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Thank you for your comment.
Terminology – voltage: The operating region definitions have been removed as defined terms. The language of the requirements has been
modified to reflect these changes. The voltage referenced in Tables 1 and 2 are clarified in Notes 5 and 6 (previous Notes 4 and 5).
Attachment 1 – : The team agrees. Notes for applicability for Tables 1 and 2 are now more specific.
IEEE: The team acknowledges that there may be different requirements required.
Joshua Phillips - Southwest Power Pool, Inc. (RTO) - 2
Answer
Document Name
Comment
Southwest Power Pool joins the ISO/RTO Council Standards Review Committee comments.
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Thank you for your comments. See response RTO Council Standards Review Committee.
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Document Name
Comment
•
It is the opinion of ACES that Section 4.2 should be modified to utilize the registration criteria as defined in the latest revision of the
NERC Rules of Procedure.
Thus, we recommend the following revisions to Section 4.2:
4. Applicability:
4.1 Functional Entities:
4.1.1 Generator Owner that owns an applicable facility in Section 4.2.1.
4.1.2 Transmission Owner that owns an applicable facility in Section 4.2.3.
4.2 Facilities:
4.2.1 Either of the following Inverter-Based Resource (IBR)1 types:
4.2.1.1 BES IBR
4.2.1.2 non-BES IBR that is:
4.2.1.2.1 Connected to the Bulk Power System, and
4.2.1.2.2 Meets the criteria for a Category 2 GO facility.
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4.2.2 High-voltage Direct Current (VSC-HVDC) Transmission facilities that serve as a dedicated connection for an Inverter-Based Resource
meeting the criteria of 4.2.1.1
•
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Transmission is a defined term in the NERC Glossary of Terms. As it is currently defined, this term does not specify a voltage threshold
for its applicability; therefore, we recommend capitalizing all uses of the word “transmission” within PRC-029-1 for the sake of clarity.
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Thank you for your comment.
The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be included as
part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of Procedure. These
are currently excluded from this draft.
Katrina Lyons - Georgia System Operations Corporation - 4
Answer
Document Name
Comment
GSOC supports Georgia Transmission Corporation (GTC) Comments.
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Thank you for your comment. See response to GTC.
Robert Blackney - Edison International - Southern California Edison Company - 1
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Document Name
Comment
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See comments submitted by Edison Electric Institute
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Thank you for your comment. See response to EEI.
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI comments
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Thank you for your comment. See response to EEI.
Kinte Whitehead - Exelon - 3
Answer
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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Thank you for your comment. See response to EEI.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT joins the comments of the IRC SRC and adopts them as its own in addition to the following comments, except to the extent of any
specific differences between the SRC comments and the following comments from ERCOT.
The proposed changes to PRC-024 create a reliability gap, as Type 1 and Type 2 wind turbines are not synchronous machines and would
therefore no longer be required to comply with PRC-024 but are not included in PRC-029 because they are not IBRs. The SDT should consider
including a specific requirement in PRC-024 or PRC-029 that addresses this technology and requires these types of units to try to meet
requirements up to their equipment limitations, to notify their PC/TP/RC/TOP of such limitations, and to reflect any such limitations in their
dynamic models. This will ensure that the PC/TP/RC/TOP can incorporate the expected performance of these units in their studies.
ERCOT agrees with the SDT’s overall approach of ensuring that PRC-029 is clearly a performance-based standard. However, the standard is not
entirely clear on this point, as the Time Horizon is “operations assessment” instead of “Real-time Operations.” Additionally, the standard
generally uses a structure of ‘owners…shall… ensure that’ instead of an ‘owners….shall.. perform’ structure. Structures found in other
standards, such as BAL-001’s ‘entity…shall.. operate such that…’ structure or BAL-001-TRE’s ‘entity….shall….meet (or exceed)’ structure may
also work well for PRC-029.
ERCOT notes that FERC Order 901 states, “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 support during a Bulk-Power System disturbance” (emphasis added). To
meet this directive, it may be important to clearly specify that partial failures (individual IBR unit trips or abnormal responses) also fall under
PRC‑029.
ERCOT therefore recommends modifying the Purpose statement for PRC-029 as follows: “To ensure that Inverter-Based Resources, and their
IBR Units, remain connected and perform operationally as expected to support the Bulk-Power System during and after defined frequency and
voltage excursions.”
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The figures in Attachments 1, 2, and 3 appear to be intended to be graphical representations of the tables. To that extent, they are redundant
(and potentially contradict what is in the tables). They may be valuable in visualizing the requirements, but they are also ambiguous in that the
lines are not precisely defined, and it is not clear if ride-through is required on the lines themselves. ERCOT recommends that these figures be
moved to the Technical Rationale or that Attachments 1, 2, and 3 include a clarification that the plots are for visualization purposes only and
that the tables define what is actually enforceable
Item 7 in Attachment 1 should not imply that the IBR shall trip beyond the minimum duration. While the inclusion of the term "minimum"
helps clarify item 7, the "shall not trip until…" language implies that the IBR shall trip once the minimum ride-through time duration has
elapsed.
SDT’s proposed language:
“At any given voltage value, each IBR shall not trip until the time duration at that voltage exceeds the specified minimum ride‐through time
duration. If the voltage is continuously varying over time, it is necessary to add the duration within each band of Tables 1 and 2 over the 10‐
second time period to determine compliance.”
ERCOT’s proposed language:
"The IBR shall ride through voltage conditions beyond those specified in Tables 1 and 2 above to the maximum extent the equipment allows. If
the voltage is continuously varying over time, it is necessary to add the duration within each band of Tables 1 and 2 over the 10‐second time
period to determine compliance.”
Similar wording should also be applied in item 3 of Attachment 2 and item 4 of Attachment 3.
ERCOT is concerned that item 10 in Attachment 1 (“If the positive sequence voltage at the high‐side of the main power transformer enters the
Permissive Operation Region, an IBR may operate in current block mode if necessary to protect the equipment”) is inconsistent with the
following directive from paragraph 190 of FERC Order 901 (as cited in the technical rationale): “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.”
The proposed defined terms do not seem to be appropriate for the NERC glossary, especially if they are intended to be used exclusively for
IBRs. If the SDT keeps these proposed terms, the definitions should be improved to include durations in addition to voltage ranges and to note
that they are only valid for application to IBRs. Furthermore, there are inconstancies between these terms and Tables 1 and 2 in Attachment
1. For example, the Continuous Operating Region is defined as 0.9-1.1 pu (inclusive), but the tables specify only a one second ride-through time
for 1.1pu voltage and an 1800 second ride-through time for voltages greater than or equal to 1.05pu, which is not consistent with the concept
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of continuous operations. Additionally, the terms are used inconsistently in PRC-029, as the terms are defined as “Operating Regions,” but
frequently appear in PRC-029 as “Operation Regions.”
The Technical Rationale includes the following language:
“The proposed PRC‐029 must be understood as an event‐based standard. Compliance with PRC‐029 is determined from IBR ride‐through
performance during transmission system events in the field and not from interconnection studies, transmission planning studies, operational
planning studies, or from IBR models.”
ERCOT recommends that the SDT add basic expectations to the Technical Rationale instead of simply stating that compliance is not determined
by studies. For example, GOs should design and/or test their facilities to help ensure they won’t be non-compliant during an actual
event. Furthermore, it would be helpful to offer advice or SDT opinions on how ride-through should be evaluated during design,
interconnection, planning, and operational studies. Even though deficient performance in such studies may not be a violation of PRC-029, it
makes little sense to proceed with or allow an interconnection of a plant whose simulation models indicate that it will be unable to comply with
PRC-029. Such guidance in the Technical Rationale would be beneficial for industry even if the Requirements in the standard do not contain a
corresponding mandate.
The Technical Rationale should describe the basis for the “6‐second frequency ride‐through capability requirement for frequencies in the
ranges of 61.8Hz to 64Hz or 57.0Hz to 56.0Hz range,” as it is unclear why this approach was chosen instead of an approach that goes all the way
up to 65 Hz and down to 55 Hz for 10 seconds or only up to 63.5 Hz and down to 56.5 Hz for 5 seconds.
It is also unclear how the SDT addressed the phase lock loop (PLL) loss of synchronism concerns discussed in FERC Order 901. While there is
certainly an interrelationship, certain protection systems like PLL loss of synch may not need to be enabled. Even if enabled, these systems
may, if not correctly configured, require additional tuning to ensure the PLL circuit properly controls and prevents some of the other
parameters from tripping the unit offline (e.g. phase angle, RoCoF, and overvoltage). The SDT should consider adding additional language to
PRC-029 to clarify that phase lock loss of synchronism trips (whether directly or indirectly involved) are not allowed.
The SDT should also consider adding the following items to Attachment 1 for clarity:
11. To the extent possible, IBRs should not use these curves as the absolute voltage or frequency protection set points but should strive to
exceed them up to their equipment capabilities while still ensuring adequate equipment protection.
12. IBRs are not required to trip when voltage and frequency are in the may-trip or permissive operation regions.
Additionally, ERCOT has overall concerns with the work plan pushing the planner and operator requirement changes to the final phases. FERC
Order 901 states, “To the extent NERC determines that a limited and documented exemption for those registered IBRs currently in operation
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and unable to meet voltage ride-through requirements is appropriate due to their inability to modify their coordinated protection and control
settings, 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 [sic] 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.”
Due to the interrelationship between these factors, the allowance for limited exemptions should be linked to the need to mitigate the impact of
such exemptions, which will take time in and of itself. In addition, Order 901 directs NERC to consider the reliability impacts of such an
exemption. If the SDT does not have identified quantities or models of likely exemptions to assess the impact of allowing exemptions, it is
unclear how NERC is considering the reliability impacts of allowing exemptions. There must be guardrails in place to ensure that exemptions
are truly limited, not open-ended, and there should be verification by means of accurate models and studies that the system can withstand the
impacts of exemptions. If such studies demonstrate unreliable operations (i.e. Instability, Cascading Outages, and uncontrolled separation)
would result from granting exemptions, then the exemptions should not be accepted. While ERCOT understands the impacts to generator
owners, such assessment and determination should be made under FERC’s direction to ensure that the limited exemptions and risk posed by
such exemptions are balanced in such a way that the system maintains Reliable Operation.
Finally, regarding the implementation plan, ERCOT does not agree with how the FERC Order 901 excerpt quoted under "Equipment Limitations
and Process for Requirement R6" has been applied. The FERC Order 901 excerpt refers to "typically older IBR technology," which would exclude
a majority of IBRs that are in operation today. Aligning eligibility for PRC-029-1 exemptions based on documented equipment limitations under
Requirement R6 with the effective date of PRC-029-1 would allow potentially hundreds of GWs of newer IBRs to qualify for exemptions. Such
an allowance could result in a failure to realize the reliability benefits FERC intended to capture, as it would allow legacy IBRs to claim
exemptions even if they are ultimately capable of complying with the requirements of PRC-029. Unless there is assurance, based on validated
and accurate models, that planners and operators can verify that the System can withstand the impact of allowing these exemptions, this
allowing this level of potential exemptions may not allow for Reliable Operations. In such instances where exemptions may not allow for
Reliable Operations, there should be additional evaluation of available physical modifications (e.g. upgrade kits, new power plant controllers,
new controller cards/circuits, control communication networks, component upgrades) for IBR technology that is not approaching its end of life
and or an upcoming replacement/refurbishment cycle like "typically older IBR technology" is. Additionally, IBRs that make physical
modifications to achieve compliance or that have to make software changes at multiple sites may need additional implementation time when
such changes require changes at each individual inverter or turbine.
ERCOT expresses appreciation for all of the SDT’s hard work in meeting an expedited timeline for developing a technically complex set of
Requirements that attempts to balance elements from IEEE 2800, FERC Orders, NERC recommendations, and vast amounts of stakeholder
input. The SDT is to be commended for its progress thus far on this critical standard.
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Thank you for your comments
Type 1 and Type 2 Wind: The team agrees and has added these resources into PRC-024-4 applicability. Language throughout the Standard was
adjusted to reflect this change.
Capability and Performance Measures: The team agrees and the measures for R1 through R3 have been adjusted to include design/capability
based requirements as well as the demonstration of performance during disturbances.
Time Horizon: The team finds that the Operational Assessment selection is appropriate. Real-time Operations is defined as “actions required
within one hour or less to preserve the reliability of the bulk electric system”. In the event of Ride-through, no actions are taken by an operator
in requirement language.
Note 5 (previous Note 4): The team finds that the per unit value should be left to the PC/TP. That approach is consistent with PRC-024-4.
Partial Failures and “IBR Unit”: The team would point to the PRC-030 draft that would analyze voltage/frequency excursions and identify if
partial plant performance would necessitate a Corrective Action Plan. PRC-029 is only applicable to the overall plant/facility.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of
Tables 1 and 2 to clarify the continuous operation region. The team believes the figures provide additional clarity and complement the tables.
Shall not trip until…: The team agrees and has modified the notes in Attachment 1 and Attachment 2 (previous attachment 3) to “shall Ridethrough unless… has been exceeded…”.
R2: The team added requirement subpart 2.3 to provide clarity on the operation within the Permissive Operation Region.
Terminology: The team has removed the definitions for operating regions. Language within the requirements and the attachments have been
revised to reflect this.
Evaluation of Studies: clarity on capability expectations as well as performance have been added to the requirements and measures.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1.
Frequency Values: The team selected these values to reflect the system need and to align with IEEE 2800 -when possible- and to accommodate
ride-through frequency requirements in PRC-024 for synchronous machines and Type 1 and 2 wind.
PLL loss of synchronism: A footnote has been added to R1 to clarify PLL loss of synchronism
Attachment 1 – Clarification: Note 12 has been added to clarify the zones.
Regarding Exemptions: The team has modified Requirement R4 (previous R6) to include clarity on allowable exemptions and requires
identification of such limitations to be documented and submitted.
Shonda McCain - Omaha Public Power District - 6
Answer
Document Name
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Comment
OPPD supports comments provided by GRE: Michael Brytowski, Great River Energy, 3, 4/17/2024
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Thank you for your comments. See response to Great River Energy.
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company, 3,
1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Document Name
Comment
For PRC-029-1
PG&E asks the SDT the following question: Does Table 1 or 2 apply to Type 4 Wind IBRs? It is unclear which table it would apply to and should
be clarified since Table 1 specifies “Wind IBR” but not which types of Wind IBRs.
PG&E suggests reconsidering the use of the term “trip” or “no-trip.” Per IEEE 2800-22, “trip” for IBRs may not mean the same as has been
traditionally used for synchronous machines and other electric elements.
For PRC-024-4
PG&E has the following question for the SDT to clarify: For Transmission Owners, does new language in sections 4.1.2 & 4.2.2 only apply to
Synchronous Condensers?
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Attachment 1 – Type 1 and Type 2 wind: Additional language was added to a new footnote 10 and adjustments were made to Note 1 to clarify.
Terminology- Ride-through: The team agrees and has defined a new term for Ride-through and replaced language the requirements with this
new term. Attachments have also been updated to utilize this term as the “Must Ride-through Zone”.
Synchronous Condensers: The applicability section has been modified to apply to synchronous condensers, their step-up transformers, and
auxiliary transformers.
Richard Vendetti - NextEra Energy - 5
Answer
Document Name
Comment
NextEra aligns with EEI's comments:
PRC-029-1 (Applicability Section) Comments: EEI does not support the Applicability Section of PRC-029-1 for the following reasons:
{C}1.
Applicability details should not be contained in footnotes. Please remove footnote 1 from the Applicability Section.
{C}2. Voltage Source Converter – High-voltage Direct Current (VSC-HVDC) are not defined or justified within the Technical Rationale as to
why these resources need to be added PRC-029.
{C}3.
Without a justification of a need to include VSC-HVDC systems, TOs should be removed from PRC-029-1.
{C}4. EEI does not support the use of the term “BPS IBRs” because no such term exists in the NERC Glossary of Terms that might provide
entities with the knowledge to know definitively which IBRs are applicable.
{C}5.
EEI also does not support language that points to the registration criteria.
To address our concerns, we suggest the following changes to the Applicability Section of PRC-029-1, noting the Facilities portion of our
comments utilize the recommendations from the Project 2020-06 SDT (see boldface changes below):
{C}4.
Applicability:
{C}4.1
Functional Entities:
{C}4.1.1
Generator Owner
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{C}4.1.2
{C}Transmission Owner (and footnote 1)
{C}4.2
Facilities: (1) BES Inverter-Based Resources; and (2) Non-BES Inverter Based Resources (IBRs) that that either have or contribute to
an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such
capacity to a common point of connection at a voltage greater than or equal to 60 kV. For purposes of this standard, the term “applicable
Inverter‐Based Resource” or “applicable Inverter‐Based Resources” refers to the following:
{C}4.2.1
{C}BPS IBRs
{C}4.2.2
{C}IBR Registration Criteria
PRC-024 Comments: While there were no questions related to the proposed modifications to PRC-024-4, EEI does not support all of the
proposed changes made to PRC-024-4. Note the following:
Applicability Section of PRC-024-4
EEI does not support changing the intent of 4.2.1.4 (Previously 4.2.1.5) to include multiple synchronous generators connecting to a common
bus under the BES Definition, Inclusion I4. Since the development of the BES definition, Inclusion I4 did not include or intend to include
synchronous generators. Had that been the intent, the SDT could have included synchronous generator resources in I4. Furthermore, the BES
Reference Document states in Chapter I4: BES Inclusion the following:
Dispersed power producing resources are small-scale power generation technologies that use a system designed primarily for aggregating
capacity providing an alternative to, or an enhancement of, the traditional electric power system. Examples could include, but are not limited
to: solar, geothermal, energy storage, flywheels, wind, microturbines, and fuel cells.
While EEI is open to making modifications to the BES Definition, trying to provide interpretations within individual Applicability Sections of
proposed NERC Reliability Guidelines is not the proper method to make such a change. For this reason, and since 4.2.1.4 (previously 4.2.1.5)
was intended to address IBRs; this part of the Applicability Section of PRC-024-4 should be deleted.
Comments on the proposed New Definitions
EEI has no concerns with the proposed new definitions, but we do have some non-substantive comments on their usage throughout PRC-029,
Implementation Plan and Technical Rationale. (See below)
{C}·
Usage of the newly defined terms deviated from the defined term within PRC-029 and the Technical Rational. (i.e., Operating vs.
Operations)
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{C}·
Incorrectly stating in the Implementation Plan that there were no newly defined terms. Please correct this error.
Continuous Operating Region – Only used once in Requirement 2.3.
{C}·
Continuous Operation Region used in Requirements 2.1, 2.1.2, 2.4, & once in Attachment 1 (i.e., suggest changing the defined term to
Continuous Operation Region or correct to Continuous Operating Region throughout)
{C}·
Continuous Operation Region used twice in the Technical Rationale; Continuous Operating Region never used in the Technical
Rationale.
Mandatory Operating Region – Never used in PRC-029
{C}·
Mandatory Operation Region used in PRC-029 in Requirements 2.2, 2.3, 2.4 & once in Attachment 1 (i.e., suggest changing the defined
term to Mandatory Operation Region or correct to Mandatory Operating Region throughout)
{C}·
Mandatory Operation Region was used twice in Technical Rationale; Mandatory Operating Region was never used in the Technical
Rational.
Permissive Operating Region – Never used in PRC-029
{C}·
Permissive Operation Region used in PRC-029 in Requirements 2.3, 2.4, & used twice in Attachment 1 (i.e., suggest changing the
defined term to Permissive Operation Region or correct to Permissive Operating Region throughout)
{C}·
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Permissive Operation Region used once in the Technical Rationale; Permissive Operating Region never used in the Technical Rationale.
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Thank you for your comments.
Applicability footnotes: The usage of footnotes in the applicability section is often used to provide clarity and is consistent with usage in PRC024-4.
VSC-HVDC: Modifications have been made to include these elements within PRC-029.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
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Operation Region: The team agrees and has removed the operation regions as defined terms.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions.
Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Has the MPT Volts/Hz capability been considered when considering the high voltage/low frequency curves?
For R6, the use of "repair" seems inappropriate - an equipment limitation is not equivalent to a broken part in need of repair. We suggest that
"repair(s) or replace the limiting element" in R6.1.4 and R6.2 be changed to "remedy the equipment limitation".
The standard requires IBR to ride-through regardless of operating condition of the transmission system. The IBR is typically designed to ridethrough for planning events, most likely defined in TPL-001 standard. Considering 24 hour/365 day operation, the transmission system may be
experiencing outages beyond planning events. During such an abnormal operating condition, the IBR may not be able ride-through system
disturbances as specified. The same could also be true as the transmission system changes over time, as new transmission lines are added to
the transmission system and generating plants are added to or removed from the transmission system. The IBR which is designed to ridethrough certain transmission network and operating conditions at the time of entering commercial operation may not be able to do so if
transmission network and operating conditions change significantly over time. The standard needs to recognize such issues and grant an
exception if IBR fails to ride-through.
The SDT proposes to add continuous operating region, mandatory operating region, and permissive operating region terms to the Glossary of
Terms. However, these terms are specific to voltage ride-through requirements. There is no reason to limit those terms to voltage ride-through
capability only. The continuous and mandatory operation region terms could be applied to frequency ride-through capability as well. Refer to
IEEE 2800 to see how these terms are used for both voltage and frequency ride-through capabilities.
Continuous/mandatory/permissive operating region terms:
1. The SDT uses continuous/mandatory/permissive “operating” region as well as continuous/mandatory/permissive “operation” region.
Be consistent with either “operating” or “operation” throughout the standard.
2. Following comments to align voltage ranges in Attachment 1, Tables 1 & 2:
o Mandatory Operating Region term should read like following: The range of voltages, measured at the high-side of main power
transformer, that are ≥ 0.1 per unit and < 0.9 per unit OR > 1.1 per unit and ≤ 1.2 per unit.
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o
Permissive Operating Region term should read like the following: The range of voltages, measured at the high-side of main
power transformer, that is ≤< 0.1 per unit.
These terms specify voltage threshold, but which voltage is used in these terms is in the Attachment 1. Per attachment 1, the
continuous and mandatory operating regions are based on phase-to-ground or phase-to-phase voltages. But the permissive operating
region is based on positive-sequence voltage. The defined terms should also make it clear which voltage thresholds are defined.
3.
Consider revising the purpose statement as following: To ensure that Inverter-Based Resources (IBRs) remain connected and support the Bulk
Power System (BPS) during and after frequency and voltage excursions events.
Transmission Owner is included as a Functional Entity in section 4. However, footnote 1 makes it confusing. Would standard only apply to
Transmission Owner when it owns the VSC-HVDC transmission facility connecting isolated IBR with BPS?
Currently, PRC-029-1 allows for a GO or TO to seek an exemption from meeting voltage-ride through requirements in R1 and R2.
Southern Company believes that GOs and TOs should be able to seek exemptions from meeting frequency and voltage ride-through
requirements in R1 – R5.
The proposed standard only provides for VRT exemptions. Any consideration for FRT, ROCOF, phase angle?
Comment to PRC-024-4:
Facilities section 4.2.1.1 should include I2 of the BES definition and section 4.2.1.4 be removed or reference I2 in place of I4. I4 of the BES
definition was intended to point to IBRs at the time of the latest BES definition adoption in 2018 as dispersed power resources and was not
intended to point to synchronous generation resources.
Opportunity to clarify that legacy IBRs must maximize capabilities:
1. For NOGRR245, it has been advocated that legacy IBRs should make software / settings changes to maximize capabilities to meet or
approach the new ride-through requirements, unless such changes are unreasonably priced.
2. Southern’s experience is that software / settings changes are commercially reasonable. The “unreasonably priced” language is
intended to protect against price gauging from OEMs.
3. The current PRC-029-1 draft requires legacy IBRs to meet the new voltage ride-through requirements unless a documented technical
limitation exists. So a legacy IBR can document an exemption and have performance capabilities less than new VRT standard. But what
happens if that legacy IBR owner later learns there is an available software / setting change that would reduce or remove the
limitation? The current draft need clarity to address this.
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4. Southern Company supports such a software / setting deployment requirement and believes it would (1) be commercially reasonable
and (2) more clearly require ride-through capability maximization.
Finally, Southern Company supports EEI and NAGF comments.
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Response
Thank you for your comments.
Voltz/Hz Capability: The team agrees this capability needed clarity and have included this as a potential exemption to voltage Ride-through
requirement R1.
Removing Limitations: The team agrees that replacing equipment associated with the limitation also remove any exemption. This has been
clarified in Requirement R4 (previous R6).
Scope of legacy IBR and approach by the team: The scope of PRC-029 is consistent with the SAR assigned to this team and the regulatory
directives from FERC Order No. 901 that were assigned to this team. There is some potential for documented limitations within Requirement
R4 and the Implementation Plan for legacy equipment that cannot meet any voltage ride-through requirements (R1 and R2). Some revisions
were made to clarify design capabilities would still be required.
Terminology and Attachment 1: The team agrees and has removed the terms for operating regions from the list of defined terms and the
requirements. Attachment 1 has been modified to add clarity for the operating conditions for each of the regions referenced in the tables.
Purpose statement: The team agrees and has modified the purpose statement.
Transmission Owner: Correct, the current version of the draft would apply to VSC-HVDCs with a dedicated IBR connection that is owned by
the TO.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901.
Frequency or phase-jump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the
ordered directives.
Regarding Excemptions: The team has modified Requirement R4 (previous R6) to include clarity on allowable exemptions and requires
identification of such limitations to be documented and submitted.
PRC-024 and PRC-029 applicability: The applicability sections have been modified to include more specific details on currently applicable
facilities. The IBR that will be included as part of registration changes (Category 2 assets) will be added following the approval of pending
changes to the NERC Rules of Procedure. These are currently excluded from these draft.
Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
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Document Name
Comment
While inclusive, is PRC-024-4 Facility Section Part 4.2.1.4 applicable to synchronous generators? Inclusion 4, when written, was designed to
catch the wind/solar aspects of the generation fleet. Inclusion 2 seems to be more appropriate (if not already covered in 4.2.1.1). The MPT
footnote appears to be limited to Quebec TO synchronous generators and does not include a reference to synchronous condensers (4.2.2
synchronous condenser applicable facilities simply says “step-up transformer(s)”). In PRC-024-4 Requirement 2 there is a reference to “MPT”
and the introduction of Transmission Owner within Requirement. It is not clear if applicable to TOs outside of Quebec based on the language
provided (from Requirement R2---“…a voltage excursion at the high-side of the GSU or MPT…” which the GSU/MPT is not mentioned in
applicable Facilities for synchronous condensers Section 4.2.2). In Attachment 1 there is a similar issue in that footnote 8 on page 21 mentions
the high-side of the GSU or MPT—Also should be noted that Footnote 8 does not appear to have an anchor (location within document to
reference the footnote). On page 22 of Attachment 2A there are references to the GSU/MPT as well. Just seeking clarification to avoid an
entity having a synchronous condenser indicating no applicability because of the language. This inconsistency in language does not appear to
follow items 8 (“Clear Language”) and 10 (“Consistent Terminology”) of the Ten Benchmarks of an Excellent Reliability Standard as referenced
in the Guideline for Quality Review of NERC Reliability Standards Project Documents.
PRC-029-1- SDTs need to use the same IBR terms and not add additional descriptors. Even the title of the Standard is not consistent. Should
use the proposed definitions in 2020-06 Verifications of Models and Data for Generators for clarity and consistency. There is no such Facility as
“IBR Registration Criteria”. Footnote 1 contains undefined terms which should be defined within this Standard if used. Because of the
inconsistency in definition use, it is not clear whether this applies to the IBR or IBR Unit locations (even when stated that it does not apply to
“individual inverter units or measurements takes at individual inverter unit terminals.” If looking at Project 2020-06, the inverters in a “common
IBR Unit configuration’ as shown in Figure 2.2 and 2.3 of the Technical Rational are exactly at the individual IBR Units (see link 202006_IBR_Definitions_Technical_Rationale_02222024.pdf (nerc.com). Is “exchange current” considered the same as “inject current” which is
used (various ways) in other Standards being proposed? The new terms introduced address range of voltages that may not correlate to the
Tables effectively. The Continuous Operating Region definition shows to include 1.1 per unit and should reflect the 1800 seconds in Table 1
and Table 2 but the 1.1 voltage per unit in the Tables show only a 1 second capability (Mathemataical expression includes 1.1 per unit in the
Table which it should not). Furthermore the 1.2 voltage per unit is shown to be included in the Mandatory Operating Region but NOT in the
Tables. Please clarify the expectations as entities had an issue in PRC-024 setting protection on the curves when initially mandatory. With
conflicting information, and Figures that are not as explicit or appear to match the Tables, WECC is concerned there may be confusion. This
language does not appear to follow Item 8 (“Clear Language”) and 10 of the Ten Benchmarks of an Excellent Reliability Standard as referenced
in the Guideline for Quality Review of NERC Reliability Standards Project Documents.
At a minimum, bullet 2 under Attachment 1 Table 2 should mention all the types of IBR as listed in other Standards (Type 3 and type 4 of wind
is covered in bullet 1, “Isolated IBR” is undefined, and 2.b. simply says “Other IBR plants” and limits hybrid to PV and “ESS” (possible typo that
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should be “BESS”?). The “not limited to” should remain and the SDT may say all are covered with said language but clarity could be provided by
adding consistent language as used in other Standards. This inconsistency in language does not appear to follow items 10 (“Consistent
Terminology”) of the Ten Benchmarks of an Excellent Reliability Standard as referenced in the Guideline for Quality Review of NERC Reliability
Standards Project Documents.
Attachment 1 Table 2 Bullet 3 leaves the applicability to the TP but the TP is not called out as an applicable entity and this is an Operations
Assessment time horizon. In the Technical Rationale it clearly states “Compliance with PRC‐029 is determined from IBR ride‐through
performance during transmission system events in the field and not from interconnection studies, transmission planning studies, operational
planning studies, or from IBR models.” So, if IBRs in a hybrid plant have issues, the TP is to blame for calling out the incorrect Table? TPs may
very well have the studies to determine how long a ride-through should be sustained by IBRs, but there is no compliance responsibility (not
saying there should be—should be responsibility properly assigned through the Standards process). Bullet 4 allows the PC or TP to change the
Requirement criteria but there is no accountability if done (furthermore no notifications for awareness to those entities in the Operations side
of business). The apparent responsibility does not appear to follow items 1 (“Applicability”) of the Ten Benchmarks of an Excellent Reliability
Standard as referenced in the Guideline for Quality Review of NERC Reliability Standards Project Documents.
“MPT” is not defined in the Standard yet used repeatedly. Clarity can be provided with a footnote or addition of a definition (not that
synchronous condenser use in PRC-024-4 was unclear for MPT).
There are only Severe VSLs for Requirements R1 through R5. Clarity on where the inverter is (based on the 2020-06 drawings provided and
language in this Standards Technical Rational) will be important to understand. Failure of individual IBR units (as defined in 2020-06) appears to
not be addressed9unless it is intended to be addressed by the Sever VSL) and will have an impact on being complaint at the IBR level.
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Response
Thank you for your comment.
PRC-024 applicability and MPTs: The applicability section has been modified to include more specific details on currently applicable facilities.
The IBR that will be included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the
NERC Rules of Procedure. These are currently excluded from this draft. Additionally, the footnotes have been modified to add clarity regarding
the MPT.
PRC-029 applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that
will be included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules
of Procedure. These are currently excluded from this draft.
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Terminology and Attachment 1: The team agrees and has removed the terms for operating regions from the list of defined terms and the
requirements. Attachment 1 has been modified to add clarity for the operating conditions for each of the regions referenced in the tables.
Further, the notes have been revised to resolve issues identified above.
VSL tables: The tables have been revised to include additional levels per the capability-based requirement language.
Romel Aquino - Edison International - Southern California Edison Company - 3
Answer
Document Name
Comment
See comments submitted by the Edison Electric Institute
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Response
Thank you for your comment. See response to EEI.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
See EEI Comments
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Response
Thank you for your comment. See response to EEI.
Carey Salisbury - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer
Document Name
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Comment
For each of the measures M1-M5, what “other evidence” can demonstrate compliance with R1-R5 other than recorded data? How does the
drafting team believe that generator owners can assure this performance expectation can be achieved prior to an actual event? There is no
test verification that can be performed to confirm the expected performance that considers every type of system disturbance that can occur.
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Response
Thank you for your comment.
Capability and Performance Measures: The team agrees and the measures for R1 through R3 have been adjusted to include design/capability
based requirements as well as the demonstration of performance during disturbances.
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Document Name
Comment
Many references in the requirements point toward Continuous Operating Region, Mandatory Operating Region, and Permissive Operating
Region "as specified in Attachment 1", yet Attachment 1 does not specify any of these regions. Operating Regions should be added to
Attachment 1 tables and figures.
No-trip zone Figures 1 & 2 don't match the tables.
Is there a point or distinction being made by using capitalized "Systen" instead of undefined "system" in requirements?
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Response
Thank you for your comment.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of
Tables 1 and 2 to clarify the continuous operation region.
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
Document Name
Comment
The Implementation Plan should be extended to 36 months to allow for monitoring equipment to be installed at sites completed before PRC029 becomes enforceable, to demonstrate performance and compliance with the standard.
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Response
Thank you for your comment.
The implementation of PRC-029 is set to follow PRC-028’s implementation plan. All of the revisions to Standards to address Order 901 must be
fully implemented no later than 2030.
Dave Krueger - SERC Reliability Corporation - 10
Answer
Document Name
Comment
On behalf of the SERC Generator Working Group:
Consider allowing for some period of time beyond the effective date of PRC-029 to document limitations per (R6) – contemplate the real
impact to BES reliability of limitation documentation.
Consider synchronizing the phase in of PRC-028 with the measures such as M1 stating “shall have evidence of actual recorded data...”.
For each of the measures M1-M5, what “other evidence” can demonstrate compliance with R1-R5 other than recorded data? How does the
drafting team believe that generator owners can assure this performance expectation can be achieved prior to an actual event? There is no
test verification that can be performed to confirm the expected performance that considers every type of system disturbance that can occur.
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Response
Thank you for your comment.
Implementation Plan: The implementation of PRC-029 is set to follow PRC-028’s implementation plan. All of the revisions to Standards to
address Order 901 must be fully implemented no later than 2030.
Measures - data: The compliance measures for demonstration of performance were revised from “actual recorded data” to “actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data”.
Capability and Performance Measures: The team agrees and the measures for R1 through R3 have been adjusted to include design/capability
based requirements as well as the demonstration of performance during disturbances.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG supports IESO, HQ, and NPCC Regional Standards Committee’s comments.
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Response
Thank you for your comment. See response to IESO, HQ, and NPCC Regional Standards Committee.
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
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MP agrees with the NSRF’s suggestions to enhance PRC-029, especially regarding limiting the power of equipment limitations from exempting
applicable entities from compliance, expanding the applicable facilities to include IBRs of 20MVA and above, and more precisely defining
applicable entities and facilities within the text of the standard.
MP also suggests that a formal definition of “Inverter-Based Resources” precede the adoption of the standard.
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Response
Thank you for your comment. See response to NSRF.
The team will incorporate changes to the applicability section and usage of IBR defined terms as those are finalized.
Junji Yamaguchi - Hydro-Quebec (HQ) - 1,5
Answer
Document Name
Comment
We are concerned that the standard refers to a defined term for IBR which has yet to be adopted in project 2020-06.
We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
2021-04 (PRC-028) and 2023-02(PRC-030). Section 4.2.2 refers to IBR Registration criteria, however it is our understanding that section 4.2.1
would refer to GOs and TOs “that own equipment as identified in section 4.2” and where section 4.2 would indicate “the Elements associated
with (1) BES Inverter‐Based Resources; and (2) Non‐BES Inverter‐Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of
connection at a voltage greater than or equal to 60 kV.” .
We question why “attachment 1” and “Requirement R6” are written in bold.
Attachment 1: should the “including, but not limited to” in table 2 include the same list (or minimally the same wording) that is found in the
technical rationale of the IBR definition in project 2020-0?. For example, the IBR list in 2020-06 refers to “solar photovoltaic” whereas table 2
refers to “photovoltaic (PV)”.
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In what standard does the PC/TP define the applicable table in point 3 of section 2 in attachment 1? Same question for the voltage base for per
unit calculation in both Attachment 1 and 2. Is there a corresponding requirement in another standard that requires the PC/TP to do this?
·
Terms : Mandatory and permissive operation should be defined based on the attachment figures allowing for interconnections to use
different requirements
·
A-4.2.2 What is the IBR registration criteria? Add a clear reference and make sur the user understands what the IBR registration criteria is.
·
B-R2-2.1 Attachment 1 only uses "no-trip zone". Define continuous operating region more clearly in the table (similar to what is done in
PRC-024-4)
·
B-R2-2.1.2 Can the TP ask for a mix of active/reactive power based on a predetermined ratio (currently only indicated as active or
reactive).
·
B-R2-2.2 Attachment 1 only uses "no-trip zone". Define "mandatory operation region" in Attachment 1.
·
B-R2-2.4 Permissive operation region is not used or defined in attachment 1.
·
B-R3. The document refers to an overvoltage value of 1.2pu. It should refer to a voltage exceeding the mandatory operating region in
order for Interconnections to set their own overvoltage table.
·
B-R3. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through these overvoltages ? An
exemption clause is required for existing IBR that cannot be modified or upgraded.
·
B-R4. The 5Hz/s value should be moved to Attachment 3 and B-R4 should only refer to the value in the Attachment.
·
B-R4. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through these frequencies and
ROCOF ? (for instance, for all the HQ connected projects, the ROCOF requirement was 4Hz/s) An exemption clause is required for existing IBR
that cannot be modified or upgraded.
·
B-R5. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through this phase angle jump ? An
exemption clause is required for existing IBR that cannot be modified or upgraded.
·
Attachment 1. Tables 1 and 2: Indicate what is considered as “continuous operation”, “mandatory operation” and “permissive operation”
in an additional column.
·
Attachment 1. HQ needs a Quebec regional variance since the Québec Interconnection has its own requirements in this regard.
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·
Attachment 2. Bullet 3: This sentence is hard to read. Proposed replacement: "Each IBR shall not trip unless the cumulative time of one or
more instances in which the instantaneous voltage exceeds the respective voltage threshold over a 1-minute time window exceeds the
minimum ride-through time"
·
Attachment 2. HQ needs a Quebec regional variance since the Québec Interconnection has its own requirements in this regard.
·
Attachment 3. This attachment should also include the maximum absolute ROCOF value.
·
Attachment 3. HQ needs a Quebec regional variance (or the equivalent through the “regie de l’energie” approval process).
·
B-R2-2.1.2 Which entity between Transmission Planner, Planning Coordinator, Reliability Coordinator and Transmission Operator has
priority to specify those requirements?
·
B-R2-2.4 Which entity between Transmission Planner, Planning Coordinator, Reliability Coordinator and Transmission Operator has
priority to specify those requirements?
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Response
Thank you for your comment.
IBR: The team agrees and will include IBR defined terms once those are approved.
Applicability section: The team agrees and has collaborated with PRC-028 and PRC-030 teams for consistent language in the applicability
section.
Attachment 1: These notes have been modified to clarify usage of the tables.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions and the “must Ride-through zone”.
The range of values in row #4 of Tables 1 and 2 to clarify the continuous operation region.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Transient Overvoltage: Previous requirement R3 and Previous Attachment 2 have been removed.
Frequency 5hz clarification: The team has made modifications to the requirement language and the attachment to address this.
Regarding Excemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No.
901. Frequency or phase-jump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the
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ordered directives.The team has modified Requirement R4 (previous R6) to include clarity on allowable exemptions and requires identification
of such limitations to be documented and submitted.
Quebec variant: The team will coordinate with Hydro Quebec to include their variant as identified by Hydro Quebec.
Priority: This issue is out of scope for the team. The language in the requirement is to make allowance for established operational instructions.
Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
The implementation plan is also very aggressive and for some generators may be impossible to meet.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Response
Thank you for your comment.
All revisions to Reliability Standards directed by Order 901 must be fully implemented by 2030.
Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Overall comments:
1. Implementation date: 6 months is not sufficient for IBR manufacturers to meet the new standard. Instead we propose 2yrs to
accommodate product development/adequacy and appropriate validation.
2.
For R6, R3,R4,R5 should be included as well for the documented limitation communication (see R6 comments below).
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3. For Attachment 1, for VSC-HVDC connected IBRs, it is not clear if Table 2 is applicable at the MPT on grid side or on the IBR side of HVDC
(see Attachment 1 comments below)
4.
For MFRT, GEV suggests to align to IEEE2800-2022 7.2.2.4 for consistency (see Attachment 1 comments below).
GEV comments to R6: The language in R6 only allows documented limitations for Requirements R1 and R2. The standard must allow for
documentation of limitations for Requirements R3, R4, and R5, as some existing site equipment was not designed to these requirements
originally.
GEV comments to Table 2 in Attachment 1: For VSC-HVDC connected IBRs, please clarify if Table 2 is applicable at the MPT on grid side or on
the IBR side.
GEV comments to MFRT: For MFRT requirements, GE Vernova strongly suggests that this language should align to IEEE2800-2022 7.2.2.4.
Exceptions from the IEEE standard that are relevant were not included, making these requirements inconsistent with 2800-2022.
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Response
Thank you for your comment.
All revisions to Reliability Standards directed by Order 901 must be fully implemented by 2030.
The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901. Frequency or phasejump requirements cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the ordered directives.
VSC-HVDC: Language has been added to identify the point of measurement for VSC-HVDC.
IEEE: Requirements within the NERC PRC-029 address the scope of the SAR and draw from IEEE2800 but are mandatory and enforceable
requirements; in contrast to IEEE2800.
Daniel Gacek - Exelon - 1
Answer
Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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Response
Thank you for your comment. See response to EEI.
Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Document Name
Comment
PRC-24-4 mentined BPS in the Purpose section. We believe it is typo becuase the rest of the standard the applicabilty is for BES elements.
The implemetation plan to to strict to allow cost effect implementation.
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0
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0
Response
Thank you for your comment.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR (for prc-024
this will include type 1 and type 2 wind) that will be included as part of registration changes (Category 2 assets) will be added following the
approval of pending changes to the NERC Rules of Procedure. These are currently excluded from this draft.
Implementation Plan: All revisions to Reliability Standards directed by Order 901 must be fully implemented by 2030.
Imane Mrini - Austin Energy - 6, Group Name Austin Energy
Answer
Document Name
Comment
AE supports comments provided by Texas RE and the NAGF
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0
Response
Thank you for your comment. See response to Texas RE and NAGF.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI offers the following additional comments on both PRC-024 & PRC-029:
PRC-029-1 (Applicability Section) Comments: EEI does not support the Applicability Section of PRC-029-1 for the following reasons:
1. Applicability details should not be contained in footnotes. Please remove footnote 1 from the Applicability Section.
2. Voltage Source Converter – High-voltage Direct Current (VSC-HVDC) are not defined or justified within the Technical Rationale as to why
these resources need to be added PRC-029.
3. Without a justification of a need to include VSC-HVDC systems, TOs should be removed from PRC-029-1.
4. EEI does not support the use of the term “BPS IBRs” because no such term exists in the NERC Glossary of Terms that might provide
entities with the knowledge to know definitively which IBRs are applicable.
5. EEI also does not support language that points to the registration criteria.
To address our concerns, we suggest the following changes to the Applicability Section of PRC-029-1, noting the Facilities portion of our
comments utilize the recommendations from the Project 2020-06 SDT (see removals (i.e., TOs, registration criteria, etc. and other text) and
boldface changes below:
4.
Applicability:
4.1
Functional Entities:
4.1.1
Generator Owner
Facilities:
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(1) BES Inverter-Based Resources; and (2) Non-BES Inverter Based Resources (IBRs) that that either have or contribute to an aggregate
nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.
PRC-024 Comments: While there were no questions related to the proposed modifications to PRC-024-4, EEI does not support all of the
proposed changes made to PRC-024-4. Note the following:
Applicability Section of PRC-024-4
EEI does not support changing the intent of 4.2.1.4 (Previously 4.2.1.5) to include multiple synchronous generators connecting to a common
bus under the BES Definition, Inclusion I4. Since the development of the BES definition, Inclusion I4 did not include or intend to include
synchronous generators. Had that been the intent, the SDT could have included synchronous generator resources in I4. Furthermore, the BES
Reference Document states in Chapter I4: BES Inclusion the following:
Dispersed power producing resources are small-scale power generation technologies that use a system designed primarily for aggregating
capacity providing an alternative to, or an enhancement of, the traditional electric power system. Examples could include, but are not limited
to: solar, geothermal, energy storage, flywheels, wind, microturbines, and fuel cells.
While EEI is open to making modifications to the BES Definition, trying to provide interpretations within individual Applicability Sections of
proposed NERC Reliability Guidelines is not the proper method to make such a change. For this reason, and since 4.2.1.4 (previously 4.2.1.5)
was intended to address IBRs; this part of the Applicability Section of PRC-024-4 should be deleted.
Comments on the proposed New Definitions
EEI has no concerns with the proposed new definitions, but we do have some non-substantive comments on their usage throughout PRC-029,
Implementation Plan and Technical Rationale. (See below)
•
•
Usage of the newly defined terms deviated from the defined term within PRC-029 and the Technical Rational. (i.e., Operating vs.
Operations)
Incorrectly stating in the Implementation Plan that there were no newly defined terms. Please correct this error.
Continuous Operating Region – Only used once in Requirement 2.3.
•
•
Continuous Operation Region used in Requirements 2.1, 2.1.2, 2.4, & once in Attachment 1 (i.e., suggest changing the defined term to
Continuous Operation Region or correct to Continuous Operating Region throughout)
Continuous Operation Region used twice in the Technical Rationale; Continuous Operating Region never used in the Technical
Rationale.
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Mandatory Operating Region – Never used in PRC-029
•
•
Mandatory Operation Region used in PRC-029 in Requirements 2.2, 2.3, 2.4 & once in Attachment 1 (i.e., suggest changing the defined
term to Mandatory Operation Region or correct to Mandatory Operating Region throughout)
Mandatory Operation Region was used twice in Technical Rationale; Mandatory Operating Region was never used in the Technical
Rational.
Permissive Operating Region – Never used in PRC-029
•
Permissive Operation Region used in PRC-029 in Requirements 2.3, 2.4, & used twice in Attachment 1 (i.e., suggest changing the defined
term to Permissive Operation Region or correct to Permissive Operating Region throughout)
Permissive Operation Region used once in the Technical Rationale; Permissive Operating Region never used in the Technical
Rationale.
•
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Response
Thank you for your comments.
Applicability footnotes: The usage of footnotes in the applicability section is often used to provide clarity and is consistent with usage in PRC024-4.
VSC-HVDC: Modifications have been made to include these elements within PRC-029.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Operation Region: The team agrees and has removed the operation regions as defined terms.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions.
Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
Document Name
Comment
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1. Implementation should align with PRC-028-1 proposed implementation to ensure data collecting information is available to adhere to PRC029-1.
2. PRC-024-4 Applicability and Purpose should include asynchronous type 1 and type 2 wind since these are not IBRs and therefore not
applicable to PRC-029:
4.2.1.4 Elements that are designed primarily for the delivery of capacity from the multiple synchronous generators or asynchronous type 1 or
type 2 wind generators, connecting to a common bus identified in the BES Definition, Inclusion I4, to the point where those resources
aggregate to greater than 75 MVA.
4.2.1.6 Type I and type II asynchronous wind generation identified in the BES Definition, Inclusion I4.
3. Suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggested the following language be included in the applicability section. Facilities: The
Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
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Response
Thank you for your comments.
Implementation Plan: The team has revised the implementation plan to follow the effective date of PRC-028.
Type 1 and Type 2 wind: The team agrees and has included these within PRC-024.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment
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Please consider using the risk-based approach when drafting standards.
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Response
Thank you for your comment.
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Duke Energy recommends the implementation of EEI and NAGF comments.
For clarification, expand the following subparts as stated below:
4.1. Functional Entities:
4.1.1. Transmission Owner that owns equipment as identified in section 4.2.
4.1.2. Generator Owner that owns equipment as identified in section 4.2.
4.2. Facilities: The Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or
contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
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0
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0
Response
Thank you for your comment.
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Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
Document Name
Comment
The applicability section should match applicability sections of other IBR standards under development, PRC-030 and PRC-028.
Likes
0
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0
Response
Thank you for your comment.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
Comment
The NAGF provides the following additional comments for consideration:
PRC-024:
a.
Section 4.2.1.2 – Consider adding the language “Main Power Transformer (MPT)”.
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b. Section 4.2.1.4 and 4.2.1.5 - Recommend that the proposed language be modified to reference BES Definition – Inclusion I2 instead of
Inclusion I4 – Dispersed Power Producing Resources. The proposed new PRC-029 standard’s focus is on Frequency and Voltage Ride‐through
Requirements for Inverter‐Based Generating Resources and therefore should include a reference BES I4 resources.
PRC-029:
a. Terms – the NAGF requests additional clarification on how the proposed defined terms work with the proposed PRC-030. Will analysis be
required for an event under the proposed PRC-029 and under PRC-030? Potential double jeopardy issue. Alternatively, if tripping is allowed
under PRC-029, would an analysis still be required under PR-030?
b.
Section 4.2 - Facilities:
i.
Use of the capitalized term “Bulk Power System (BPS) Inverter-Based Resources (IBR)” should be reviewed as it is not a defined term in the
NERC Glossary of Terms. In addition, it is very likely that not all Bulk Power System Inverter-Based Resources will be registered even under
NERC’s modified Rules of Procedure. Until the definition of Inverter-Based Resources is approved, the SDT should only use the term “inverterbased resource” if needed.
ii.
c.
The NAGF requests clarification if IBR plants that include synchronous condensers should meet the PRC-029 requirements.
Comments Related to Attachments:
i.
Attachment 1 – Recommend adding to the table a column that species what area is the Continuous Operating Region, Mandatory
Operating Region and Permissive Operating Region. As currently structured, it is not clear where the different regions begin or end. If possible,
the NAGF recommends a graph showing the different areas for clarity.
ii.
The abbreviations “MPT” and “ESS” are not defined within the standard/attachment. Please ensure all acronyms/initializations are fully
defined for use.
iii.
If the term ESS is intended to mean Energy Storage Systems, does this also apply to water storage systems, or only Battery Energy
Storage Systems? If the intent is to refer to Battery Energy Storage Systems, please modify the term used.
iv.
Attachment 1, note 3 – There does not appear to be a requirement proposed for the Transmission Planner (TP) to provide direction as
stated in note 3. Request clarification on how the TP will provide such guidance/direction on the applicable table to be used.
v.
Attachment 1, Note 7 – These notes appear to state that no unit should trip in a 10 second period if voltage is fluctuating, but the
summation of time interval does not appear to be 10 seconds in most instances. As an example, assuming that the SDT intends for a generator
to follow the voltage for 10 seconds when it is fluctuating between .7 and .5, the unit should be allowed to trip when voltage is below the .5 level
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for 1.2 seconds. However, note 7 appears to state that there is a 10 second limit if voltage were to be below .7 for 1 second, then goes below .5
for 3 seconds, then returns to the .7 for 6 seconds. Please verify this interpretation is correct, or how this language should be understood.
vi.
Attachment 1, Notes 7 and 8 – Both of these items discuss cumulative numbers in Tables 1 and 2. As worded, it is unclear if the intent is
to add the numbers in Table 1 to the numbers in Table 2, or if the intent is to add the numbers in the second column of Table 1 for those
resources that are considered Table 1 entities, and similar for Table 2 entities. Please clarify the wording so the intent of the standard is clear.
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Response
Thank you for your comments.
MPT: The team agrees and has modified PRC-024 and PRC-029 to clarify language for the MPT.
Thank you for your comment.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Measures (events): The evidence of compliance for disturbance monitoring that are associated with voltage and frequency excursions that
were System disturbances and would be identified for analysis or another trigger by an applicable entity within draft PRC-030. Evidence of
disturbance monitoring of IBR associated with those disturbances would be triggered by compliance under the requirements for PRC-030. A
GO/TO who provides the data per the requirements in PRC-030 would fulfill the obligations of those requirements.
Operation Region: The team agrees and has removed the operation regions as defined terms.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions.
ESS: This has been revised to BESS
Attachment 1 Notes: The team has modified notes to address which table should be used.
10 second accumulation: The team has added clarity to the requirements and TR on how to determine the 10-second window and changing
voltages.
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Document Name
Comment
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AZPS supports the following comments that were submitted by EEI on behalf of its members:
PRC-029-1 (Applicability Section) Comments: EEI does not support the Applicability Section of PRC-029-1 for the following reasons:
1.
Applicability details should not be contained in footnotes. Please remove footnote 1 from the Applicability Section.
2. Voltage Source Converter – High-voltage Direct Current (VSC-HVDC) are not defined or justified within the Technical Rationale as to why
these resources need to be added PRC-029.
3.
Without a justification of a need to include VSC-HVDC systems, TOs should be removed from PRC-029-1.
4. EEI does not support the use of the term “BPS IBRs” because no such term exists in the NERC Glossary of Terms that might provide entities
with the knowledge to know definitively which IBRs are applicable.
5.
EEI also does not support language that points to the registration criteria.
To address our concerns, we suggest the following language in the Applicability Section of PRC-029-1, noting the Facilities portion of our
comments utilize the recommendations from the Project 2020-06 SDT):
4.
4.1
Applicability:
Functional Entities:
4.1.1 Generator Owner
4.2
Facilities: (1) BES Inverter-Based Resources; and (2) Non-BES Inverter Based Resources (IBRs) that that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
PRC-024 Comments: While there were no questions related to the proposed modifications to PRC-024-4, EEI does not support all of the
proposed changes made to PRC-024-4. Note the following:
Applicability Section of PRC-024-4
EEI does not support changing the intent of 4.2.1.4 (Previously 4.2.1.5) to include multiple synchronous generators connecting to a common
bus under the BES Definition, Inclusion I4. Since the development of the BES definition, Inclusion I4 did not include or intend to include
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synchronous generators. Had that been the intent, the SDT could have included synchronous generator resources in I4. Furthermore, the BES
Reference Document states in Chapter I4: BES Inclusion the following:
Dispersed power producing resources are small-scale power generation technologies that use a system designed primarily for aggregating
capacity providing an alternative to, or an enhancement of, the traditional electric power system. Examples could include, but are not limited
to: solar, geothermal, energy storage, flywheels, wind, microturbines, and fuel cells.
While EEI is open to making modifications to the BES Definition, trying to provide interpretations within individual Applicability Sections of
proposed NERC Reliability Guidelines is not the proper method to make such a change. For this reason, and since 4.2.1.4 (previously 4.2.1.5)
was intended to address IBRs; this part of the Applicability Section of PRC-024-4 should be deleted.
Comments on the proposed New Definitions
EEI has no concerns with the proposed new definitions, but we do have some non-substantive comments on their usage throughout PRC-029,
Implementation Plan and Technical Rationale. (See below)
•
Usage of the newly defined terms deviated from the defined term within PRC-029 and the Technical Rational. (i.e., Operating vs.
Operations)
•
Incorrectly stating in the Implementation Plan that there were no newly defined terms. Please correct this error.
Continuous Operating Region – Only used once in Requirement 2.3.
•
•
Continuous Operation Region used in Requirements 2.1, 2.1.2, 2.4, & once in Attachment 1 (i.e., suggest changing the defined term to
Continuous Operation Region or correct to Continuous Operating Region throughout)
Continuous Operation Region used twice in the Technical Rationale; Continuous Operating Region never used in the Technical
Rationale.
Mandatory Operating Region – Never used in PRC-029
•
•
Mandatory Operation Region used in PRC-029 in Requirements 2.2, 2.3, 2.4 & once in Attachment 1 (i.e., suggest changing the defined
term to Mandatory Operation Region or correct to Mandatory Operating Region throughout)
Mandatory Operation Region was used twice in Technical Rationale; Mandatory Operating Region was never used in the Technical
Rational.
Permissive Operating Region – Never used in PRC-029
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•
•
Likes
Permissive Operation Region used in PRC-029 in Requirements 2.3, 2.4, & used twice in Attachment 1 (i.e., suggest changing the defined
term to Permissive Operation Region or correct to Permissive Operating Region throughout)
Permissive Operation Region used once in the Technical Rationale; Permissive Operating Region never used in the Technical Rationale.
0
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0
Response
Thank you for your comments.
Applicability footnotes: The usage of footnotes in the applicability section is often used to provide clarity and is consistent with usage in PRC024-4.
VSC-HVDC: Modifications have been made to include these elements within PRC-029.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Operation Region: The team agrees and has removed the operation regions as defined terms.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions.
Joy Brake - Nova Scotia Power Inc. - NA - Not Applicable - NPCC
Answer
Document Name
Comment
If using ALL CAPS, consider RCF as the acronym. It is not that significant a metric to require capitalization of “of”.
RoCoF is also used in many other jurisdictions.
FERC order:
“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. “ Yes, but PRC-024 now prohibits this. In some cases, settings in the older plants can be tweaked to improve performance but we
are having trouble getting good models from the GOs. To address NERC concerns we need requirements for better models.
“some models and simulations incorrectly predict that some IBRs will ride through disturbances, i.e., maintain real power output at predisturbance levels and provide voltage and frequency support consistent with Reliability Standard PRC-024-3”. Only if incorrectly modelled.
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Require better modelling to identify issues and determine mitigations. PRC-029 will not stop the problem of simulating a system that works
great in the virtual world but will not perform when called upon.
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Response
Thank you for your comment.
The team has modified the term to RoCoF.
The team agrees the model improvements are needed. Modifications to model requirements will be covered by other projects addressing
Order 901.
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3 - WECC
Answer
Document Name
Comment
PNM agrees with EEI's comments.
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Response
Thank you for your comment. See response to EEI.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has the following additional comments for PRC-029-1:
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1. Texas RE recommends the new terms included in PRC-029-1 clearly state the voltage measurements included are at the high-side of the
main transformer connecting to the BPS transmission system. Texas RE suggests the following changes (in bold):
Term(s): Continuous Operating Region – The range of voltages, measured at the high‐side of the BPS main power transformer, that are ≥ 0.9
per unit and ≤ 1.1 per unit.
Mandatory Operating Region – The range of voltages, measured at the high‐side of the BPS main power transformer, that are > 0.1 per unit and
< 0.9 per unit – or – > 1.1 and ≤ 1.2 per unit.
Permissive Operating Region – The range of voltages, measured at the high‐side of the BPS main power transformer, that is ≤ 0.1 per unit.
2.
Consider changing ‘each IBR’ to ‘each IBR Facility’ for all the requirements.
3.
For consistency, consider modifying the title of the standard to (in bold):
Title: Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
4. Consider changing 4.2.1 to BES IBRs (instead of BPS IBRs) to be consistent with other PRC standards such as proposed reliability standards
PRC-028-1 and PRC-024-4.
5. Consider changing voltage (per unit) in Attachment 1 (third row) to greater than 1.05 pu only (i.e. remove the equal 1.05 criterion). Typical
BES and BPS systems are expected to operate continuously for voltage levels 0.95 – 1.05 pu.
Attachment 1 - changes
In Table 1 & Table 2 change > 1.05 to >1.05
Add the following to Table 1 and 2:
Voltage (per unit):
> 0.9 Minimum Ride-Through: Continuous
Voltage (per unit):
< 1.05
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Minimum Ride-Through: Continuous
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Thank you for your comment.
Operation Region: The team agrees and has removed the operation regions as defined terms and added clarity on the point of measurement.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation region. Additionally, values were
corrected.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Comment
•
GTC recommends increasing the implementation timeline to be 12 to 18 months after the effective date of the applicable
governmental authority’s order approving for both the PRC-024-4 and PRC-029-1 standards.
•
There were no balloting questions provided for the language changes in the PRC-024-4 standard. GTC recommends providing balloting
questions for the industry to respond to the changes in the PRC-024-4 standard.
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Response
Thank you for your comment.
Implementation Plan: The Implementation Plan has been revised to follow the effective date of PRC-028. All revisions to Reliability Standards
directed by Order 901 must be fully implemented by 2030.
Question 4 was provided to allow for any other responses to the proposed changes.
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name
Comment
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NERC should remain consistent with their revised Rules of Procedure by avoiding the use of “BPS IBR” terminology in the applicable facilities.
This is overly broad and can lead to misinterpretation for Generator Owners who own IBRs that do and do not fit the 60 kV and 20 MVA
thresholds. The third question in the Project 2020-06 comment form, copied below, is a clearer definition of IBR which NERC has determined
has a material impact to the BPS. NERC should consider adopting this terminology in PRC-029
Section 4. Applicability:
4.1 Functional Entities: Generator Owner, Generator Operator
4.2 Facilities: (1) BES Inverter-Based Resources; and (2) Non-BES Inverter Based Resources (IBRs) that that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
Likes
0
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0
Response
Thank you for your comment.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and North American Generator Forum
(NAGF) on question 4
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Response
Thank you for your comment. See response to EEI and NAGF.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Dominion Energy supports EEI comments. In addition, we have the following coments:
The term BPS IBRs and IBR Registration Criteria are not clear-cut Facilities. The standard should reference terms available for use in the NERC
Glossary of Terms to determine applicability, such as the BES defintion. As stated in the EEI comments, the BES defintion would be the
appropriate place to address defintions of this type.
The Effective Date of 6 months following approval by FERC is too short for Generator Owners and Transmission Owners that own numerous IBR
generating sites, to develop internal controls and processes; and perform the necessary compliance evaluations and possible settings changes
to meet the ride-through criteria. Conversely, 6 months after the effective date is too long for documenting Limitations per Requirement R6.
The documentation of limitations is typically done during the compliance analysis and study. A staggered implementation plan, that takes into
account the registration and requirements for Level 2 GO registrations should be designed and implemented.
The Implementation Plan should also consider those IBRs that are approved to be built and have had their Interconnection Studies approved.
The contracts for building these sites are signed years in advance with the inverters ordered. A staggered applicability for R6 should be
considered that allow for projects in service prior to 2027 or 2028 to be eligible for equipment limitations and those in service after to meet the
performance criteria without limitations.
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Response
Thank you for your comment. See response to EEI.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
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Implementation Plan: The Implementation Plan has been revised to follow the effective date of PRC-028. All revisions to Reliability Standards
directed by Order 901 must be fully implemented by 2030.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901. New IBR
(those in-service after the effective date of PRC-029) cannot apply for exemption per the Order.
George E Brown - Pattern Operators LP - 5
Answer
Document Name
Comment
Pattern Energy supports GRE’s comments for this question.
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Thank you for your comment. See response to GRE.
Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer
Document Name
Comment
The SDT explains in the draft PRC-029-1 Technical Rationale that “An IBR becomes noncompliant with PRC‐029 only when an event in the field
occurs that shows that one or more requirements were not satisfied.” This, coupled with the removal of IBRs from PRC-024 applicability, would
result in a lack of accountability until actual harm (i.e., failure to adequately support the reliability of the BES during a system event) occurs for
IBRs not prepared to meet the performance requirements. There would not be auditable and enforceable requirements for owners of IBRs to
proactively take action to reasonably ensure the performance requirements will be met. Reliability standards exist to prevent potential harm,
which minimizes actual harm.
While RF acknowledges the observed limitations of the existing PRC-024 standard in preventing the undesirable responses of IBRs to the system
disturbance events cited in the SAR, RF does not support the whole-sale elimination of frequency and voltage protection settings verification
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requirements for IBRs. Generator frequency protection settings verification is critical in ensuring UFLS programs are adequately coordinated
with generator capabilities, and RF does not wish to rely on self-revealing events to determine where miscoordination exists between IBR
frequency protection and UFLS. Unless additional verification requirements are added to PRC-029, RF believes PRC-024 should remain
applicable to IBRs.
RF notes that the range of system conditions in which PRC-029 would require IBRs to remain online appear to be significantly larger than those
established in PRC-024 (which would remain applicable to synchronous generators). Although the unique capabilities of IBRs may support such
a large expansion for only IBR resource types, additional discussion of the technical justification for this expansion would be useful.
Regarding implementation, RF finds a 12-month implementation period acceptable.
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Response
Thank you for your comments.
Capability and Performance Measures: The team agrees that the ability to validate the capability of each applicable IBR was not clear from the
initial draft. Changes have been made to ensure the design/capability of each IBR can be validated prior to an event – in addition to retaining
the event and performance-based requirements.
Please refer to the TR for clarity regarding IBR performance measures.
Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
The implementation plan is also very aggressive and for some generators may be impossible to meet.
Kimberly Turco on behalf of Constellation Segments 5 and 6
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Thank you for your comment.
Implementation Plan: The Implementation Plan has been revised to follow the effective date of PRC-028. All revisions to Reliability Standards
directed by Order 901 must be fully implemented by 2030
Ruchi Shah - AES - AES Corporation - 5
Answer
Document Name
Comment
•
The new performance-based approach opens us up to a lot of issues with other tripping/cessation besides basic overvoltage/under
voltage/frequency that our operations team has seen during events.
o
This protection is not modeled in basic models right now and will require substantial effort to ensure we can perform as
required. AES CE requests that the Implementation Plan be modified to use a phased-in approach for existing sites to allow
adequate time to prepare for these performance requirements.
Additionally, the standard and rationale is absent of language on studies/assessments that should be performed. AESCE believes
that providing examples of the types of studies and assessments that should be run to ensure that resources would perform as
expected is necessary for reliability and adequate implementation of this standard by GOs.
•
•
•
•
Please provide additional clarification on acceptable limitations under R6. Language such as “hardware replacements or other costly
upgrades” from the Technical rationale document is vague and open to interpretation.
AESCE would like the SDT to consider the challenges with ensuring plants, particularly legacy operational plants, can ride through per
the requirements. To ensure this or identify equipment limitations, studies and equipment information is necessary and is not available
for most legacy equipment.
First, EMT studies and RMS model studies are necessary to study plant ride-through capabilities specified in the standard. However,
there are significant challenges with these models today that should be considered in the implementation and equipment limitations.
Quality EMT models including all equipment information needed are not available for legacy equipment (inverters, PPCs). Many legacy
inverters do not have an EMT model, and those that do have models that are not adequately validated against equipment performance.
Creation of models is either not supported or can be developed at a very high cost. Models created after the inverters were initially
released are of inadequate quality because the equipment is no longer able to be in a lab environment.
o To consider this, AESCE suggests that the SDT include exceptions for legacy equipment where the performance may not be
predictable due to a lack of modeling or inverter information.
Second, not all current models are of the level of quality that they can be used to ensure that the plant will ride-through as specified in
the standard. The implementation of this standard should consider the significant resources and cost to implement.
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•
Third, manufacturer support for GOs to ensure that IBRs only trip to prevent equipment damage as noted in R2.5 is limited for existing
equipment and is unavailable for some legacy equipment. Additionally, this support has been very costly for us to obtain and will strain
manufacturer resources to provide.
Considering these limitations, AESCE suggests that the SDT include exceptions for legacy equipment where 1. The performance may not be
predictable due to a lack of accurate models at a reasonable cost, 2. Equipment limits may not be known or where the cost may be egregious to
provide.
•
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Expectations for demonstrating and checking performance are unclear, please add language or examples to illustrate how the SDT
believes this will happen.
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Response
Thank you for your comment.
Implementation Plan: The Implementation Plan has been revised to follow the effective date of PRC-028. All revisions to Reliability Standards
directed by Order 901 must be fully implemented by 2030.
Models: The team agrees the model improvements are needed however those will not be addressed within PRC-029. Modifications to model
requirements will be covered by other projects addressing Order 901.
Regarding Exemptions: The team has modified Requirement R4 (previous R6) to include clarity on allowable exemptions and requires
identification of such limitations to be documented and submitted.
Scope: The team acknowledges challenges with some plants meeting Ride-through requirements per PRC-029. The scope of these performance
requirements and allowable exemptions is consistent with the regulatory directives of Order No. 901 and cannot be modified as suggested.
Rhonda Jones - Invenergy LLC - 5
Answer
Document Name
Comment
Invenergy thanks the drafting team for their work and the opportunity to provide comments.
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Regarding the proposed Implementation Plan for R6, six months may not be enough time to gather all applicable documentation regarding
equipment limitations. There are a limited number of vendors of IBR technology that have serviced the industry, and they will be inundated
with requests for documentation once the standard becomes effective.
On a final note, NERC appears to have borrowed from some of the requirements within IEEE 2800-2022 and brought them into this standard
(e.g. the phase-angle jump requirement, etc.). Invenergy believes it would be incorrect to adopt such requirements until the work of IEEE
Working Group p2800.2 has been completed and their recommended practice standard published. Without such an approved recommended
practice standard, there is no industry-wide accepted set of procedures for verifying conformity to the borrowed requirements in PRC-029-1.
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Response
Thank you for your comment.
The Implementation Plan has been modified to 12 months following the effective date of PRC-028.
Requirements within the NERC PRC-029 address the scope of the SAR and draw from IEEE2800 but are mandatory and enforceable
requirements.
David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
Document Name
Comment
Ameren agrees with EEI's comments.
In addition, Ameren believes that ride-through requirements should be in a MOD standard instead of a PRC standard. Protection relay
engineers do not have access to the necessary IBR equipment and do not have the expertise to determine the root cause of why an IBR
behaved in an unexpected manner. Thus, evaluating and establishing a CAP to correct a reduction in power following a disturbance will not be
performed by a relay engineer.
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Thank you for your comment. See response to EEI.
Capability and Performance Measures: . The team agrees that the ability to validate the capability of each applicable IBR was not clear from
the initial draft. Changes have been made to ensure the design/capability of each IBR can be validated prior to an event – in addition to
retaining the event and performance-based requirements.
Colin Chilcoat - Invenergy LLC - 6
Answer
Document Name
Comment
Invenergy thanks the drafting team for their work and the opportunity to provide comments.
Regarding the proposed Implementation Plan for R6, six months may not be enough time to gather all applicable documentation regarding
equipment limitations. There are a limited number of vendors of IBR technology that have serviced the industry, and they will be inundated
with requests for documentation once the standard becomes effective.
On a final note, NERC appears to have borrowed from some of the requirements within IEEE 2800-2022 and brought them into this standard
(e.g. the phase-angle jump requirement, etc.). Invenergy believes it would be incorrect to adopt such requirements until the work of IEEE
Working Group p2800.2 has been completed and their recommended practice standard published. Without such an approved recommended
practice standard, there is no industry-wide accepted set of procedures for verifying conformity to the borrowed requirements in PRC-029-1.
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Response
Thank you for your comment.
The Implementation Plan has been modified to 12 months following the effective date of PRC-028.
Requirements within the NERC PRC-029 address the scope of the SAR and draw from IEEE2800 but are mandatory and enforceable
requirements.
Brittany Millard - Lincoln Electric System - 5
Answer
Document Name
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Comment
With regards to PRC-029 we woulkd ask:
1. Clarify and emphasize that limitations must not be construed as complete exemptions. If entities are unable to ride-through portions of
the ride-through curve, this does not automatically exempt them from complying with the balance of the ride-through curve as described in the
Technical Rationale. While this is clear in the Technical Rationale for Requirement R6 (page 9), this point needs to be brought out more clearly
in the PRC-029 standard itself.
2. Expand PRC-029 to require Corrective Action Plans be implemented to remove equipment limitations within a specified timeline.
3.
we recommend modifying Section 4 of PRC-029-1 as follows:
4. Applicability:
4.1 Functional Entities: 4.1.1 Generator Owner that owns equipment identified in section 4.2, 4.1.2 Transmission Owner that owns equipment
as identified in section 4.2 Generator Owner that owns equipment identified in section 4.2.
4.2 Facilities: to include 4.2.3 Shunt static or dynamic reactive device(s) associated with IBR that either have or contribute to meeting the
performance requirements.
4. The standard is event-based compliance that requires installing recorded equipment data with higher sampling rates at all applicable
legacy IBR Facilities. Therefore, we suggest that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC-028-1) for
the legacy IBR. Also, we suggest having a different implementation plan for the legacy IBR from IBR connected after the approval date of
PRC-029.
5. Some clarity on how these requirements would be enforced in the location where no data recording is available at the IBR
facility during system events.
6. M1-M5 required GO to maintain the evidence of actual recorded data or other evidence for each applicable IBR demonstrating
adherence to ride‐through requirements, as specified in Requirement R1-R5. What are the criteria for selecting the event(s) that should be
analyzed to demonstrate compliance with the VRT, FRT, and VRT performance requirement(s)? If the performance does not meet the
requirement(s), do Generator Owner needs to present a correction action plan and provide it to each applicable Reliability Coordinator. We
suggest coordinate this project 2020-02 (PRC-029) with project 2023-02(PRC-030) regarding the IBR ride‐through performance analysis.
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7.
We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggested the following language be included in the applicability section. Facilities: The
Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
8. The title of the standard calls out “Inverter-Based Generating Resources”, should “Generating” be removed to be consistent?
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Response
Thank you for your comment.
Exemption: The team agrees that only specific ride-through limitations would be applied and there is no global exemption intended. Language
has modified within the Requirement R4 (previous R6) as well as the Technical Rationale to clarify this.
CAPs: The scope for some documented exemptions is consistent with the Order.
Applicability: Language within the applicability section has been modified per other suggestions.
Implementation Plan: The Implementation Plan has been modified to 12 months following the effective date of PRC-028.
PRC-029 compliance: The team agrees that the ability to validate the capability of each applicable IBR was not clear from the initial draft.
Changes have been made to ensure the design/capability of each IBR can be validated prior to an event – in addition to retaining the event and
performance-based requirements. PRC-028 compliance will be established within PRC-028 and the associated Implementation Plan.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Title: The title has been modified as suggested.
Ben Hammer - Western Area Power Administration - 1
Answer
Document Name
Comment
Several enhansments to PRC-029 are requested:
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1. Clarify and emphasize that limitations must not be construed as complete exemptions. If entities are unable to ride-through portions
of the ride-through curve, this does not automatically exempt them from complying with the balance of the ride-through curve as
described in the Technical Rationale. While this is clear in the Technical Rationale for Requirement R6 (page 9), this point needs to be
brought out more clearly in the PRC-029 standard itself.
2. Expand PRC-029 to require Corrective Action Plans be implemented to remove equipment limitations within a specified timeline.
3. we recommend modifying Section 4 of PRC-029-1 as follows:
4. Applicability:
4.1 Functional Entities: 4.1.1 Generator Owner that owns equipment identified in section 4.2, 4.1.2 Transmission Owner that owns
equipment as identified in section 4.2 Generator Owner that owns equipment identified in section 4.2.
4.2 Facilities: to include 4.2.3 Shunt static or dynamic reactive device(s) associated with IBR that either have or contribute to meeting the
performance requirements.
4. The standard is event-based compliance that requires installing recorded equipment data with higher sampling rates at all applicable
legacy IBR Facilities. Therefore, we suggest that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC028-1) for the legacy IBR. Also, we suggest having a different implementation plan for the legacy IBR from IBR connected after the
approval date of PRC-029.
5. Some clarity on how these requirements would be enforced in the location where no data recording is available at the IBR
facility during system events.
6. M1-M5 required GO to maintain the evidence of actual recorded data or other evidence for each applicable IBR demonstrating
adherence to ride‐through requirements, as specified in Requirement R1-R5. What are the criteria for selecting the event(s) that
should be analyzed to demonstrate compliance with the VRT, FRT, and VRT performance requirement(s)? If the performance does
not meet the requirement(s), do Generator Owner needs to present a correction action plan and provide it to each applicable
Reliability Coordinator. We suggest coordinate this project 2020-02 (PRC-029) with project 2023-02(PRC-030) regarding the IBR ride‐
through performance analysis.
7. We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects
such as Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggested the following language be included in the applicability
section. Facilities: The Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that
either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system
designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
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Response
Thank you for your comment.
Exemption: The team agrees that only specific ride-through limitations would be applied and there is no global exemption intended. Language
has modified within the Requirement R4 (previous R6) as well as the Technical Rationale to clarify this.
CAPs: The scope for some documented exemptions is consistent with the Order.
Applicability: Language within the applicability section has been modified per other suggestions.
Implementation Plan: The Implementation Plan has been modified to 12 months following the effective date of PRC-028.
PRC-029 compliance: The team agrees that the ability to validate the capability of each applicable IBR was not clear from the initial draft.
Changes have been made to ensure the design/capability of each IBR can be validated prior to an event – in addition to retaining the event and
performance-based requirements. PRC-028 compliance will be established within PRC-028 and the associated Implementation Plan.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
New terms are introduced on page 2 (Continuous Operating Region, Mandatory Operating Region, Permissive Operating
Region). Requirement R1 includes the words “operation regions” and R2 includes the terms “Continuous Operation Region” (Part 2.1) and
“Mandatory Operation Region” (Part 2.2). We recommend the drafting team review all instances of “operation region” within the standard
and determine if it should be changed to “operating region” to align with the proposed terms. Or conversely, consider if the word “Operating”
within the defined terms should be changed to “Operation”.
For Requirement R2:
How will the Generator Owner or Transmission Owner of an applicable IBR be made aware that a PRC-029-1 applicable “System disturbance”
has occurred within their associated Planning Coordinator(s) area(s)?
Part 2.1.2 refers to “requirements [for active or reactive power preference] specified by the Transmission Planner, Planning Coordinator,
Reliability Coordinator, or Transmission Operator”.
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Part 2.2.2 refers to a “certain magnitude of reactive power response to voltage changes” or a preference for “active power priority instead of
reactive power priority” that can be specified by the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission
Operator.
Part 2.4 refers to a “lower post‐disturbance active power level requirement” or “different post‐disturbance active power restoration time”
specified by the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
With up to four registered entity types being able to provide these preferences (spanning the operations and planning time horizons), is there a
chance the Generator Owner or Transmission Owner of an applicable IBR will receive conflicting requirements? Is there a corresponding
standard(s) that includes a requirement(s) for the TP, PC, RC or TOP to specify these preferences?
For Requirement R3, how will the Generator Owner or Transmission Owner of an applicable IBR know that a PRC-029-1 applicable transient
overvoltage period has occurred within their associated Planning Coordinator(s) area(s)?
For Requirement R4, how will the Generator Owner or Transmission Owner of an applicable IBR know that a PRC-029-1 applicable frequency
excursion event has occurred within their associated Planning Coordinator(s) area(s)?
Requirement R6 requires that a Generator Owner or Transmission Owner of an applicable IBR that has a documented equipment limitation,
that prevents it from meeting voltage ride‐through requirements as detailed in Requirements R1 and R2, communicate each equipment
limitation to their associated Planning Coordinator(s), Transmission Planner(s), and Reliability Coordinator(s). Since the Transmission Operator
is also identified in R2, it seems strange to omit the TOP from R6.
With regard to the Implementation Plan, having PRC-024-4 becoming effective six months after approval is reasonable, since this Standard’s
changes are primarily to limit its applicability to synchronous generators / condensers, and they should already be compliant with the existing
version.
However, having PRC-029-1 become effective six months after approval is not reasonable. The technical rationale doesn't provide guidance on
how to provide evidence of compliance. It can take considerable time to develop and perform the required analyses, generate potential design
changes to make the required setting changes, and implement them.
We recommend providing implementation guidance or technical data showing how to demonstrate performance.
We also recommend allowing at least 24 months to achieve full compliance with the proposed requirements in PRC-029-1.
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Response
Thank you for your comments.
Operation Region: The team agrees and has removed the operation regions as defined terms.
Measures (events): The evidence of compliance for disturbance monitoring that are associated with voltage and frequency excursions that
were System disturbances and would be identified for analysis or another trigger by an applicable entity within draft PRC-030. Evidence of
disturbance monitoring of IBR associated with those disturbances would be triggered by compliance under the requirements for PRC-030.
R2 General operation expectations: Requirement 2.2. was clarified to allow for operating instructions from the TOP/PC/RC/TP to be followed
but only if specified. Further usage of AVR was removed from the requirement.
Previous Requirement R3: This requirement and attachment 2 have been removed.
TOP: This was an error. The TOP has been added to Requirement R4 (previous r6).
Implementation Plan: The Implementation Plan has been modified to 12 months following the effective date of PRC-028. All revisions to
Reliability Standards directed by Order 901 must be fully implemented by 2030.
Capability and Performance Measures: The team agrees that the ability to validate the capability of each applicable IBR was not clear from the
initial draft. Changes have been made to ensure the design/capability of each IBR can be validated prior to an event – in addition to retaining
the event and performance-based requirements.
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name
Comment
Black Hills Corporation supports EEI’s and NAGF’s additional comments.
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Response
Thank you for your comment. See response to EEI and NAGF.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
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Document Name
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Comment
FirstEnergy finds inconsistency in how these newly created standards are applying IBR applicability in the Applicable Section – leading to
confusion from one project and standard to another. We request these Drafting Teams align these Applicable Sections.
FE cannot support the Implementation Plan until it is clear how R2 will be clarified toward requirement responsibility.
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Response
Thank you for your comment.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
R2 General operation expectations: Requirement 2.2. was clarified to allow for operating instructions from the TOP/PC/RC/TP to be followed
but only if specified. Further usage of AVR was removed from the requirement.
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by the NAGF
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Thank you for your comment. See response to NAGF.
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District,
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3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Tim Kelley, Group Name SMUD and BANC
Answer
Document Name
Comment
The language proposed in the Applicability section of PRC-029-1 is inadequate to define what IBR Facilities this Standard would apply to. The
terms “BPS IBRs” and “IBR Registration Criteria” are too broad, vague, and undefined, and could include all IBRs interconnected to the Bulk
Power System at any voltage level.
SMUD recommends the Standards Drafting Team use similar language to that proposed in NERC Standards Project 2021-04 Modifications to
PRC-002 - Phase II, PRC-028-1 draft #2. If modified accordingly, the Applicability section would state:
“4.1. Functional Entities:
4.1.1. Generator Owner that owns equipment as identified in section 4.2
4.1.2. Transmission Owner that owns equipment as identified in section 4.2
4.2. Facilities: The Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or
contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.”
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Response
Thank you for your comment.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Brian Lindsey - Entergy - 1
Answer
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Document Name
Comment
No Comment
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Thank you.
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
NA
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Thank you.
Michael Brytowski - Great River Energy - 3
Answer
Document Name
Comment
1. Clarify and emphasize that limitations must not be construed as complete exemptions. If entities are unable to ride-through portions of
the ride-through curve, this does not automatically exempt them from complying with the balance of the ride-through curve as described in the
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Technical Rationale. While this is clear in the Technical Rationale for Requirement R6 (page 9), this point needs to be brought out more clearly
in the PRC-029 standard itself.
2. Expand PRC-029 to require Corrective Action Plans be implemented to remove equipment limitations within a specified timeline.
3.. we recommend modifying Section 4 of PRC-029-1 as follows:
4. Applicability:
4.1 Functional Entities: 4.1.1 Generator Owner that owns equipment identified in section 4.2, 4.1.2 Transmission Owner that owns equipment
as identified in section 4.2 Generator Owner that owns equipment identified in section 4.2.
4.2 Facilities: to include 4.2.3 Shunt static or dynamic reactive device(s) associated with IBR that either have or contribute to meeting the
performance requirements.
4. The standard is event-based compliance that requires installing recorded equipment data with higher sampling rates at all applicable
legacy IBR Facilities. Therefore, we suggest that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC-028-1) for
the legacy IBR. Also, we suggest having a different implementation plan for the legacy IBR from IBR connected after the approval date of
PRC-029.
5. Some clarity on how these requirements would be enforced in the location where no data recording is available at the IBR facility during
system events.
6. M1-M5 required GO to maintain the evidence of actual recorded data or other evidence for each applicable IBR demonstrating
adherence to ride‐through requirements, as specified in Requirement R1-R5. What are the criteria for selecting the event(s) that should be
analyzed to demonstrate compliance with the VRT, FRT, and VRT performance requirement(s)? If the performance does not meet the
requirement(s), do Generator Owner needs to present a correction action plan and provide it to each applicable Reliability Coordinator. We
suggest coordinate this project 2020-02 (PRC-029) with project 2023-02(PRC-030) regarding the IBR ride‐through performance analysis.
7. We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggested the following language be included in the applicability section. Facilities: The
Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
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Dislikes
0
Response
Thank you for your comment.
Exemption: The team agrees that only specific ride-through limitations would be applied and there is no global exemption intended. Language
has modified within the Requirement R4 (previous R6) as well as the Technical Rationale to clarify this.
CAPs: The scope for some documented exemptions is consistent with the Order.
Applicability: Language within the applicability section has been modified per other suggestions.
Implementation Plan: The Implementation Plan has been modified to 12 months following the effective date of PRC-028.
PRC-029 compliance: The team agrees that the ability to validate the capability of each applicable IBR was not clear from the initial draft.
Changes have been made to ensure the design/capability of each IBR can be validated prior to an event – in addition to retaining the event and
performance-based requirements. PRC-028 compliance will be established within PRC-028 and the associated Implementation Plan.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer
Document Name
Comment
BC Hydro appreciates the drafting team’s efforts and the opportunity to comment, and offers the following:
1. The Applicability section (A.4.2 Facilities) of PRC-029-1 references BPS IBR and IBR Registration Criteria. BC Hydro suggests that the
Facilities section instead use wording reflective of the proposed Category 2 GO as included in the recent revisions to the NERC Rules of
Procedure.
2. BC Hydro suggests that the use of “shall” in the language of the Measures may not be appropriate as it could imply a new Requirement
or expansion on the existing Requirement. The obligation of having evidence is adequately established and enforceable via the CMEP.
3. The Measure M3 of PRC-029-1 references "the associated Planning Coordinator". The associated Requirement R3 does not. BC Hydro
suggests that this is not needed as there may be switching events within a PC's area that do not create overvoltage conditions to trigger
R3 for certain IBRs within the PC area.
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Response
Thank you for your comment.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Measures: The team agrees and has removed the word “shall” from the Measures.
Previous M3: The previous requirement R3 has been removed.
Helen Lainis - Independent Electricity System Operator - 2
Answer
Document Name
Comment
Applicability:
In Introduction, Section 4.2.2, it is not obvious what aspect of ‘IBR Registration Criteria’ makes an IBR an ‘applicable’ IBR – is it simply that an
IBR meets NERC Registration Criteria? This bullet point should be elaborated to ensure clarity.
Event-Based Standard:
The IESO has concerns with this standard being an event-based standard, in that it does not necessarily provide an assurance of reliability
before events occur, such as would be provided by having an engineering analysis, or bench-testing/real-time simulations of controls
equipment that indicates successful ride through of prescribed disturbances is expected.
Without disturbance events that challenge the IBRs to perform properly it would be unknown if the IBR is compliant. At a minimum, the
measures (e.g, M2-M5) should be extended to allow a statement that no such events are known to have occurred to ‘count’ as evidence of
compliance.
Presentation of Ride Through Ranges:
The intended ride through requirements could be made more clear if the ‘minimum ride through times’ were associated with precisely stated,
non-overlapping ranges of voltages or frequencies, such as in the example ‘Table 2’ provided by the IESO in the comments above, for Section
2.1.
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Nominal Voltages:
To ensure clarity of intent in note #4 of Attachment 1, the 'nominal' system voltage values should be listed as they are in the existing PRC-024,
i.e., “(e.g., 100 kV, 115 kV, 138 kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.)”
Harmonize Tables, Figures, Requirements:
The levels of voltage/frequency excursion and the minimum ride through times for all tables, figures, and any associated performance
requirements that modify the requirements at given times should be carefully reviewed and harmonized. There are presently some conflicting
entries in the tables/figures.
Likes
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Dislikes
Ontario Power Generation Inc., 5, Chitescu Constantin
0
Response
Thank you for your comment.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Capability and Performance Measures: The team agrees that the ability to validate the capability of each applicable IBR was not clear from the
initial draft. Changes have been made to ensure the design/capability of each IBR can be validated prior to an event – in addition to retaining
the event and performance-based requirements.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions and the values in the tables. This
should address issues with identifying more than one row.
Attachment 1 clarification on 500kv: Attachment 1 sets the minimum expectation for operation regardless of voltage class. Expanding the no
trip zone for 500kV may still be done based on the system need.
Chantal Mazza - Hydro-Quebec (HQ) - 1 - NPCC
Answer
Document Name
Comment
We are concerned that the standard refers to a defined term for IBR which has yet to be adopted in project 2020-06.
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We suggest that the drafting team ensure consistent language is used in the section 4.2 “Facilities” section with the other projects such as
2021-04 (PRC-028) and 2023-02(PRC-030). Section 4.2.2 refers to IBR Registration criteria, however it is our understanding that section 4.2.1
would refer to GOs and TOs “that own equipment as identified in section 4.2” and where section 4.2 would indicate “the Elements associated
with (1) BES Inverter‐Based Resources; and (2) Non‐BES Inverter‐Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of
connection at a voltage greater than or equal to 60 kV.” .
We question why “attachment 1” and “Requirement R6” are written in bold.
Attachment 1: should the “including, but not limited to” in table 2 include the same list (or minimally the same wording) that is found in the
technical rationale of the IBR definition in project 2020-0?. For example, the IBR list in 2020-06 refers to “solar photovoltaic” whereas table 2
refers to “photovoltaic (PV)”.
In what standard does the PC/TP define the applicable table in point 3 of section 2 in attachment 1? Same question for the voltage base for per
unit calculation in both Attachment 1 and 2. Is there a corresponding requirement in another standard that requires the PC/TP to do this?
·
Terms : Mandatory and permissive operation should be defined based on the attachment figures allowing for interconnections to use
different requirements
·
A-4.2.2 What is the IBR registration criteria? Add a clear reference and make sur the user understands what the IBR registration criteria is.
·
B-R2-2.1 Attachment 1 only uses "no-trip zone". Define continuous operating region more clearly in the table (similar to what is done in
PRC-024-4)
·
B-R2-2.1.2 Can the TP ask for a mix of active/reactive power based on a predetermined ratio (currently only indicated as active or
reactive).
·
B-R2-2.2 Attachment 1 only uses "no-trip zone". Define "mandatory operation region" in Attachment 1.
·
B-R2-2.4 Permissive operation region is not used or defined in attachment 1.
·
B-R3. The document refers to an overvoltage value of 1.2pu. It should refer to a voltage exceeding the mandatory operating region in
order for Interconnections to set their own overvoltage table.
·
B-R3. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through these overvoltages ? An
exemption clause is required for existing IBR that cannot be modified or upgraded.
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·
B-R4. The 5Hz/s value should be moved to Attachment 3 and B-R4 should only refer to the value in the Attachment.
·
B-R4. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through these frequencies and
ROCOF ? (for instance, for all the HQ connected projects, the ROCOF requirement was 4Hz/s) An exemption clause is required for existing IBR
that cannot be modified or upgraded.
·
B-R5. Since R6 does not apply to this requirement, what will be done with existing IBR that cannot ride through this phase angle jump ? An
exemption clause is required for existing IBR that cannot be modified or upgraded.
·
Attachment 1. Tables 1 and 2: Indicate what is considered as “continuous operation”, “mandatory operation” and “permissive operation”
in an additional column.
·
Attachment 1. HQ needs a Quebec regional variance since the Québec Interconnection has its own requirements in this regard.
·
Attachment 2. Bullet 3: This sentence is hard to read. Proposed replacement: "Each IBR shall not trip unless the cumulative time of one or
more instances in which the instantaneous voltage exceeds the respective voltage threshold over a 1-minute time window exceeds the
minimum ride-through time"
·
Attachment 2. HQ needs a Quebec regional variance since the Québec Interconnection has its own requirements in this regard.
·
Attachment 3. This attachment should also include the maximum absolute ROCOF value.
·
Attachment 3. HQ needs a Quebec regional variance
·
B-R2-2.1.2 Which entity between Transmission Planner, Planning Coordinator, Reliability Coordinator and Transmission Operator has
priority to specify those requirements?
·
B-R2-2.4 Which entity between Transmission Planner, Planning Coordinator, Reliability Coordinator and Transmission Operator has
priority to specify those requirements?
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Ontario Power Generation Inc., 5, Chitescu Constantin
0
Response
Thank you for your comment.
IBR: The team has removed the currently undefined term IBR and will include the term once it has been approved.
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Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Attachment 1: Tables and Figures in Attachment 1 have been revised to add clarity on the operation regions. The range of values in row #4 of
Tables 1 and 2 to clarify the continuous operation region. Changes were made to align terms used throughout.
R2.1.2 (previous R2.1.1) and R2.1.3 (previous 2.1.2): Language was clarified in R2.1.2 and R2.1.3 to address apparent vs reactive power limits
per above and other comments. R2.1.3 has been clarified that the GO/TO shall follow provided TP/PC/RC/TOP requirements if those are
provided. Requirement R2 subparts require the GO/TO to follow provided TP/PC/RC/TOP restoration time or active power recovery threshold
requirements – if different than default values in the sub-requirement. R2 does not intend that values other than the default values must be
specified, only that performance for the plant/facility will be evaluated in accordance with those values if provided. Language has been added
to M2 to clarify what evidence is expected if the TP/PC/RC/TOP provide other performance requirements.
Previous Requirement R3: This requirement has been removed.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901.
Frequency cannot apply for exemption. New IBR cannot apply for exemption. This is consistent with the ordered directives.
Previous Requirement R5: This requirement has been removed and the non-fault exclusionary language has been added to R1. A requirement
to notify the Generator Owner or Transmisson Owner and to evaluate performance when the plant/facility tripped because of a switching
event is in the current draft PRC-030.
Quebec variant: The team will coordinate with Hydro Quebec to include their variant as identified by Hydro Quebec.
Priority: This issue is out of scope for the team. The language in the requirement is to make allowance for established operational instructions
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name
Comment
- Evidence Retention: We would suggest that the evidence retention period for both Standards should be changed from five years to three
years, to be consistent with other NERC Standards.
- The standard is event-based compliance that required installing recorded equipment data with higher sampling rates at all applicable legacy
IBR Facilities. Therefore, we recommend that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC-028-1) for the
legacy IBR. Also, we suggest have different implementation plan for the legacy IBR from IBR connected after the approval date of PRC-029.
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- Some clarity how these requirements would be enforced in a location where no data recording is available at an IBR facility during system
events.
- M1-M5 required the GO to maintain the evidence of actual recorded data or other evidence for each applicable IBR demonstrating adherence
to ride‐through requirements, as specified in Requirement R1-R5. What are the criteria for selecting the event(s) that should be analyzed to
demonstrate compliance with the VRT, FRT and VRT performance requirement(s)? If the performance does not meet the requirement(s), do
Generator Owner need to present a corrective action plan and provide it to each applicable Reliability Coordinator. We suggest coordinating
this project 2020-02 (PRC-029) with project 2023-02(PRC-030) regarding the IBR ride‐through performance analysis.
- R2: We agree with the present flexibility that some of the IBR VRT performance could be modified to meet the individual system needs by the
applicable Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator. However, some clarity may be
required on how this process is initiated and what type of evidence is required to demonstrate the request is received and implemented. This
may be an additional requirement assigned to the Transmission Planner. Each Transmission Planner, Planning Coordinator, and Transmission
Operator that jointly specifies the following voltage ride-through performance requirements within their area(s) different than those specified
under R2, shall make those requirements available to each associated applicable IBR Generator Owner and Transmission Owner.
- We suggest that the drafting team ensures consistent language is used in the section 4.2 “Facilities” section with the other projects such as
Project 2021-04 (PRC-028) and 2023-02(PRC-030). We suggest the following language be included in the applicability section. Facilities: The
Elements associated with (1) BES Inverter-Based Resources; and (2) Non-BES Inverter-Based Resources that either have or contribute to an
aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity
to a common point of connection at a voltage greater than or equal to 60 kV.
- R3: we suggest adding to the attachment 2 how the instantaneous transient overvoltage should be calculated (such as what is the pu based
on? and the minimum sampling rate?)
Likes
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Dislikes
0
Response
Thank you for your comment.
Retention: The compliance retention period was modified to align with PRC-030.
Implementation Plan: The Implementation Plan has been modified to 12 months following the effective date of PRC-028. All revisions to
Reliability Standards directed by Order 901 must be fully implemented by 2030.
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Capability and Performance Measures: . The team agrees that the ability to validate the capability of each applicable IBR was not clear from
the initial draft. Changes have been made to ensure the design/capability of each IBR can be validated prior to an event – in addition to
retaining the event and performance-based requirements.
Measures - data: The compliance measures for demonstration of performance were revised from “actual recorded data” to “actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data”.
R2.1.2 (previous R2.1.1) and R2.1.3 (previous 2.1.2): Language was clarified in R2.1.2 and R2.1.3 to address apparent vs reactive power limits
per above and other comments. R2.1.3 has been clarified that the GO/TO shall follow provided TP/PC/RC/TOP requirements if those are
provided. Requirement R2 subparts require the GO/TO to follow provided TP/PC/RC/TOP restoration time or active power recovery threshold
requirements – if different than default values in the sub-requirement. R2 does not intend that values other than the default values must be
specified, only that performance for the plant/facility will be evaluated in accordance with those values if provided. Language has been added
to M2 to clarify what evidence is expected if the TP/PC/RC/TOP provide other performance requirements.
Applicability: The applicability section has been modified to include more specific details on currently applicable facilities. The IBR that will be
included as part of registration changes (Category 2 assets) will be added following the approval of pending changes to the NERC Rules of
Procedure. These are currently excluded from this draft.
Previous Requirement R3: This requirement has been removed.
Leah Gully - Madison Fields Solar Project, LLC - 5 - RF
Answer
Document Name
Comment
1. The proposed Standard refers to four different operating regions (no-trip zone, Continuous Operation Region, Mandatory Operation
Region, and Permissive Operating Region). The different zones require Generator Owners to take different actions based on the number
of disturbances and deviations that occur within in a 10 second period as well as the positive sequence voltage on the high side of the
MPT. The ability of plant operators or inverter controls to identify, track, and respond effectively to all these variables is unrealistic.
Why are these requirements not applied to non-IBR owners?
2. In R1, GOs are required to ensure that IBRs continue to “exchange current in accordance with the no-trip zones and operation regions
as specified in Attachment 1.” The Standard does not define the term “exchange current”. Please define this term.
3. Measure 1 requires the Generator Owner and Transmission Owner to have actual recorded data for each applicable IBR demonstrating
ridethrough adherence. This measure needs a timeframe for retention of the data.
4. The second half of the sentence in 2.1.1 doesn’t appear to add any value to the sub-requirement. Please clarify what added operational
requirement is meant by, “…and continue to deliver active power and reactive power up to its apparent power limit.”
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5. Requirement R2.1.2 allows four different entities to dictate each IBR’s operating mode. This contradicts the requirements of VAR-001
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
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which states that GOs must operate in voltage control mode unless exempted by the TOP. Recommend selecting one of these entities
to determine the preference.
For overvoltage conditions greater than 140% Attachment 2 requires Generator Owners to distinguish and respond with different time
delays, all less than or equal to 3 ms. Recommend requiring IBRs to delay their response to voltage excursions and program their IBRs to
match the responses of synchronous machines.
Clarify Requirement 2.2.1 to address the expected operational response to close-in faults. Recommend the Standard specify separate
performance requirements for close-in faults and more distant faults.
Requirement 2.2 appears to mandate that IBRs who operate in active power priority mode in the continuous operating region would be
required to switch to the reactive power mode if a voltage disturbance occurs. What criteria are IBRs expected to use to determine
when this switch should occur? What are IBRs expected to do if their inverters cannot be switched without software modifications?
The ride through requirements should all be specified in the same units of time.
Couldn’t the voltage overshoot concerns addressed by Requirement 2.3 be addressed more reliably by slowing the response time of the
IBR plant controllers to match that of synchronous generation?
Measure 2 requires the GO and TO to have actual recorded data during each system disturbance. Recommend establishing a timeframe
for the retention of this data.
Measure 3 requires the GO and TO to have actual recorded data during each transient voltage event. Recommend establishing a
timeframe for the retention of this data.
Measure 4 requires the GO and TO to have actual recorded data during each frequency excursion event. Recommend establishing a
timeframe for the retention of this data.
Measure 5 requires the GO and TO to have actual recorded data during each positive sequence voltage phase angle changes that are
less than 25 electrical degrees at the high side of the main transformer. Recommend establishing a timeframe for the retention of this
data.
Requirement 6 has more specific requirements for an equipment limitation than is being proposed for the synchronous generators.
Recommend PRC-029 reflect the wording proposed for PRC-024-4.
PRC-029 frequency ride-through is a single graph for all regions. The graph no trip zone is larger than the existing PRC-024 frequency notrip zone for Eastern, Western, and ERCOT zones. The wording in the rationale is very soft (may be required). The change will cause the
LFRT and HFRT settings to be updated as well as collector and transformer frequency settings. Recommend the frequency settings
remain consistent with PRC-024 until the time that it is justified from grid events.
0
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Thank you for your comments.
Ride-through expectations: PRC-029 is not an equipment setting standard and sets minimum performance thresholds for determining Ridethrough. Both the SAR and the assigned Order 901 direct the team to include capability and performance-based requirements for ride-through.
The criteria does not cover any equipment failure during a disturbance.
Terminology “exchange current”: Also the team agrees for more clarity and has defined a new term for Ride-through and replaced language
the requirements with this new term. Attachments have also been updated to utilize this term as the “Must Ride-through Zone”. The operating
regions have been removed as defined terms as well.
Measures (events): The evidence of compliance for disturbance monitoring that are associated with voltage and frequency excursions that
were System disturbances and would be identified for analysis or another trigger by an applicable entity within draft PRC-030. Evidence of
disturbance monitoring of IBR associated with those disturbances would be triggered by compliance under the requirements for PRC-030.
R2 – use of reactive power: The team agrees that changes to clarify reaction power support in 2.1 was needed and made some adjustments to
specify reactive power. This was broken into 2.1.1 and 2.1.2.
R2.1.2 (previous R2.1.1) and R2.1.3 (previous 2.1.2): Language was clarified in R2.1.2 and R2.1.3 to address apparent vs reactive power limits
per above and other comments. R2.1.3 has been clarified that the GO/TO shall follow provided TP/PC/RC/TOP requirements if those are
provided. Requirement R2 subparts require the GO/TO to follow provided TP/PC/RC/TOP restoration time or active power recovery threshold
requirements – if different than default values in the sub-requirement. R2 does not intend that values other than the default values must be
specified, only that performance for the plant/facility will be evaluated in accordance with those values if provided. Language has been added
to M2 to clarify what evidence is expected if the TP/PC/RC/TOP provide other performance requirements.
Previous R3: Previous requirement R3 has been removed. Information on the TOV calculation has been added to Attachment 1.
R2- -dynamic switching: Requirement 2.1.3 (previously 2.1.2) does not require dynamic switching between these two modes of operation.
However, if that capability already exists, the operating mode would need to be specified by the TP, PC, RC, or TOP.
Previous R5: Previous Requirement R5 has been removed and added as an exemption to Requirement R1. There is no exemption to trip within
the no-trip zone for a fault. If there is a trip during non-fault initiated switching events, measurement data taken from the high-side of the MPT
would include this information. The measure for R1 has been modified to reflect this change.
Exemptions: The scope of allowable exemptions within R4 (previously R6) is consistent with the regulatory directives of Order No. 901.
Regional Variants: Additional regional variants; such as by Interconnection may be pursued as needed.
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
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In some cases, the initial 6-month implementation period to develop a technical rationale for an exemption may be too short. This is
attributable to the necessary input from the original OEM and in some cases due to the complexity associated with facilities comprised of new
and old equipment. One example where this may exist are plants where a repower project may have taken place that does not replace all
inverters. In a case such as this, the new equipment may meet the requirements, but the remaining existing equipment may not. This may
require a detailed study to verify compliance, or perhaps instead, require some form of hybrid exemption for the site. Unlike the stated
technical goal of the standard where this is a “performance based” standard, the justification for a technical exemption will require some form
of a study to justify that exemption. This could lead to a greater than 6-month period in developing the exemption request. To accommodate
these situations, AEP recommends an implementation period of 18 months.
PRC-029 requires that IBR’s shall ride through 110%-120% overvoltage from 0-1 seconds as seen at the high side of the main power step-up
transformer. Due to voltage drop, the voltage seen at the equipment terminals can be another 5% higher leading to potential equipment
damage from overvoltage. AEP suggests that the SDT consider lowering the ride through to 110% at the high side of the main step-up
transformer.
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0
Response
Thank you for your comment.
Regarding Exemptions: The team has modified Requirement R4 (previous R6) to include clarity on allowable exemptions and requires
identification of such limitations to be documented and submitted. The Implementation Plan has been modified to 12 months following the
effective date of PRC-028. All revisions to Reliability Standards directed by Order 901 must be fully implemented by 2030.
Previous R3: Previous requirement R3 has been removed. Information on the TOV calculation has been added to Attachment 1.
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
2020-02_EPRI Comments on Draft NERC PRC-029 (IBR ride-through) Reliability Standard.pdf
Comment
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Response
Thank you for your comments. Please see responses herein.
End of Report
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Reminder
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough) | PRC-024-4 and PRC-029-1
Initial Ballots and Non-binding Polls Open through April 22, 2024
Now Available
Initial ballots for Project 2020-02 Modifications to PRC-024 (Generator Ride-through) and non-binding
polls of the associated Violation Risk Factors and Violation Severity Levels are open through 8 p.m.
Eastern, Monday, 22, 2024.
The Standards Committee approved waivers to the Standard Processes Manual at their December 2023
meeting. These waivers were sought by NERC Standards staff for reduced formal comment and ballot
periods. This will assist the drafting teams in expediting the standards development process due to firm
timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket No. RM22-12000 on October 19, 2023.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot pool.
Contact ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
Balloting
Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m.
Eastern) for problems regarding accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
RELIABILITY | RESILIENCE | SECURITY
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Manager of Standards Development, Jamie Calderon (via email)
or at 404-960-0568 Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
(Generator Ride-through) observer list” in the Titla and Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Ballot Open Reminder
Project 2020-02 Modifications to PRC-024 (Generator Ride-through | April 12, 2024
2
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough) | PRC-024-4 and PRC-029-1
Formal Comment Period Open through April 22, 2024
Ballot Pools Forming through April 5, 2024
Now Available
A 25-day formal comment period for Project 2020-02 Modifications to PRC-024 (Generator Ridethrough), is open through 8 p.m. Eastern, Monday, April 22, 2024.
The Standards Committee approved waivers to the Standard Processes Manual at their December 2023
meeting. These waivers were sought by NERC Standards staff for reduced formal comment and ballot
periods. This will assist the drafting teams in expediting the standards development process due to firm
timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket No. RM22-12-000
on October 19, 2023.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot pool.
Contact ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Friday, April 5, 2024. Registered Ballot Body
members can join the ballot pools here.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
RELIABILITY | RESILIENCE | SECURITY
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
Initial ballots for the standards and implementation plan, as well as non-binding polls of the associated
Violation Risk Factors and Violation Severity Levels will be conducted April 12 - 22, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Manager of Standards Development, Jamie Calderon (via email)
or at 404-960-0568 Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
(Generator Ride-through) observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | March 2024
2
NERC Balloting Tool (/)
Dashboard (/)
Users
Ballots
Comment Forms
Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/321)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 IN 1 ST
Voting Start Date: 4/12/2024 12:01:00 AM
Voting End Date: 4/22/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 248
Total Ballot Pool: 271
Quorum: 91.51
Quorum Established Date: 4/22/2024 3:10:52 PM
Weighted Segment Value: 61.73
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
75
1
38
0.633
22
0.367
0
8
7
Segment:
2
8
0.7
2
0.2
5
0.5
0
0
1
Segment:
3
55
1
30
0.6
20
0.4
0
3
2
Segment:
4
14
1
9
0.9
1
0.1
0
2
2
Segment:
5
68
1
37
0.661
19
0.339
0
6
6
Segment:
6
46
1
20
0.571
15
0.429
1
5
5
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.4
2
0.2
2
0.2
0
1
0
Totals:
271
6.1
138
3.765
84
2.335
1
25
23
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Affirmative
N/A
1
Ameren - Ameren
Services
Tamara Evey
Affirmative
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
None
N/A
1
Arkansas Electric
Cooperative Corporation
Emily Corley
Abstain
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
Negative
Comments
Submitted
Negative
Comments
Submitted
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
NERC
Memo
Affirmative
N/A
Adrian Andreoiu
Abstain
N/A
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Affirmative
N/A
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
None
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Abstain
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Affirmative
N/A
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Third-Party
Comments
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Affirmative
N/A
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Negative
Comments
Submitted
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Ballot
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Glencoe Light and Power
Commission
Terry Volkmann
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Emma Halilovic
Abstain
N/A
1
IDACORP - Idaho Power
Company
Sean Steffensen
None
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Denise Sanchez
Affirmative
N/A
1
International
Transmission Company
Holdings Corporation
Michael Moltane
Gail Elliott
Affirmative
N/A
1
JEA
Joseph McClung
Affirmative
N/A
1
KAMO Electric
Cooperative
Micah Breedlove
Negative
Third-Party
Comments
1
Lakeland Electric
Larry Watt
Negative
Third-Party
Comments
1
Lincoln Electric System
Josh Johnson
Affirmative
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Third-Party
Comments
1
Manitoba Hydro
Nazra Gladu
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Affirmative
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Affirmative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Negative
Third-Party
Comments
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ijad Dewan
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
National Grid USA
Michael Jones
Negative
Third-Party
Comments
1
NB Power Corporation
Jeffrey Streifling
Affirmative
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Affirmative
N/A
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Negative
Third-Party
Comments
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug Peterchuck
Affirmative
N/A
1
Oncor Electric Delivery
Byron Booker
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Affirmative
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Negative
Third-Party
Comments
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Negative
Third-Party
Comments
1
Public Utility District No. 1
of Chelan County
Diane E Landry
Affirmative
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
None
N/A
Affirmative
N/A
1
Sacramento Municipal
Wei Shao
Utility District
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Broc Bruton
Bob Cardle
Tim Kelley
Segment
Organization
Voter
1
Salt River Project
Matthew
Jaramilla
1
SaskPower
1
Designated
Proxy
NERC
Memo
Affirmative
N/A
Wayne
Guttormson
Abstain
N/A
Seminole Electric
Cooperative, Inc.
Kristine Ward
Abstain
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Negative
Third-Party
Comments
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Negative
Comments
Submitted
1
Tennessee Valley
Authority
David Plumb
Negative
Comments
Submitted
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
Sam Rugel
Negative
Third-Party
Comments
1
Western Area Power
Administration
Ben Hammer
Affirmative
N/A
1
Xcel Energy, Inc.
Eric Barry
None
N/A
2
California ISO
Darcy O'Connell
Negative
Comments
Submitted
Negative
Comments
Submitted
2
Electric Reliability Council
Kennedy Meier
of Texas,
Inc. Name: ATLVPEROWEB02
© 2024 - NERC Ver 4.2.1.0
Machine
Israel Perez
Ballot
Jennie Wike
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
2
Independent Electricity
System Operator
Helen Lainis
Negative
Comments
Submitted
2
ISO New England, Inc.
John Pearson
Negative
Comments
Submitted
2
Midcontinent ISO, Inc.
Bobbi Welch
Affirmative
N/A
2
New York Independent
System Operator
Gregory Campoli
None
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
Negative
Comments
Submitted
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Abstain
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
Comments
Submitted
3
Austin Energy
Lovita Griffin
Negative
Comments
Submitted
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Affirmative
N/A
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Third-Party
Comments
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
Affirmative
N/A
3 - NERC Ver 4.2.1.0
Colorado
Springs
Utilities
Hillary Dobson
© 2024
Machine
Name:
ATLVPEROWEB02
Elizabeth Davis
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Negative
Third-Party
Comments
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Entergy
James Keele
Affirmative
N/A
3
Evergy
Marcus Moor
Negative
Comments
Submitted
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
3
Exelon
Kinte Whitehead
Negative
Comments
Submitted
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Affirmative
N/A
3
Great River Energy
Michael
Brytowski
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Affirmative
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
None
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
Third-Party
Comments
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Negative
Comments
Submitted
Affirmative
N/A
3
Muscatine Power and
Seth Shoemaker
Water
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
3
Nebraska Public Power
District
Tony Eddleman
Affirmative
N/A
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
Heath Henry
Negative
Third-Party
Comments
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Omaha Public Power
District
David Heins
Affirmative
N/A
3
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
3
Pacific Gas and Electric
Company
Sandra Ellis
Affirmative
N/A
3
Platte River Power
Authority
Richard Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
James Frank
Negative
Third-Party
Comments
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Negative
Third-Party
Comments
3
Public Utility District No. 1
of Chelan County
Joyce Gundry
Affirmative
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Seminole Electric
Cooperative, Inc.
Marc Sedor
Abstain
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
Third-Party
Comments
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power
Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Negative
Comments
Submitted
3
Tri-State G and T
Association, Inc.
Ryan Walter
Affirmative
N/A
3
WEC Energy Group, Inc.
Christine Kane
Affirmative
N/A
3
Xcel Energy, Inc.
Nicholas Friebel
Affirmative
N/A
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Affirmative
N/A
4
Austin Energy
Tony Hua
Negative
Comments
Submitted
4
Buckeye Power, Inc.
Jason Procuniar
Affirmative
N/A
4
CMS Energy Consumers Energy
Company
Aric Root
Affirmative
N/A
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Affirmative
N/A
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Affirmative
N/A
4
Oklahoma Municipal
Power Authority
Michael Watt
None
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ryan Strom
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Abstain
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Ken Habgood
Abstain
N/A
4
Utility Services, Inc.
Carver Powers
None
N/A
4
Western Power Pool
Kevin Conway
Affirmative
N/A
5
AEP
Thomas Foltz
Affirmative
N/A
5
AES - AES Corporation
Ruchi Shah
Affirmative
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
American Municipal
Power
Amy Ritts
None
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
Comments
Submitted
5
Austin Energy
Michael Dillard
Negative
Comments
Submitted
5
Avista - Avista
Corporation
Glen Farmer
Negative
Comments
Submitted
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
Abstain
N/A
5
Bonneville Power
Juergen Bermejo
Administration
© 2024 - NERC Ver 4.2.1.0
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Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
None
N/A
5
CMS Energy Consumers Energy
Company
David
Greyerbiehl
Negative
Comments
Submitted
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Helen Wang
Negative
Third-Party
Comments
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Affirmative
N/A
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
None
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
None
N/A
5
Evergy
Jeremy Harris
Negative
Comments
Submitted
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Affirmative
N/A
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
Negative
Third-Party
Comments
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
David Campbell
Hayden Maples
Segment
Organization
Voter
5
Grid Strategies LLC
Michael Goggin
5
Imperial Irrigation District
Tino Zaragoza
5
Invenergy LLC
5
Designated
Proxy
Ballot
NERC
Memo
Negative
Comments
Submitted
Affirmative
N/A
Rhonda Jones
Affirmative
N/A
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Affirmative
N/A
5
Los Angeles Department
of Water and Power
Glenn Barry
Abstain
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Affirmative
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Manitoba Hydro
Kristy-Lee Young
Affirmative
N/A
5
Muscatine Power and
Water
Neal Nelson
Affirmative
N/A
5
National Grid USA
Robin Berry
Negative
Third-Party
Comments
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Affirmative
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
Affirmative
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Affirmative
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
Affirmative
N/A
Affirmative
N/A
5
Ontario Power
Constantin
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Generation Inc.
Chitescu
Denise Sanchez
Scott Brame
Segment
Organization
Voter
5
OTP - Otter Tail Power
Company
Stacy Wahlund
5
Pacific Gas and Electric
Company
Tyler Brun
5
Pattern Operators LP
5
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Affirmative
N/A
George E Brown
Affirmative
N/A
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Negative
Third-Party
Comments
5
PSEG Nuclear LLC
Tim Kucey
Negative
Third-Party
Comments
5
Public Utility District No. 1
of Chelan County
Rebecca Zahler
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Affirmative
N/A
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
Abstain
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Negative
Comments
Submitted
5
Tennessee Valley
Authority
Darren Boehm
Negative
Comments
Submitted
5
TransAlta Corporation
Ashley Scheelar
Abstain
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
None
N/A
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Affirmative
N/A
Affirmative
N/A
5
Vistra Energy
Daniel
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Roethemeyer
Bob Cardle
Adam Burlock
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
WEC Energy Group, Inc.
Clarice Zellmer
Affirmative
N/A
5
Xcel Energy, Inc.
Gerry Huitt
Affirmative
N/A
6
AEP
Mathew Miller
Affirmative
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Abstain
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Negative
Comments
Submitted
6
Austin Energy
Imane Mrini
Negative
Comments
Submitted
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
None
N/A
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Abstain
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Third-Party
Comments
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
6
Edison International Southern California
Edison Company
Stephanie Kenny
Affirmative
N/A
6
Entergy
Julie Hall
Affirmative
N/A
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Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
Hayden Maples
Negative
Comments
Submitted
6
Evergy
Tiffany Lake
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Affirmative
N/A
6
Great River Energy
Brian Meloy
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Invenergy LLC
Colin Chilcoat
Affirmative
N/A
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Affirmative
N/A
6
Los Angeles Department
of Water and Power
Anton Vu
Abstain
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Negative
No Comment
Submitted
6
Manitoba Hydro
Kelly Bertholet
Affirmative
N/A
6
Muscatine Power and
Water
Nicholas Burns
Affirmative
N/A
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Affirmative
N/A
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Affirmative
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Affirmative
N/A
6
Omaha Public Power
District
Shonda McCain
Affirmative
N/A
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
Third-Party
Comments
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
Negative
Third-Party
Comments
6
Public Utility District No. 1
of Chelan County
Tamarra Hardie
Affirmative
N/A
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Affirmative
N/A
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
Abstain
N/A
6
Snohomish County PUD
No. 1
John Liang
None
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
Negative
Comments
Submitted
6
WEC Energy Group, Inc.
David Boeshaar
Affirmative
N/A
6
Xcel Energy, Inc.
Steve Szablya
None
N/A
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Negative
Comments
Submitted
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Negative
Comments
Submitted
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/321)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 IN 1 ST
Voting Start Date: 4/12/2024 12:01:00 AM
Voting End Date: 4/22/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 243
Total Ballot Pool: 267
Quorum: 91.01
Quorum Established Date: 4/22/2024 3:13:20 PM
Weighted Segment Value: 25.37
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
74
1
15
0.273
40
0.727
1
11
7
Segment:
2
8
0.6
0
0
6
0.6
0
0
2
Segment:
3
54
1
11
0.224
38
0.776
0
3
2
Segment:
4
14
1
4
0.4
6
0.6
0
2
2
Segment:
5
67
1
16
0.296
38
0.704
0
7
6
Segment:
6
45
1
8
0.229
27
0.771
0
5
5
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.4
1
0.1
3
0.3
0
1
0
Totals:
267
6
55
1.522
158
4.478
1
29
24
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren
Services
Tamara Evey
Affirmative
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
None
N/A
1
Arkansas Electric
Cooperative Corporation
Emily Corley
Abstain
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
Negative
Comments
Submitted
Negative
Comments
Submitted
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
NERC
Memo
Negative
Comments
Submitted
Adrian Andreoiu
Negative
Comments
Submitted
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
None
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Abstain
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Third-Party
Comments
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Third-Party
Comments
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Negative
Comments
Submitted
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Negative
Comments
Submitted
Affirmative
N/A
1
Georgia Transmission
Greg Davis
Corporation
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB02
Tim Kelley
Ballot
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Glencoe Light and Power
Commission
Terry Volkmann
Negative
No Comment
Submitted
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Emma Halilovic
Abstain
N/A
1
IDACORP - Idaho Power
Company
Sean Steffensen
None
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Denise Sanchez
Affirmative
N/A
1
International
Transmission Company
Holdings Corporation
Michael Moltane
Gail Elliott
Affirmative
N/A
1
JEA
Joseph McClung
Negative
Third-Party
Comments
1
KAMO Electric
Cooperative
Micah Breedlove
Negative
Third-Party
Comments
1
Lakeland Electric
Larry Watt
Negative
Third-Party
Comments
1
Lincoln Electric System
Josh Johnson
Negative
Comments
Submitted
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Third-Party
Comments
1
Manitoba Hydro
Nazra Gladu
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Affirmative
N/A
Negative
Third-Party
Comments
1
N.W. Electric Power
Mark Ramsey
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Cooperative, Inc.
Ijad Dewan
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
National Grid USA
Michael Jones
Negative
Third-Party
Comments
1
NB Power Corporation
Jeffrey Streifling
Affirmative
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Negative
Comments
Submitted
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Negative
Third-Party
Comments
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Negative
Third-Party
Comments
1
Omaha Public Power
District
Doug Peterchuck
Negative
Comments
Submitted
1
Oncor Electric Delivery
Byron Booker
Abstain
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Negative
Third-Party
Comments
1
Pacific Gas and Electric
Company
Marco Rios
Negative
Comments
Submitted
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Negative
Third-Party
Comments
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Negative
Third-Party
Comments
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
None
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Negative
Comments
Submitted
1
Salt River Project
Israel Perez
Affirmative
N/A
Matthew
Jaramilla
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Broc Bruton
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
SaskPower
Wayne
Guttormson
Abstain
N/A
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
Abstain
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Negative
Third-Party
Comments
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Abstain
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Negative
Comments
Submitted
1
Tennessee Valley
Authority
David Plumb
Negative
Comments
Submitted
1
Tri-State G and T
Association, Inc.
Donna Wood
Negative
Comments
Submitted
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Sam Rugel
Negative
Third-Party
Comments
1
Western Area Power
Administration
Ben Hammer
Negative
Comments
Submitted
1
Xcel Energy, Inc.
Eric Barry
None
N/A
2
California ISO
Darcy O'Connell
Negative
Comments
Submitted
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
Negative
Comments
Submitted
2
Independent Electricity
Helen Lainis
System
Operator
© 2024 - NERC Ver 4.2.1.0
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Name: ATLVPEROWEB02
Jennie Wike
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
2
ISO New England, Inc.
John Pearson
None
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Negative
Third-Party
Comments
2
New York Independent
System Operator
Gregory Campoli
None
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Negative
Third-Party
Comments
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
Negative
Comments
Submitted
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Abstain
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
Comments
Submitted
3
Austin Energy
Lovita Griffin
Negative
Comments
Submitted
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Negative
Comments
Submitted
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Third-Party
Comments
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Negative
Comments
Submitted
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
Negative
Third-Party
Comments
3
Con Ed - Consolidated
Peter Yost
EdisonMachine
Co. of New
YorkATLVPEROWEB02
© 2024 - NERC Ver 4.2.1.0
Name:
Elizabeth Davis
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Entergy
James Keele
Affirmative
N/A
3
Evergy
Marcus Moor
Negative
Comments
Submitted
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
3
Exelon
Kinte Whitehead
Negative
Comments
Submitted
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Negative
Comments
Submitted
3
Great River Energy
Michael
Brytowski
Negative
Comments
Submitted
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Negative
Third-Party
Comments
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Negative
Comments
Submitted
3
Los Angeles Department
of Water and Power
Fausto Serratos
None
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
Third-Party
Comments
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Negative
Comments
Submitted
3
Muscatine Power and
Water
Seth Shoemaker
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
3
Nebraska Public Power
District
Tony Eddleman
Negative
Third-Party
Comments
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Negative
Third-Party
Comments
3
NW Electric Power
Cooperative, Inc.
Heath Henry
Negative
Third-Party
Comments
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Negative
Third-Party
Comments
3
Omaha Public Power
District
David Heins
Negative
Comments
Submitted
3
OTP - Otter Tail Power
Company
Wendi Olson
Negative
Third-Party
Comments
3
Pacific Gas and Electric
Company
Sandra Ellis
Negative
Comments
Submitted
3
Platte River Power
Authority
Richard Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Negative
Comments
Submitted
3
PPL - Louisville Gas and
Electric Co.
James Frank
Negative
Third-Party
Comments
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Negative
Third-Party
Comments
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Negative
Comments
Submitted
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Marc Sedor
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
Third-Party
Comments
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power
Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Negative
Comments
Submitted
3
Tri-State G and T
Association, Inc.
Ryan Walter
Negative
Comments
Submitted
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Nicholas Friebel
Negative
Third-Party
Comments
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Affirmative
N/A
4
Austin Energy
Tony Hua
Negative
Comments
Submitted
4
Buckeye Power, Inc.
Jason Procuniar
Negative
Third-Party
Comments
4
CMS Energy Consumers Energy
Company
Aric Root
Negative
Comments
Submitted
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Negative
Comments
Submitted
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Negative
Third-Party
Comments
4
Oklahoma Municipal
Power Authority
Michael Watt
None
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ryan Strom
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Abstain
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Negative
Comments
Submitted
4
Seminole Electric
Cooperative, Inc.
Ken Habgood
Abstain
N/A
4
Utility Services, Inc.
Carver Powers
None
N/A
4
Western Power Pool
Kevin Conway
Affirmative
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
AES - AES Corporation
Ruchi Shah
Negative
Comments
Submitted
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
American Municipal
Power
Amy Ritts
None
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
Comments
Submitted
5
Austin Energy
Michael Dillard
Negative
Comments
Submitted
5
Avista - Avista
Corporation
Glen Farmer
Negative
Comments
Submitted
5
BC Hydro and Power
Authority
Quincy Wang
Negative
Comments
Submitted
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Bonneville Power
Administration
Juergen Bermejo
Abstain
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
None
N/A
5
CMS Energy Consumers Energy
Company
David
Greyerbiehl
Negative
Comments
Submitted
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Helen Wang
Negative
Third-Party
Comments
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Negative
Third-Party
Comments
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
None
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
None
N/A
5
Evergy
Jeremy Harris
Negative
Comments
Submitted
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Negative
Comments
Submitted
5
Great River Energy
Jacalynn Bentz
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
David Campbell
Hayden Maples
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Greybeard Compliance
Services, LLC
Mike Gabriel
Negative
Third-Party
Comments
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Affirmative
N/A
5
Invenergy LLC
Rhonda Jones
Negative
Comments
Submitted
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Negative
Comments
Submitted
5
Los Angeles Department
of Water and Power
Glenn Barry
Abstain
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Affirmative
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Manitoba Hydro
Kristy-Lee Young
Affirmative
N/A
5
Muscatine Power and
Water
Neal Nelson
Abstain
N/A
5
National Grid USA
Robin Berry
Negative
Third-Party
Comments
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Affirmative
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Negative
Third-Party
Comments
5
NRG - NRG Energy, Inc.
Patricia Lynch
Affirmative
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Negative
Third-Party
Comments
Affirmative
N/A
5
Oglethorpe Power
Donna Johnson
Corporation
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Omaha Public Power
District
Kayleigh
Wilkerson
Negative
Comments
Submitted
5
Ontario Power
Generation Inc.
Constantin
Chitescu
Negative
Comments
Submitted
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Negative
Third-Party
Comments
5
Pacific Gas and Electric
Company
Tyler Brun
Negative
Comments
Submitted
5
Pattern Operators LP
George E Brown
Negative
Comments
Submitted
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Negative
Third-Party
Comments
5
PSEG Nuclear LLC
Tim Kucey
Negative
Third-Party
Comments
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Negative
Comments
Submitted
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
Abstain
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Negative
Comments
Submitted
5
Tennessee Valley
Authority
Darren Boehm
Negative
Comments
Submitted
5
TransAlta Corporation
Ashley Scheelar
Abstain
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
None
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Bob Cardle
Adam Burlock
Segment
Organization
Voter
5
U.S. Bureau of
Reclamation
Wendy Kalidass
5
Vistra Energy
Daniel
Roethemeyer
5
WEC Energy Group, Inc.
5
Designated
Proxy
Ballot
NERC
Memo
Abstain
N/A
Negative
Comments
Submitted
Clarice Zellmer
Negative
Comments
Submitted
Xcel Energy, Inc.
Gerry Huitt
Negative
Third-Party
Comments
6
AEP
Mathew Miller
Negative
Comments
Submitted
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Abstain
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Negative
Comments
Submitted
6
Austin Energy
Imane Mrini
Negative
Comments
Submitted
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
None
N/A
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Abstain
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Third-Party
Comments
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
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David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
6
Edison International Southern California
Edison Company
Stephanie Kenny
Affirmative
N/A
6
Entergy
Julie Hall
Negative
Comments
Submitted
6
Evergy
Tiffany Lake
Negative
Comments
Submitted
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Negative
Comments
Submitted
6
Great River Energy
Brian Meloy
Negative
Comments
Submitted
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Invenergy LLC
Colin Chilcoat
Negative
Comments
Submitted
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Negative
Comments
Submitted
6
Los Angeles Department
of Water and Power
Anton Vu
Abstain
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Negative
Third-Party
Comments
6
Manitoba Hydro
Kelly Bertholet
Affirmative
N/A
6
Muscatine Power and
Water
Nicholas Burns
Abstain
N/A
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Affirmative
N/A
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
6
NRG - NRG Energy, Inc.
Martin Sidor
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Negative
Third-Party
Comments
6
Omaha Public Power
District
Shonda McCain
Negative
Comments
Submitted
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Negative
Third-Party
Comments
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
Third-Party
Comments
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
Negative
Third-Party
Comments
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Negative
Comments
Submitted
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
Abstain
N/A
6
Snohomish County PUD
No. 1
John Liang
None
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
Negative
Comments
Submitted
6
WEC Energy Group, Inc.
David Boeshaar
Negative
Comments
Submitted
6
Xcel Energy, Inc.
Steve Szablya
None
N/A
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Negative
Comments
Submitted
Affirmative
N/A
10
SERC Reliability
Dave Krueger
Corporation
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Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Negative
Comments
Submitted
10
Western Electricity
Coordinating Council
Steven Rueckert
Negative
Comments
Submitted
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/321)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan IN 1 OT
Voting Start Date: 4/12/2024 12:01:00 AM
Voting End Date: 4/22/2024 8:00:00 PM
Ballot Type: OT
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 247
Total Ballot Pool: 271
Quorum: 91.14
Quorum Established Date: 4/22/2024 3:12:23 PM
Weighted Segment Value: 37.5
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
75
1
25
0.439
32
0.561
0
11
7
Segment:
2
8
0.5
2
0.2
3
0.3
0
1
2
Segment:
3
55
1
15
0.313
33
0.688
0
5
2
Segment:
4
14
0.8
2
0.2
6
0.6
1
3
2
Segment:
5
68
1
21
0.389
33
0.611
0
9
5
Segment:
6
46
1
10
0.323
21
0.677
0
9
6
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.2
2
0.2
0
0
0
3
0
Totals:
271
5.5
77
2.063
128
3.437
1
41
24
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren
Services
Tamara Evey
Affirmative
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
None
N/A
1
Arkansas Electric
Cooperative Corporation
Emily Corley
Abstain
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
Abstain
N/A
Negative
Comments
Submitted
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
NERC
Memo
Negative
Comments
Submitted
Adrian Andreoiu
Abstain
N/A
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
None
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Abstain
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Third-Party
Comments
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Third-Party
Comments
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Negative
Comments
Submitted
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Negative
Comments
Submitted
Negative
Comments
Submitted
1
Georgia Transmission
Greg Davis
Corporation
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Tim Kelley
Ballot
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Glencoe Light and Power
Commission
Terry Volkmann
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Emma Halilovic
Abstain
N/A
1
IDACORP - Idaho Power
Company
Sean Steffensen
None
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Denise Sanchez
Affirmative
N/A
1
International
Transmission Company
Holdings Corporation
Michael Moltane
Gail Elliott
Affirmative
N/A
1
JEA
Joseph McClung
Negative
Third-Party
Comments
1
KAMO Electric
Cooperative
Micah Breedlove
Negative
Third-Party
Comments
1
Lakeland Electric
Larry Watt
Affirmative
N/A
1
Lincoln Electric System
Josh Johnson
Negative
Comments
Submitted
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Third-Party
Comments
1
Manitoba Hydro
Nazra Gladu
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Affirmative
N/A
Negative
Third-Party
Comments
1
N.W. Electric Power
Mark Ramsey
Cooperative, Inc.
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Ijad Dewan
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
National Grid USA
Michael Jones
Negative
Third-Party
Comments
1
NB Power Corporation
Jeffrey Streifling
Affirmative
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Affirmative
N/A
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Negative
Third-Party
Comments
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Negative
Third-Party
Comments
1
Omaha Public Power
District
Doug Peterchuck
Affirmative
N/A
1
Oncor Electric Delivery
Byron Booker
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Negative
Third-Party
Comments
1
Pacific Gas and Electric
Company
Marco Rios
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Negative
Third-Party
Comments
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Abstain
N/A
1
Public Utility District No. 1
of Chelan County
Diane E Landry
Affirmative
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
None
N/A
Negative
Comments
Submitted
1
Sacramento Municipal
Wei Shao
Utility District
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Broc Bruton
Bob Cardle
Tim Kelley
Segment
Organization
Voter
1
Salt River Project
Matthew
Jaramilla
1
SaskPower
1
Designated
Proxy
NERC
Memo
Affirmative
N/A
Wayne
Guttormson
Abstain
N/A
Seminole Electric
Cooperative, Inc.
Kristine Ward
Abstain
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Negative
Third-Party
Comments
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Negative
Comments
Submitted
1
Tennessee Valley
Authority
David Plumb
Negative
Comments
Submitted
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
Sam Rugel
Negative
Third-Party
Comments
1
Western Area Power
Administration
Ben Hammer
Negative
Comments
Submitted
1
Xcel Energy, Inc.
Eric Barry
None
N/A
2
California ISO
Darcy O'Connell
Negative
Comments
Submitted
Negative
Comments
Submitted
2
Electric Reliability Council
Kennedy Meier
of Texas,
Inc. Name: ATLVPEROWEB02
© 2024 - NERC Ver 4.2.1.0
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Israel Perez
Ballot
Jennie Wike
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
2
Independent Electricity
System Operator
Helen Lainis
Abstain
N/A
2
ISO New England, Inc.
John Pearson
None
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Affirmative
N/A
2
New York Independent
System Operator
Gregory Campoli
None
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
Negative
Comments
Submitted
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Abstain
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
Comments
Submitted
3
Austin Energy
Lovita Griffin
Negative
Comments
Submitted
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Third-Party
Comments
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Negative
Comments
Submitted
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Elizabeth Davis
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Negative
Third-Party
Comments
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Negative
Comments
Submitted
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Entergy
James Keele
Negative
Comments
Submitted
3
Evergy
Marcus Moor
Negative
Comments
Submitted
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
3
Exelon
Kinte Whitehead
Negative
Comments
Submitted
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Negative
Comments
Submitted
3
Great River Energy
Michael
Brytowski
Negative
Comments
Submitted
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Negative
Comments
Submitted
3
Los Angeles Department
of Water and Power
Fausto Serratos
None
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
Third-Party
Comments
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Muscatine Power and
Water
Seth Shoemaker
Abstain
N/A
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
3
Nebraska Public Power
District
Tony Eddleman
Negative
Third-Party
Comments
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Negative
Third-Party
Comments
3
NW Electric Power
Cooperative, Inc.
Heath Henry
Negative
Third-Party
Comments
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Omaha Public Power
District
David Heins
Negative
Comments
Submitted
3
OTP - Otter Tail Power
Company
Wendi Olson
Negative
Third-Party
Comments
3
Pacific Gas and Electric
Company
Sandra Ellis
Affirmative
N/A
3
Platte River Power
Authority
Richard Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
James Frank
Negative
Third-Party
Comments
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Abstain
N/A
3
Public Utility District No. 1
of Chelan County
Joyce Gundry
Affirmative
N/A
Negative
Comments
Submitted
3
Sacramento Municipal
Nicole Looney
Utility District
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Tim Kelley
Segment
Organization
Voter
3
Salt River Project
Mathew Weber
3
Seminole Electric
Cooperative, Inc.
3
Designated
Proxy
NERC
Memo
Affirmative
N/A
Marc Sedor
Abstain
N/A
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
Third-Party
Comments
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power
Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Negative
Comments
Submitted
3
Tri-State G and T
Association, Inc.
Ryan Walter
Affirmative
N/A
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Nicholas Friebel
Negative
Third-Party
Comments
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Negative
No Comment
Submitted
4
Austin Energy
Tony Hua
Abstain
N/A
4
Buckeye Power, Inc.
Jason Procuniar
Negative
Third-Party
Comments
4
CMS Energy Consumers Energy
Company
Aric Root
Negative
Comments
Submitted
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Negative
Comments
Submitted
4
Georgia System
Operations Corporation
Katrina Lyons
Negative
Comments
Submitted
Negative
Third-Party
Comments
4
North Carolina Electric
Richard McCall
Membership
Corporation
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB02
Israel Perez
Ballot
Ryan Strom
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Oklahoma Municipal
Power Authority
Michael Watt
None
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Abstain
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Negative
Comments
Submitted
4
Seminole Electric
Cooperative, Inc.
Ken Habgood
Abstain
N/A
4
Utility Services, Inc.
Carver Powers
None
N/A
4
Western Power Pool
Kevin Conway
Affirmative
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
AES - AES Corporation
Ruchi Shah
Affirmative
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
American Municipal
Power
Amy Ritts
None
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
Comments
Submitted
5
Austin Energy
Michael Dillard
Abstain
N/A
5
Avista - Avista
Corporation
Glen Farmer
Negative
Comments
Submitted
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Bonneville Power
Administration
Juergen Bermejo
Abstain
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
Negative
Third-Party
Comments
5
CMS Energy Consumers Energy
Company
David
Greyerbiehl
Negative
Comments
Submitted
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Helen Wang
Negative
Third-Party
Comments
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Affirmative
N/A
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Negative
Comments
Submitted
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
None
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
None
N/A
5
Evergy
Jeremy Harris
Negative
Comments
Submitted
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Negative
Comments
Submitted
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
David Campbell
Hayden Maples
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Greybeard Compliance
Services, LLC
Mike Gabriel
Negative
Third-Party
Comments
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Affirmative
N/A
5
Invenergy LLC
Rhonda Jones
Negative
Comments
Submitted
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Negative
Comments
Submitted
5
Los Angeles Department
of Water and Power
Glenn Barry
Abstain
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Affirmative
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Manitoba Hydro
Kristy-Lee Young
Affirmative
N/A
5
Muscatine Power and
Water
Neal Nelson
Abstain
N/A
5
National Grid USA
Robin Berry
Negative
Third-Party
Comments
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Affirmative
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Negative
Third-Party
Comments
5
NRG - NRG Energy, Inc.
Patricia Lynch
Affirmative
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Affirmative
N/A
Negative
Third-Party
Comments
5
Oglethorpe Power
Donna Johnson
Corporation
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Omaha Public Power
District
Kayleigh
Wilkerson
Negative
Comments
Submitted
5
Ontario Power
Generation Inc.
Constantin
Chitescu
Negative
Comments
Submitted
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Negative
Third-Party
Comments
5
Pacific Gas and Electric
Company
Tyler Brun
Affirmative
N/A
5
Pattern Operators LP
George E Brown
Negative
Comments
Submitted
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Negative
Third-Party
Comments
5
PSEG Nuclear LLC
Tim Kucey
Abstain
N/A
5
Public Utility District No. 1
of Chelan County
Rebecca Zahler
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Negative
Comments
Submitted
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
Abstain
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Negative
Comments
Submitted
5
Tennessee Valley
Authority
Darren Boehm
Negative
Comments
Submitted
5
TransAlta Corporation
Ashley Scheelar
Abstain
N/A
None
N/A
5
Tri-State G and T
Sergio Banuelos
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Association, Inc.
Bob Cardle
Adam Burlock
Segment
Organization
Voter
5
U.S. Bureau of
Reclamation
Wendy Kalidass
5
Vistra Energy
Daniel
Roethemeyer
5
WEC Energy Group, Inc.
5
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Negative
Comments
Submitted
Clarice Zellmer
Negative
Comments
Submitted
Xcel Energy, Inc.
Gerry Huitt
Negative
Third-Party
Comments
6
AEP
Mathew Miller
Negative
Comments
Submitted
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Abstain
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Negative
Comments
Submitted
6
Austin Energy
Imane Mrini
Abstain
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
None
N/A
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Abstain
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Third-Party
Comments
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
Negative
Comments
Submitted
6
Duke Energy
John Sturgeon
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David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Edison International Southern California
Edison Company
Stephanie Kenny
Affirmative
N/A
6
Entergy
Julie Hall
Negative
Comments
Submitted
6
Evergy
Tiffany Lake
Negative
Comments
Submitted
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Negative
Comments
Submitted
6
Great River Energy
Brian Meloy
None
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Invenergy LLC
Colin Chilcoat
Negative
Comments
Submitted
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Negative
Comments
Submitted
6
Los Angeles Department
of Water and Power
Anton Vu
Abstain
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Abstain
N/A
6
Manitoba Hydro
Kelly Bertholet
Affirmative
N/A
6
Muscatine Power and
Water
Nicholas Burns
Abstain
N/A
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Affirmative
N/A
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Affirmative
N/A
Affirmative
N/A
6
OGE Energy - Oklahoma
Ashley F Stringer
Gas and Electric Co.
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Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Omaha Public Power
District
Shonda McCain
Negative
Comments
Submitted
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
Third-Party
Comments
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
Abstain
N/A
6
Public Utility District No. 1
of Chelan County
Tamarra Hardie
Affirmative
N/A
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Negative
Comments
Submitted
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
Abstain
N/A
6
Snohomish County PUD
No. 1
John Liang
None
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
Negative
Comments
Submitted
6
WEC Energy Group, Inc.
David Boeshaar
Negative
Comments
Submitted
6
Xcel Energy, Inc.
Steve Szablya
None
N/A
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Affirmative
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Abstain
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Abstain
N/A
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/321)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 | Non-binding Poll IN 1 NB
Voting Start Date: 4/12/2024 12:01:00 AM
Voting End Date: 4/22/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 227
Total Ballot Pool: 254
Quorum: 89.37
Quorum Established Date: 4/22/2024 3:17:32 PM
Weighted Segment Value: 63.79
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
1
71
1
32
0.681
15
0.319
18
6
Segment:
2
7
0.2
0
0
2
0.2
3
2
Segment:
3
52
1
25
0.595
17
0.405
7
3
Segment:
4
14
0.9
8
0.8
1
0.1
3
2
Segment:
5
63
1
31
0.674
15
0.326
10
7
Segment:
6
42
1
14
0.538
12
0.462
9
7
Segment:
7
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
Segment:
9
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
10
5
0.2
1
0.1
1
0.1
3
0
Totals:
254
5.3
111
3.388
63
1.912
53
27
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Abstain
N/A
1
Ameren - Ameren
Services
Tamara Evey
Abstain
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
None
N/A
1
Arkansas Electric
Cooperative Corporation
Emily Corley
Abstain
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
Abstain
N/A
1
Avista - Avista
Corporation
Mike Magruder
Abstain
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
BC Hydro and Power
Authority
Adrian Andreoiu
Abstain
N/A
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Affirmative
N/A
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
None
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Abstain
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Affirmative
N/A
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Comments
Submitted
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Affirmative
N/A
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Negative
Comments
Submitted
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
1
Glencoe Light and Power
Commission
Terry Volkmann
Affirmative
N/A
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1
Great River Energy
Gordon Pietsch
Affirmative
N/A
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
1
Hydro One Networks, Inc.
Emma Halilovic
1
IDACORP - Idaho Power
Company
Sean Steffensen
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
1
International Transmission
Company Holdings
Corporation
Michael Moltane
1
JEA
1
Designated
Proxy
NERC
Memo
Abstain
N/A
None
N/A
Denise Sanchez
Affirmative
N/A
Gail Elliott
Affirmative
N/A
Joseph McClung
Affirmative
N/A
KAMO Electric
Cooperative
Micah Breedlove
Negative
Comments
Submitted
1
Lakeland Electric
Larry Watt
Negative
Comments
Submitted
1
Lincoln Electric System
Josh Johnson
Abstain
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Comments
Submitted
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Affirmative
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Affirmative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Negative
Comments
Submitted
1
National Grid USA
Michael Jones
Negative
Comments
Submitted
1
NB Power Corporation
Jeffrey Streifling
Affirmative
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Abstain
N/A
Negative
Comments
Submitted
1
Northeast Missouri
Brett Douglas
Electric Power
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Cooperative
Ijad Dewan
Ballot
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug Peterchuck
Affirmative
N/A
1
Oncor Electric Delivery
Byron Booker
Broc Bruton
Affirmative
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Bob Cardle
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
None
N/A
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Abstain
N/A
1
Public Utility District No. 1
of Chelan County
Diane E Landry
Affirmative
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
None
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Matthew
Jaramilla
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
Abstain
N/A
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
Abstain
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
Negative
Comments
Submitted
1
Sho-Me Power Electric
Olivia Olson
Cooperative
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
Sam Rugel
Abstain
N/A
1
Western Area Power
Administration
Ben Hammer
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Abstain
N/A
2
ISO New England, Inc.
John Pearson
None
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Abstain
N/A
2
New York Independent
System Operator
Gregory Campoli
None
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Abstain
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
Negative
Comments
Submitted
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Jennie Wike
Elizabeth Davis
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Abstain
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
Comments
Submitted
3
Austin Energy
Lovita Griffin
Negative
Comments
Submitted
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Affirmative
N/A
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Comments
Submitted
3
CMS Energy - Consumers
Energy Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Negative
Comments
Submitted
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Entergy
James Keele
Affirmative
N/A
3
Evergy
Marcus Moor
Negative
Comments
Submitted
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Carly Miller
Hayden Maples
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Exelon
Kinte Whitehead
Negative
Comments
Submitted
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Affirmative
N/A
3
Great River Energy
Michael
Brytowski
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Abstain
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
None
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
Comments
Submitted
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Negative
Comments
Submitted
3
Muscatine Power and
Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
Negative
Comments
Submitted
3
Nebraska Public Power
District
Tony Eddleman
Abstain
N/A
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
Heath Henry
Negative
Comments
Submitted
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Affirmative
N/A
Affirmative
N/A
3
Omaha Public Power
David Heins
District
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Segment
Organization
Voter
3
Pacific Gas and Electric
Company
Sandra Ellis
3
Platte River Power
Authority
3
Designated
Proxy
NERC
Memo
Affirmative
N/A
Richard Kiess
Affirmative
N/A
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
James Frank
None
N/A
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Abstain
N/A
3
Public Utility District No. 1
of Chelan County
Joyce Gundry
Affirmative
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Marc Sedor
Abstain
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
Comments
Submitted
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Ryan Walter
Affirmative
N/A
3
WEC Energy Group, Inc.
Christine Kane
Affirmative
N/A
4
Alliant Energy Corporation
Services, Inc.
Larry Heckert
Affirmative
N/A
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
4
Austin Energy
Tony Hua
Bob Cardle
Ballot
Segment
Organization
Voter
4
Buckeye Power, Inc.
Jason Procuniar
4
CMS Energy - Consumers
Energy Company
4
Designated
Proxy
NERC
Memo
Affirmative
N/A
Aric Root
Affirmative
N/A
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Affirmative
N/A
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Negative
Comments
Submitted
4
Oklahoma Municipal
Power Authority
Michael Watt
None
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Abstain
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Ken Habgood
Abstain
N/A
4
Utility Services, Inc.
Carver Powers
None
N/A
4
Western Power Pool
Kevin Conway
Affirmative
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
AES - AES Corporation
Ruchi Shah
Affirmative
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Abstain
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
Comments
Submitted
5
Austin Energy
Michael Dillard
Abstain
N/A
Negative
Comments
Submitted
5
Avista - Avista
Glen Farmer
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Ryan Strom
Ballot
Scott Brame
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
5
Bonneville Power
Administration
Juergen Bermejo
Abstain
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
None
N/A
5
CMS Energy - Consumers
Energy Company
David
Greyerbiehl
Negative
Comments
Submitted
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Helen Wang
Negative
Comments
Submitted
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Affirmative
N/A
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
None
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
None
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
David Campbell
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
Hayden Maples
Negative
Comments
Submitted
5
Evergy
Jeremy Harris
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Affirmative
N/A
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
Negative
Comments
Submitted
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Affirmative
N/A
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Abstain
N/A
5
Los Angeles Department
of Water and Power
Glenn Barry
Abstain
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Affirmative
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Muscatine Power and
Water
Neal Nelson
Affirmative
N/A
5
National Grid USA
Robin Berry
Negative
Comments
Submitted
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Affirmative
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Comments
Submitted
5
North Carolina Electric
Membership Corporation
Reid Cashion
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
Affirmative
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
Affirmative
N/A
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Affirmative
N/A
5
Pacific Gas and Electric
Company
Tyler Brun
Affirmative
N/A
5
Pattern Operators LP
George E Brown
Affirmative
N/A
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
None
N/A
5
PSEG Nuclear LLC
Tim Kucey
Abstain
N/A
5
Public Utility District No. 1
of Chelan County
Rebecca Zahler
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Affirmative
N/A
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
Abstain
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Negative
Comments
Submitted
5
Tennessee Valley
Authority
Darren Boehm
None
N/A
None
N/A
5
Tri-State G and T
Sergio Banuelos
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Association, Inc.
Bob Cardle
Segment
Organization
Voter
5
U.S. Bureau of
Reclamation
Wendy Kalidass
5
Vistra Energy
Daniel
Roethemeyer
5
WEC Energy Group, Inc.
6
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Affirmative
N/A
Clarice Zellmer
Affirmative
N/A
AEP
Mathew Miller
Abstain
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Abstain
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Abstain
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Negative
Comments
Submitted
6
Austin Energy
Imane Mrini
Abstain
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
None
N/A
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
None
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Comments
Submitted
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
6
Edison International Southern California
Edison Company
Stephanie Kenny
Affirmative
N/A
Affirmative
N/A
6
Entergy
Julie Hall
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
Hayden Maples
Negative
Comments
Submitted
6
Evergy
Tiffany Lake
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Affirmative
N/A
6
Great River Energy
Brian Meloy
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Abstain
N/A
6
Los Angeles Department
of Water and Power
Anton Vu
Abstain
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Negative
Comments
Submitted
6
Muscatine Power and
Water
Nicholas Burns
Affirmative
N/A
6
New York Power Authority
Shelly Dineen
Negative
Comments
Submitted
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Affirmative
N/A
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Affirmative
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Affirmative
N/A
6
Omaha Public Power
District
Shonda McCain
Affirmative
N/A
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
None
N/A
Abstain
N/A
6
PSEG - PSEG Energy
Laura Wu
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Resources and Trade LLC
Denise Sanchez
Segment
Organization
Voter
6
Public Utility District No. 1
of Chelan County
Tamarra Hardie
6
Sacramento Municipal
Utility District
Charles Norton
6
Salt River Project
Timothy Singh
6
Seminole Electric
Cooperative, Inc.
6
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Tim Kelley
Affirmative
N/A
Israel Perez
Affirmative
N/A
Bret Galbraith
Abstain
N/A
Snohomish County PUD
No. 1
John Liang
None
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
None
N/A
6
WEC Energy Group, Inc.
David Boeshaar
Affirmative
N/A
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Abstain
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Negative
Comments
Submitted
10
Western Electricity
Coordinating Council
Steven Rueckert
Abstain
N/A
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/321)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 | Non-binding Poll IN 1 NB
Voting Start Date: 4/12/2024 12:01:00 AM
Voting End Date: 4/22/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 222
Total Ballot Pool: 251
Quorum: 88.45
Quorum Established Date: 4/22/2024 3:26:39 PM
Weighted Segment Value: 25.15
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
1
71
1
12
0.273
32
0.727
20
7
Segment:
2
7
0.2
0
0
2
0.2
3
2
Segment:
3
51
1
10
0.244
31
0.756
7
3
Segment:
4
14
0.9
3
0.3
6
0.6
3
2
Segment:
5
62
1
12
0.273
32
0.727
10
8
Segment:
6
41
1
4
0.16
21
0.84
9
7
Segment:
7
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
Segment:
9
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
10
5
0.2
1
0.1
1
0.1
3
0
Totals:
251
5.3
42
1.349
125
3.951
55
29
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Abstain
N/A
1
Ameren - Ameren
Services
Tamara Evey
Abstain
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
None
N/A
1
Arkansas Electric
Cooperative Corporation
Emily Corley
Abstain
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
Abstain
N/A
1
Avista - Avista
Corporation
Mike Magruder
Abstain
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
BC Hydro and Power
Authority
Adrian Andreoiu
Negative
Comments
Submitted
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
None
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Abstain
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Comments
Submitted
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Comments
Submitted
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Negative
Comments
Submitted
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Negative
Comments
Submitted
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
Negative
Comments
Submitted
1
Glencoe Light and Power
Terry Volkmann
Commission
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB02
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
1
Great River Energy
Gordon Pietsch
1
Hydro One Networks, Inc.
Emma Halilovic
1
IDACORP - Idaho Power
Company
Sean Steffensen
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
1
International Transmission
Company Holdings
Corporation
Michael Moltane
1
JEA
1
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Abstain
N/A
None
N/A
Denise Sanchez
Affirmative
N/A
Gail Elliott
Affirmative
N/A
Joseph McClung
Negative
Comments
Submitted
KAMO Electric
Cooperative
Micah Breedlove
Negative
Comments
Submitted
1
Lakeland Electric
Larry Watt
Negative
Comments
Submitted
1
Lincoln Electric System
Josh Johnson
Abstain
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Comments
Submitted
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Abstain
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Negative
Comments
Submitted
1
National Grid USA
Michael Jones
Negative
Comments
Submitted
Affirmative
N/A
1
NB Power Corporation
Jeffrey Streifling
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ijad Dewan
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Negative
Comments
Submitted
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Negative
Comments
Submitted
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Negative
Comments
Submitted
1
Omaha Public Power
District
Doug Peterchuck
Negative
Comments
Submitted
1
Oncor Electric Delivery
Byron Booker
Broc Bruton
Abstain
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Bob Cardle
Negative
Comments
Submitted
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
None
N/A
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Abstain
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
None
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Negative
Comments
Submitted
1
Salt River Project
Matthew
Jaramilla
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
Abstain
N/A
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
Abstain
N/A
Affirmative
N/A
1
Sempra - San Diego Gas
Mohamed
and Electric
Derbas
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Negative
Comments
Submitted
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Abstain
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Negative
Comments
Submitted
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Negative
Comments
Submitted
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Sam Rugel
Abstain
N/A
1
Western Area Power
Administration
Ben Hammer
Negative
Comments
Submitted
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Abstain
N/A
2
ISO New England, Inc.
John Pearson
None
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Abstain
N/A
2
New York Independent
System Operator
Gregory Campoli
None
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Abstain
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Jennie Wike
Elizabeth Davis
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Abstain
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
Comments
Submitted
3
Austin Energy
Lovita Griffin
Negative
Comments
Submitted
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Negative
Comments
Submitted
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Comments
Submitted
3
CMS Energy - Consumers
Energy Company
Karl Blaszkowski
Negative
Comments
Submitted
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Negative
Comments
Submitted
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Entergy
James Keele
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
Hayden Maples
Negative
Comments
Submitted
3
Evergy
Marcus Moor
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
3
Exelon
Kinte Whitehead
Negative
Comments
Submitted
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Negative
Comments
Submitted
3
Great River Energy
Michael
Brytowski
Negative
Comments
Submitted
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Negative
Comments
Submitted
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Abstain
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
None
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
Comments
Submitted
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Abstain
N/A
3
National Grid USA
Brian Shanahan
Negative
Comments
Submitted
3
Nebraska Public Power
District
Tony Eddleman
Abstain
N/A
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Negative
Comments
Submitted
Negative
Comments
Submitted
3
NW Electric Power
Heath Henry
Cooperative, Inc.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Negative
Comments
Submitted
3
Omaha Public Power
District
David Heins
Negative
Comments
Submitted
3
Pacific Gas and Electric
Company
Sandra Ellis
Negative
Comments
Submitted
3
Platte River Power
Authority
Richard Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Negative
Comments
Submitted
3
PPL - Louisville Gas and
Electric Co.
James Frank
None
N/A
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Abstain
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Negative
Comments
Submitted
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Marc Sedor
Abstain
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
Comments
Submitted
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Ryan Walter
Negative
Comments
Submitted
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Alliant Energy Corporation
Services, Inc.
Larry Heckert
Negative
Comments
Submitted
4
Austin Energy
Tony Hua
Abstain
N/A
4
Buckeye Power, Inc.
Jason Procuniar
Negative
Comments
Submitted
4
CMS Energy - Consumers
Energy Company
Aric Root
Negative
Comments
Submitted
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Negative
Comments
Submitted
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Negative
Comments
Submitted
4
Oklahoma Municipal
Power Authority
Michael Watt
None
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Abstain
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Negative
Comments
Submitted
4
Seminole Electric
Cooperative, Inc.
Ken Habgood
Abstain
N/A
4
Utility Services, Inc.
Carver Powers
None
N/A
4
Western Power Pool
Kevin Conway
Affirmative
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
AES - AES Corporation
Ruchi Shah
Negative
Comments
Submitted
5
Ameren - Ameren
Missouri
Sam Dwyer
Abstain
N/A
Negative
Comments
Submitted
5
APS - Arizona Public
Andrew Smith
Service Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ryan Strom
Scott Brame
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
Comments
Submitted
5
Austin Energy
Michael Dillard
Abstain
N/A
5
Avista - Avista
Corporation
Glen Farmer
Negative
Comments
Submitted
5
BC Hydro and Power
Authority
Quincy Wang
Negative
Comments
Submitted
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
5
Bonneville Power
Administration
Juergen Bermejo
None
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
None
N/A
5
CMS Energy - Consumers
Energy Company
David
Greyerbiehl
Negative
Comments
Submitted
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Helen Wang
Negative
Comments
Submitted
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Negative
Comments
Submitted
5
Decatur Energy Center
LLC
Megan Melham
Negative
Comments
Submitted
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
5
Edison International Southern California
Edison Company
Selene Willis
5
Enel Green Power
Natalie Johnson
5
Entergy - Entergy
Services, Inc.
Gail Golden
5
Evergy
Jeremy Harris
5
FirstEnergy - FirstEnergy
Corporation
5
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
None
N/A
None
N/A
Negative
Comments
Submitted
Matthew
Augustin
Negative
Comments
Submitted
Great River Energy
Jacalynn Bentz
Negative
Comments
Submitted
5
Greybeard Compliance
Services, LLC
Mike Gabriel
Negative
Comments
Submitted
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Affirmative
N/A
5
JEA
John Babik
Negative
Comments
Submitted
5
Lincoln Electric System
Brittany Millard
Abstain
N/A
5
Los Angeles Department
of Water and Power
Glenn Barry
Abstain
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Affirmative
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Muscatine Power and
Water
Neal Nelson
Abstain
N/A
5
National Grid USA
Robin Berry
Negative
Comments
Submitted
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
David Campbell
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
5
New York Power Authority
Zahid Qayyum
5
North Carolina Electric
Membership Corporation
Reid Cashion
5
NRG - NRG Energy, Inc.
5
Designated
Proxy
Ballot
NERC
Memo
Negative
Comments
Submitted
Negative
Comments
Submitted
Patricia Lynch
Affirmative
N/A
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Negative
Comments
Submitted
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
Negative
Comments
Submitted
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Negative
Comments
Submitted
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Negative
Comments
Submitted
5
Pacific Gas and Electric
Company
Tyler Brun
Negative
Comments
Submitted
5
Pattern Operators LP
George E Brown
Negative
Comments
Submitted
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
None
N/A
5
PSEG Nuclear LLC
Tim Kucey
Abstain
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Negative
Comments
Submitted
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
Abstain
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
Negative
Comments
Submitted
5
Southern Company Leslie Burke
Southern Company
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Generation
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Negative
Comments
Submitted
5
Tennessee Valley
Authority
Darren Boehm
None
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
None
N/A
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Abstain
N/A
5
Vistra Energy
Daniel
Roethemeyer
Negative
Comments
Submitted
5
WEC Energy Group, Inc.
Clarice Zellmer
Negative
Comments
Submitted
6
AEP
Mathew Miller
Abstain
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Abstain
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Abstain
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Negative
Comments
Submitted
6
Austin Energy
Imane Mrini
Abstain
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
None
N/A
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
None
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Comments
Submitted
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
Negative
Comments
Submitted
6
Dominion - Dominion
Sean Bodkin
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Resources, Inc.
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
6
Edison International Southern California
Edison Company
Stephanie Kenny
Affirmative
N/A
6
Entergy
Julie Hall
Negative
Comments
Submitted
6
Evergy
Tiffany Lake
Negative
Comments
Submitted
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Negative
Comments
Submitted
6
Great River Energy
Brian Meloy
Negative
Comments
Submitted
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Abstain
N/A
6
Los Angeles Department
of Water and Power
Anton Vu
Abstain
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Negative
Comments
Submitted
6
Muscatine Power and
Water
Nicholas Burns
Abstain
N/A
6
New York Power Authority
Shelly Dineen
Negative
Comments
Submitted
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Negative
Comments
Submitted
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Affirmative
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Negative
Comments
Submitted
Negative
Comments
Submitted
6
Omaha Public Power
Shonda McCain
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
District
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Negative
Comments
Submitted
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
None
N/A
6
PSEG - PSEG Energy
Resources and Trade LLC
Laura Wu
Abstain
N/A
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Negative
Comments
Submitted
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
Abstain
N/A
6
Snohomish County PUD
No. 1
John Liang
None
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
None
N/A
6
WEC Energy Group, Inc.
David Boeshaar
Negative
Comments
Submitted
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Abstain
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Negative
Comments
Submitted
10
Western Electricity
Coordinating Council
Steven Rueckert
Abstain
N/A
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© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 2 of PRC-024-4 is posted for a 15-day formal comment period with additional ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process Manual
December 13, 2023
25-day formal comment period with initial ballot
March 27 - April 22, 2024
Anticipated Actions
Date
15-day formal comment period and additional ballot
June 18 – July 8, 2024
Final Ballot
July 15 – July 19, 2024
Board Adoption
August 14, 2024
Draft 2 of PRC-024-4
June 2024
Page 1 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Draft 2 of PRC-024-4
June 2024
Page 2 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
A. Introduction
1.
Title:
Frequency and Voltage Protection Settings for Synchronous Generators,
Type 1 and Type 2 Wind Resources, and Synchronous Condensers
2.
Number:
PRC-024-4
3.
Purpose:
To assure that protection of synchronous generators, type 1 and type 2
wind resources, and synchronous condensers do not cause tripping
during defined frequency and voltage excursions in support of the Bulk
Power System (BPS).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Generator Owners that apply protection listed in Sections 4.2.1 or 4.2.2.
4.1.2. Transmission Owners that apply protection listed in Section 4.2.2.
4.1.3. Transmission Owners (in the Quebec Interconnection only) that own a
BES generator step-up (GSU) transformer or main power transformer
(MPT) 1 and apply protection listed in Section 4.2.1.
4.1.4. Planning Coordinators (in the Quebec Interconnection only)
4.2. Facilities 2:
4.2.1 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the generating resource(s); or (ii)
provide signals to the generating resource(s) to trip; and are applied to
the following:
4.2.1.1
Bulk Electric System (BES) synchronous generators.
4.2.1.2
BES GSU transformer(s) for synchronous generators.
4.2.1.3
High-side of the synchronous generator-connected unit
auxiliary transformer 3 (UAT) installed on BES generating
resource(s).
4.2.1.4
Individual dispersed power producing type 1 or type 2 wind
resource(s) identified in the BES Definition, Inclusion I4.
1
For the purpose of this standard, the MPT is the power transformer that steps up voltage from multiple small synchronous
generators (e.g. multiple small hydro generators connecting to a common bus) or from a type 1 or type 2 wind resource
collector station to transmission voltage .
2 It is not required to install or activate the protections described in Facilities Section 4.2.
3 These transformers are variously referred to as station power UAT, or station service transformer(s) used to provide overall
auxiliary power to the synchronous generators. This UAT is the transformer connected on the generator bus between the low
side of the GSU and the generator terminal.
Draft 2 of PRC-024-4
June 2024
Page 3 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
4.2.1.5
Elements that are designed primarily for the delivery of
capacity from multiple synchronous generators connecting to
a common bus or individual dispersed power producing type 1
or type 2 wind resources identified in the BES Definition,
Inclusion I4, to the point where those resources aggregate to
greater than 75 MVA.
4.2.1.6
MPT of multiple synchronous generators connecting to a
common bus or MPT of individual dispersed power producing
type 1 or type 2 wind resources as identified in the BES
Definition, Inclusion I4.
4.2.2 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip transmission connected synchronous
condensers; or (ii) provide signals to trip transmission connected
synchronous condenser and are applied to the following:
4.2.2.1
BES synchronous condensers
4.2.2.2
BES step-up transformer(s) for synchronous condensers.
4.2.2.3
High-side of the synchronous condenser-connected unit
auxiliary transformer (UAT).
4.2.3 Exemptions: Protection on all auxiliary equipment within the
synchronous generator, type 1 or type 2 wind resource, or synchronous
condenser Facility.
5.
Effective Date: See Implementation Plan for PRC-024-4
Draft 2 of PRC-024-4
June 2024
Page 4 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
B. Requirements and Measures
R1.
Each Generator Owner and Transmission Owner shall set applicable frequency
protection 4 in accordance with PRC-024-4 Attachment 1 such that the applicable
protection does not cause the Facility to which it is applied to trip within the “no trip
zone” during a frequency excursion with the following exceptions: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•
Applicable frequency protection may be set to trip within a portion of the “no
trip zone” for documented and communicated regulatory or equipment
limitations in accordance with Requirement R3.
M1. Each Generator Owner and Transmission Owner shall have evidence that the
applicable frequency protection has been set in accordance with Requirement R1,
such as dated setting sheets, calibration sheets, calculations, or other documentation.
R2.
Each Generator Owner and Transmission Owner shall set applicable voltage
protection 5 in accordance with PRC-024-4 Attachment 2, such that the applicable
protection does not cause the Facility to which it is applied trip within the “no trip
zone” during a voltage excursion at the high-side of the GSU or MPT, subject to the
following exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
•
If the Transmission Planner allows less stringent voltage protection settings than
those required to meet PRC-024-4 Attachment 2, then the Generator Owner or
Transmission Owner may set its protection within the voltage recovery
characteristics of a location-specific Transmission Planner’s study.
•
Applicable voltage protection may be set to trip during a voltage excursion
within a portion of the “no trip zone” for documented and communicated
regulatory or equipment limitations in accordance with Requirement R3.
M2. Each Generator Owner and Transmission Owner shall have evidence that applicable
voltage protection has been set in accordance with Requirement R2, such as dated
setting sheets, voltage-time boundaries, calibration sheets, coordination plots,
dynamic simulation studies, calculations, or other documentation.
R3.
Each Generator Owner and Transmission Owner shall document each known
regulatory or equipment limitation 6 that prevents an its synchronous generator, type
1 or type 2 wind resource, or synchronous condenser, with applicable 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
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to same to trip.
5 Ibid.
6 Excludes limitations caused by the setting capability of the frequency, voltage, and volts per hertz protective relays applied to
the synchronous generator(s), type 1 and type 2 wind resource(s), and condenser(s). This does not exclude limitations
originating in the equipment protected by the relay(s).
4
Draft 2 of PRC-024-4
June 2024
Page 5 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
manufacturer’s advice. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
3.1. The Generator Owner and Transmission Owner shall communicate the
documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and
Transmission Planner within 30 calendar days of any of the following:
•
Identification of a regulatory or equipment limitation.
•
Repair of the equipment causing the limitation that removes the limitation.
•
Replacement of the equipment causing the limitation with equipment that
removes the limitation.
•
Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life-time frequency excursion allowance.
M3. Each Generator Owner and Transmission Owner shall have evidence that it has
documented and communicated any known regulatory or equipment limitations that
resulted in an exception to Requirements R1 or R2 in accordance with Requirement
R3, such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
R4.
Each Generator Owner and Transmission Owner shall provide its applicable protection
settings associated with Requirements R1 and R2 to the Planning Coordinator or
Transmission Planner that models the associated Facility within 60 calendar days of
receipt of a written request for the data and within 60 calendar days of any change to
those previously requested settings unless directed by the requesting Planning
Coordinator or Transmission Planner that the reporting of protection setting changes
is not required. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M4. Each Generator Owner and Transmission Owner shall have evidence that it
communicated applicable protection settings in accordance with Requirement R4,
such as dated e-mails, correspondence or other evidence and copies of any requests it
has received for that information.
Draft 2 of PRC-024-4
June 2024
Page 6 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
The Generator Owner and Transmission Owner shall keep data or evidence
of Requirements R1 through R4 for five years or until the next audit,
whichever is longer.
•
If a Generator Owner or Transmission Owner is found non-compliant, the
Generator Owner or Transmission Owner shall keep information related to
the non-compliance until mitigation is complete and approved for the time
period specified above, whichever is longer.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Draft 2 of PRC-024-4
June 2024
Page 7 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
R1.
N/A
N/A
N/A
R2.
N/A
N/A
N/A
R3.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 30 calendar days but less
than or equal to 60 calendar
days of identifying the
limitation.
Draft 2 of PRC-024-4
June 2024
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 60 calendar days but less
than or equal to 90 calendar
days of identifying the
limitation.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 90 calendar days but less
than or equal to 120 calendar
days of identifying the
limitation.
Severe VSL
The Generator Owner or
Transmission Owner failed to
set its applicable frequency
protection so that it does not
trip according to Requirement
R1.
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does not
trip according to Requirement
R2.
The Generator Owner or
Transmission Owner failed to
document any known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar
Page 8 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
days of identifying the
limitation.
R4.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 60 calendar days but less
than or equal to 90 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 90 calendar days but less
than or equal to 120 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 120 calendar days but less
than or equal to 150 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner failed to
provide its protection settings
within 150 calendar days of any
change to those settings.
OR
OR
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
60 calendar days but less than
or equal to 90 calendar days of
a written request.
The Generator Owner or
Transmission Owner provided
protection settings more than
90 calendar days but less than
or equal to 120 calendar days
of a written request.
The Generator Owner or
Transmission Owner or
provided protection settings
more than 120 calendar days
but less than or equal to 150
calendar days of a written
request.
The Generator Owner or
Transmission Owner failed to
provide protection settings
within 150 calendar days of a
written request.
Draft 2 of PRC-024-4
June 2024
OR
Page 9 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
D. Regional Variances
D.A.
Variance for the Quebec Interconnection
This Variance replaces Requirement R2 of the continent-wide standard in its entirety
and adds a new requirement, Requirement D.A.5., applicable to Planning
Coordinators in the Quebec Interconnection.
This Variance replaces continent-wide Requirement R2 in its entirety with the
following:
D.A.2.
Each Generator Owner and Transmission Owner shall set applicable
voltage protection 7 in accordance with PRC-024 Attachment 2B, such that
the applicable protection does not cause the Facility to which it is applied
to trip within the “no trip zone” during a voltage excursion at the
high-side of the GSU or MPT, subject to the following exceptions:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
•
For newly designated strategic power plants, applicable protections
must comply with the high voltage durations for such plants within 48
calendar months of the notification made pursuant to Requirement
D.A.5. During this transition period, voltage protections must at least
comply with the high voltage durations for “all power plants”.
•
Applicable voltage protection may be set to trip during a voltage
excursion within a portion of the “no trip zone” of PRC-024
Attachment 2B for documented and communicated regulatory or
equipment limitations in accordance with Requirement R3.
•
If the Transmission Planner allows less stringent voltage protection
settings than those required to meet PRC-024 Attachment 2B, then
the Generator Owner or Transmission Owner may set its protection
within the voltage recovery characteristics of a location-specific
Transmission Planner’s study.
M.D.A.2. Each Generator Owner and Transmission Owner shall have evidence that
applicable voltage protection has been set in accordance with
Requirement R2, such as dated setting sheets, voltage-time boundaries,
calibration sheets, coordination plots, dynamic simulation studies,
calculations, or other documentation.
This Variance adds the following Requirement:
D.A.5
Each Planning Coordinator shall designate, at least once every five
calendar years, the strategic power plants that must comply with
Attachment 2B and notify, within 30 calendar days of its designation,
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to same to trip.
7
Draft 2 of PRC-024-4
June 2024
Page 10 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
each Generator Owner or Transmission Owner that owns facilities 8 in the
strategic power plants. [Violation Risk Factor: Medium] [Time Horizon:
Long-term planning]
M.D.A.5
Each Planning Coordinator shall have evidence that it designated, at least
once every five calendar years, strategic power plants in accordance with
Requirement D.A.5, Part 5 and shall have dated evidence that each
Generator Owner or Transmission Owner has been notified in accordance
with Requirement D.A.5, part 5.2. Evidence may include, but is not
limited to letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
Facilities in the strategic power plants include facilities with synchronous generator(s) from the generator up to and including
the MPT or GSU.
8
Draft 2 of PRC-024-4
June 2024
Page 11 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
This Variance adds a VSL for D.A.5 and modifies the VSL for R2 as follows:
R#
D.A.2.
Violation Severity Levels
Lower
VSL
N/A
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Generator Owner or Transmission
Owner failed to set its applicable
voltage protection so that it does not
trip in accordance with Requirement
D.A.2.
OR
D.A.5.
N/A
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or Transmission
Owner that owns facilities in the
strategic power plants between 31
days and 45 days after its designation.
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or Transmission
Owner that owns facilities in the
strategic power plants between 46
days and 60 days after its designation.
The Generator Owner or Transmission
Owner set its applicable voltage
protection in accordance with
Requirement D.A.2 but, for strategic
power plants, failed to do so within 48
months of notification.
The Planning Coordinator failed to
designate, at least once every five
years, the strategic power plants that
must comply with Attachment 2B.
OR
The Planning Coordinator failed to
notify, each Generator Owner or
Transmission Owner that owns
facilities in the strategic power plants
or notified them more than 60 days
after its designation.
E. Associated Documents
Implementation Plan
Draft 2 of PRC-024-4
June 2024
Page 12 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Version History
Version
Date
Action
Change Tracking
1
May 9, 2013
Adopted by the NERC Board of
Trustees
1
March 20, 2014
FERC Order issued approving PRC024-1. (Order becomes effective on
7/1/16.)
2
February 12, 2015
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2014-01:
Applicability revised to
clarify application of
requirements to BES
dispersed power
producing resources
2
May 29, 2015
FERC Letter Order in Docket No.
RD15-3-000 approving PRC-024-2
Modifications to adjust
the applicability to
owners of dispersed
generation resources.
3
February 6, 2020
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2018-04
3
July 9, 2020
FERC Letter Order approved PRC0243. Docket No. RD20-7-000
3
July 17, 2020
Effective Date
10/1/2022
4
TBD
Revisions made by the 2020-02
Drafting Team
Revision
Draft 2 of PRC-024-4
June 2024
Page 13 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 1
(Frequency No Trip Boundaries by Interconnection 9)
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1: Eastern Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 1: Frequency Boundary Data Points - Eastern Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥60.5
Instantaneous 10
10(90.935-1.45713*f)
≤57.8
≤59.5
Instantaneous11
10(1.7373*f-100.116)
<60.5
Continuous operation
> 59.5
Continuous operation
The figures do not visually represent the “no trip zone” boundaries before 0.1 seconds and after 10,000 seconds. The
Frequency Boundary Data Points Table defines the entirety of the “no trip zone” boundaries.
10 Frequency is calculated over a window of time. While the frequency boundaries include the option to trip instantaneously for
frequencies outside the specified range, this calculation should occur over a time window. Typical window/filtering lengths are
three to six cycles (50 – 100 milliseconds). Instantaneous trip settings based on instantaneously calculated frequency
measurement is not permissible.
9
Draft 2 of PRC-024-4
June 2024
Page 14 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
63
Frequency (Hz)
62
61
60
59
No Trip Zone*
58
57
56
0.1
1
10
100
1000
10000
Time (Sec)
Figure 2: Western Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 2: Frequency Boundary Data Points – Western Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.7
≥61.6
≥60.6
<60.6
Instantaneous11
30
180
Continuous operation
≤57.0
≤57.3
≤57.8
≤58.4
≤59.4
Instantaneous11
0.75
7.5
30
180
>59.4
Continuous operation
Draft 2 of PRC-024-4
June 2024
Page 15 of 22
Frequency (Hz)
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
67
66
65
64
63
62
61
60
59
58
57
56
55
No Trip Zone*
0.1
1
10
100
1000
10000
Time (Sec)
Figure 3: Quebec Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 3: Frequency Boundary Data Points – Quebec Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (Sec)
>66.0
Instantaneous11
<55.5
Instantaneous11
≥63.0
5
≤56.5
0.35
≥61.5
90
≤57.0
2
≥60.6
660
≤57.5
10
<60.6
Continuous operation
≤58.5
90
≤59.4
660
>59.4
Continuous operation
Draft 2 of PRC-024-4
June 2024
Page 16 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 4: ERCOT Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 4: Frequency Boundary Data Points – ERCOT Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
Instantaneous11
≤57.5
Instantaneous11
≥61.6
30
≤58.0
2
≥60.6
540
≤58.4
30
<60.6
Continuous operation
≤59.4
540
>59.4
Continuous operation
Draft 2 of PRC-024-4
June 2024
Page 17 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
PRC-024 — Attachment 2
Voltage (per unit)8
(Voltage No-Trip Boundaries – Eastern, Western, and ERCOT Interconnections)
1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
The Voltage No Trip Zone ends at 4
seconds for applicability to PRC-024
No Trip Zone*
0
0.5
1
1.5
2
2.5
Time (sec)
High Voltage Duration
3
3.5
4
Low Voltage Duration
Figure 5: Voltage No-Trip Boundaries – Eastern, Western, and ERCOT
Interconnections
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 5: Voltage Boundary Data Points
High Voltage Duration
Low Voltage Duration
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
≥1.200
≥1.175
≥1.15
≥1.10
<1.10
0.00
0.20
0.50
1.00
4.00
<0.45
<0.65
<0.75
<0.90
≥ 0.90
0.15
0.30
2.00
3.00
4.00
Draft 2 of PRC-024-4
June 2024
Page 18 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 2A: Voltage Boundary Clarifications – Eastern, Western,
and ERCOT Interconnections
Boundary Details:
1. Unless otherwise specified by the Transmission Planner, the per unit voltage base for
these boundaries is the nominal transmission system voltage (e.g., 100 kV, 115 kV, 138
kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the boundaries assume RMS fundamental frequency phase-to-ground or
phase-to-phase per unit voltage.
5. For applicability to PRC-024, the “no trip zone” ends at 4 seconds.
Evaluating Protection Settings:
The voltage values in the Attachment 2 voltage boundaries are voltages at the high-side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high-side of the transformer with a low side below 100kV and a high-side 100kV or above.
When evaluating protection settings, consider the voltage differences between where the
protection is measuring voltage and the high-side of the GSU/MPT. A steady state calculation or
dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high-side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Draft 2 of PRC-024-4
June 2024
Page 19 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
PRC-024— Attachment 2B
(Voltage No-Trip Boundaries – Quebec Interconnection)
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
0 0.1
0.033
0.15
2.5
0.5
1
2
3
4
5
30
300
Time (sec)
Low Voltage/High Voltage Duration – Synchronous Generators and Condensers
High Voltage Duration - Strategic Power Plants
Figure 6: Voltage No-Trip Boundaries – Quebec Interconnection
* The area outside the “No Trip Zone” is not a “Must Trip Zone.”
Draft 2 of PRC-024-4
June 2024
Page 20 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Table 6: High Voltage Boundary Data Points – Quebec Interconnection
High Voltage Duration for all
Synchronous Generators and
Condensers
High Voltage Duration for strategic
Power Plants
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
-->1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
--0.033
0.10
2.00
30
300
continuous
>1.50
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
0.033
0.10
2.50
5.00
30
300
continuous
Table 7: Low Voltage Boundary Data Points – Quebec Interconnection
Low Voltage Duration for all
Synchronous Generators and
Condensers
Draft 2 of PRC-024-4
June 2024
Voltage (per unit)
Minimum Time (sec)
<0.25
<0.75
<0.85
<0.90
≥0.90
0.15
1.00
2.00
30
continuous
Page 21 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 2C: Voltage Boundary Clarifications – Quebec
Interconnection
Boundary Details:
1. The per unit voltage base for these boundaries is the nominal operating voltage (e.g.,
120 kV, 161 kV, 230 kV, 315 kV, 735 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the Quebec Interconnection boundaries assume positive-sequence values.
Evaluating Protection Settings:
The voltage values in the Attachment 2B voltage boundaries are voltages at the high-side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high-side of the transformer that connects to the interconnecting voltage. When evaluating
protection settings, consider the voltage differences between where the protection is
measuring voltage and the high-side of the GSU/MPT. A steady state calculation or dynamic
simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high-side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Draft 2 of PRC-024-4
June 2024
Page 22 of 22
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 2 of PRC‐024‐4 is posted for a 15‐day formal comment period with additional ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process Manual
December 13, 2023
25‐day formal comment period with initial ballot
March 27 ‐ April 22, 2024
Anticipated Actions
Date
15‐day formal comment period and additional ballot
June 18 – July 8, 2024
Final Ballot
July 15 – July 19, 2024
Board Adoption
August 14, 2024
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 1 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 2 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
A. Introduction
1.
Title:
Frequency and Voltage Protection Settings for Synchronous Generators,
Type 1 and Type 2 Wind Resources, and Synchronous Condensers
2.
Number:
PRC‐024‐4
3.
Purpose:
To assure that protection of synchronous generators, type 1 and type 2
wind resources, and synchronous condensers do not cause tripping
during defined frequency and voltage excursions in support of the Bulk
Power System (BPS).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Generator Owners that apply protection listed in Sections 4.2.1 or 4.2.2.
4.1.2. Transmission Owners that apply protection listed in Section 4.2.2.
4.1.3. Transmission Owners (in the Quebec Interconnection only) that own a
BES generator step‐up (GSU) transformer or main power transformer
(MPT)1 and apply protection listed in Section 4.2.1.
4.1.4. Planning Coordinators (in the Quebec Interconnection only)
4.2. Facilities2:
4.2.1 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the generating resource(s); or (ii)
provide signals to the generating resource(s) to trip; and are applied to
the following:
4.2.1.1
Bulk Electric System (BES) synchronous generators.
4.2.1.2
BES GSU transformer(s) for synchronous generators.
4.2.1.3
High‐side of the synchronous generator‐connected unit
auxiliary transformer3 (UAT) installed on BES generating
resource(s).
4.2.1.4
Individual dispersed power producing type 1 or type 2 wind
resource(s) identified in the BES Definition, Inclusion I4.
1
For the purpose of this standard, the MPT is the power transformer that steps up voltage from multiple small synchronous
generators, (e.g. multiple small hydro generators connecting to a common bus) or from a type 1 or type 2 wind resource
collector station to transmission voltage .
2 It is not required to install or activate the protections described in Facilities Section 4.2.
3 These transformers are variously referred to as station power UAT, or station service transformer(s) used to provide overall
auxiliary power to the synchronous generators. This UAT is the transformer connected on the generator bus between the low
side of the GSU and the generator terminal.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 3 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
4.2.1.44.2.1.5 Elements that are designed primarily for the delivery of
capacity from multiple synchronous generators connecting to
a common bus or individual dispersed power producing type 1
or type 2 wind resources identified in the BES Definition,
Inclusion I4, to the point where those resources aggregate to
greater than 75 MVA.
4.2.1.54.2.1.6 MPT of multiple synchronous generators connecting to a
common bus or MPT of individual dispersed power producing
type 1 or type 2 wind resources as identified in the BES
Definition, Inclusion I4.
4.2.2 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip transmission connected synchronous
condensers; or (ii) provide signals to trip transmission connected
synchronous condenser and are applied to the following:
4.2.2.1
BES synchronous condensers
4.2.2.2
BES step‐up transformer(s) for synchronous condensers.
4.2.2.3
High‐side of the synchronous condenser‐connected unit
auxiliary transformer (UAT).
4.2.3 Exemptions: Protection on all auxiliary equipment within the
synchronous generator, type 1 or type 2 wind resource, or synchronous
condenser Facility.
5.
Effective Date: See Implementation Plan for PRC‐024‐4
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 4 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
B. Requirements and Measures
R1.
Each Generator Owner and Transmission Owner shall set applicable frequency
protection4 in accordance with PRC‐024‐4 Attachment 1 such that the applicable
protection does not cause the synchronous generator(s) or condenser(s)Facility to
which it is applied to trip within the “no trip zone” during a frequency excursion with
the following exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long‐term
Planning]
Applicable frequency protection may be set to trip within a portion of the “no
trip zone” for documented and communicated regulatory or equipment
limitations in accordance with Requirement R3.
M1. Each Generator Owner and Transmission Owner shall have evidence that the
applicable frequency protection has been set in accordance with Requirement R1,
such as dated setting sheets, calibration sheets, calculations, or other documentation.
R2.
Each Generator Owner and Transmission Owner shall set applicable voltage
protection5 in accordance with PRC‐024‐4 Attachment 2, such that the applicable
protection does not cause the synchronous generator(s) or condenser(s)Facility to
which it is applied trip within the “no trip zone” during a voltage excursion at the high‐
side of the GSU or MPT, subject to the following exceptions: [Violation Risk Factor:
Medium] [Time Horizon: Long‐term Planning]
If the Transmission Planner allows less stringent voltage protection settings than
those required to meet PRC‐024‐4 Attachment 2, then the Generator Owner or
Transmission Owner may set its protection within the voltage recovery
characteristics of a location‐specific Transmission Planner’s study.
Applicable voltage protection may be set to trip during a voltage excursion
within a portion of the “no trip zone” for documented and communicated
regulatory or equipment limitations in accordance with Requirement R3.
M2. Each Generator Owner and Transmission Owner shall have evidence that applicable
voltage protection has been set in accordance with Requirement R2, such as dated
setting sheets, voltage‐time boundaries, calibration sheets, coordination plots,
dynamic simulation studies, calculations, or other documentation.
R3.
Each Generator Owner and Transmission Owner shall document each known
regulatory or equipment limitation6 that prevents an applicableits synchronous
generator(s), type 1 or type 2 wind resource, or synchronous condenser(s), with
applicable frequency or voltage protection from meeting the protection setting
criteria in Requirements R1 or R2, including (but not limited to) study results,
4 Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s)), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to the synchronous generator(s) or condenser(s)same to trip.
5 Ibid.
6 Excludes limitations caused by the setting capability of the frequency, voltage, and volts per hertz protective relays forapplied
to the synchronous generator(s) or), type 1 and type 2 wind resource(s), and condenser(s). This does not exclude limitations
originating in the equipment protected by the relay.(s).
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 5 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
experience from an actual event, or manufacturer’s advice. [Violation Risk Factor:
Lower] [Time Horizon: Long‐term Planning]
3.1. The Generator Owner and Transmission Owner shall communicate the
documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and
Transmission Planner within 30 calendar days of any of the following:
Identification of a regulatory or equipment limitation.
Repair of the equipment causing the limitation that removes the limitation.
Replacement of the equipment causing the limitation with equipment that
removes the limitation.
Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life‐time frequency excursion allowance.
M3. Each Generator Owner and Transmission Owner shall have evidence that it has
documented and communicated any known regulatory or equipment limitations that
resulted in an exception to Requirements R1 or R2 in accordance with Requirement
R3, such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
R4.
Each Generator Owner and Transmission Owner shall provide its applicable protection
settings associated with Requirements R1 and R2 to the Planning Coordinator or
Transmission Planner that models the associated synchronous generator(s) or
condenser(s)Facility within 60 calendar days of receipt of a written request for the
data and within 60 calendar days of any change to those previously requested settings
unless directed by the requesting Planning Coordinator or Transmission Planner that
the reporting of protection setting changes is not required. [Violation Risk Factor:
Lower] [Time Horizon: Operations Planning]
M4. Each Generator Owner and Transmission Owner shall have evidence that it
communicated applicable protection settings in accordance with Requirement R4,
such as dated e‐mails, correspondence or other evidence and copies of any requests it
has received for that information.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 6 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full‐time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
The Generator Owner and Transmission Owner shall keep data or evidence
of Requirements R1 through R4 for five years or until the next audit,
whichever is longer.
If a Generator Owner or Transmission Owner is found non‐compliant, the
Generator Owner or Transmission Owner shall keep information related to
the non‐compliance until mitigation is complete and approved for the time
period specified above, whichever is longer.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 7 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
R2.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
set its applicable frequency
protection so that it does not
trip according to Requirement
R1.
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does not
trip according to Requirement
R2.
The Generator Owner or
Transmission Owner failed to
document any known non‐
protection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar
R3.
The Generator Owner or
Transmission Owner
documented the known non‐
protection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 30 calendar days but less
than or equal to 60 calendar
days of identifying the
limitation.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
The Generator Owner or
Transmission Owner
documented the known non‐
protection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 60 calendar days but less
than or equal to 90 calendar
days of identifying the
limitation.
The Generator Owner or
Transmission Owner
documented the known non‐
protection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 90 calendar days but less
than or equal to 120 calendar
days of identifying the
limitation.
Page 8 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
days of identifying the
limitation.
R4.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 60 calendar days but less
than or equal to 90 calendar
days of any change to those
settings.
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
60 calendar days but less than
or equal to 90 calendar days of
a written request.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
The Generator Owner or
Transmission Owner provided
its protection settings more
than 90 calendar days but less
than or equal to 120 calendar
days of any change to those
settings.
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
90 calendar days but less than
or equal to 120 calendar days
of a written request.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 120 calendar days but less
than or equal to 150 calendar
days of any change to those
settings.
OR
The Generator Owner or
Transmission Owner or
provided protection settings
more than 120 calendar days
but less than or equal to 150
calendar days of a written
request.
The Generator Owner or
Transmission Owner failed to
provide its protection settings
within 150 calendar days of any
change to those settings.
OR
The Generator Owner or
Transmission Owner failed to
provide protection settings
within 150 calendar days of a
written request.
Page 9 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
D. Regional Variances
D.A.
Variance for the Quebec Interconnection
This Variance replaces Requirement R2 of the continent‐wide standard in its entirety
and adds a new requirement, Requirement D.A.5., applicable to Planning
Coordinators in the Quebec Interconnection.
This Variance replaces continent‐wide Requirement R2 in its entirety with the
following:
D.A.2.
Each Generator Owner and Transmission Owner shall set applicable
voltage protection67 in accordance with PRC‐024 Attachment 2B, such
that the applicable protection does not cause the synchronous
generator(s) or condenser(s)Facility to which it is applied to trip within
the “no trip zone” during a voltage excursion at the high‐‐side of the GSU
or MPT, subject to the following exceptions: [Violation Risk Factor:
Medium] [Time Horizon: Long‐term Planning]
For newly designated strategic power plants, applicable protections
must comply with the high voltage durations for such plants within 48
calendar months of the notification made pursuant to Requirement
D.A.5. During this transition period, voltage protections must at least
comply with the high voltage durations for “all power plants”.
Synchronous generator(s) are permitted toApplicable voltage
protection may be set to trip during a voltage excursion bounded
bywithin a portion of the “no trip zone” of PRC‐024 Attachment 2B
for documented and communicated regulatory or equipment
limitations in accordance with Requirement R3.
If the Transmission Planner allows less stringent voltage protection
settings than those required to meet PRC‐024 Attachment 2B, then
the Generator Owner or Transmission Owner may set its protection
within the voltage recovery characteristics of a location‐specific
Transmission Planner’s study.
M.D.A.2. Each Generator Owner and Transmission Owner shall have evidence that
applicable voltage protection has been set in accordance with
Requirement R2, such as dated setting sheets, voltage‐time boundaries,
calibration sheets, coordination plots, dynamic simulation studies,
calculations, or other documentation.
This Variance adds the following Requirement:
D.A.5
Each Planning Coordinator shall designate, at least once every five
calendar years, the strategic power plants that must comply with
7 Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to same to trip.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 10 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Attachment 2B and notify, within 30 calendar days of its designation,
each Generator Owner or Transmission Owner that owns facilities8 in the
strategic power plants. [Violation Risk Factor: Medium] [Time Horizon:
Long‐term planning]
M.D.A.5 Each Planning Coordinator shall have evidence that it designated, at least
once every five calendar years, strategic power plants in accordance with
Requirement D.A.5, Part 5 and shall have dated evidence that each
Generator Owner or Transmission Owner has been notified in accordance
with Requirement D.A.5, part 5.2. Evidence may include, but is not
limited to letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
8 Facilities in the strategic power plants include facilities with synchronous generator(s) from the generator up to and including
the MPT or GSU.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 11 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
This Variance adds a VSL for D.A.5 and modifies the VSL for R2 as follows:
Violation Severity Levels
R#
D.A.2.
Lower
VSL
N/A
D.A.5.
N/A
Moderate VSL
High VSL
N/A
N/A
Severe VSL
The Generator Owner or Transmission
Owner failed to set its applicable
voltage protection so that it does not
trip in accordance with Requirement
D.A.2.
OR
The Generator Owner or Transmission
Owner set its applicable voltage
protection in accordance with
Requirement D.A.2 but, for strategic
power plants, failed to do so within 48
months of notification.
The Planning Coordinator designated
The Planning Coordinator failed to
The Planning Coordinator designated
strategic power plants at least once
designate, at least once every five
strategic power plants at least once
years, the strategic power plants that
every five calendar years but notified
every five calendar years but notified
each Generator Owner or Transmission each Generator Owner or Transmission must comply with Attachment 2B.
Owner that owns facilities in the
Owner that owns facilities in the
strategic power plants between 31
strategic power plants between 46
OR
days and 45 days after its designation. days and 60 days after its designation.
The Planning Coordinator failed to
notify, each Generator Owner or
Transmission Owner that owns
facilities in the strategic power plants
or notified them more than 60 days
after its designation.
E. Associated Documents
Implementation Plan
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 12 of 23
PRC‐024‐4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Version History
Version
Date
Action
Change Tracking
1
May 9, 2013
Adopted by the NERC Board of
Trustees
1
March 20, 2014
FERC Order issued approving PRC‐
024‐1. (Order becomes effective on
7/1/16.)
2
February 12, 2015
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2014‐01:
Applicability revised to
clarify application of
requirements to BES
dispersed power
producing resources
2
May 29, 2015
FERC Letter Order in Docket No.
RD15‐3‐000 approving PRC‐024‐2
Modifications to adjust
the applicability to
owners of dispersed
generation resources.
3
February 6, 2020
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2018‐04
3
July 9, 2020
FERC Letter Order approved
PRC‐‐024‐‐3. Docket No. RD20‐7‐000
3
July 17, 2020
Effective Date
10/1/2022
4
TBD
Revisions made by the 2020‐02
Drafting Team
Revision
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 13 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
Attachment 1
(Frequency No Trip Boundaries by Interconnection9)
Eastern Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
1000
10000
Time (Sec)
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
Time (Sec)
Figure 11.1
: Eastern Interconnection Boundaries
9 The figures do not visually represent the “no trip zone” boundaries before 0.1 seconds and after 10,000 seconds. The
Frequency Boundary Data Points Table defines the entirety of the “no trip zone” boundaries.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 14 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 1: Frequency Boundary Data Points –- Eastern Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥60.5
Instantaneous10
10(90.935‐1.45713*f)
≤57.8
≤59.5
Instantaneous11
10(1.7373*f‐100.116)
<60.5
Continuous operation
> 59.5
Continuous operation
Table 1.2
10 Frequency is calculated over a window of time. While the frequency boundaries include the option to trip instantaneously for
frequencies outside the specified range, this calculation should occur over a time window. Typical window/filtering lengths are
three to six cycles (50 – 100 milliseconds). Instantaneous trip settings based on instantaneously calculated frequency
measurement is not permissible.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 15 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
Western Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
56
0.1
1
10
100
1000
10000
Time (Sec)
Figure1.3 Figure 2: Western Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 2: Frequency Boundary Data Points – Western Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.7
≥61.6
≥60.6
<60.6
Instantaneous11
30
180
Continuous operation
≤57.0
≤57.3
≤57.8
≤58.4
≤59.4
Instantaneous11
0.75
7.5
30
180
>59.4
Continuous operation
Table 1.4
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 16 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
Frequency (Hz)
Quebec Interconnection Boundaries
67
66
65
64
63
62
61
60
59
58
57
56
55
No Trip Zone*
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1.5 Figure 3: Quebec Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 3: Frequency Boundary Data Points – Quebec Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (Sec)
>66.0
Instantaneous11
<55.5
Instantaneous11
≥63.0
5
≤56.5
0.35
≥61.5
90
≤57.0
2
≥60.6
660
≤57.5
10
<60.6
Continuous operation
≤58.5
90
≤59.4
660
>59.4
Continuous operation
Table 1.6
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 17 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
ERCOT Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1.7 Figure 4: ERCOT Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 4: Frequency Boundary Data Points – ERCOT Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
Instantaneous11
≤57.5
Instantaneous11
≥61.6
30
≤58.0
2
≥60.6
540
≤58.4
30
<60.6
Continuous operation
≤59.4
540
>59.4
Continuous operation
Table 1.8
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 18 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
PRC-024 — Attachment 2
Voltage (per unit)8
(Voltage No-Trip Boundaries – Eastern, Western, and ERCOT Interconnections)
The Voltage No Trip Zone ends at 4
seconds for applicability to PRC‐024
1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
No Trip Zone*
0
0.5
1
1.5
2
2.5
3
3.5
4
Time (sec)
High Voltage Duration
11Figure 2.1
Low Voltage Duration
Figure 5: Voltage No-Trip Boundaries – Eastern, Western, and ERCOT
Interconnections
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 5: Voltage Boundary Data Points
High Voltage Duration
Low Voltage Duration
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
≥1.200
≥1.175
≥1.15
≥1.10
<1.10
0.00
0.20
0.50
1.00
4.00
<0.45
<0.65
<0.75
<0.90
≥ 0.90
0.15
0.30
2.00
3.00
4.00
Table 2.2
8Voltage at the high‐side of the GSU or MPT.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 19 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
Attachment 2A: Voltage Boundary Clarifications
( – Eastern, Western, and ERCOT Interconnections)
Boundary Details:
1. Unless otherwise specified by the Transmission Planner, the per unit voltage base for
these boundaries is the nominal transmission system voltage (e.g., 100 kV, 115 kV, 138
kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the boundaries assume RMS fundamental frequency phase‐to‐ground or
phase‐to‐phase per unit voltage.
5. For applicability to PRC‐024, the “no trip zone” ends at 4 seconds.
Evaluating Protection Settings:
The voltage values in the Attachment 2 voltage boundaries are voltages at the high‐side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high‐side of the transformer with a low side below 100kV and a high‐side 100kV or above.
When evaluating protection settings, consider the voltage differences between where the
protection is measuring voltage and the high‐side of the GSU/MPT. A steady state calculation or
dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high‐side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 20 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
PRC-024— Attachment 2B
(Voltage No-Trip Boundaries – Quebec Interconnection)
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
2.5
0 0.1
0.033
0.5
0.15
1
2
3
4
5
30
300
Time (sec)
Low Voltage/High Voltage Duration – Synchronous Generators and Condensers
High Voltage Duration - Strategic Power Plants
Figure 1
Figure 6: Voltage No-Trip Boundaries – Quebec Interconnection
* The area outside the “No Trip Zone” is not a “Must Trip Zone.”
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 21 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
Table 6: High Voltage Boundary Data Points – Quebec Interconnection
High Voltage Duration for all
Synchronous Generators and
Condensers
High Voltage Duration for strategic1
Power Plants
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
‐‐‐
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
‐‐‐
0.033
0.10
2.00
30
300
continuous
>1.50
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
0.033
0.10
2.50
5.00
30
300
continuous
Table 1
Table 7: Low Voltage Boundary Data Points – Quebec Interconnection
Low Voltage Duration for all
Synchronous Generators and
Condensers
Voltage (per unit)
Minimum Time (sec)
<0.25
<0.75
<0.85
<0.90
≥0.90
0.15
1.00
2.00
30
continuous
Table 2
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 22 of 23
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2
Wind, and Synchronous Condensers
Attachment 2C
(: Voltage Boundary Clarifications – Quebec Interconnection)
Boundary Details:
1. The per unit voltage base for these boundaries is the nominal operating voltage (e.g.,
120 kV, 161 kV, 230 kV, 315 kV, 735 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the Quebec Interconnection boundaries assume positive‐sequence values.
Evaluating Protection Settings:
The voltage values in the Attachment 2B voltage boundaries are voltages at the high‐side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high‐side of the transformer that connects to the interconnecting voltage. When evaluating
protection settings, consider the voltage differences between where the protection is
measuring voltage and the high‐side of the GSU/MPT. A steady state calculation or dynamic
simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high‐side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Initial Draft 2 of PRC‐024‐4
MarchJune 2024
Page 23 of 23
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
Initial 25-day formal comment period and additional ballot
March 27 – April 21, 2024
Anticipated Actions
Date
15-day formal comment period and additional ballot
June 18 – July 8, 2024
Final Ballot
July 16 - 20, 2024
Board adoption
August 14, 2024
Draft 2 of PRC-029-1
June 2024
Page 1 of 19
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Ride-through: Remaining connected, synchronized with the Transmission System, and
continuing to operate in response to System conditions through the time-frame of a System
Disturbance.
Draft 2 of PRC-029-1
June 2024
Page 2 of 19
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
A. Introduction
1. Title:
Resources
Frequency and Voltage Ride-through Requirements for Inverter-Based
2. Number:
PRC-029-1
3. Purpose:
To ensure that Inverter-Based Resources (IBRs) adhere to Ride-through
requirements as expected to support the Bulk Power System (BPS) during and after
defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.1.2. Transmission Owner 1
4.2
Facilities:
4.2.1. BES inverter-based resources 2
4.2.2. IBR Registration Criteria
Effective Date: See Implementation Plan for Project 2020-02 – PRC-029-1
Standard-Only Definition: None
For owners of Voltage Source Converter – High-voltage Direct Current (VSC-HVDC) transmission facilities that are
dedicated connections for IBR to the BPS
2
For the purpose of this standard, “inverter-based resources” refers to a collection of individual solar photovoltaic
(PV), Type 3 and Type 4 wind turbines, battery energy storage system (BESS), or fuel cells that operate as a single
plant/resource. In case of offshore wind plants connecting via a dedicated VSC-HVDC, the inverter-based resource
includes the VSC-HVDC system.
1
Draft 2 of PRC-029-1
June 2024
Page 3 of 19
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
B. Requirements and Measures
R1.
Each Generator Owner or Transmission Owner shall ensure the design and operation
is such that each facility adheres to Ride-through requirements, in accordance with
the “must Ride-through 3 zone” as specified in Attachment 1, except for the following:
[Violation Risk Factor: High] [Time Horizon: Operations Assessment]
•
The facility needed to electrically disconnect in order to clear a fault;
•
A documented equipment limitation exists in accordance with Requirement
R4; or
•
The instantaneous positive sequence voltage phase angle change is more than
25 electrical degrees at the high-side of the main power transformer and is
initiated by a non-fault switching event on the transmission system; or
•
The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than
2 seconds.
M1. Each Generator Owner and Transmission Owner have evidence of dynamic
simulations, studies, or other evidence to demonstrate the design of each facility will
adhere to Ride-through requirements, as specified in Requirement R1. Each
Generator Owner and Transmission Owner have evidence of actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and
Fault Recorder) to demonstrate that the operation of each facility did adhere to Ridethrough requirements, as specified in Requirement R1. If the Generator Owner and
Transmission Owner choose to utilize Ride-through exemptions that occur within the
“must Ride-through zone” and are caused by non-fault initiated phase jumps of
greater than 25 electrical degrees, then each Generator Owner and Transmission
Owner also have evidence of actual disturbance monitoring (i.e. Sequence of Event
Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate
that the facility failed to Ride-through during a phase jump of greater than or equal to
25 electrical degrees, and documentation from their Transmission Planner, Reliability
Coordinator, Planning Coordinator, or Transmission Operator that a non-fault initiated
switching event occurred.
R2. Each Generator Owner or Transmission Owner shall ensure the design and operation
is such that the voltage performance for each facility adheres to the following during
a voltage excursion, unless a documented equipment limitation exists in accordance
with Requirement R4. [Violation Risk Factor: High] [Time Horizon: Operations
Assessment]
3
Includes no tripping associated with phase lock loop loss of synchronism
Draft 2 of PRC-029-1
June 2024
Page 4 of 19
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
2.1.
While the voltage at the high-side of the main power transformer 4 remains
within the continuous operation region as specified in Attachment 1, each
facility shall:
2.1.1 Continue to deliver the pre-disturbance level of active power or
available active power, whichever is less. 5
2.1.2 Continue to deliver reactive power up to its reactive power limit and
according to its controller settings.
2.1.3 If the facility cannot deliver both active and reactive power due to a
current limit or reactive power limit, when the voltage is below 95 per
unit and still within the continuous operation region, then preference
shall be given to active or reactive power according to requirements if
required by the Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator.
2.2.
2.3.
While voltage at the high-side of the main power transformer is within the
mandatory operation region as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support,
on the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under 6:
•
Reactive power priority by default; or
•
Active power priority if required by the Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator.
While voltage at the high-side of the main power transformer is within the
permissive operation region, as specified in Attachment 1, each facility may
operate in current block mode if necessary to avoid tripping. Otherwise, each
facility shall follow the requirements for the mandatory operation region in
Requirement R2.2.
2.3.1
2.4.
If a facility enters current block mode, it shall restart current
exchange in less than or equal to five cycles of positive sequence
voltage returning to a continuous operation region or mandatory
operation region.
Each facility shall not itself cause voltage at the high-side of the main power
transformer to exceed the applicable high voltage thresholds and time
For the purpose of this standard, the main power transformer is the power transformer that steps up voltage
from the collection system voltage to the nominal transmission/interconnecting system voltage for inverter-based
resources. In case of offshore wind plants connecting via a dedicated VSC-HVDC, the main power transformer is
the onshore main power transformer.
5
Except if this would occur during a frequency excursion. The active power response should recover in accordance
with the primary frequency controller.
6
In either case and if required, the magnitude of active power and reactive current shall be as specified by the
Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
4
Draft 2 of PRC-029-1
June 2024
Page 5 of 19
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
durations in its response as voltage recovers from the mandatory or permissive
operation regions to the continuous operation region.
2.5.
Each facility shall restore active power output to the pre-disturbance or
available level (whichever is lesser) within 1.0 second when the voltage at the
high-side of the main power transformer returns from the mandatory
operation region or permissive operation region (including operating in current
block mode), as specified in Attachment 1, unless the Transmission Planner,
Planning Coordinator, Reliability Coordinator, or Transmission Operator
requires a lower post-disturbance active power level requirement or requires a
different post-disturbance active power restoration time. 7
M2. Each Generator Owner and Transmission Owner have evidence of dynamic
simulations, studies, or other evidence to demonstrate the design of each facility will
adhere to requirements, as specified in Requirement R2. Each Generator Owner and
Transmission Owner also have evidence of actual disturbance monitoring (i.e.
Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data
to demonstrating that the operation of each facility did adhere to performance
requirements, as specified in Requirement R2, during each voltage excursion
measured at the high-side of the main power transformer. The Generator Owner or
Transmission Owner have evidence of receiving such performance requirements, (e.g.
email exchange, contract information) if the Transmission Planner, Transmission
Operator, Reliability Coordinator, or Planning Coordinator has required the Generator
Owner or Transmission Owner to follow performance requirements other than those
in Requirement R2 (e.g. ramp rates, reactive power prioritization).
R3. Each Generator Owner or Transmission Owner shall ensure the design and operation
is such that each facility adheres to Ride-through requirements during a frequency
excursion event whereby the System frequency remains within the “must Ridethrough zone” according to Attachment 2 and the absolute rate of change of
frequency (RoCoF) 8 magnitude is less than or equal to 5 Hz/second. [Violation Risk
Factor: High] [Time Horizon: Operations Assessment]
M3. Each Generator Owner and Transmission Owner have evidence of dynamic
simulations, studies, or other evidence to demonstrate the design of each facility will
adhere to Ride-through requirements, as specified in Requirement R3. Each Generator
Owner and Transmission Owner also have evidence of actual disturbance monitoring
(i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder)
data to demonstrate the operation of each facility did adhere to Ride-through
requirements, as specified in Requirement R3, during each frequency excursion event
measured at the high-side of the main power transformer.
R4. Each Generator Owner and Transmission Owner identifying a facility that is in-service
by the effective date of PRC-029-1, has known hardware limitations that prevent the
Except if this would occur during a frequency excursion. The active power response should recover in accordance with the
primary frequency controller.
8 Rate of change of frequency (ROCOF) is calculated as the average rate of change for multiple calculated system frequencies
for a time period of greater than or equal to 0.1 second. ROCOF is not calculated during the fault occurrence and clearance.
7
Draft 2 of PRC-029-1
June 2024
Page 6 of 19
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
facility from meeting voltage Ride-through criteria as detailed in Requirements R1 and
R2, and requires an exemption from specific voltage Ride-through criteria shall: 9
Lower] [Time Horizon: Long-term Planning]
4.1.
Document information supporting the identified hardware limitation no later
than 12 months following the effective date of PRC-029-1. This documentation
shall include:
4.1.1 Identifying information of the IBR (name, facility #, other);
4.1.2 Which aspects of voltage ride-through requirements that the IBR would
be unable to meet and the capability of the equipment due to the
limitation;
4.1.3 Identify the specific piece(s) of equipment causing the limitation;
4.1.4 Supporting technical documentation verifying the limitation is due to
hardware that needs to be physically replaced or that the limitation
cannot be removed by software updates or setting changes, and;
4.1.5 Information regarding any plans to remedy the equipment limitation
(such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the
applicable Planning Coordinator(s), Transmission Planner(s), Transmission
Operator(s), Reliability Coordinator(s), and to the Regional Entity no later than
12 months following the effective date of PRC-029-1.
4.2.1
4.3.
Any response to additional information requested by the applicable
Planning Coordinator(s), Transmission Planner(s), Transmission
Operator(s), Reliability Coordinator(s), and to the Regional Entity
shall be provided back to the requestor within 90 days of the
request.
Each Generator Owner and Transmission Owner with a previously submitted
request for exemption that replace the equipment causing the limitation shall
document and communicate such an equipment change to the associated
Planning Coordinator(s), Transmission Planner(s), Transmission Operator(s),
and Reliability Coordinator(s) within 90 days of the equipment change.
4.3.1
When existing equipment is replaced, the exemption for that
Ride-through criteria no longer applies.
M4. Each Generator Owner and Transmission Owner seeking an exemption for facilities
that are in-service by the effective date of PRC-029-1 have evidence of submission to
the Regional Entity consistent with the information listed in Requirement R4.1. Each
Generator Owner and Transmission Owner have evidence of communicated copies of
each submission in accordance with Requirement R4.2 and to the applicable entities
described in Requirement R4.2. Acceptable type of evidence for submittals include but
The exemption requests for a non-US Registered Entity should be implemented in a manner that is consistent with, or under
the direction of, the applicable governmental authority or its agency in the non-US jurisdiction
9
Draft 2 of PRC-029-1
June 2024
Page 7 of 19
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
are not limited to, meeting minutes, agreements, copies of procedures or protocols in
effect, or email correspondence. Acceptable types of evidence for an equipment
limitation may include but is not limited to, documentation that contains study results,
experience from an actual event, or manufacturer’s advice. Each Generator Owner
and Transmission Owner that replace equipment at a facility that is directly
associated with an approved exemption and that equipment is the cause for the
limitation, have evidence of communicating the equipment change to the applicable
entities described in Requirement R4.3 within 30 calendar days of the equipment
replacement.
Draft 2 of PRC-029-1
June 2024
Page 8 of 19
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
Each Generator Owner and Transmission Owner shall retain evidence with
Requirements R1, R2, and R3 in this standard for 36 calendar months.
•
Each Generator Owner and Transmission Owner shall retain evidence with
Requirement R4 in this standard for five calendar years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Draft 2 of PRC-029-1
June 2024
Page 9 of 19
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of
each applicable facility to
Ride-through in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to
Ride-through requirements in
accordance with Attachment
1, except for those conditions
identified in Requirement R1.
R2.
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of
each applicable facility to
adhere to performance
requirements during voltage
excursions, as specified in
Requirement R2.
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to
performance requirements
during voltage excursions, as
specified in Requirement R2.
R3.
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of
each applicable facility to
Ride-through in accordance
with Attachment 2.
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to
Ride-through requirements in
accordance with Attachment
2.
R4.
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that
The Generator Owner or
Transmission Owner failed to
document complete
information for facilities
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
Violation Severity Levels
R#
Lower VSL
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), Reliability
Coordinator(s), and Regional
Entity more than 30 calendar
days but less than or equal to
60 calendar days after the
change to the equipment.
OR
The Generator Owner or
Transmission Owner provided
a copy to the applicable
entities as detailed in R4.2
more than 12 months but less
than or equal to 15 months
after the effective date of R4.
Moderate VSL
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and Regional
Entity more than 60 calendar
days but less than or equal to
90 calendar days after the
change to the equipment.
High VSL
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and Regional
Entity more than 90 calendar
days but less than or equal to
120 calendar days after the
change to the equipment.
Severe VSL
identified with known
hardware limitations that
prevent the facility from
meeting voltage Ride-through
criteria as detailed in
Requirements R1 or R2.
OR
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s),Reliability
Coordinator(s), and Regional
Entity more than 120 calendar
days after the change to the
equipment.
OR
The Generator Owner or
Transmission Owner failed to
provide a copy to the
applicable entities as detailed
in R4.2 within 24 months after
the effective date of R4.
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
Version History
Version
Date
Initial Draft
3/27/24
DRAFT
DRAFT 2
6/4/24
Revised follow initial comment review
Draft 2 of PRC-029-1
June 2024
Action
Change
Tracking
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-Through Requirements for AC-Connected Wind Facility 10
Voltage (per unit) 11
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 12
N/A
≤ 1.20 and ≥ 1.1
Mandatory Operation Region
1.0
≤ 1.10 and > 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90 and ≥ 0.70
Mandatory Operation Region
3.00
< 0.70 and ≥ 0.50
Mandatory Operation Region
2.50
< 0.50 and ≥ 0.25
Mandatory Operation Region
1.20
< 0.25 and ≥ 0.10
Mandatory Operation Region
0.16
< 0.10
Permissive Operation Region
0.16
Table 2: Voltage Ride-Through Requirements for All Other Inverter-based Resource
Facilities
Voltage
(per unit) 13
Operation Region
Minimum RideThrough Time (sec)
>1.20
N/A 14
N/A
≤ 1.20 and > 1.1
Mandatory Operation Region
1.0
≤ 1.10 and > 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90 and ≥ 0.70
Mandatory Operation Region
6.00
< 0.70 and ≥ 0.50
Mandatory Operation Region
3.00
< 0.50 and ≥ 0.25
Mandatory Operation Region
1.20
< 0.25 and ≥ 0.10
Mandatory Operation Region
0.32
< 0.10
Permissive Operation Region
0.32
Type 3 and type 4 wind resources directly connected to the AC Transmission System
Refer to bullet #5 below.
12
These conditions are referred to as the “may Ride-through zone”.
13
Refer to bullet #5 below.
14
These conditions are referred to as the “may Ride-through zone”.
10
11
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
1. Table 1 applies to type 3 and type 4 wind facilities unless connected via a dedicated
VSC-HVDC transmission facility.
2. Table 2 applies to all other inverter-based resource facility types not covered in
Table 1; including, but not limited to, the following facilities:
a. Inverter-based resources, regardless of their energy resource, interconnecting
via a dedicated VSC-HVDC transmission facility.
b. Other inverter-based resource plants or hybrid plants consisting of photovoltaic
(PV) and BESS.
3. The applicable voltage for Voltage Source Converter High Voltage Direct Current
(VSC HVDC) system with a dedicated connection to an inverter-based resource is on
the AC side of the transformer(s) that is (are) used to connect the VSC HVDC system
to the interconnected transmission system
4. Table 1 applies to hybrid facilities consisting of wind (type 3 or type 4) and various
other IBR technologies. Otherwise, Table 2 applies to hybrid facilities with no wind
(type 3 or type 4).
5. The voltage base for per unit calculation is the nominal phase-to-ground or
phase-to-phase transmission system voltage unless otherwise defined by the
Planning Coordinator or Transmission Planner.
6. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase to neutral or phase to phase fundamental root mean square (RMS) voltage at
the high side of the main power transformer.
7. Tables 1 and 2 are only applicable when the frequency is within the “must
Ride-through zone” as specified in Table 3 of Attachment 2.
8. At any given voltage value, each facility shall Ride-through unless the time duration
at that voltage has exceeded the specified minimum Ride-through time duration. If
the voltage is continuously varying over time, it is necessary to add the duration
within each band of Tables 1 and 2 over any 10 second time period.
9. The specified duration of the mandatory operation regions and the permissive
operation regions in Tables 1 and 2 is cumulative over one or more disturbances
within any 10 second time period.
10. The facility may trip for more than four deviations of the applicable voltage at the
high-side of the main power transformer outside of the continuous operation region
within any 10 second time period.
11. Instantaneous trip settings based on instantaneously calculated voltage
measurements with less than filtering lengths of one cycle (16.6 msec) are not
permissible.
12. The “must Ride-through zone” is the combined area of the mandatory operating
regions, the continuous operating regions, and the permissive operating region. All
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
area outside of these operating regions is referred to as the “may Ride-through
zone”.
No-Trip Zone No – Trip Zone
Figure 1: Voltage Ride-Through Requirements for AC-Connected Wind Facilities
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
Figure 2: Voltage Ride-Through Requirements for All Other IBR
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
Attachment 2: Frequency Ride-Through Criteria
Table 3: Frequency Ride-Through Capability Requirements
System Frequency (Hz)
Minimum Ride-Through
Time (sec)
≥64
May trip
< 64 and ≥61.8
6
< 61.8 and ≥ 61.5
299
< 61.5 and > 61.2
660
≤ 61.2 and < 58.8
Continuous
≤ 58.8 and < 58.8
660
< 58.5 and ≥ 57
299
< 57.0 and ≥ 56
6
< 56
May trip
1. Frequency measurements are taken at the high-side of the main power transformer.
2. Frequency is measured over a period of time (typically 3-6 cycles) to calculate system
frequency at the high-side of the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency value, each facility shall Ride-through unless the time duration at
that frequency has exceeded the specified minimum ride-through time duration.
5. The specified durations of Table 3 are cumulative over one or more disturbances within
a 15-minute time period.
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-Based Resources
Figure 3: PRC-029 Frequency Ride-Through Requirements
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
Anticipated Actions
Date
15‐day formal comment period and additional ballot
June 18 – July 8, 2024
Final Ballot
July 16 ‐ 20, 2024
Board adoption
August 14, 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Ride‐through: Remaining connected, synchronized with the Transmission System, and
continuing to operate in response to System conditions through the time‐frame of a System
Disturbance.
Continuous Operating Region – The range of voltages, measured at the high‐side of the main
power transformer, that are ≥ 0.9 per unit and ≤ 1.1 per unit.
Mandatory Operating Region – The range of voltages, measured at the high‐side of the main
power transformer, that are > 0.1 per unit and < 0.9 per unit – or – > 1.1 and ≤ 1.2 per unit.
Permissive Operating Region – The range of voltages, measured at the high‐side of the main
power transformer, that is ≤ 0.1 per unit.
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
A. Introduction
1. Title:
Frequency and Voltage Ride‐through Requirements for Inverter‐Based
Generating Resources
2. Number:
PRC‐029‐1
3. Purpose:
To ensure that Inverter‐Based Resources (IBRs) adhere to Ride‐through
requirements remain connected and perform operationally as expected to support of
the Bulk Power System (BPS) during and after defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.1.2. Transmission Owner1
4.2
Facilities: For purposes of this standard, the term “applicable Inverter‐Based
Resource” or “applicable Inverter‐Based Resources” refers to the following:
4.2.1. BEPS inverter‐based resources2IBRs
4.2.2. IBR Registration Criteria
5.
Effective Date: See Implementation Plan for Project 2020‐02 – PRC‐029‐1
Standard‐Only Definition: None
For owners of Voltage Source Converter – High‐voltage Direct Current (VSC‐HVDC) transmission facilities that are
dedicated connections for IBR to the BPS
2
For the purpose of this standard, “inverter‐based resources” refers to a collection of individual solar photovoltaic
(PV), Type 3 and Type 4 wind turbines, battery energy storage system (BESS), or fuel cells that operate as a single
plant/resource. In case of offshore wind plants connecting via a dedicated VSC‐HVDC, the inverter‐based resource
includes the VSC‐HVDC system.
1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
B. Requirements and Measures
R1.
Each Generator Owner or Transmission Owner of an applicable IBR shall ensure theat
design and operation is such that each facilityIBR adheres to Ride‐through
requirements,remains electrically connected and continues to exchange current in
accordance with the “must Ride‐through3no‐trip zones” and operation regions as
specified in Attachment 1, except for the following: unless needed to clear a fault or a
documented equipment limitation exists in accordance with Requirement R6.
[Violation Risk Factor: High] [Time Horizon: Operations Assessment]
• The facility needed to electrically disconnect in order to clear a fault;
•
A documented equipment limitation exists in accordance with Requirement
R4; or
•
The instantaneous positive sequence voltage phase angle change is more than
25 electrical degrees at the high‐side of the main power transformer and is
initiated by a non‐fault switching event on the transmission system; or
•
The Volts per Hz (V/Hz) at the high‐side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than
2 seconds.
M1. Each Generator Owner and Transmission Owner shall have evidence of dynamic
simulations, studies, or other evidence to demonstrate the design of each facility will
adhere to Ride‐through requirements, as specified in Requirement R1. Each
Generator Owner and Transmission Owner have evidence of actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and
Fault Recorder) recorded to demonstrate that the operation of each facility did
adhere to Ride‐through requirements, as specified in Requirement R1. If the
Generator Owner and Transmission Owner choose to utilize Ride‐through exemptions
that occur within the “must Ride‐through zone” and are caused by non‐fault initiated
phase jumps of greater than 25 electrical degrees, then each Generator Owner and
Transmission Owner also have evidence of actual disturbance monitoring (i.e.
Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data
to demonstrate that the facility failed to Ride‐through during a phase jump of greater
than or equal to 25 electrical degrees, and documentation from their Transmission
Planner, Reliability Coordinator, Planning Coordinator, or Transmission Operator that
a non‐fault initiated switching event occurred.data or other evidence for each
applicable IBR demonstrating adherence to ride‐through requirements, as specified in
Requirement R1.
R2. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure the
design and operation is such that at during a System disturbance, each IBR’s the
voltage performance for each facility adheres to the following during a voltage
excursion, unless a documented equipment limitation exists in accordance with
Requirement R46. [Violation Risk Factor: High] [Time Horizon: Operations Assessment]
3
Includes no tripping associated with phase lock loop loss of synchronism
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
2.1.
While the voltage at the high‐side of the main power transformer4 remains
within the Ccontinuous Ooperation Rregion as specified in Attachment 1, each
IBR facility shall:
2.1.1 Continue to deliver the pre‐disturbance level of active power or
available active power, whichever is less.5,
2.1.12.1.2 and cContinue to deliver reactive power and reactive power up to
its apparent reactive power limit and according to its controller
settings.
2.1.22.1.3 If the facilityIBR cannot deliver both active and reactive power
due to a current or apparent power limit or reactive power limit, when
the applicable voltage is below 95% per unit and still within the
Ccontinuous oOperation Rregion, then preference shall be given to
active or reactive power according to requirements if required specified
by the Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator.
2.2.
While voltage at the high‐side of the main power transformer is within the
Mmandatory oOperation Rregion as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support,
on the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under6:
2.2.1 Reactive power priority by default; orExchange current, up to the
maximum capability while maintaining automatic voltage regulation,
on the affected phases during both symmetrical and asymmetrical
voltage disturbances.
2.2.2 Active djust reactive current injection at the high‐side of the main
power priority transformer so that the magnitude of the reactive
current responds to changes in voltage at the high‐side of the main
power transformer in accordance with default reactive prioritization
unless the if required by the Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator.
specifies a certain magnitude of reactive power response to voltage
changes or specifies active power priority instead of reactive power
priority.
For the purpose of this standard, the main power transformer is the power transformer that steps up voltage
from the collection system voltage to the nominal transmission/interconnecting system voltage for inverter‐based
resources. In case of offshore wind plants connecting via a dedicated VSC‐HVDC, the main power transformer is
the onshore main power transformer.
5
Except if this would occur during a frequency excursion. The active power response should recover in accordance
with the primary frequency controller.
6
In either case and if required, the magnitude of active power and reactive current shall be as specified by the
Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
4
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
2.3.
While The IBR shall not itself cause voltage at the high‐side of the main power
transformer is within the permissive operation regionto exceed the applicable,
as specified in Attachment 1, each facility Table 1 or Table may operate in
current block mode if necessary to avoid tripping. Otherwise, each facility shall
follow the requirements for the 2 no‐trip zone voltage thresholds and time
durations in its response from Mmandatory or Permissive Ooperation Rregion
in Requirement R2.2s to the Continuous Operating Region.
2.3.2.3.1 If a facility enters current block mode, it shall restart current
exchange in less than or equal to five cycles of positive sequence
voltage returning to a continuous operation region or mandatory
operation region.
2.4.
Each IBR facility shall not itself cause restore active power output to the pre‐
disturbance or available level within 1.0 second when the voltage at the high‐
side of the main power transformer returns to exceed the applicable high
voltage thresholds and time durations in its response as voltage recovers from
the mandatory or permissive operation regions to the Ccontinuous Ooperation
Rregion from the Mandatory Operation Region or Permissive Operation Region
(including operation in current block mode) as specified in Attachment 1,
unless the Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator specifies a lower post‐disturbance active power level
requirement or specifies a different post‐disturbance active power restoration
time.
2.5.
Each IBR facility shall restore active power output to the pre‐disturbance or
available level (whichever is lesser) within 1.0 secondonly trip to prevent
equipment damage, when the voltage at the high‐side of the main power
transformer returns from the mandatory operation region or permissive
operation region (including operating in current block mode), is outside of the
no‐trip zone as specified in Attachment 1, unless the Transmission Planner,
Planning Coordinator, Reliability Coordinator, or Transmission Operator
requires a lower post‐disturbance active power level requirement or requires a
different post‐disturbance active power restoration time.7
M2. Each Generator Owner and Transmission Owner shall have evidence of dynamic
simulations, studies, or other evidence to demonstrate the design of each facility will
adhere to requirements, as specified in Requirement R2. Each Generator Owner and
Transmission Owner also have evidence of actual disturbance monitoring (i.e.
Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault
Recorder)recorded data or other evidence for each applicable IBRto
demonstratingdemonstrating that the operation of each facility did adherence to
performance requirements, as specified in Requirement R2, during each System
voltage excursion measured at the high‐side of the main power transformer. The
Generator Owner or Transmission Owner have evidence of receiving such
7
Except if this would occur during a frequency excursion. The active power response should recover in accordance
with the primary frequency controller.
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
performance requirements, (e.g. email exchange, contract information) if the
Transmission Planner, Transmission Operator, Reliability Coordinator, or disturbance
which has occurred within the associated Planning Coordinator(s) area(s) has required
the Generator Owner or Transmission Owner to follow performance requirements
other than those in Requirement R2 (e.g. ramp rates, reactive power prioritization).
R3. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure that
during a transient overvoltage as a result of a switching event whereby instantaneous
voltage at the high‐side of the main power transformer exceeds
1.2 per unit, each IBR shall either: [Violation Risk Factor: Lower] [Time Horizon:
Operations Assessment]
Remain electrically connected and continue to exchange current in accordance
with instantaneous transient overvoltage levels and durations specified in
Attachment 2; or
Remain electrically connected in current block mode in accordance with
instantaneous transient overvoltage levels and durations specified in
Attachment 2, and restart current exchange within 5 cycles of the instantaneous
voltage falling below (and remaining below) 1.2 per unit.
M3. Each Generator Owner and Transmission Owner shall have evidence of actual
recorded data or other evidence for each applicable IBR demonstrating adherence to
performance requirements, as specified in Requirement R3, during each transient
overvoltage period which has occurred within the associated Planning Coordinator(s)
area(s).
R4.R3.
Each Generator Owner or Transmission Owner of an applicable IBR shall ensure
the design and operation is such that each IBR facilityremains electrically connected
and continues to exchange current adheres to Ride‐through requirements during a
frequency excursion event whereby the System frequency remains within the “no
tripmust Ride‐through zone” according to Attachment 23 and the absolute rate of
change of frequency (ROoCOoF)8 magnitude is less than or equal to 5 Hz/second.
[Violation Risk Factor: LowerHigh] [Time Horizon: Operations Assessment]
M43. Each Generator Owner and Transmission Owner shall have evidence of dynamic
simulations, studies, or other evidence to demonstrate the design of each facility will
adhere to Ride‐through requirements, as specified in Requirement R3. Each Generator
Owner and Transmission Owner also have evidence of actual disturbance monitoring
(i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder)
recorded data or other evidence to demonstrate the operation offor each applicable
IBRfacility did demonstrating adherence to rRide‐through requirements, as specified in
Requirement R43, during each frequency excursion event measured which has
occurred within the associated Planning Coordinator(s) area(s) at the high‐side of the
main power transformer.
8 Rate of change of frequency (ROCOF) is calculated as the average rate of change for multiple calculated system frequencies
for a time period of greater than or equal to 0.1 second. ROCOF is not calculated during the fault occurrence and clearance.
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
R5. Each Generator Owner or Transmission Owner of an applicable IBR shall ensure each
IBR remains electrically connected and continues to exchange current during
instantaneous positive sequence voltage phase angle changes that are initiated by
non‐fault switching events on the transmission system and are changes of less than 25
electrical degrees at the high‐side of the main power transformer. [Violation Risk
Factor: Lower] [Time Horizon: Operations Assessment]
5.1.
When the instantaneous positive sequence voltage phase angle change is more
than 25 electrical degrees at the high‐side of the main power transformer and
is initiated by a non‐fault switching event on the transmission system, the IBR
may trip, but shall only trip to prevent equipment damage.
M5. Each Generator Owner and Transmission Owner shall have evidence of actual
recorded data or other evidence for each applicable IBR demonstrating adherence to
ride‐through requirements, as specified in Requirement R5, during instantaneous
positive sequence voltage phase angle changes that are changes of less than 25
electrical degrees at the high‐side of the main power transformer and that such
changes are not initiated by non‐fault switching events.
R6.R4.
Each Generator Owner and Transmission Owner identifying a facility that is in‐
service by the effective date of PRC‐029‐1, has known hardwarewith a documented
equipment limitations that would prevent the facilityan applicable IBR that is in‐
service by the effective date of this standard from meeting voltage rRide‐through
requirements criteria as detailed in Requirements R1 and R2, and requires an
exemption from specific voltage Ride‐through criteria shall communicate each
equipment limitation to the associated Planning Coordinator(s), Transmission
Planner(s), and Reliability Coordinator(s). [Violation Risk Factor:9 Lower] [Time
Horizon: Long‐term Planning]
6.1.4.1.
Each Generator Owner and Transmission Owner shall include in its
dDocument information supporting the identified hardware limitation no later
than 12 months following the effective date of PRC‐029‐1. This documentation
shall includeation:
6.1.14.1.1
Identifying information of the IBR (name, facility #, other);
6.1.24.1.2 Which aspects of voltage ride‐through requirements that the IBR
would be unable to meet and the capability of the equipment due to
the limitation;
6.1.34.1.3
Identify the specific piece(s) of equipment causing the limitation;
4.1.4 Supporting technical documentation verifying the limitation is due to
hardware that needs to be physically replaced or that the limitation
cannot be removed by software updates or setting changes, and;
The exemption requests for a non‐US Registered Entity should be implemented in a manner that is consistent
with, or under the direction of, the applicable governmental authority or its agency in the non‐US jurisdiction
9
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
6.1.44.1.5 Information regarding any plans to repair or remedyplace the
limiting equipment that would remove the limitation (such as an
estimated date of repair/replacement).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the
applicable Planning Coordinator(s), Transmission Planner(s), Transmission
Operator(s), Reliability Coordinator(s), and to the Regional Entity no later than
12 months following the effective date of PRC‐029‐1.
4.2.1
4.3.
Any response to additional information requested by the applicable
Planning Coordinator(s), Transmission Planner(s), Transmission
Operator(s), Reliability Coordinator(s), and to the Regional Entity
shall be provided back to the requestor within 90 days of the
request.
Each Generator Owner and Transmission Owner with a previously
communicated submitted request for exemptionequipment limitation that
repairs or replaces the equipment causing the limitation shall document and
communicate such an equipment change to the associated Planning
Coordinator(s), Transmission Planner(s), Transmission Operator(s), and
Reliability Coordinator(s) within 390 days of the equipment change.
6.2.4.3.1 When existing equipment is replaced, the exemption for that
Ride‐through criteria no longer applies.
M64. Each Generator Owner and Transmission Owner seeking an exemption for facilities
that are in‐service by the effective date of PRC‐029‐1 shall have evidence of
submission to the Regional Entity consistent with the information listed equipment
limitations, as specified in Requirement R64.1, documented prior to the effective date
of PRC‐029‐1. Each Generator Owner and Transmission Owner have evidence of
communicated copies of each submission in accordance with Requirement R4.2 and to
the applicable entities described in Requirement R4.2. Acceptable type of evidence for
submittals include but are not limited to, meeting minutes, agreements, copies of
procedures or protocols in effect, or email correspondence. Acceptable types of
evidence for an equipment limitation may include but is not limited to, documentation
that contains study results, experience from an actual event, or manufacturer’s advice.
Each Generator Owner and Transmission Owner that replace with changes to
equipment at a facility that is directly associated with an approved exemption and
that equipment is the cause for the limitation, shall have evidence of communicating
the equipment change to the applicable entities described in Requirement R4.3 within
30 calendar days of the equipment replacementcommunication to each associated
Planning Coordinator, Transmission Planner, and Reliability Coordinator. Acceptable
types of evidence may include, but are not limited to, meeting minutes, agreements,
copies of procedures or protocols in effect between entities or between departments
of a vertically integrated system, or email correspondence.
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full‐time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
Each Generator Owner and Transmission Owner shall retain evidence with
Requirements R1, R2, and R3 in this standard for 36 calendar months.
Each Generator Owner and Transmission Owner shall retain evidence with
Requirement R4 each requirement in this standard for five calendar years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Draft 2 of PRC‐029‐1
June 2024
Page 10 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of
each applicable facility to
Ride‐through in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to
Ride‐through requirements in
accordance with Attachment
1, except for those conditions
identified in IBR remains
electrically connected and
continued to exchange current
in accordance with
Attachment 1, unless needed
to clear a fault, in accordance
with Requirement R1.
R2.
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of
each applicable facility to
adhere to performance
requirements during voltage
excursions, as specified in
Requirement R2.N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to
performance requirements
during voltage excursionsIBR
adhered to performance
requirements during each
System disturbance, as
specified in Requirement R2.
R3.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
Draft 2 of PRC‐029‐1
June 2024
Page 11 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
IBR adhered to performance
requirements during each
transient overvoltage period
as specified in Requirement
R3.
R34.
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of
each applicable facility to
Ride‐through in accordance
with Attachment 2.N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to
Ride‐through requirements in
accordance with Attachment
2.IBR adhered to performance
requirements during each
frequency excursion event, as
specified in Requirement R4.
R5.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
IBR adhered to performance
requirements during each
instantaneous positive
sequence voltage phase angle
change of less than 25
electrical degrees, as specified
in Requirement R5.
R46.
The Generator Owner or
Transmission Owner with a
previously communicated
The Generator Owner or
Transmission Owner with a
previously communicated
The Generator Owner or
Transmission Owner with a
previously communicated
The Generator Owner or
Transmission Owner failed to
document complete
Draft 2 of PRC‐029‐1
June 2024
Page 12 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
equipment limitation that
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), and Reliability
Coordinator(s), and Regional
Entity more than 30 calendar
days but less than or equal to
60 calendar days after the
change to the equipment.
equipment limitation that
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), and Reliability
Coordinator(s), Transmission
Operator(s), and Regional
Entity more than 60 calendar
days but less than or equal to
90 calendar days after the
change to the equipment.
equipment limitation that
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), and Reliability
Coordinator(s), Transmission
Operator(s), and Regional
Entity more than 90 calendar
days but less than or equal to
120 calendar days after the
change to the equipment.
information for facilities
identified with known
hardwareevidence of
equipment limitations that
prevent the facility from
meeting voltage Ride‐through
criteria as detailed in
Requirements R1 or
R2consistent with
Requirement R6 and prior to
the effective date of
PRC‐029‐1 Requirement R6.
OR
OR
The Generator Owner or
Transmission Owner provided
a copy to the applicable
entities as detailed in R4.2
more than 12 months but less
than or equal to 15 months
after the effective date of R4.
Draft 2 of PRC‐029‐1
June 2024
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that
repairs or replaces the
documented limiting
equipment but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s),and Reliability
Coordinator(s), and Regional
Entity more than 120 calendar
Page 13 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
days after the change to the
equipment.
OR
The Generator Owner or
Transmission Owner failed to
provide a copy to the
applicable entities as detailed
in R4.2 within 24 months after
the effective date of R4.
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
Draft 2 of PRC‐029‐1
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Page 14 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Version History
Change
Tracking
Version
Date
Initial Draft
3/27/24
DRAFT
DRAFT 2
6/4/24
Revised follow initial comment review
Draft 2 of PRC‐029‐1
June 2024
Action
Page 15 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-Through Requirements for AC-Connected Wind IBR Facility10
Voltage (per unit)11
Operation Region
Minimum RideThrough Time (sec)
>≥ 1.200
N/A12
N/A
≤ 1.20 and ≥ 1.1
Mandatory Operation Region
1.0
≤ 1.10 and >≥ 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90 and ≥ 0.70
Mandatory Operation Region
3.00
< 0.70 and ≥ 0.50
Mandatory Operation Region
2.50
< 0.50 and ≥ 0.25
Mandatory Operation Region
1.20
< 0.25 and ≥ 0.10
Mandatory Operation Region
0.16
< 0.10
Permissive Operation Region
0.16
Table 2: Voltage Ride-Through Requirements for All Other IBRInverter-based
Resource Facilities
Voltage
(per unit)13
Operation Region
Minimum RideThrough Time (sec)
>≥1.200
N/A14
N/A
≤ 1.20 and > ≥1.1
Mandatory Operation Region
1.0
≤ 1.10 and > ≥1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90 and ≥ 0.70
Mandatory Operation Region
6.00
< 0.70 and ≥ 0.50
Mandatory Operation Region
3.00
< 0.50 and ≥ 0.25
Mandatory Operation Region
1.20
< 0.25 and ≥ 0.10
Mandatory Operation Region
0.32
< 0.10
Permissive Operation Region
0.32
10
Type 3 and type 4 wind resources directly connected to the AC Transmission System
Refer to bullet #5 below.
12
These conditions are referred to as the “may Ride-through zone”.
13
Refer to bullet #5 below.
14
These conditions are referred to as the “may Ride-through zone”.
11
Draft 2 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
1. Table 1 applies to type 3 and type 4 wind facilities applicable wind IBR unless
connected via a dedicated VSC‐HVDC transmission facility.
2. Table 2 applies to all other inverter‐based resource facility IBR types not covered in
Table 1; including, but not limited to, the following IBRfacilities:
a. Isolated Inverter‐based resourcesIBR, regardless of their energy resource,
interconnecting via a dedicated VSC‐HVDC transmission facility.
b. Other IBR inverter‐based resource plants or hybrid plants consisting of
photovoltaic (PV) and BESS.
3. The applicable voltage for Voltage Source Converter High Voltage Direct Current
(VSC HVDC) system with a dedicated connection to an inverter‐based resource is on
the AC side of the transformer(s) that is (are) used to connect the VSC HVDC system
to the interconnected transmission system
3.4. Table 1 applies to hybrid facilities consisting of wind (type 3 or type 4) In the case
of hybrid IBR consisting of wind and various other IBR technologies, the applicable
table shall be based on direction by the Transmission Planner. Otherwise, Table 2
applies to hybrid facilities with no wind (type 3 or type 4).
4.5. The voltage base for per unit calculation is the nominal phase‐to‐ground or
phase‐to‐phase transmission system voltage unless otherwise defined by the
Planning Coordinator or Transmission Planner.
5.6. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase to neutral or phase to phase fundamental root mean square (RMS) voltage at
the high side of the MPTmain power transformer.
6.7. Tables 1 and 2 are only applicable when the frequency is within the “must
Ride‐throughno trip zone” as specified in Table 3 of Attachment 32.
7.8. At any given voltage value, each IBR facility shall Ride‐through not trip until
unless the time duration at that voltage has exceedsed the specified minimum Rride‐
through time duration. If the voltage is continuously varying over time, it is
necessary to add the duration within each band of Tables 1 and 2 over the any 10‐
second time period to determine compliance.
8.9. The specified duration of the Mmandatory Ooperation Rregions and the
Ppermissive Ooperation Rregions in Tables 1 and 2 is cumulative over one or more
disturbances within any 10 second time period.
9.10. The IBR facility may trip for more than four deviations of the applicable voltage
at the high‐side of the main power transformer outside of the Ccontinuous
Ooperation Rregion within any 10 second time period.
11. Instantaneous trip settings based on instantaneously calculated voltage
measurements with less than filtering lengths of one cycle (16.6 msec) are not
permissible.
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
12. The “must Ride‐through zone” is the combined area of the mandatory operating
regions, the continuous operating regions, and the permissive operating region. All
area outside of these operating regions is referred to as the “may Ride‐through
zone”.
10. If the positive sequence voltage at the high‐side of the main power transformer
enters the Permissive Operation Region, an IBR may operate in current block mode
if necessary to protect the equipment.
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June 2024
Page 18 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Voltage (per unit)
No‐Trip Zone
0.1
1.3
1.2
1.1
1
0.9
0.8
No – Trip Zone
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
1
10
Time (seconds)
Draft 2 of PRC‐029‐1
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Page 19 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Figure 1: Voltage Ride‐Through Requirements for AC‐Connected Wind FacilitiesIBR
Draft 2 of PRC‐029‐1
June 2024
Page 20 of 25
Voltage (per unit)
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
0.1
No‐Trip Zone
1.3
1.2
1.1
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
1
10
Time (seconds)
Figure 2: Voltage Ride‐Through Requirements for All Other IBR
Draft 2 of PRC‐029‐1
June 2024
Page 21 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Attachment 2: Transient Overvoltage Ride-Through Criteria
Table 3: Transient Overvoltage Ride-Through Criteria
Voltage (per unit) at the
high side of the MPT
Minimum Ride-Through
Time (millisec)
> 1.8
May trip
> 1.7
0.2
> 1.6
1.0
> 1.4
3.0
> 1.2
15.0
1. The voltage base for per unit calculation is the nominal instantaneous phase‐to‐
ground or phase‐to‐phase voltage at the high side of the MPT unless otherwise
defined by the Planning Coordinator or Transmission Planner.
1. If surge protection devices are installed within the plant, the per unit voltage refers
to the residual voltage with the surge arresters applied.
2. Each IBR shall not trip unless the cumulative time of one or more instances over a
1‐minute time window in which the instantaneous voltage exceeds the respective
voltage threshold and the minimum ride‐through time.
1.9
Voltage (per unit)
1.8
1.7
1.6
1.5
1.4
No‐Trip Zone
1.3
1.2
0
2
4
6
8
10
12
14
16
Minimum Ride‐Through Time (milliseconds)
Figure 3: Transient Overvoltage Ride‐Through Criteria
Draft 2 of PRC‐029‐1
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Page 22 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Attachment 23: Frequency Ride-Through Criteria
Table 33: Frequency Ride-Through Capability Requirements
Averaged System
Frequency (Hz)
Minimum Ride-Through
Time (sec)
≥64
May trip
< 64 and ≥61.8
6
< 61.8 and ≥> 61.5
299
< 61.5 and > 61.2
660
≤ 61.2 and < 58.8
Continuous
≤ 58.8 and < 58.8
660
< 58.5 and ≥ 57
299
< 57.0 and ≥ 56
6
< 56
May trip
1. Frequency Mmeasurements are taken at the high‐side of the main power transformer
for each phase (phase to neutral).
2. Frequency is Mmeasuredments are averaged over a set time period of time
(typicallysuch as 3‐6 cycles) to calculate averaged system frequency at the high‐side of
the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency values, each IBR facility shall Ride‐throughnot trip until unless
the time duration at that frequency has exceededs the specified minimum ride‐through
time duration.
5. The specified durations of Table 34 are cumulative over one or more disturbances
within a 15‐minute time period.
Draft 2 of PRC‐029‐1
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Page 23 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
65
64
63
Frequency (Hz)
62
61
60
No‐Trip Zone
59
58
57
56
55
Draft 2 of PRC‐029‐1
June 2024
Time (seconds)
Page 24 of 25
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Generating Resources
Figure 43: PRC‐029 Frequency EnvelopesRide‐Through Requirements
Draft 2 of PRC‐029‐1
June 2024
Page 25 of 25
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Reliability Standards PRC-024-4 and PRC-029-1
Applicable Standard(s)
•
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1
and Type 2 Wind Resources, and Synchronous Condensers
•
PRC-029-1 Frequency and Voltage Ride Through Requirements for Inverter-Based
Generating Resources
Requested Retirement(s)
•
PRC-024-3 Frequency and Voltage Protection Settings for Generating Resources
Prerequisite Standard(s)
•
PRC-028-1 Disturbance Monitoring and Reporting Requirements for Inverter-Based
Resources
Proposed Definition(s)
•
None
Applicable Entities
•
See subject Reliability Standards.
Background
The purpose of Project 2020-02 is to modify Reliability Standard PRC-024-3 or replace it with a
performance-based ride-through standard that ensures generators remain connected to the
Bulk-Power System (BPS) during system disturbances. Specifically, the project focuses on using
disturbance monitoring data to substantiate inverter-based resource (IBR) ride-through performance
during grid disturbances. The project also ensures associated generators that fail to ride-through system
events are addressed with a corrective action plan (if possible) and reported to necessary entities for
situational awareness.
The purpose for this project is based on the culmination of multiple analyses conducted by the ERO
Enterprise regarding widespread inverter-based resource tripping events. Furthermore, the NERC
Inverter-Based Resource Performance Subcommittee 1 has developed comprehensive recommendations
See documents at the NERC IRPS website: https://www.nerc.com/comm/RSTC/Pages/IRPS.aspx and the previous Inverter-Based
Resource Performance Working Group website https://www.nerc.com/comm/RSTC/Pages/IRPWG.aspx
1
RELIABILITY | RESILIENCE | SECURITY
for improved performance of inverter-based resources, including the recommendation to develop
comprehensive ride-through requirements.
In October 2023, FERC issued Order No. 901 2 which directs the development of new or modified
Reliability Standards that include new requirements for disturbance monitoring, data sharing, postevent performance validation, and correction of IBR performance. In January 2024, NERC submitted a
filing to FERC outlining a comprehensive work plan to address the directives within Order No. 901. 3
Within the work plan, NERC identified three active Standards Development projects that would need to
be filed for regulatory approval with FERC by November 4, 2024. These projects include 2020-02
Modifications to PRC-024 (Generator Ride-through) 4, 2021-04 Modifications to PRC-002-2 5, and 202302 Analysis and Mitigation of BES Inverter-Based Resource Performance Issues 6.
Project 2020-02
Proposed Reliability Standard PRC-029-1 is a new Reliability Standard that includes ride-through
requirements and performance requirements for IBRs. The scope of this project was adjusted to align
with associated regulatory directives from FERC Order No. 901 and the scope of the other projects
related to “Milestone 2” of the NERC work plan. The components of this project’s Standard
Authorization Request (SAR) that related to the inclusions of new data recording requirements are
covered in Project 2021-04 and the proposed new PRC-028-1 Reliability Standard. Components of this
project’s SAR that relate to analytics and corrective actions plans are covered in Project 2023-02 and the
proposed new PRC-030-1 Reliability Standard.
PRC-029-1 includes requirements for Generator Owner and Transmission Owner IBR to continue to
inject current and perform frequency support during a BPS disturbance. The standard also specifically
requires Generator Owner and Transmission Owner IBR to prohibit momentary cessation in the no-trip
zone during disturbances.
PRC-024-4 includes modifications to revise applicable facility types to remove IBR and to include
synchronous condensers.
See FERC Order 901, Docket No. RM22-12-000; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=202310193157&optimized=false; October 19, 2023
3 See INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF
RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%2
0901%20Work%20Plan_packaged%20-%20public%20label.pdf; January 17, 2024
4 See NERC Standards Development Project page for Project 2002-02; https://www.nerc.com/pa/Stand/Pages/Project_202002_Transmission-connected_Resources.aspx
5 See NERC Standards Development Project page for Project 2021-04; https://www.nerc.com/pa/Stand/Pages/Project-2021-04Modifications-to-PRC-002-2.aspx
6 See NERC Standards Development Project page for Project 2023-02; https://www.nerc.com/pa/Stand/Pages/Project-2023-02Performance-of-IBRs.aspx
2
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
2
General Considerations
The ERO Enterprise acknowledges that there are IBRs currently in operation and unable to meet voltage
ride-through requirements due to their inability to modify their coordinated protection and control
settings. Consistent with FERC Order No. 901, a limited and documented exemption process for those
IBR is appropriate and included within this Implementation Plan. Other NERC Standards Development
projects will be pursued to address ongoing identification and mitigation of any potential reliability
impacts to the BPS for such exemptions.
Effective Date and Phased-in Compliance Dates
The effective dates for the proposed Reliability Standards are provided below. Where the standard
drafting team identified the need for a longer implementation period for compliance with a particular
section of a proposed Reliability Standard (i.e., an entire Requirement or a portion thereof), the
additional time for compliance with that section is specified below. The phased-in compliance dates for
those particular sections represent the date that entities must begin to comply with that particular
section of the Reliability Standard, even where the Reliability Standard goes into effect at an earlier
date.
PRC-024-4
Where approval by an applicable governmental authority is required, Reliability Standard PRC-024-4
shall become effective on the first day of the first calendar quarter that is 6 months after the effective
date of the applicable governmental authority’s order approving the PRC-028-1 standard, or as
otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC024-4 shall become effective on the first day of the first calendar quarter that is 6 months after the date
the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
PRC-029-1
Where approval by an applicable governmental authority is required, Reliability Standard PRC-029-1
shall become effective on the first day of the first calendar quarter that is six months after the effective
date of the applicable governmental authority’s order approving the PRC-028-1 standard, or as
otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC029-1 shall become effective on the first day of the first calendar quarter that is six months after the
date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
3
Retirement Date
PRC-024-3
Reliability Standard PRC-024-3 shall be retired immediately prior to the effective date of Reliability
Standards PRC-024-04 and PRC-029-1 in the particular jurisdiction in which the revised standard is
becoming effective.
Equipment Limitations and Process for Requirement R4
Consistent with FERC Order No. 901, a limited and documented exemption for some legacy IBR with
certain documented equipment limitations are acceptable. Per the Order, these IBRs are
“…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.” 7
To ensure compliance with Requirement R4 and alignment with FERC Order No. 901, only those IBR that
are in operation as of the effective date of PRC-029-1 may be considered for potential exemption.
Further, only those IBR that are unable to meet voltage ride-through requirements due to their inability
to modify their coordinated protection and control settings may be considered for potential exemption.
7
Order No. 901 at p. 193.
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
4
Unofficial Comment Form
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on Project 2020-02 Modifications to PRC-024 (Generator Ride-through) by 8
p.m. Eastern, Monday, July 8, 2024.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Manager of
Standards Development, Jamie Calderon (email), or at 404-960-0568.
Background Information
The goal of Project 2020-02 is to mitigate the recent and ongoing disturbance ride through performance
issues identified across multiple Interconnections and numbers of disturbances analyzed by NERC and the
Regions. These issues have been associated with Inverter-Based Resources (IBR) with many causes of their
tripping or cessation unrelated to voltage and frequency protection settings requirements in the currently
effective version of PRC-024, PRC-024-3. Proposed Reliability Standard PRC-024-4 includes revisions to limit
its applicability to synchronous generators and synchronous condensers only and remains as a protectionbased standard. A new standard, PRC-029-1, is proposed as a true disturbance ride-through Reliability
Standard with applicability to inverter-based resources.
In October 2023, FERC issued Order No. 901, which directed NERC to develop new or modified existing
Reliability Standards that include new requirements for disturbance monitoring, data sharing, post-event
performance validation, and correction of IBR performance. Project 2020-02 was one of three projects
identified by NERC that must be completed and filed with FERC by November 4, 2024 to address Order No.
901 directives. At the December 2023 SC meeting, the SC approved waivers for Project 2020-02, allowing
formal comment periods to be reduced from 45 days to 25 calendar days, and final ballot periods to be
reduced from 10 days to as few as 5 calendar days.
The initial draft of the PRC-024-4 and PRC-029-1 drafts were posted for comment March 27, 2024- April 22,
2024. Comments have been reviewed and incorporated. Substantive changes were made to the PRC-029-1
draft based on comments received. Formal comment responses are available in the consideration of
comments received document posted along with these additional drafts.
Questions
1. Provide any additional comments for the Drafting Team to consider, if desired.
Comments:
RELIABILITY | RESILIENCE | SECURITY
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-024-4 – Frequency and Voltage Protection Settings for Synchronous
Generators and Synchronous Condensers
General Rationale
The drafting team proposes to modify PRC‐024‐3 to retain the Reliability Standard as a protection‐based
standard with applicability to only synchronous generators and synchronous condensers. This proposal is
a consequence of both the different natures of synchronous and inverter‐based generation resources and
several recent events exhibiting significant IBR ride‐through deficiencies. The behavior of rotating
synchronous generators during faults and other disturbances on the transmission system is well
established and understood in comparison to IBR generation. The disturbance ride‐through vulnerabilities
of synchronous generators are pole slipping instability and undervoltage dropout of critical plant auxiliary
equipment, leading to tripping of a generator. Pole slipping can be managed by active power dispatch and
system condition constraints, and is outside the scope of PRC‐024‐3. Undervoltage dropout of critical
auxiliary equipment is also outside the scope of PRC‐024‐3 because of complexities associated with
auxiliary systems and how such equipment behaves under low voltage conditions.
The Project 2020‐02 Standard Authorization Request (SAR) notes that auxiliary equipment has not posed a
ride‐through risk and the SAR specifically excludes modifications in PRC‐024‐3 for auxiliary equipment.
Over‐frequency protection, under‐frequency protection, and voltage protection may or may not be
applied to synchronous generating units. If applied however, settings should be coordinated between the
needs of generating unit protection, reasonable expected excursions of system frequency and voltage in a
straightforward fashion, e.g., as no‐trip zones within PRC‐024‐3 attachments, as well as the coordination
of generating unit capabilities, voltage regulating controls, and protection within PRC‐019‐2. Excitation
and governing controls affect synchronous generator ride‐through behavior to some degree but because
of progressive improvement, standardization, and level of maturity of these controls, they are rarely if
ever cause unnecessary tripping during disturbances.
In addition, there are other existing NERC standards to prevent unnecessary tripping of the generators
during a system disturbance such as PRC‐025‐2 “Generator Relay Loadability”, and PRC‐026‐2 “Relay
Performance During Stable Power Swings”. For these reasons, there is no need to impose actual
disturbance ride‐through requirements on synchronous units and only include restrictions for frequency
and voltage protection setting ranges as maintained in PCR‐024‐4.
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for setting frequency, voltage, and volts per hertz protection for
synchronous generators and synchronous condensers is the Generator Owner (GO) and Transmission
RELIABILITY | RESILIENCE | SECURITY
Owner (TO). Planning Coordinators (PC) are also retained as applicable entities but are only in the Quebec
Interconnection. Modifications are proposed in PRC‐024‐4 to expand functional entity applicability to
includes those Transmission Owners that apply protection, as listed in new Facility applicability section
4.2.2.
Facilities (4.2)
Applicability Facilities subparts in Section 4.1.1 were modified to restrict PRC‐024‐4 to synchronous
generators. Section 4.2.2 was added as new subparts to identify which synchronous condensers and
equipment.
Rationale for Requirements R1 through R4
Modifications were made to Requirements R1, R2, R3, and R4 to include the Transmission Owner as an
functional entity applicable to each requirement.
Modifications were made to Requirements R1, R2, R3, and R4 to include language for synchronous
condensers and to remove language that relates to inverter‐based resource functionality (i.e., “cease
injecting current”).
Technical Rationale for Reliability Standard PRC‐024‐4
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | March 2024
2
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1 – Frequency and Voltage Ride-Through Requirements for
Inverter-Based Generating Resources
General Rationale
The drafting team has created a new Reliability Standard (PRC-029-1) to address inverter-based resource
(IBR) disturbance ride-through performance criteria. This proposal is a consequence of both the different
natures of synchronous and inverter-based generation resources and several recent events exhibiting
significant IBR ride-through deficiencies. The proposed PRC-029-1 coincides with certain ride-through
requirements of IEEE 2800-2022 but is structured to follow language from FERC Order No. 901, which
states that “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.” 1
The lack of standardization of IBR technology (equipment/controller behavior) has created reliability
challenges associated with the interconnection of IBR facilities to the power grid. The nature of the fast
switching of power electronics of IBR generation and the electronic interface to the transmission system is
such that disturbance ride-through behavior is largely determined by manufacturer-specific equipment
and controls system designs. These controls may be programmed but also have more restrictive limits on
current, both in magnitude and duration. IBR responses to grid disturbances are highly controlled and
managed by using fast switching of power electronics devices dependent upon manufacturer specific
control system design that can be programmed in many ways and with various and concurrent ridethrough performance objectives. Rather than attempting to restrict the myriad of control approaches,
protections, and settings, it is more straightforward to require ride-through during defined frequency and
voltage excursions.
In contrast to synchronous generation, the need for IBR ride-through requirements has been heightened
by recent events during which IBRs have not met PRC-024-3 frequency and voltage ride-through
expectations, often due to controls and protection only indirectly associated with the system voltage and
frequency excursions. In addition to ride-through, there is the question of what IBRs should be doing as
they ride-through. IBR responses to system disturbances can be beneficial or detrimental to both their
own ride-through and system reliability, often depending on adjustable control settings. Thus, it is
essential to set expectations on performance during ride-through as well as ride-through capability.
IBR do not provide inertia or short circuit contributions, unlike synchronous machines. The drafting team
thinks that IBR should compensate for their lack of inertia and short circuit contributions with wider
P 195, FERC Order No. 901; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019-3157&optimized=false; October 17,
2023
1
RELIABILITY | RESILIENCE | SECURITY
tolerances for frequency and voltage excursions. This is the reason for the differences in the frequency
and voltage tables and graphs between the two standards.
The proposed PRC-029 must be understood as an event-based standard though it is also required to
provide evidence of the ability to ride-through disturbance events by means of dynamic models and
simulation results. Compliance with PRC-029 is determined chiefly though not exclusively from IBR ridethrough performance during transmission system events in the field. An IBR becomes noncompliant with
PRC-029 when an event in the field occurs that shows that one or more requirements were not satisfied.
This intent is clarified by Operations Assessment as the Time Horizon designation of requirements R1-R5.
FERC Order No. 901 Directives
PRC-029-1 is proposed in consideration of directives from FERC Order No. 901 that were assigned to the
Project 2020-02 drafting team. The following directives were assigned to this drafting team for inclusion in
this Standards Project (paragraph numbers of the FERC Order are included for reference):
•
Paragraph 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.”
•
Paragraph 190: “The new or modified Reliability Standards must require registered IBRs to
continue to inject current and perform frequency support during a Bulk-Power System
disturbance.”
•
Paragraph 190: “Any new or modified Reliability Standard must also require registered IBR
generator owners and operators to prohibit momentary cessation in the must ride-through zone
during disturbances.”
•
Paragraph 190: “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.”
•
Paragraph 193: “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.”
•
Paragraph 193: “Further, we direct NERC to ensure that any such exemption would be applicable
for only existing equipment that is unable to meet voltage ride-through 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.).”
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
2
•
Paragraph 193: “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).”
•
Paragraph 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, we direct NERC to
develop new or modified Reliability Standards to mitigate the reliability impacts to the Bulk-Power
System of such an exemption.”
•
Paragraph 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 pre-disturbance output level
in a quick and stable manner after a Bulk-Power System.”
•
Paragraph 209: “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 predisturbance levels during a disturbance, consistent with the IBR Interconnection Requirements
Guideline and Canyon 2 Fire Event Report recommendations.”
•
Paragraph 209: “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.”
•
Paragraph 226: “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 rule prior to
that date.” (pertains multiple projects)
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for assuring acceptable ride-through performance of IBR is either the
Generator Owner (GO) or, in the case of High-voltage Direct Current (VSC-HVDC) transmission facilities
that are dedicated connections for IBR inverter-based resources to the BPS, the Transmission Owner (TO).
Facilities (4.2)
Applicability Facilities includes only those IBR that also meet NERC registration criteria. Language used
within PRC-029-1 applicability only refers to IBR as a whole plant/facility. Consistent with FERC Order
No. 901, IBR performance is based on the overall IBR plant and disturbance monitoring equipment
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
3
requirements established under the proposed PRC-028-1. Requirements within PRC-029-1 do not apply to
individual inverter units or measurements taken at individual inverter unit terminals.
Rationale for Requirement R1
The objective of Requirement R1 is to ensure that all applicable IBRs will ride through grid voltage
disturbances consistent with the must ride-through zone and operation regions specified in Attachment
1. IBRs must be able to demonstrate ride-through performance, that they remain electrically connected,
i.e., shall not trip, and continue to exchange current, i.e., shall not enter momentary cessation.
The drafting team determined that the definition of “must ride-through zones” and “operation regions”
should be consistent with those terms as used within IEEE 2800-2022. Additionally, the team determined
that the voltage thresholds of each operation region should be based on measurements taken on the
high-side of the main power transformer in PRC-029-1, also consistent with IEEE 2800-2022.
Exceptions to Attachment 1 performance criteria are allowable when 1) an IBR needs to trip to clear a
fault within its zone of protection, and 2) a documented equipment limitation prevents an IBR from riding
through the disturbance as permitted under Requirement R4.
When a grid disturbance occurs, such as a close-in fault or a relatively large switching event, the grid
voltage may experience a rapid phase angle shift. In such cases, the phase displacement Δθ can be large
enough to pose challenges for the PLL to track the terminal voltage, cause control instability within the
inverter, such as the inner current control loop or the DC link control loop, and even lead to tripping of
the inverter due to the malfunction of the controls.
Since phase angle jumps are common occurrences on the BPS, this standard requires the IBR to be
designed and operated to ride-through a minimum phase angle jump of 25 electrical degrees. This is a
typical value and aligns with the requirement in IEEE 2800 2022.
Some IBR equipment has PLL loss of synchronism protection, referring to a protective function that
operates when the angle displacement Δθ exceeds a threshold for a predetermined period of time (on the
order of a couple of milliseconds). Historically, this protection has been used by some inverter
manufacturers, especially for inverters in distribution systems. For the IBR connected to the BPS, this
protection function should be disabled. If it is enabled, the phase angle jump protection setting should be
configured such that the IBR shall only trip to prevent equipment damage.
Rationale for Requirement R2
In addition to having minimum voltage ride-through capability specified in Requirement R1, all applicable
IBRs are also required to adhere to certain voltage ride-through performance criteria during system
disturbances. Acceptable performance criteria depend on the operation region that an IBR is presently in
or when in transition from one operation region to another operation region. Requirement R2 includes
specific performance criteria and is needed to assure consistent IBR performance within and each
operation region in Attachment 1 and when in transition between regions.
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
4
R ationale for R equirem ent R 2.1
This subpart of Requirement 2 ensures, when the voltage at the high-side of the main power transformer
(MPT) recovers to the Continuous Operation Region from either the Mandatory Operation Region or the
Permissive Operation Region, an IBR is expected to deliver the pre-disturbance level of active power or
available active power, whichever is less. This requires an IBR to exit the “High Voltage Ride Through
(HVRT)” or “Low Voltage Ridge Through (LVRT)” modes properly such that it does not cause reduction in
the active power when the system already recovers the voltage within the Continuous Operation Region.
When the voltage at the high-side of the MPT is greater than 0.9 per-unit and less than 0.95 per-unit, IBRs
are expected to exit the LVRT mode and come back to “normal operating mode”. If an IBR has a default
total current limit of 1.0 per-unit, the apparent power production of an IBR will be limited to be below 1.0
per-unit (e.g., the per-unit value of IBR terminal voltage). In such case, IBR needs to configure a
preference setting, either to maintain pre-disturbance active power or maximize the reactive power in
order to further help with voltage recovery, according to requirements specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
R ationale for R equirem ent R 2.2
This subpart of Requirement 2 ensures when the voltage at the high-side of the MPT is within the
Mandatory Operation Region, IBRs are expected to enter the HVRT and LVRT mode such that it will inject
or absorb reactive current proportional to the level of terminal voltage deviations it measures. IBR shall
follow Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator
specified certain magnitude of reactive power response to voltage changes, if available.
By default, reactive current prioritization shall be configured unless Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator requires active power priority.
R ationale for R equirem ent R 2.3
This subpart of Requirement 2 ensures when the voltage at the high-side of the MPT is within the
permissive operation region, IBRs are allowed to enter the current block mode to avoid tripping off from
the grid. The drafting team takes into consideration the physical operational capability of the power
electronics devices under such low voltage condition. However, the IBR facility shall restart current
exchange in less than or equal to five cycles of positive sequence voltage retraining to a continuous
operation region or mandatory operation region.
R ationale for R equirem ent R 2.4
This subpart of Requirement 2 ensures when a fault is cleared on the transmission system, the voltage
regulators of connected IBRs must adjust the reactive current injection to restore the transmission system
voltage to the pre-disturbance voltage as defined by the automatic voltage regulator (AVR) setpoint. The
drafting team acknowledges that tuning of the AVR requires a balance between multiple competing
physical factors, e.g., rise time, overshoot, and transient stability. However, it is anticipated that IBR
controls will be tuned to allow for a stable post-disturbance voltage recovery without causing excessive
overshoot or undershoot of the setpoint. When such overshoots do occur, they must not exceed the
magnitude and duration of the applicable table given in Attachment 1. Furthermore, this standard
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
5
anticipates that control system tuning to prevent such over/under voltages will focus on the speed at
which the controller responds to setpoint changes rather than on the magnitude of the reactive current
response. For example, reductions in k-factor to prevent over/under voltages should only be considered
as a last resort.
R ationale for R equirem ent R 2.5
This subpart of Requirement 2 ensures that IBR returns to effective pre-disturbance operation unless
otherwise specified or needed by the Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator.
Must Ride-through
Rationale for Requirement R3
The objective of Requirement R3 is to ensure that IBRs remain electrically connected, synchronized, and
exchanging current, that is, continuing to operate during a frequency excursion event.
Grid frequency reflects the balance of system generation and load. A system event that causes a
generation/load imbalance will cause system frequency to deviate from nominal. The system may
experience an over-frequency event (in the case of more generation than load) or an under-frequency
event (in the case of less generation than load). Inertia resists the deviation from nominal frequency,
giving the operators additional time to rebalance generation and load. System inertia depends on the
amount of rotating mass connected to the system (such as the synchronous generators or motors). The
larger the system inertia, the slower the system frequency will deviate from the nominal value and the
lower the grid Rate Of Change Of Frequency (ROCOF), giving more time to try to rebalance generation and
load. Also, higher system inertia may minimize the risk of Cascading generation loss caused by the
operation of generator frequency protection.
A reduction in system inertia is an inevitable consequence of a power system transiting toward more IBR
and less synchronous generators. As discussed in the previous paragraph, less system inertia means the
frequency will deviate from the nominal value more quickly during a generation/load imbalance event
and will expose the system to a higher ROCOF. A wider frequency ride-through capability for IBR may be
required to avoid the risk of widespread tripping. To reduce the risk of widespread IBR tripping during
frequency disturbances, and more generally to ensure the reliability of future grids with high IBR
penetration, the drafting team proposes a 6-second frequency ride-through capability requirement for
frequencies in the ranges of 61.8Hz to 64Hz or 57.0Hz to 56.0Hz range. The proposed 6-second time
frame of the frequency ride-through capability requirement is beyond the IEEE 2800 standard frequency
ride-through requirement and beyond frequency ride-through requirements for synchronous machines
under PRC-024.
IBRs lack the inertia and short circuit contributions of synchronous machines. To compensate for the lack
of inertia and short circuit contributions, they should have wider tolerances for frequency and voltage
excursions to meet the needs of future power systems with a higher percentage of IBR. Synchronous
resources are more sensitive to frequency deviations than IBR resources. All IBR resources (except for
type 3 wind turbines) interface to the grid through fast switching of power electronics devices. These
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
6
power electronic devices are much less sensitive to the transmission system frequency excursion than
non-hydraulic turbine synchronous resources (steam turbines and combustion turbines). In the case of
the non-hydraulic turbine synchronous resources, the turbine is usually considered to be more restrictive
than the generator in limiting IBR frequency ride-through because of possible mechanical resonances in
the many stages of turbine blades. Off-nominal frequencies may bring blade vibrational frequencies closer
to a mechanical resonate frequency and cause damage due to the vibration stresses. However, inverterinterfaced-IBR does not share this vibrational failure mode. Therefore, IBR should be capable of riding
through the increased proposed 6-second frequency ride-through requirement without risk of equipment
damage or need for frequency protection to operate.
Requirement R3 does not prescribe specific frequency protection settings for IBR equipment. IBR
frequency protection settings should only be set to protect the IBR from damage caused by operation at
off-nominal frequency. An IBR owner must ensure that the IBR frequency protection does not prevent an
IBR from meeting the R3 ride-through requirement.
This standard requires that IBRs remain electrically connected and continue to exchange current during a
frequency excursion event in which the frequency remains within the must ride-through zone according
to Attachment 3 and while the absolute ROCOF magnitude is less than or equal to 5 Hz/second. Some IBR
controllers and their ability to remain electrically connected and continue to exchange current with the
grid are sensitive to ROCOF during a frequency excursion event. If needed to maintain the stability of the
IBR or prevent equipment damage, the R3 requirement allows the IBR to trip for an absolute ROCOF
exceeding 5Hz/sec within the must ride-through zone as shown in Attachment 2. Failure to ride-through
due to ROCOF exceeding 5Hz/sec shall only be allowed during a generator/load imbalance event that
causes the frequency to deviate from nominal.
The ROCOF protection should not operate at the onset of a fault, during a fault, or at fault clearance, i.e.,
it should be disabled for faults. The IBR shall ride-through any system disturbance while the voltage at the
high side of the main power transformer remains within the must ride-through zones as specified in
Attachment 1. Furthermore, to reduce the risk of IBR tripping on ROCOF protection, ROCOF shall be
calculated as the average rate of change for multiple calculated system frequencies for some time greater
than or equal to 0.1 seconds.
Rationale for Requirement R4
The objective of Requirement R4 is to ensure legacy IBR are able to obtain an exemption to the voltage
ride-through requirements if hardware replacements or other costly upgrades would be necessary to
comply with Requirements R1 or Requirement R2. This provision allows such exemptions as long as such
limitations are documented and communicated to the Planning Coordinator, Transmission Planner, and
Reliability Coordinator of the respective footprints in which the IBR project is located. The Planning
Coordinator, Transmission Planner, and Reliability Coordinator will then need to take the voltage ridethrough limitations into account in planning and operations.
Limitations must not be construed as complete exemptions from the applicable Attachment 1 table but
must be specific as to which voltage band(s) and associated duration(s) cannot be satisfied or specific as
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
7
to the number of cumulative voltage deviations within a ten-second time period that the equipment can
ride-through if less than four. Limitation descriptions should identify the specific equipment and explain
the characteristic(s) of that equipment that prevent ride-through. If any equipment limitation is removed
or otherwise corrected, it is likewise necessary to communicate to the Planning Coordinator, Transmission
Planner, and Reliability Coordinator of this.
FERC Order No. 901 states that this provision would be limited to exempting “certain registered IBRs from
voltage ride-through performance requirements.” This is the reason that no similar provisions are
included for exemptions for frequency or rate-of-change-of-frequency (ROCOF) ride-through
requirements per R3.
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
8
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1 – Frequency and Voltage Ride-Through Requirements for
Inverter-Based Generating Resources
General Rationale
The drafting team has created a new Reliability Standard (PRC‐029‐1) to address inverter‐based resource
(IBR) disturbance ride‐through performance criteria. This proposal is a consequence of both the different
natures of synchronous and inverter‐based generation resources and several recent events exhibiting
significant IBR ride‐through deficiencies. The proposed PRC‐029‐1 coincides with certain ride‐through
requirements of IEEE 2800‐2022 but is structured to follow language from FERC Order No. 901, which
states that “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.”1
The lack of standardization of IBR technology (equipment/controller behavior) has created reliability
challenges associated with the interconnection of IBR facilities to the power grid. The nature of the fast
switching of power electronics of IBR generation and the electronic interface to the transmission system is
such that disturbance ride‐through behavior is largely determined by manufacturer‐specific equipment
and controls system designs. These controls may be programmed but also have more restrictive limits on
current, both in magnitude and duration. IBR responses to grid disturbances are highly controlled and
managed by using fast switching of power electronics devices dependent upon manufacturer specific
control system design that can be programmed in many ways and with various and concurrent ride‐
through performance objectives. Rather than attempting to restrict the myriad of control approaches,
protections, and settings, it is more straightforward to require ride‐through during defined frequency and
voltage excursions.
In contrast to synchronous generation, the need for IBR ride‐through requirements has been heightened
by recent events during which IBRs have not met PRC‐024‐3 frequency and voltage ride‐through
expectations, often due to controls and protection only indirectly associated with the system voltage and
frequency excursions. In addition to ride‐through, there is the question of what IBRs should be doing as
they ride‐through. IBR responses to system disturbances can be beneficial or detrimental to both their
own ride‐through and system reliability, often depending on adjustable control settings. Thus, it is
essential to set expectations on performance during ride‐through as well as ride‐through capability.
IBR do not provide inertia or short circuit contributions, unlike synchronous machines. The drafting team
thinks that IBR should compensate for their lack of inertia and short circuit contributions with wider
1 P 195, FERC Order No. 901; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019‐3157&optimized=false; October 17,
2023
RELIABILITY | RESILIENCE | SECURITY
tolerances for frequency and voltage excursions. This is the reason for the differences in the frequency
and voltage tables and graphs between the two standards.
The proposed PRC‐029 must be understood as an event‐based standard. though it is also required to
provide evidence of the ability to ride‐through disturbance events by means of dynamic models and
simulation results. Compliance with PRC‐029 is determined chiefly though not exclusively from IBR ride‐
through performance during transmission system events in the field and not from interconnection
studies, transmission planning studies, operational planning studies, or from IBR models.. An IBR becomes
noncompliant with PRC‐029 only when an event in the field occurs that shows that one or more
requirements were not satisfied. This intent is clarified by Operations Assessment as the Time Horizon
designation of requirements R1‐R5.
FERC Order No. 901 Directives
PRC‐029‐1 is proposed in consideration of directives from FERC Order No. 901 that were assigned to the
Project 2020‐02 drafting team. The following directives were assigned to this drafting team for inclusion in
this Standards Project (paragraph numbers of the FERC Order are included for reference):
Paragraph 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.”
Paragraph 190: “The new or modified Reliability Standards must require registered IBRs to
continue to inject current and perform frequency support during a Bulk‐Power System
disturbance.”
Paragraph 190: “Any new or modified Reliability Standard must also require registered IBR
generator owners and operators to prohibit momentary cessation in the no‐tripmust ride‐through
zone during disturbances.”
Paragraph 190: “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.”
Paragraph 193: “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.”
Paragraph 193: “Further, we direct NERC to ensure that any such exemption would be applicable
for only existing equipment that is unable to meet voltage ride‐through performance. When such
existing equipment is replaced, the exemption would no longer apply, and the new equipment
Technical Rationale for Reliability Standard PRC‐029‐1
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | MarchJune 2024
2
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.).”
Paragraph 193: “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).”
Paragraph 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, we direct NERC to
develop new or modified Reliability Standards to mitigate the reliability impacts to the Bulk‐Power
System of such an exemption.”
Paragraph 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 pre‐disturbance output level
in a quick and stable manner after a Bulk‐Power System.”
Paragraph 209: “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.”
Paragraph 209: “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.”
Paragraph 226: “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 rule prior to
that date.” (pertains multiple projects)
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for assuring acceptable ride‐through performance of IBR is either the
Generator Owner (GO) andor, in the case of High‐voltage Direct Current (VSC‐HVDC) transmission
facilities that are dedicated connections for IBR inverter‐based resources to the BPS, the Transmission
Owner (TO).
Technical Rationale for Reliability Standard PRC‐029‐1
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3
Facilities (4.2)
Applicability Facilities includes only those IBR that also meet NERC registration criteria. Language used
within PRC‐029‐1 applicability only refers to IBR as a whole plant/facility. Consistent with FERC Order
No. 901, IBR performance is based on the overall IBR plant and disturbance monitoring equipment
requirements established under the proposed PRC‐028‐1. Requirements within PRC‐029‐1 do not apply to
individual inverter units or measurements taken at individual inverter unit terminals.
Rationale for Requirement R1
The objective of Requirement R1 is to ensure anthat all applicable IBRIBRs will ride‐ through a grid voltage
disturbancedisturbances consistent with the no‐tripmust ride‐through zone and Operation
Regionsoperation regions specified in Attachment 1. IBRIBRs must be able to demonstrate ride‐through
performance, that they remain electrically connected, i.e., shall not trip, and continue to exchange
current, i.e., shall not enter momentary cessation.
The drafting team determined that the definition of “no‐tripmust ride‐through zones” and “Operation
Regionsoperation regions” should be consistent with those terms as used within IEEE 2800‐2022.
Additionally, the team determined that the voltage thresholds of each Operation Region areoperation
region should be based on measurements taken on the high‐side of the main power transformer in PRC‐
029‐1, also consistent with IEEE 2800‐2022.
Exceptions to Attachment 1 performance criteria are allowable when 1) an IBR needs to trip to clear a
fault within its zone of protection, and 2) a documented equipment limitation prevents an IBR from riding
through the disturbance in accordance withas permitted under Requirement R6R4.
When a grid disturbance occurs, such as a close‐in fault or a relatively large switching event, the grid
voltage may experience a rapid phase angle shift. In such cases, the phase displacement Δθ can be large
enough to pose challenges for the PLL to track the terminal voltage, cause control instability within the
inverter, such as the inner current control loop or the DC link control loop, and even lead to tripping of
the inverter due to the malfunction of the controls.
Since phase angle jumps are common occurrences on the BPS, this standard requires the IBR to be
designed and operated to ride‐through a minimum phase angle jump of 25 electrical degrees. This is a
typical value and aligns with the requirement in IEEE 2800 2022.
Some IBR equipment has PLL loss of synchronism protection, referring to a protective function that
operates when the angle displacement Δθ exceeds a threshold for a predetermined period of time (on the
order of a couple of milliseconds). Historically, this protection has been used by some inverter
manufacturers, especially for inverters in distribution systems. For the IBR connected to the BPS, this
protection function should be disabled. If it is enabled, the phase angle jump protection setting should be
configured such that the IBR shall only trip to prevent equipment damage.
Rationale for Requirement R2
Technical Rationale for Reliability Standard PRC‐029‐1
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4
In addition to having minimum voltage ride‐through capability specified in Requirement R1, anall
applicable IBR isIBRs are also required to adhere to certain voltage ride‐through performance criteria
during a system disturbancedisturbances. Acceptable performance criteria is dependentdepend on the
Operation Regionoperation region that an IBR is presently in, or it’s changewhen in transition from one
Operation Regionoperation region to another Operation Regionoperation region. Requirement R2
includes specific performance criteria and is needed to assure consistent IBR performance duringwithin
and each Operation Regionoperation region in Attachment 1 and when in transition between regions.
Rationale for Requirement R2.1
This subpart of Requirement 2 ensures, when the voltage at the high‐side of the main power transformer
(MPT) recovers to the Continuous Operation Region from either the Mandatory Operation Region or the
Permissive Operation Region, an IBR is expected to deliver the pre‐disturbance level of active power or
available active power, whichever is less. This requires an IBR to exit the “High Voltage Ride Through
(HVRT)” or “Low Voltage Ridge Through (LVRT)” modes properly such that it does not cause reduction in
the active power when the system already recovers the voltage within the Continuous Operation Region.
When the voltage at the high‐side of the MPT is greater than 0.9 per‐unit and less than 0.95 per‐unit, IBRs
are expected to exit the LVRT mode and come back to “normal operating mode”. If an IBR has a default
total current limit of 1.0 per‐unit, the apparent power production of an IBR will be limited to be below 1.0
per‐unit (e.g., the per‐unit value of IBR terminal voltage). In such case, IBR needs to configure a
preference setting, either to maintain pre‐disturbance active power or maximize the reactive power in
order to further help with voltage recovery, according to requirements specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
Technical Rationale for Reliability Standard PRC‐029‐1
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Rationale for Requirement R2.2
This subpart of Requirement 2 ensures when the voltage at the high‐side of the MPT is within the
Mandatory Operation Region, IBRs are expected to enter the HVRT and LVRT mode such that it will inject
or absorb reactive current proportional to the level of terminal voltage deviations it measures. IBR shall
follow Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator
specified certain magnitude of reactive power response to voltage changes, if available.
By default, reactive current prioritization shall be configured unless Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator requires active power priority.
Rationale for Requirement R2.3
This subpart of Requirement 2 ensures when the voltage at the high‐side of the MPT is within the
permissive operation region, IBRs are allowed to enter the current block mode to avoid tripping off from
the grid. The drafting team takes into consideration the physical operational capability of the power
electronics devices under such low voltage condition. However, the IBR facility shall restart current
exchange in less than or equal to five cycles of positive sequence voltage retraining to a continuous
operation region or mandatory operation region.
Rationale for Requirement R2.4
This subpart of Requirement 2 ensures when a fault is cleared on the transmission system, the voltage
regulators of connected IBRs must adjust the reactive current injection to restore the transmission system
voltage to the pre‐disturbance voltage as defined by the automatic voltage regulator (AVR) setpoint. The
drafting team acknowledges that tuning of the AVR requires a balance between multiple competing
physical factors, e.g., rise time, overshoot, and transient stability. However, it is anticipated that IBR
controls will be tuned to allow for a stable post‐disturbance voltage recovery without causing excessive
overshoot or undershoot of the setpoint. When such overshoots do occur, they must not exceed the
magnitude and duration of the applicable table given in Attachment 1. Furthermore, this standard
anticipates that control system tuning to prevent such over/under voltages will focus on the speed at
which the controller responds to setpoint changes rather than on the magnitude of the reactive current
response. For example, reductions in k‐factor to prevent over/under voltages should only be considered
as a last resort.
Rationale for Requirement R2.45
This subpart of Requirement 2 ensures that IBR returns to effective pre‐disturbance operation unless
otherwise specified or needed by the Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator.
Rationale for Requirement R2.5
This subpart of Requirement 2 ensures that voltage protection settings of IBR are based on maximum
equipment capabilities rather than settings based directly on, or just outside, of the no‐trip zone.
Must Ride-through
Rationale for Requirement R3
Technical Rationale for Reliability Standard PRC‐029‐1
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The objective of Requirement R3 is to provide transient overvoltage ride‐through for IBR during the non‐
fault switching event. Voltage transients are commonly occurring on the BPS due to switching actions,
fault clearing, lightning, etc. IBR shall ride‐through the transient overvoltage condition specified in
Attachment 2 during the non‐fault switching events in the transmission systems. During this transient
overvoltage event, IBRs should continue to inject current, but it does not have to respond to transient
overvoltage, i.e., enter reactive priority mode and/or change magnitude of current output.
If necessary, IBRs may operate in current blocking mode, when instantaneous voltage exceeds
1.2 p.u., to help ensure stable response that does not lead to tripping and to eliminate the IBR as a
possible cause for the overvoltage. If IBRs operate in the current blocking mode, it shall restart
current exchange in less than or equal to five cycles following instantaneous voltage falling below, and
remaining below, 1.2 p.u. This is different than momentary cessation, which involves a resource returning
over a longer time frame with a specified delay and ramp rate.
The drafting team notes that IBR should not be set to trip on an instantaneous, unfiltered voltage
measurements, except due to known equipment limitations.
Rationale for Requirement R4
The objective of Requirement R4 is to ensure that IBR remainsIBRs remain electrically connected,
synchronized, and exchanging current , that is, continuing to operate during a frequency excursion event.
Grid frequency reflects the balance of system generation and load. A system event that causes a
generation/load imbalance will cause system frequency to deviate from nominal. The system may
experience an over‐frequency event (in the case of more generation than load) or an under‐frequency
event (in the case of less generation than load). Inertia resists the deviation from nominal frequency,
giving the operators additional time to rebalance generation and load. System inertia depends on the
amount of rotating mass connected to the system (such as the synchronous generators or motors). The
larger the system inertia, the slower the system frequency will deviate from the nominal value and the
lower the grid Rate Of Change Of Frequency (ROCOF), giving more time to try to rebalance generation and
load. Also, higher system inertia may minimize the risk of Cascading generation loss caused by the
operation of generator frequency protection.
A reduction in system inertia is an inevitable consequence of a power system transiting toward more IBR
and less synchronous generators. As discussed in the previous paragraph, less system inertia means the
frequency will deviate from the nominal value more quickly during a generation/load imbalance event
and will expose the system to a higher ROCOF. A wider frequency ride‐through capability for IBR may be
required to avoid the risk of widespread tripping. To reduce the risk of widespread IBR tripping during
frequency disturbances, and more generally to ensure the reliability of future grids with high IBR
penetration, the drafting team proposes a 6‐second frequency ride‐through capability requirement for
frequencies in the ranges of 61.8Hz to 64Hz or 57.0Hz to 56.0Hz range. The proposed 6‐second time
frame of the frequency ride‐through capability requirement is beyond the IEEE 2800 standard frequency
ride‐through requirement and beyond frequency ride‐through requirements for synchronous machines
under proposed PRC‐024‐4.
Technical Rationale for Reliability Standard PRC‐029‐1
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7
IBR lacksIBRs lack the inertia and short circuit contributions of synchronous machines. To compensate for
the lack of inertia and short circuit contributions, they should have wider tolerances for frequency and
voltage excursions to meet the needs of future power systemsystems with a higher percentage of IBR.
Synchronous resources are more sensitive to frequency deviations than IBR resources. All IBR resources
(except for type 3 wind turbines) interface to the grid through fast switching of power electronics devices.
These power electronic devices are much less sensitive to the transmission system frequency excursion
than non‐hydraulic turbine synchronous resources (steam turbines and combustion turbines). In the case
of the non‐hydraulic turbine synchronous resources, the turbine is usually considered to be more
restrictive than the generator in limiting IBR frequency ride‐through because of possible mechanical
resonances in the many stages of turbine blades. Off‐nominal frequencies may bring blade vibrational
frequencies closer to a mechanical resonate frequency and cause damage due to the vibration stresses.
However, inverter‐interfaced‐IBR does not share this vibrational failure mode. Therefore, IBR should be
capable of riding through the increased proposed 6‐second frequency ride‐through requirement without
risk of equipment damage or need for frequency protection to operate.
Requirement R4R3 does not prescribe specific frequency protection settings for IBR equipment. IBR
frequency protection settings should only be set to protect the IBR from damage caused by operation at
off‐nominal frequency. An IBR owner must ensure that the IBR frequency protection does not prevent an
IBR from meeting the R4R3 ride‐through requirement.
This standard requires that IBR remainsIBRs remain electrically connected and continuescontinue to
exchange current during a frequency excursion event in which the frequency remains within the no‐
tripmust ride‐through zone\ according to Attachment 3 and while the absolute ROCOF magnitude is less
than or equal to 5 Hz/second. Some IBR controllers and their ability to remain electrically connected and
continue to exchange current towith the grid are sensitive to ROCOF during a frequency excursion event.
If needed to maintain the stability of the IBR or prevent equipment damage, the R4R3 requirement allows
the IBR to trip for an absolute ROCOF exceeding 5Hz/sec within the no‐tripmust ride‐through zone as
shown in Attachment 32. Failure to ride‐through due to ROCOF exceeding 5Hz/sec shall only be allowed
during a generator/load imbalance event that causes the frequency to deviate from nominal.
The ROCOF protection should not operate at the onset of a fault, during a fault, or at fault clearance, i.e.,
it should be disabled for faults. The IBR shall ride‐through any system disturbance while the voltage at the
high side of the main power transformer remains within the no‐tripmust ride‐through zones as specified
in Attachment 1. Furthermore, to reduce the risk of IBR tripping on ROCOF protection, ROCOF shall be
calculated as the average rate of change for multiple calculated system frequencies for some time greater
than or equal to 0.1 seconds.
Rationale for Requirement R5R4
The objective of Requirement R5 is to ensure IBR remains electrically connected and exchanging current
during instantaneous positive sequence voltage phase angle changes initiated by certain non‐fault
switching events.
Technical Rationale for Reliability Standard PRC‐029‐1
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Unlike synchronous generators, for which the synchronization mechanism to the grid is naturally
preserved by the inertia, the grid following voltage source inverters (VSI) used for the majority of existing
IBR facilities are equipped with the Phase‐lock‐loop (PLL) device for synchronization purposes. A typical
synchronous reference frame PLL schematic is given in Fig. 1, where the three‐phase voltages in the abc
reference frame (va, vb, and vc) are transformed to the dq frame (vd’ and vq’) by the Park’s transformation
and the phase angle θ is controlled by a feedback loop that regulates the q component to zero.
Figure 1: Schematic Diagram of a Synchronous Reference Frame PLL
When the inverter operates in the steady state, it is locked to the grid voltage via the PLL, assuming the PI
controller is well tuned. In this case the phase displacement between the grid voltage and that measured
by the PLL, Δθ is zero, as shown in Fig. 2.
Figure 2: Phasor Diagram of Grid Voltage and Current
When a grid disturbance occurs, such as a close‐in fault or a relatively large switching event, the grid
voltage may experience a rapid phase angle shift. In such cases, the phase displacement Δθ can be large
enough to pose challenges for the PLL to track the terminal voltage, cause control instability within the
inverter, such as the inner current control loop or the DC link control loop, and even lead to tripping of
the inverter due to the malfunction of the controls.
Since phase angle jumps are common occurrences on the BPS, this standard requires the IBR to be
designed and operated to ride‐through a minimum phase angle jump of 25 electrical degrees. This is a
typical value and aligns with the requirement in IEEE 2800 2022. Furthermore, for a phase angle jump of
25 degrees or more, the IBR shall only trip to prevent equipment damage.
Technical Rationale for Reliability Standard PRC‐029‐1
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Some IBR equipment has PLL loss of synchronism protection, referring to a protective function that
operates when the angle displacement Δθ exceeds a threshold for a predetermined period of time (on the
order of a couple of milliseconds). Historically, this protection has been used by some inverter
manufacturers, especially for inverters in distribution systems. For the IBR connected to the BPS, this
protection function should be disabled. If it is enabled, the phase angle jump protection setting shall be
configured such that the IBR shall only trip to prevent equipment damage.
Rationale for Requirement R6
The objective of Requirement R5R4 is to ensure legacy IBR may needare able to obtain an exemption to
the voltage ride‐through requirements if hardware replacements or other costly upgrades would be
necessary to comply with Requirements R1 or Requirement R2. This provision allows such exemptions as
long as such limitations are documented and communicated to the Planning Coordinator, Transmission
Planner, and Reliability Coordinator of the respective footprints in which the IBR project is located. The
Planning Coordinator, Transmission Planner, and Reliability Coordinator will then need to take the voltage
ride‐through limitations into account in planning and operations.
Limitations must not be construed as complete exemptions from the applicable Attachment 1 table but
must be specific as to which voltage band(s) and associated duration(s) cannot be satisfied or specific as
to the number of cumulative voltage deviations within a ten‐second time period that the equipment can
ride‐through if less than four. Limitation descriptions should identify the specific equipment and explain
the characteristic(s) of that equipment that prevent ride‐through. If any equipment limitation is removed
or otherwise corrected, it is likewise necessary to communicate to the Planning Coordinator, Transmission
Planner, and Reliability Coordinator of this.
FERC Order No. 901 states that this provision would be limited to exempting “certain registered IBRs from
voltage ride‐through performance requirements.” This is the reason that no similar provisions are
included for exemptions for frequency, or rate‐of‐change‐of‐frequency (ROCOF) ,phase angle change
ride‐through requirements per R3.
Technical Rationale for Reliability Standard PRC‐029‐1
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Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-024-4
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐024‐4. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to BulkPower System instability, separation, or a cascading sequence of
failures, or could place the Bulk‐Power System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to BulkPower System instability, separation, or a cascading sequence of failures, or could place the Bulk‐Power System at
an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk‐Power System, or the ability to effectively
monitor and control the Bulk‐Power System. However, violation of a medium risk requirement is unlikely to lead to Bulk‐ Power System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the BulkPower
System, or the ability to effectively monitor, control, or restore the BulkPower System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Power System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk‐Power System, or the ability to effectively monitor and control the Bulk‐Power System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk‐Power
System, or the ability to effectively monitor, control, or restore the Bulk‐Power System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk‐Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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VRF and VSL Justifications | March 2024
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Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of the measured does not meet the
intent of the requirement.
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non‐compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
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The VRF did not change from the previously FERC approved PRC‐024‐3 Reliability Standard.
VSLs for PRC-024-4, Requirement R1
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to set its
applicable frequency protection so
that it does not trip according to
Requirement R1.
VSL Justifications for PRC-024-4, Requirement R1
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
FERC VSL G1
Violation Severity Level Assignments consequence of lowering the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-024-4, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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The VRF did not change from the previously FERC approved PRC‐024‐3 Reliability Standard.
VSLs for PRC-024-4, Requirement R2
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to set its
applicable voltage protection so that
it does not trip according to
Requirement R2.
VSL Justifications for PRC-024-4, Requirement R2
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
FERC VSL G1
Violation Severity Level Assignments consequence of lowering the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-024-4, Requirement R2
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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The VRF did not change from the previously FERC approved PRC‐024‐3 Reliability Standard.
VSLs for PRC-024-4, Requirement R3
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner documented
the known non‐protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 30
calendar days but less than or
equal to 60 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner documented
the known non‐protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 60
calendar days but less than or
equal to 90 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner documented
the known non‐protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 90
calendar days but less than or
equal to 120 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner failed to
document any known non‐
protection system equipment
limitation that prevented it from
meeting the criteria in Requirement
R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar days of
identifying the limitation.
VSL Justifications for PRC-024-4, Requirement R3
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
FERC VSL G1
Violation Severity Level Assignments consequence of lowering the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐024‐4
VRF and VSL Justifications | March 2024
10
VSL Justifications for PRC-024-4, Requirement R3
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐024‐4
VRF and VSL Justifications | March 2024
11
The VRF did not change from the previously FERC approved PRC‐024‐3 Reliability Standard.
VSLs for PRC-024-4, Requirement R4
Lower
Moderate
High
The Generator Owner or
Transmission Owner provided its
protection settings more than 60
calendar days but less than or
equal to 90 calendar days of any
change to those settings.
OR
The Generator Owner or
Transmission Owner provided its
protection settings more than 90
calendar days but less than or
equal to 120 calendar days of any
change to those settings.
OR
The Generator Owner or
Transmission Owner provided its
protection settings more than 120
calendar days but less than or
equal to 150 calendar days of any
change to those settings.
OR
The Generator Owner or
Transmission Owner provided
protection settings more than 60
calendar days but less than or
equal to 90 calendar days of a
written request.
The Generator Owner or
Transmission Owner provided
protection settings more than 90
calendar days but less than or
equal to 120 calendar days of a
written request.
The Generator Owner or
Transmission Owner or provided
protection settings more than 120
calendar days but less than or
equal to 150 calendar days of a
written request.
Severe
The Generator Owner or
Transmission Owner failed to
provide its protection settings within
150 calendar days of any change to
those settings.
OR
The Generator Owner or
Transmission Owner failed to
provide protection settings within
150 calendar days of a written
request.
VSL Justifications for PRC-024-4, Requirement R4
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
FERC VSL G1
Violation Severity Level Assignments consequence of lowering the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐024‐4
VRF and VSL Justifications | March 2024
12
VSL Justifications for PRC-024-4, Requirement R4
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐024‐4
VRF and VSL Justifications | March 2024
13
Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1
This document provides the drafting team’s (DT’s) justification for assignment of violation risk factors (VRFs) and violation severity levels
(VSLs) for each requirement in PRC-029-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in the
Electric Reliability Organizations (ERO) Sanction Guidelines. The DT applied the following NERC criteria and FERC Guidelines when developing
the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to BulkPower System instability, separation, or a cascading sequence of
failures, or could place the Bulk-Power System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to BulkPower System instability, separation, or a cascading sequence of failures, or could place the Bulk-Power System at
an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk-Power System, or the ability to effectively
monitor and control the Bulk-Power System. However, violation of a medium risk requirement is unlikely to lead to Bulk- Power System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the BulkPower
System, or the ability to effectively monitor, control, or restore the BulkPower System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Power System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk-Power System, or the ability to effectively monitor and control the Bulk-Power System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk-Power
System, or the ability to effectively monitor, control, or restore the Bulk-Power System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
RELIABILITY | RESILIENCE | SECURITY
Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
RELIABILITY | RESILIENCE | SECURITY
NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the
requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
RELIABILITY | RESILIENCE | SECURITY
Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for PRC-029-1, Requirement R1
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
RELIABILITY | RESILIENCE | SECURITY
VSLs for PRC-029-1, Requirement R1
Lower
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of each
applicable facility to Ride-through
in accordance with Attachment 1,
except for those conditions
identified in Requirement R1.
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to Ride-through
requirements in accordance with
Attachment 1, except for those
conditions identified in
Requirement R1.
VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
RELIABILITY | RESILIENCE | SECURITY
VSL Justifications for PRC-029-1, Requirement R1
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
RELIABILITY | RESILIENCE | SECURITY
VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
Guideline 3- Consistency among
Reliability Standards
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R2
Lower
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of each
applicable facility to adhere to
performance requirements during
voltage excursions, as specified in
Requirement R2.
Moderate
N/A
High
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to performance
requirements during voltage
excursions, as specified in
Requirement R2.
N/A
VSL Justifications for PRC-029-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
RELIABILITY | RESILIENCE | SECURITY
VSL Justifications for PRC-029-1, Requirement R2
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
RELIABILITY | RESILIENCE | SECURITY
VRF Justifications for PRC-029-1, Requirement R3
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is appropriate that if violated, it would be expected to adversely affect the electrical state or
capability of the Bulk-Power System.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R3
Lower
Moderate
High
Severe
RELIABILITY | RESILIENCE | SECURITY
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of each
applicable facility to Ride-through
in accordance with Attachment 2.
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to Ride-through
requirements in accordance with
Attachment 2.
VSL Justifications for PRC-029-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
RELIABILITY | RESILIENCE | SECURITY
VSL Justifications for PRC-029-1, Requirement R3
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
VRF Justifications for PRC-029-1, Requirement R4
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk-Power System.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
RELIABILITY | RESILIENCE | SECURITY
VRF Justifications for PRC-029-1, Requirement R4
Proposed VRF
Lower
than One Obligation
VSLs for PRC-029-1, Requirement R4
Lower
Moderate
High
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the documented
limiting equipment but failed to
document and communicate the
change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), and Reliability
Coordinator(s) more than 30
calendar days but less than or
equal to 60 calendar days after the
change to the equipment.
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the documented
limiting equipment but failed to
document and communicate the
change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), and Reliability
Coordinator(s) more than 60
calendar days but less than or
equal to 90 calendar days after the
change to the equipment.
OR
OR
OR
The Generator Owner or
Transmission Owner provided a
copy to the applicable entities as
detailed in R4.2 more than 12
months but less than or equal to 15
The Generator Owner or
Transmission Owner provided a
copy to the applicable entities as
detailed in R4.2 more than 15
months but less than or equal to 18
The Generator Owner or
Transmission Owner provided a
copy to the applicable entities as
detailed in R4.2 more than 18
months but less than or equal to 21
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the documented
limiting equipment but failed to
document and communicate the
change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), and Reliability
Coordinator(s) more than 90
calendar days but less than or
equal to 120 calendar days after
the change to the equipment.
Severe
The Generator Owner or
Transmission Owner failed to
document complete information
for facilities identified with known
hardware limitations that prevent
the facility from meeting voltage
Ride-through criteria as detailed in
Requirements R1 or R2.
OR
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the limiting equipment
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s), and
Reliability Coordinator(s) more
than 120 calendar days after the
change to the equipment.
RELIABILITY | RESILIENCE | SECURITY
months after the effective date of
R4.
months after the effective date of
R4.
months after the effective date of
R4.
OR
The Generator Owner or
Transmission Owner failed to
provide a copy to the applicable
entities as detailed in R4.2 within
24 months after the effective date
of R4.
VSL Justifications for PRC-029-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
RELIABILITY | RESILIENCE | SECURITY
VSL Justifications for PRC-029-1, Requirement R4
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
RELIABILITY | RESILIENCE | SECURITY
Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐029‐1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to BulkPower System instability, separation, or a cascading sequence of
failures, or could place the Bulk‐Power System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to BulkPower System instability, separation, or a cascading sequence of failures, or could place the Bulk‐Power System at
an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk‐Power System, or the ability to effectively
monitor and control the Bulk‐Power System. However, violation of a medium risk requirement is unlikely to lead to Bulk‐ Power System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the BulkPower
System, or the ability to effectively monitor, control, or restore the BulkPower System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Power System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk‐Power System, or the ability to effectively monitor and control the Bulk‐Power System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk‐Power
System, or the ability to effectively monitor, control, or restore the Bulk‐Power System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk‐Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
Severe VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
The performance or product
measured does not substantively
meet the intent of the
requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non‐compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for PRC-029-1, Requirement R1
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride‐through system
disturbances. Failure to ride‐through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
Similar requirements in PRC‐024‐3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R1
Lower
AThe Generator Owner or
Transmission Owner failed to
demonstrate the capability of each
applicable facility to Ride‐through
in accordance with Attachment 1,
except for those conditions
identified in Requirement R1.N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable facility
adhered to Ride‐through
requirements in accordance with
Attachment 1, except for those
conditions identified in IBR remains
electrically connected and continued
to exchange current in accordance
with Attachment 1, unless needed
to clear a fault, in accordance with
Requirement R1.
VSL Justifications for PRC-029-1, Requirement R1
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
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VSL Justifications for PRC-029-1, Requirement R1
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride‐through system
disturbances. Failure to ride‐through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
Similar requirements in PRC‐024‐3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R2
Lower
Moderate
The Generator Owner or
N/A
Transmission Owner failed to
demonstrate the capability of each
applicable facility to adhere to
performance requirements during
voltage excursions, as specified in
Requirement R2.N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable facility
adhered to performance
requirements during voltage
excursionsIBR adhered to
performance requirements during
each System disturbance, as
specified in Requirement R2.
VSL Justifications for PRC-029-1, Requirement R2
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
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VSL Justifications for PRC-029-1, Requirement R2
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R3
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R3
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable IBR
adhered to performance
requirements during each transient
overvoltage period as specified in
Requirement R3.
VSL Justifications for PRC-029-1, Requirement R3
FERC VSL G1
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R3
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R34
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower High is appropriate that if violated, it would not be expected to adversely affect the electrical
state or capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower High VRF is consistent with the VRF assignments for other requirements in the
proposed Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower High VRF requirement per the criteria filed with FERC as part of
the ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R43
Lower
The Generator Owner or
Transmission Owner failed to
demonstrate the capability of each
applicable facility to Ride‐through
in accordance with Attachment
2.N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable facility
adhered to Ride‐through
requirements in accordance with
Attachment 2IBR adhered to
performance requirements during
each frequency excursion event, as
specified in Requirement R4.
VSL Justifications for PRC-029-1, Requirement R34
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
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VSL Justifications for PRC-029-1, Requirement R34
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R5
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R5
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable IBR
adhered to performance
requirements during each
instantaneous positive sequence
voltage phase angle change of less
than 25 electrical degrees, as
specified in Requirement R5.
VSL Justifications for PRC-029-1, Requirement R5
FERC VSL G1
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
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VSL Justifications for PRC-029-1, Requirement R5
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R46
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R46
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the documented
limiting equipment but failed to
document and communicate the
change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), and Reliability
Coordinator(s), and Regional Entity
more than 30 calendar days but
less than or equal to 60 calendar
days after the change to the
equipment.
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the documented
limiting equipment but failed to
document and communicate the
change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), and Reliability
Coordinator(s), and Regional Entity
more than 60 calendar days but
less than or equal to 90 calendar
days after the change to the
equipment.
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs
or replaces the documented
limiting equipment but failed to
document and communicate the
change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), and Reliability
Coordinator(s), and Regional Entity
more than 90 calendar days but
less than or equal to 120 calendar
days after the change to the
equipment.
The Generator Owner or
Transmission Owner failed to
document complete information for
facilities identified with known
hardware evidence of equipment
limitations that prevent the facility
from meeting voltage Ride‐through
criteria as detailed in Requirements
R1 or R2consistent with
Requirement R6 and prior to the
effective date of PRC 029 1
Requirement R6.
OR
The Generator Owner or
Transmission Owner with a
previously communicated
equipment limitation that repairs or
replaces the documented limiting
equipment but failed to document
and communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s), and
Reliability Coordinator(s), and
Regional Entity more than 120
calendar days after the change to
OR
The Generator Owner or
Transmission Owner provided a
copy to the applicable entities as
detailed in R4.2 more than 12
months but less than or equal to 15
months after the effective date of
R4.
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the equipment.
OR
The Generator Owner or
Transmission Owner failed to
provide a copy to the applicable
entities as detailed in R4.2 within 24
months after the effective date of
R4.
VSL Justifications for PRC-029-1, Requirement R46
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐029‐1
VRF and VSL Justifications | March 2024RELIABILITY
| RESILIENCE | SECURITY
22
VSL Justifications for PRC-029-1, Requirement R46
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | PRC‐029‐1
VRF and VSL Justifications | March 2024RELIABILITY
| RESILIENCE | SECURITY
23
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough) | PRC-024-4 and PRC-029-1
Formal Comment Period Open through July 8, 2024
Now Available
A 20-day formal comment period for Project 2020-02 Modifications to PRC-024 (Generator Ridethrough), is open through 8 p.m. Eastern, Monday, July 8, 2024.
The Standards Committee approved waivers to the Standard Processes Manual at their December 2023
meeting. These waivers were sought by NERC Standards staff for reduced formal comment and ballot
periods. This will assist the drafting teams in expediting the standards development process due to firm
timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket No. RM22-12-000
on October 19, 2023.
The standard drafting team’s considerations of the responses received from the previous comment
period are reflected in these drafts of the standards and other documents.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
RELIABILITY | RESILIENCE | SECURITY
Next Steps
Additional ballots for the standards and implementation plans, as well as the non-binding polls of the
associated Violation Risk Factors and Violation Severity Levels will be conducted June 28 – July 8, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Manager of Standards Development, Jamie Calderon (via email)
or at 404-960-0568 Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
(Generator Ride-through) observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Formal Comment Period Open
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | June 2024
2
Comment Report
Project Name:
2020-02 Modifications to PRC-024 (Generator Ride-through) | Draft 2
Comment Period Start Date:
6/18/2024
Comment Period End Date:
7/8/2024
Associated Ballots:
2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan AB 2 OT
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 AB 2 ST
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 AB 2 ST
There were 63 sets of responses, including comments from approximately 138 different people from approximately 91 companies
representing 7 of the Industry Segments as shown in the table on the following pages.
Questions
1. Provide any comments for the drafting team to consider, if desired.
Organization
Name
MRO
Name
Segment(s)
Anna Martinson 1,2,3,4,5,6
Region
MRO
Group Name
MRO Group
Group Member
Name
Shonda McCain
Group
Member
Organization
Group
Member
Segment(s)
Omaha Public 1,3,5,6
Power District
(OPPD)
Group Member
Region
MRO
Michael Brytowski Great River
Energy
1,3,5,6
MRO
Jamison Cawley
Nebraska
Public Power
District
1,3,5
MRO
Jay Sethi
Manitoba
Hydro (MH)
1,3,5,6
MRO
Husam Al-Hadidi
Manitoba
1,3,5,6
Hydro (System
Preformance)
MRO
Kimberly Bentley
Western Area
Power
Adminstration
MRO
Jaimin Patal
Saskatchewan 1
Power
Coporation
(SPC)
MRO
George Brown
Pattern
Operators LP
5
MRO
Larry Heckert
Alliant Energy
(ALTE)
4
MRO
Terry Harbour
MidAmerican
Energy
Company
(MEC)
1,3
MRO
Dane Rogers
Oklahoma Gas 1,3,5,6
and Electric
(OG&E)
MRO
Seth Shoemaker
Muscatine
1,3,5,6
Power & Water
MRO
Michael Ayotte
ITC Holdings
MRO
Andrew Coffelt
Board of Public 1,3,5,6
UtilitiesKansas (BPU)
MRO
Peter Brown
Invenergy
MRO
Angela Wheat
Southwestern 1
Power
Administration
1,6
1
5,6
MRO
WEC Energy
Group, Inc.
Christine Kane
California ISO Darcy
O'Connell
FirstEnergy FirstEnergy
Corporation
Mark Garza
3
2
4
WEC Energy
Group
WECC
Bobbi Welch
Midcontinent
ISO, Inc.
2
MRO
Christine Kane
WEC Energy
Group
3
RF
Matthew Beilfuss
WEC Energy
Group, Inc.
4
RF
Clarice Zellmer
WEC Energy
Group, Inc.
5
RF
David Boeshaar
WEC Energy
Group, Inc.
6
RF
California ISO
2
WECC
New York
Independent
System
Operator
2
NPCC
John Pearson
ISO New
England, Inc.
2
NPCC
Helen Lainis
Independent
Electricity
System
Operator
2
NPCC
Elizabeth Davis
PJM
2
Interconnection
RF
Charles Yeung
Southwest
Power Pool,
Inc.
2
MRO
Bobbi Welch
Midcontinent
ISO, Inc.
2
RF
Kennedy Meier
Electric
Reliability
Council of
Texas, Inc.
2
Texas RE
Julie Severino
FirstEnergy FirstEnergy
Corporation
1
RF
Aaron
Ghodooshim
FirstEnergy FirstEnergy
Corporation
3
RF
Robert Loy
FirstEnergy FirstEnergy
Solutions
5
RF
Mark Garza
FirstEnergyFirstEnergy
1,3,4,5,6
RF
Stacey Sheehan
FirstEnergy FirstEnergy
6
RF
ISO/RTO
Ali Miremadi
Council (IRC)
Gregory Campoli
Standards
Review
Committee
FE Voter
Corporation
Austin Energy Michael Dillard
5
Southern
Pamela Hunter 1,3,5,6
Company Southern
Company
Services, Inc.
DTE Energy
Black Hills
Corporation
Patricia Ireland 4
Rachel Schuldt 6
Austin Energy Michael Dillard
SERC
Southern
Company
DTE Energy
Black Hills
Corporation All Segments
Austin Energy
5
Texas RE
Lovita Griffin
Austin Energy
3
Texas RE
Tony Hua
Austin Energy
4
Texas RE
Imane Mrini
Austin Energy
6
Texas RE
Thomas Standifur Austin Energy
1
Texas RE
Matt Carden
Southern
Company Southern
Company
Services, Inc.
1
SERC
Joel Dembowski
Southern
Company Alabama
Power
Company
3
SERC
Ron Carlsen
Southern
Company Southern
Company
Generation
6
SERC
Leslie Burke
Southern
Company Southern
Company
Generation
5
SERC
Patricia Ireland
DTE Energy - 4
Detroit Edison
RF
Karie Barczak
DTE Energy - 3
Detroit Edison
Company
RF
Adrian Raducea
DTE Energy - 5
Detroit Edison
Company
RF
Micah Runner
Black Hills
Corporation
1
WECC
Josh Combs
Black Hills
Corporation
3
WECC
Rachel Schuldt
Black Hills
Corporation
6
WECC
Carly Miller
Black Hills
Corporation
5
WECC
Sheila Suurmeier
Black Hills
Corporation
5
WECC
Dominion Dominion
Resources,
Inc.
Sean Bodkin
Western
Electricity
Coordinating
Council
Steven
Rueckert
Tim Kelley
Tim Kelley
Associated
Electric
Cooperative,
Inc.
Todd Bennett
6
Dominion
10
WECC
WECC
3
SMUD and
BANC
AECI
Connie Lowe
Dominion Dominion
Resources,
Inc.
3
NA - Not
Applicable
Lou Oberski
Dominion Dominion
Resources,
Inc.
5
NA - Not
Applicable
Larry Nash
Dominion 1
Dominion
Virginia Power
NA - Not
Applicable
Rachel Snead
Dominion Dominion
Resources,
Inc.
5
NA - Not
Applicable
Steve Rueckert
WECC
10
WECC
Curtis Crews
WECC
10
WECC
Nicole Looney
Sacramento
Municipal
Utility District
3
WECC
Charles Norton
Sacramento
Municipal
Utility District
6
WECC
Wei Shao
Sacramento
Municipal
Utility District
1
WECC
Foung Mua
Sacramento
Municipal
Utility District
4
WECC
Nicole Goi
Sacramento
Municipal
Utility District
5
WECC
Kevin Smith
Balancing
Authority of
Northern
California
1
WECC
Michael Bax
Central Electric 1
Power
Cooperative
(Missouri)
SERC
Adam Weber
Central Electric 3
Power
Cooperative
(Missouri)
SERC
Gary Dollins
M and A
SERC
3
Electric Power
Cooperative
William Price
M and A
1
Electric Power
Cooperative
SERC
Olivia Olson
Sho-Me Power 1
Electric
Cooperative
SERC
Mark Ramsey
N.W. Electric
Power
Cooperative,
Inc.
1
SERC
Heath Henry
NW Electric
Power
Cooperative,
Inc.
3
SERC
Tony Gott
KAMO Electric 3
Cooperative
SERC
Micah Breedlove
KAMO Electric 1
Cooperative
SERC
Brett Douglas
Northeast
1
Missouri
Electric Power
Cooperative
SERC
Skyler Wiegmann
Northeast
3
Missouri
Electric Power
Cooperative
SERC
Mark Riley
Associated
Electric
Cooperative,
Inc.
1
SERC
Brian Ackermann
Associated
Electric
Cooperative,
Inc.
6
SERC
Chuck Booth
Associated
Electric
Cooperative,
Inc.
5
SERC
Jarrod Murdaugh
Sho-Me Power 3
Electric
Cooperative
SERC
1. Provide any comments for the drafting team to consider, if desired.
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
The R1, R2, and R3 design requirement is problematic because of at least two major issues: dynamic modeling deficiencies and lack of standardized
test procedures. IBR dynamic modeling is well proven to be deficient in representing performance of equipment in the field, particularly disturbance ridethrough performance, and even though MOD-026-2 is addressing model verification/validation, it is still only post-interconnection (or postcommissioning). What is needed here is to expand the scope of MOD-026-2 to also encompass pre-interconnection model verification/validation so that
“simulations” and “studies” on IBR plant models evaluating the plant designs are performed on verified and validated dynamic models ahead of
interconnection. Secondly, without well-defined, standardized test procedures to assess ride-through capability, there is little possibility that simulations
and studies on IBR designs will result in uniform across-the-board assurance that IBR equipment and plant designs adequately adhere to the PRC-029
ride-through requirements. Completion of IEEE 2800.2, which is intended to define the necessary testing and verification procedures, and selective
consideration and use of its content in PRC-029 is necessary just as 2800 itself has been instrumental in formulating the mandatory ride-through
requirements in PRC-029. Without dynamic model verification/validation and well-defined, standardized test procedures, the design components of R1,
R2, and R3 will not achieve the desired outcome and will only result in confusion as to what evidence is actually required from GOs and TOs.
Need to indicate in association with R1 third bullet that momentary current blocking is an acceptable means of reacting to non-fault initiated phase
jumps greater than 25 degrees.
There is inconsistency throughout the document in instances of both “TO and GO” and “TO or GO”. Please resolve the inconsistencies.
Please clarify what “other evidence” in M1, M2, and M3 would be acceptable to assure compliance. Please also reinsert “shall” in M1, M2, and M3
where it has been removed (to read “Each GO and TO shall have evidence…”). The sentences are not complete without it and measures in other
standards (such as PRC-024-4) read that way.
Figures 1 and 2 in Attachment 1 should be better aligned. One has a log scale on the horizontal axis and the other is linear. There is no valid reason for
these differences, and we recommend they be consistent in the axes used. The only difference between them should be the slight difference in the
lower boundary of the must ride-through zone reflecting the slight difference between Attachment 1 tables 1 and 2.
There needs to be an exemption for system-related causes of ride-through failure. IBRs should be exempt from ride-through requirements in R1 through
R3 if tripping or failure to ride through is attributable to any of the following:
1. Sub-synchronous control interaction or ferro-resonance involving series compensation confirmed by the TOP, RC, TP, or PC
2. Unstable behavior of other nearby IBRs or dynamic devices such as FACTS or HVDC confirmed by the TOP, RC, TP, or PC
3. System short circuit levels during contingencies below the level of IBR stable operation confirmed by the TOP, RC, TP, or PC
4. System-level transient or oscillatory instabilities confirmed by the TOP, RC, TP, or PC
R 2.1.3 should be .95 per unit (with a decimal point) rather than 95 per unit.
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Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric
Company, 3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Document Name
Comment
1)
Editorial suggestions BOLD and ITALICS for the Measures in below
2) In PRC-029, standard as follows:
4.2 Facilities:
4.2.1. BEPS inverter‐based resources(2)
(2)For the purpose of this standard, “inverter‐based resources” refers to a collection of individual solar photovoltaic (PV), Type 3 and Type 4 wind
turbines, battery energy storage system (BESS), or fuel cells that operate as a single plant/resource. In case of offshore wind plants connecting via
a dedicated VSC‐HVDC, the inverter‐based resource includes the VSC‐HVDC system.
Question for SDT: Should VSC_HVDC be included even if it’s not associated with a windplant (ie Transbay Cable HVDC)?
M1. Is very clunky, below is my attempt to making it read better.
1}·
Replace have with has.
2}·
Reword per the following:
o Has evidence of dynamic simulations, studies, or other evidence to demonstrate the design of each facility will adhere to Ride‐through requirements,
as specified in Requirement R1. As system conditions allow each Generator Owner and Transmission Owner retain evidence of actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) recorded to demonstrate that the operation of each
facility did adhere to Ride‐through requirements, as specified in Requirement R1. If the Generator Owner and Transmission Owner choose to utilize
Ride‐through exemptions that occur within the “must Ride‐through zone” and are caused by non‐fault initiated phase jumps of greater than 25 electrical
degrees, then each Generator Owner and Transmission Owner also retain evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder,
Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate that the facility failed to Ride‐through during a phase jump of greater than or
equal to 25 electrical degrees, and documentation from their Transmission Planner, Reliability Coordinator, Planning Coordinator, or Transmission
Operator that a non‐fault initiated switching event occurred.
M2 .
Each Generator Owner and Transmission Owner has evidence of dynamic simulations, studies, or other evidence to demonstrate the design of each
facility will adhere to requirements, as specified in Requirement R2. Each Generator Owner and Transmission Owner also retain evidence of actual
disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data demonstrating that the operation of
each facility did adhere to performance requirements, as specified in Requirement R2, during each voltage excursion measured at the high‐side of the
main power transformer. The Generator Owner or Transmission Owner have evidence of receiving such performance requirements, (e.g. email
exchange, contract information) if the Transmission Planner, Transmission Operator, Reliability Coordinator, Planning Coordinator has
required the Generator Owner or Transmission Owner to follow performance requirements other than those in Requirement R2 (e.g. ramp
rates, reactive power prioritization).
3) Question for SDT: What does this mean? M3 Same comments as M2.
4) Figure -1 “Voltage ride-through requirement for AC-connected wind” on page 20 does not match Attachment 1 Table-1 on page16 for the requirement
of <1.2 and > 1.1 minimum ride-through time of 1 second.
5)
For PRC-029-1, section B (Requirements and Measures)-
R2- Section 2.2:
In section 2.2, footnote 6: mentions that “In either case and if required, the magnitude of active power and reactive current shall be as specified by the
Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.“
Question/comment for SDT: It has not been mentioned how to identify the magnitude of active power and reactive current, and it seems that
Electromagnetic Transient (EMT) studies should be performed to evaluate each IBR and it will result in a significant amount of extra work for PTO to
receive, evaluate and perform EMT studies.
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Ijad Dewan - Ijad Dewan On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Ijad Dewan
Answer
Document Name
Comment
The Technical Rationale must include reasons for inclusion of Synchronous Condenser to the standard under the applicability section.
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Dominion Energy supports EEI’s additional comments.
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
FirstEnergy requests the DT consider changing PRC-029-1 Requirement 2 R2.5 from active power to apparent.
Entities may incorporate solar sites that automatically change reactive power to attempt to control voltage similar to FirstEnergy’s sites. This change
will inevitably cause changes in active power post event, such that meeting this requirement as written could be difficult. Since changes in reactive
power are desired for voltage control, the requirement should be changed to allow this response. Using apparent power in the requirement versus
active power is one way to achieve this.
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Brian Lindsey - Entergy - 1
Answer
Document Name
Comment
•
M1: This seems more like a requirement than a measure for meeting the requirement.
•
R2, M2, M3 and R4: Duplicative of Mod-026 and MOD-027. Also, seems to be dependent on PRC-028 passing and sites having DDRs
installed.
•
R2: is not clear. It seems to overlap significantly with VAR-002.
o
Should that be .95 per unit?
•
R3: No provisions for exemptions for frequency limitations.
•
R4.1 thru 4.2: Are we seeking approval from this large list of entities for an exemption or are we documenting the limitation that prevents from
meeting requirement 1? If we have to get approval there is no requirement in this standard that require any of these entities to provide that
approval.
o
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Recommend limiting who must be notified to just the TP or TP and RC. There needs to be a single point of contact instead multiple
entities.
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Response
Mark Flanary - Midwest Reliability Organization - 10
Answer
Document Name
Comment
The draft PRC-029-1 includes expectations in R1, R2, and R3 for entities to demonstrate ride-through adherence (R1 & R3) and performance (R2)
through two separate means: 1) dynamics simulations/studies and 2) data from actual system events. These two separate expectations are combined
in each requirement but are not clearly delineated within the requirement text. It is only in the measures associated with each requirement that it
becomes clear that both expectations exist. This lack of clarity leads to concerns about the auditability of this standard.
The Standard should clearly specify during which timeframes and under what conditions an entity is expected to show compliance using
simulations/studies vs. data from actual events. For instance, upon commissioning of a new facility, no event data will be available. Should the CEA
expect to see a study completed for a new facility prior to commercial operation? For existing facilities with extensive recorded event data is it still
necessary to perform simulations and studies to show compliance? How much event data and how serious must the events be for this to be
acceptable?
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Chantal Mazza - Hydro-Quebec (HQ) - 1 - NPCC
Answer
Document Name
Comment
It is imperative that the standard drafting teams for this project as well as the 2021-04 (PRC-002 and PRC-028) and 2023-02 (PRC-030 vs PRC-004)
assure a coherent way of addressing the inclusion and exclusion of IBRs in current and upcoming standards.
The following comments are applicable to PRC-029-1
The definition for Inverter Based Resource (IBR) was approved by industry in April under Project 2020-06. We do not agree with inserting the
uncapitalized version of IBR into 4.2 Facilities section because it is unbounded and insufficient to identify the Facilities applicable to this Standard, as
required in the Rules of Procedure (Appendix 3a, Standard Processes Manual). Furthermore, these definitions are the foundation of several ongoing
projects in response to FERC Order 901, where FERC “directs NERC to submit new or modified Reliability Standards that address specific matters
pertaining to the impacts of IBRs on the reliable operation of the BPS.”
Chapter A, -Section 4.2.2 What is the “IBR registration criteria”? Please add a footnote to describe it.
Requirement R1: 25degrees, 1.1pu-45s and 1.18pu-2s should be moved to attachment 1 to allow for regional variance.
Requirement -R2-2.1.3 and B-R2-2.2 Can the TP ask for a mix of active/reactive power based on a predetermined ratio (currently only indicated as
active OR reactive).
Requirement -R3: No exemption exists for existing equipment limitation to meet frequency and ROCOF ride-through? (like R4 for voltage) One should
be added.
Requirement -R3. The 5Hz/s value should be moved to Attachment 2 to allow for a regional variance.
Requirement -R3 The 5Hz/s requirement is already indicated in R1. It should not be repeated.
Requirement -R4: Are the phase shift and V/Hz requirements described in R1 considered as being part of the “voltage ride-through criteria”? (or is it for
amplitude only) An exemption should be provided for existing equipment with limitations.
Requirement -R4 and M4 What should be done when the manufacturer does not exist anymore or refuses to collaborate?
Attachment 1: Please explain (footnote) why the ride through requirement for a type-4 wind turbine needs to be different of a PV plant.
The Technical Rationale must include reasons for inclusion of Synchronous Condenser to the standard under the applicability section.
The term “active power” is not defined and appears to be used in conjunction with Real Power. Recommend consistency throughout the standards
when using Real Power vs active power, such as MOD-025, BAL-001, and many others.
Recommend the DT reevaluate the implementation period of 6 months. Recommend making implementation period 18 months or greater to account for
the need for working with OEMs to implement any setting changes and the need for IBR settings reviews conducted by third parties, as necessary.
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
Tri-State has no additional comments for PRC-024-4
Tri-State agrees with MRO NSRF Comments regarding PRC-029-1
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
•
•
Likes
PRC-029-1 Attachment 1
o Footnotes 10 and bullet 1 seem redundant. Consider consolidation with bullet 4.
o Footnotes 11, 13 and bullet 5 seem redundant. Consider consolidation.
Technical Rational for Reliability Standard PRC-029-1
o Requirement R1, paragraph 5 – missing hyphen in “IEEE 2800-2022”.
0
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Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name
Comment
PRC-024: Black Hills Corporation does not have any further comments for this revision for this standard as part of this project.
PRC-029: Black Hills Corporation agrees with the comments identified by the NAGF. They are as follows:
The NAGF believes that PRC-029 should allow for frequency ride through (“FRT”) exemptions similar to its treatment of voltage ride through (“VRT”)
exemptions. The justification for allowing VRT exemptions in FERC Order 901 also apply to FRT. We believe the statement in FERC Order 901,
paragraph 193 in response to ACP/SEIA’s comment in paragraph 188 does not preclude the standard drafting team from considering FRT exemptions
due legacy equipment limitations. Here are a few reasons why:
1.
If FERC’s intent was to exclude Frequency Ride Through exemptions while allowing Voltage ride through exemptions, there would be more of a
record established to support this differential treatment.
2.
FERC responded to ACP/SEIA’s comment on ride-through requirements as if they were only asking about voltage ride through requirements.
FERC made no mention of frequency ride through requirements.
3.
Similar to FERC’s rational for the consideration of voltage ride through exemptions, there are also older IBR technologies with hardware that
would need to be physically replaced to meet frequency ride through requirements as well.
4.
NERC and the NERC Standard Drafting Teams have the technical expertise to address complex technical issues such as legacy equipment
limitations that FERC does not have.
Applicability Section, 4.2.2 – Recommend removing this section.
Requirement R1: The NAGF notes that R1 only addresses voltage ride through and should be revised to include frequency ride through as well. In
addition, R1 should address frequency ride through limitations for legacy IBR facilities.
Measurement M1 – The proposed narrative reads more like requirements than measures; recommend to revise the narrative accordingly. In addition,
the NAGF notes that the proposed narrative seems to assume that PRC-028 will be need to be approved/in place for PRC-029 to be a viable standard.
Requirement 2.1.3: The narrative is unclear as to what is expected for this proposed requirement. Request that the narrative be
rewritten/restructured to address this issue. In addition, it is unclear which entity will define the preference for active or reactive power. The NAGF
suggests that the Transmission Planner (TP) should have the authority to define this preference. This recommendation also applies to Requirement 2,
second bullet and Footnote 6.
Requirement R2.5: The NAGF recommends that the narrative be revised to state that active power shall be restored when” the voltage at the high‐side
of the main power transformer returns to the Continuous Operating Region”.
Requirement R4: The draft narrative does not clearly specify who is responsible for approving the exemption. The NAGF requests the narrative be
revised to address this issue.
Measure M4: Recommend replacing the word “seeking: with “submitting” in the first sentence.
Additionally, Black Hills Corporation reviewed and agrees with EEI’s high level concerns for PRC-029, which are:
1.
The Standard attempts to redefine the approved definition of IBR by adding VSC-HVDC systems after the IBR definition was approved by the
industry.
2.
The Standard adds TOs to this Standard solely to address VSC-HVDC systems, yet no technical justification has been provided. Moreover, these
systems were not identified in FERC Order No. 901, or this SAR and they were not clearly identified in the Applicability Section of this proposed
Reliability Standard.
3.
EEI is concerned with the inclusion of requirements that are not clearly defined or set by multiple registered entities (i.e., TP, PC, RC, or TOP).
This creates regulatory confusion and places IBR-GOs in a position where they may need to comply with any number of entities without clearly defining
who is responsible. (See Requirement R2, subpart 2.1.3; subpart 2.2 (bullet 2); subpart 2.5) Moreover, the identification of multiple entities who could
be responsible creates a situation where IBR-GOs will have reporting obligations to multiple entities because no single entity is identified as being
responsible. (See requirement R4, subparts 4.2 & 4.2.1; subpart 4.3) We further note that none of the entities identified (i.e., TP, PC, RC, or TOP) are
identified within the Applicability section of this proposed Reliability Standard. All of this can create confusion and places considerable burden on the
IBR-GOs that needs to be resolved and clarified.
4.
Throughout this Reliability Standard there is use of non-glossary terms (i.e., active power vs. Real Power) where glossary terms are available and
should be used. While in other cases glossary terms are used but not capitalized. (e.g., reactive power vs. Reactive Power) Greater efforts should be
made to use NERC Glossary terms where appropriate and capitalize those terms, as required.
Detailed Concerns
Ride-through Definition Comments: EEI does not support the proposed definition for “Ride-through” as proposed because it is too vague and
contains no defined limits, as proposed. We recommend the following changes:
Ride‐through: Ability to withstand voltage or frequency Disturbances within defined regulatory limits remaining connected, synchronized with
the Transmission System, and continuing to operate. (remove: in response to System conditions through the time‐frame of a System
Disturbance.)
Applicability Section Comments:
Footnote 1: EEI does not support adding TO that own VSC-HVDC systems because this was not a scope item and is therefore not be included in the
scope of this SAR. Moreover, Footnote 1 conflicts with Footnote 2 which defines VSC-HVDC as an IBR, which is again does not in alignment with the
approved definition of an IBR.
Footnote 2: EEI does not support Footnote 2 because it expands the definition of IBRs beyond what was recently approved by the industry, noting the
expansion of IBRs to include VSC‐HVDC. Furthermore, there was no technical justification for adding VSC-HVDC and the SAR did not include adding
VSC-HVDC systems to this project. For this reason, we ask that the definition of IBR not be expanded through footnotes and suggest that the DT
submit a technical justification for adding VSC-HVDC systems to the applicability section of this Standard, rather than redefining an approved definition
in a footnote.
To address our concerns related to Footnotes 1 & 2 we suggest that if VSC-HVDC systems are to be classified as IBRs, then the approved definition
should be pulled by NERC and resubmitted with those resources added to the definition and resubmitted to the industry for approval. Alternatively,
VSC-HVDC systems could be defined separately, and that definition submitted to the industry for approval. In both cases, a technical justification
should be provided to the industry that defines the issues and risks to BPS reliability that VSC-HVDC systems pose
EEI suggests that if the DT believes that certain IBR capabilities as identified under Requirement R2 need (or may need) to be specified then they
should identify the entity who should be responsible among the four identified (i.e., TP, PC, RC or TOP); add them to the applicability section of this
Reliability Standard; add clear requirements and adjust the reporting obligations for the IBR-GO under Requirement R4.
Requirement R1 & R2 Comments: EEI does not agree with the inclusion of Transmission Owners because they would only have an obligation under
this Reliability Standard if VSC-HVDC systems were included. Given we do not support the inclusion of VSC-HVDC systems without a technical
justification and modified SAR, we ask that Transmission Owners be removed from Requirement R1.
Measures M1 & M2: EEI is concerned that M1 & M2 contains measures that are overly prescriptive providing little discretion to IBR-GOs in
demonstrating their compliance with Requirements R1 and R2 that seem to align more with a Requirement than a Measure. To address our concerns,
we offer the following suggested changes to M1 and suggest similar changes be made to M2:
M1. Each Generator Owner (remove: and Transmission Owner) shall have evidence (remove: of dynamic simulations, studies, or other
evidence to demonstrate the design of each facility will adhere) that supports the Ride-through capability of each of their facilities, as specified
in Requirement R1. (e.g., simulations, studies, recorded data from disturbance monitoring equipment, etc.) (remove: Each Generator Owner and
Transmission Owner have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and
Fault Recorder) to demonstrate that the operation of each facility did adhere to Ride-through requirements, as specified in Requirement R1.)
If the Generator Owner and Transmission Owner choose to utilize Ride-through exemptions that occur within the “must Ride-through zone” and are
caused by non-fault-initiated phase jumps of greater than 25 electrical degrees, then each Generator Owner (remove: and Transmission Owner) also
have evidence supporting that exemption. (e.g., studies, simulations or supporting data from disturbance monitoring equipment) (remove: of
actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate
that the facility failed to Ride-through during a phase jump of greater than or equal to 25 electrical degrees, and documentation from their
Transmission Planner, Reliability Coordinator, Planning Coordinator, or Transmission Operator that a non-fault initiated switching event
occurred).
Requirement R3 & R4: EEI does not support the inclusion of Transmission Owners within Requirements R3 & R4 for the same reasons identified
above.
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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name
Comment
PRC-024-4
No Comments, MH is generally supportive of this proposed standard.
PRC-029-1
Applicability:
The standard switches between BPS (bulk power system) and BES (bulk electric system). For consistency, one term should be used throughout the
standard.
R1: bullet # 3:
MH recommends adding a footnote stating that the facility may operate in current block mode if necessary to avoid tripping for non-fault initiated phase
jumps greater than 25 degrees.
R2:
MH recommends that the defined terms, Real Power and Reactive Power be used throughout the document instead of active power and reactive
power.
R 2.1.3
To SDT: “The voltage is below 95 per unit” should be replaced by “The voltage is below 0.95 per unit”
R 2.1.3 & 2.2
Allowing multiple entities to place potentially conflicting requirements upon an applicable functional entity is unacceptable. Either a single entity be
tasked with the obligation, or a hierarchy be provided so that an entity is not placed in a multibed conflicted request situation.
M1, M2, M3, and R4
To SDT: Consistently replace “Each Generator Owner and Transmission Owner” with “Each Generator Owner or Transmission Owner”
R3
This requirement requires that Each Generator Owner or Transmission Owner shall ensure the design and operation are such that each facility adheres
to Ride‐through requirements during a frequency excursion but does not require any governor response action or capability. The inverter‐based
resources that “adhere to Ride‐through requirements” but are not based on frequency deviation, would comply with the standard requirements, which is
not ideal. The TP/PC is expected to specify inverter‐based resources performance during abnormal system frequency.
MH recommends:
Each Generator Owner or Transmission Owner shall ensure the design and operation is such that each facility adheres to Ride‐through requirements
and response as specified by TP, RC, TOP, or PC during a frequency excursion.
Implementation plan:
The standard is event-based compliance that requires installing recorded equipment data with higher sampling rates at all applicable legacy IBR
Facilities. Therefore, we suggest that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC-028-1) for the legacy IBRs.
Also, MH recommends that the implementation plan of legacy IBR (a facility that is in service by the effective date of PRC‐029‐1) be longer than any
new interconnected IBR (a facility that is in service after the effective date of PRC‐029‐1/ PRC-028-1)
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Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
Constellation feels that the draft 2 added significant technical requirements that would require OEM collaboration and input on their equipment.
Operating at Max capability requires additional analysis from GOs and OEMs to ensure subcomponents in the BOP and WTG side will be able to
operate at these limits.
Further, the added language for the high side transformer volts per hz ( Hz) settings to exceed 1.1 per unit longer than 45 seconds or exceed 1.18 for
longer than 2 seconds will require GO/GOPs to work with the transformer manufacturer to see if these new limits can be met. The volt/hz settings are
set to protect the transformer during over excitation conditions and they are above the provided transformer excitation curve from the manufacturer.
Also, the new ride through voltage limits is set so high that the current WTGs will not be able to ride through without tripping due to equipment operating
conditions. OEMs are still unsure and not incentivized to collaborate in a timely manner to understand capabilities and limitations.
Finally, Constellation asks the DT to address scheduling and implementation plan. The current plan is not reasonable to implement.
Kimberly Turco on behalf of Constellation Segments 5 and 6
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Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation feels that the draft 2 added significant technical requirements that would require OEM collaboration and input on their equipment.
Operating at Max capability requires additional analysis from GOs and OEMs to ensure subcomponents in the BOP and WTG side will be able to
operate at these limits.
Further, the added language for the high side transformer volts per hz ( Hz) settings to exceed 1.1 per unit longer than 45 seconds or exceed 1.18 for
longer than 2 seconds will require GO/GOPs to work with the transformer manufacturer to see if these new limits can be met. The volt/hz settings are
set to protect the transformer during over excitation conditions and they are above the provided transformer excitation curve from the manufacturer.
Also, the new ride through voltage limits is set so high that the current WTGs will not be able to ride through without tripping due to equipment operating
conditions. OEMs are still unsure and not incentivized to collaborate in a timely manner to understand capabilities and limitations.
Finally, Constellation asks the DT to address scheduling and implementation plan. The current plan is not reasonable to implement.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of its members:
PRC-029-1 Comments:
While EEI appreciates that changes made to address our previous comments for the 1st draft of PRC-029-1, we have some new concerns that need to
be addressed.
Our high level concerns are described in our comments below:
1. The Standard attempts to redefine the approved definition of IBR by adding VSC-HVDC systems after the IBR definition was approved by the
industry.
2. The Standard adds TOs to this Standard solely to address VSC-HVDC systems, yet no technical justification has been provided. Moreover, these
systems were not identified in FERC Order No. 901, or this SAR and they were not clearly identified in the Applicability Section of this proposed
Reliability Standard.
3. EEI is concerned with the inclusion of requirements that are not clearly defined or set by multiple registered entities (i.e., TP, PC, RC, or TOP).
This creates regulatory confusion and places IBR-GOs in a position where they may need to comply with any number of entities without clearly defining
who is responsible. (See Requirement R2, subpart 2.1.3; subpart 2.2 (bullet 2); subpart 2.5) Moreover, the identification of multiple entities who could
be responsible creates a situation where IBR-GOs will have reporting obligations to multiple entities because no single entity is identified as being
responsible. (See requirement R4, subparts 4.2 & 4.2.1; subpart 4.3) We further note that none of the entities identified (i.e., TP, PC, RC, or TOP) are
identified within the Applicability section of this proposed Reliability Standard. All of this can create confusion and places considerable burden on the
IBR-GOs that needs to be resolved and clarified.
4. Throughout this Reliability Standard there is use of non-glossary terms (i.e., active power vs. Real Power) where glossary terms are available and
should be used. While in other cases glossary terms are used but not capitalized. (e.g., reactive power vs. Reactive Power) Greater efforts should be
made to use NERC Glossary terms where appropriate and capitalize those terms, as required.
Detailed Concerns
Ride-through Definition Comments:
EEI does not support the proposed definition for “Ride-through” as proposed because it is too vague and contains no defined limits, as proposed. We
recommend the following changes:
Ride‐through: Ability to withstand voltage or frequency Disturbances within defined regulatory limits remaining connected, synchronized with
the Transmission System, and continuing to operate. in response to System conditions through the time‐frame of a System
Disturbance(remove).
Applicability Section Comments:
Footnote 1: EEI does not support adding TO that own VSC-HVDC systems because this was not a scope item and is therefore not be included in the
scope of this SAR. Moreover, Footnote 1 conflicts with Footnote 2 which defines VSC-HVDC as an IBR, which is again does not in alignment with the
approved definition of an IBR.
Footnote 2: EEI does not support Footnote 2 because it expands the definition of IBRs beyond what was recently approved by the industry, noting the
expansion of IBRs to include VSC‐HVDC. Furthermore, there was no technical justification for adding VSC-HVDC and the SAR did not include adding
VSC-HVDC systems to this project. For this reason, we ask that the definition of IBR not be expanded through footnotes and suggest that the DT
submit a technical justification for adding VSC-HVDC systems to the applicability section of this Standard, rather than redefining an approved definition
in a footnote.
To address our concerns related to Footnotes 1 & 2 we suggest that if VSC-HVDC systems are to be classified as IBRs, then the approved definition
should be pulled by NERC and resubmitted with those resources added to the definition and resubmitted to the industry for approval. Alternatively,
VSC-HVDC systems could be defined separately, and that definition submitted to the industry for approval. In both cases, a technical justification
should be provided to the industry that defines the issues and risks to BPS reliability that VSC-HVDC systems pose
EEI suggests that if the DT believes that certain IBR capabilities as identified under Requirement R2 need (or may need) to be specified then they
should identify the entity who should be responsible among the four identified (i.e., TP, PC, RC or TOP); add them to the applicability section of this
Reliability Standard; add clear requirements and adjust the reporting obligations for the IBR-GO under Requirement R4.
Requirement R1 & R2 Comments: EEI does not agree with the inclusion of Transmission Owners because they would only have an obligation under
this Reliability Standard if VSC-HVDC systems were included. Given we do not support the inclusion of VSC-HVDC systems without a technical
justification and modified SAR, we ask that Transmission Owners be removed from Requirement R1.
Measures M1 & M2: EEI is concerned that M1 & M2 contains measures that are overly prescriptive providing little discretion to IBR-GOs in
demonstrating their compliance with Requirements R1 and R2 that seem to align more with a Requirement than a Measure. To address our concerns,
we offer the following suggested changes to M1 and suggest similar changes be made to M2:
M1. Each Generator Owner shall have evidence that supports the Ride-through capability of each of their facilities, as specified in Requirement R1.
(e.g., simulations, studies, recorded data from disturbance monitoring equipment, etc.) If the Generator Owner and Transmission Owner choose to
utilize Ride-through exemptions that occur within the “must Ride-through zone” and are caused by non-fault initiated phase jumps of greater than 25
electrical degrees, then each Generator Owner also have evidence supporting that exemption. (e.g., studies, simulations or supporting data from
disturbance monitoring equipment)
Requirement R3 & R4: EEI does not support the inclusion of Transmission Owners within Requirements R3 & R4 for the same reasons identified
above.
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David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
Document Name
Comment
Vistra supports comments made by EEI and Entergy.
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 1
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Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by the NAGF.
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
Comment
PRC-029:
General Comment: The NAGF believes that PRC-029 should allow for frequency ride through (“FRT”) exemptions similar to its treatment of voltage ride
through (“VRT”) exemptions. The justification for allowing VRT exemptions in FERC Order 901 also apply to FRT. We believe the statement in FERC
Order 901, paragraph 193 in response to ACP/SEIA’s comment in paragraph 188 does not preclude the standard drafting team from considering FRT
exemptions due legacy equipment limitations. Here are a few reasons why:
1.
If FERC’s intent was to exclude Frequency Ride Through exemptions while allowing Voltage ride through exemptions, there would be more of a
record established to support this differential treatment.
2.
FERC responded to ACP/SEIA’s comment on ride-through requirements as if they were only asking about voltage ride through requirements.
FERC made no mention of frequency ride through requirements.
3.
Similar to FERC’s rational for the consideration of voltage ride through exemptions, there are also older IBR technologies with hardware that
would need to be physically replaced to meet frequency ride through requirements as well.
4.
NERC and the NERC Standard Drafting Teams have the technical expertise to address complex technical issues such as legacy equipment
limitations that FERC does not have.
Applicability Section, 4.2.2 – Recommend removing this section.
Requirement R1: The NAGF notes that R1 only addresses voltage ride through and should be revised to include frequency ride through as well. In
addition, R1 should address frequency ride through limitations for legacy IBR facilities.
Measurement M1 – The proposed narrative reads more like requirements than measures; recommend to revise the narrative accordingly. In addition,
the NAGF notes that the proposed narrative seems to assume that PRC-028 will be need to be approved/in place for PRC-029 to be a viable standard.
Requirement 2.1.3: The narrative is unclear as to what is expected for this proposed requirement. Request that the narrative be
rewritten/restructured to address this issue. In addition, it is unclear which entity will define the preference for active or reactive power. The NAGF
suggests that the Transmission Planner (TP) should have the authority to define this preference. This recommendation also applies to Requirement 2,
second bullet and Footnote 6.
Requirement R2.5: The NAGF recommends that the narrative be revised to state that active power shall be restored when” the voltage at the high‐side
of the main power transformer returns to the Continuous Operating Region”.
Requirement R4: The draft narrative does not clearly specify who is responsible for approving the exemption. The NAGF requests the narrative be
revised to address this issue.
Measure M4: Recommend replacing the word “seeking: with “submitting” in the first sentence.
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Scott Brame, N/A, Brame Scott
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Karen Demos - NextEra Energy - Florida Power and Light Co. - 1,3,6
Answer
Document Name
Comment
Support NEE comments submitted
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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
Comment
PRC-024-4
No Comments, MRO NSRF is generally supportive of this proposed standard.
PRC-029-1
MRO NSRF recommends that the defined terms, Real Power and Reactive Power be used throughout the document instead of active power and
reactive power.
Section 4, footnote 2 – MRO NSRF does not support using a definition for “inverter based resources” that differs from the what is currently being
proposed by the standard drafting team responsible for developing the Glossary of Terms definition for this term. There must be alignment between
standards prior to any of them being able to move forward.
Measure 1 – This measure is overly prescriptive and does not allow the applicable functional entity sufficient flexibility to demonstrate compliance with
Requirement 1. MRO NSRF would recommend the standard drafting team review measures from PRC-024 and align with the approach taken there.
Measure 2 – This measure is overly prescriptive and does not allow the applicable functional entity sufficient flexibility to demonstrate compliance with
Requirement 2. MRO NSRF would recommend the standard drafting team review measures from PRC-024 and align with the approach taken there.
Requirement 2.1.3 – This requirement is unclear in its intent. Additionally, allowing multiple entities to place potentially conflicting requirements upon an
applicable functional entity is unacceptable. Either a single entity be tasked with the obligation, or a hierarchy be provided so that an entity is not placed
in a “catch-22” situation.
Requirement 4 – MRO NSRF Recommends the following modifications to improve clarity:
Each Generator Owner and Transmission Owner identifying a facility that is in-service by the effective date of PRC-029-1, that has known hardware
limitations which prevent the facility from meeting voltage Ride-through criteria as detailed in Requirements R1 and R2, and requires an exemption from
specific voltage Ride-through criteria shall:
Measure 4 – MRO NSRF recommends changing “seeking” to “documenting” or “submitting”.
Additional comments:
1. The standard switches between BPS (bulk power system) and BES (bulk electric system). For consistency, one term should be used throughout the
standard.
2. R1 bullet # 3: MRO NSRF recommends adding a footnote stating that the facility may operate in current block mode if necessary to avoid tripping for
non-fault initiated phase jumps greater than 25 degrees
3. M1, M2, M3, and R4: consistent replace “Each Generator Owner and Transmission Owner” with “Each Generator Owner or Transmission Owner”
4. R2, 2.1.3: “The voltage is below 95 per unit” should be replaced by “The voltage is below 0.95 per unit”
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Lincoln Electric System, 3, Christensen Sam
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Richard Vendetti - NextEra Energy - 5
Answer
Document Name
Comment
R1 “The instantaneous positive sequence voltage phase angle change is more than 25 electrical degrees at the high-side of the main power
transformer and is initiated by a non-fault switching event on the transmission system” - How is the GO of IBR going to identify the cause of the fault?
R1 “The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for
longer than 2 seconds.” – What is the technical rationale behind the 45 second and 2 seconds? This is a very specific scenario as described in the
“Technical Rationale”. Requests incorporating language that suggests where it applies.
M1 M1 requires multiple data requirements. It is not clear in language. Interpretation is that GO / TO should have evidence that design can meet as well
as performance based evidence that it does or does not perform. The amount and time frame to collect evidence is not provided. Is the expectation that
this data is only required for a specific event upon the data request?
The language in R2 requirements does not explicitly state that changes in resource availability (i.e wind or sun) will also affect the active and reactive
current or recovery of the IBR.
R2.5 “Each facility shall restore active power output to the pre-disturbance or available level (whichever is lesser) within 1.0 second when the voltage at
the high-side of the main power transformer returns from the mandatory operation region or permissive operation region (including operating in current
block mode)” Recommend language updated to “continuous operating region”. IBR units will be limited in capabilities until transient has ended and IBR
equipment is no longer sitting at its equipment limiters”
It is not understood why requirement R1 exists when R2 has all the details. The standard appears to be first written as the test criteria for model
validation. Secondly, as a standard to provide data that plant performance matches model. A standard practice guide on the method to demonstrate
compliance through dynamic simulations, studies or other evidence is necessary before full adoption of new standard.
Attachment 1
Overall there are concerns with the PRC-029 implementation timeline for any requirement where the OEM has not had time to fully assess the new
requirement and utilize the new IEEE2800 testing standard. New standard implementation needs to give GO/TO time to fully assess new requirements;
in particular with the multiple disturbance criteria or method OEMs calculate values.
There is no R6
R3/M3 – All Measurement requirements should be confirmed as inclusion into the PRC-028 standard (RoCoF, V/Hz, Phase Angle, etc)
There is no instruction regarding requirement if IBR cannot meet R3 due to Equipment Limitation
R4 Implementation timeline is too short to assess all facilities with additional requirements in PRC-029. There is also not enough time to allow for OEM
responses. Recommend tracking an implementation guideline similar to PRC-028 and PRC-030 to meet FERC deadline.
There is no instruction on process to report a new limitation after the full implementation of R4 when a piece of equipment within the IBR may
temporarily limit the capability
R4.3 Each Generator Owner and Transmission Owner with a previously submitted request for exemption that replace the equipment causing the
limitation shall document and communicate such an equipment change to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s) within 90 days of the equipment change
The language should be clear to state “full replacement”. Should not be misinterpreted to include subcomponent replacement.
There is no R5
The Implementation timeline of this standard is the most concerning given the additional requirements generating new review of all facilities and the
need to receive additional feedback from OEMs without new testing standard.
The performance data collection requirements will need to align with implementation timeline of PRC-028 at each facility.
A practice guide is highly recommended to demonstrate method and expectation for compliance.
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Robert Follini - Avista - Avista Corporation - 3
Answer
Document Name
Comment
Avista supports the development of a new Reliability Standard to address gaps in Inverter-Based Resource Performance but has concerns with
numerous definitions/verbiage.
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Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
Document Name
Comment
R1: Revise text as follows: “…each facility adheres to voltage Ride-through requirements…”
WEC also disagrees with M1 and agrees with the comments made by NAGF and EEI.
R2: WEC disagrees with text “…shall ensure the design and operation is such…”. The requirement must state what TO and GO must do. Otherwise,
this requirement is open-ended without a measurable statement. The “…shall ensure” has no quantitative meaning and it does not benefit the BES
stability.
2.1: The proposed “continuous operating region” range conflicts with acceptable continuous operating ranges by Transmission Operators. Many
Transmission Operators classify continuous operating range from 0.95 and 1.05 pu, and consider voltage ranges from 0.9 to 0.95 pu and 1.05 to 1.1 pu
as abnormal voltage ranges.
2.1.1: Continue to deliver the pre-disturbance level of active power or available active power, whichever is less. Please explain and list what entity
must do to ensure this requirement is met.
2.1.2: Continue to deliver reactive power up to its reactive power limit and according to its controller settings. Please explain and list what entity must
do to ensure this requirement is met.
2.1.3: What document governs a TP, PC, RC or TO to specify active/reactive power prioritization.
2.3: Term “current block mode” may not be understood and its meaning could be misinterpreted. Does it mean mandatory cessation? Please explain
and at least define it in footnotes. Assuming this means momentary cessation, it looks like this requirement will allow momentary cessation if necessary
to avoid tripping, OR, per 2.3.1 entity can enter current cessation for 5 cycles. It seems the statement contradicts itself.
2.5: WEC owns and operates multiple IBR sites and it is in our experience that the limitation to the one second requirement will come from the power
plant controller. The ramp rate capabilities of the power plant controllers are far slower than inverter ramp rates and are typically in minutes range.
WEC also had an instance where the power plant controller ramp rate increase was denied by the Transmission Operator/Planner. Applying one
second requirement will simply be impractical and most entities will take equipment limitation exception that will not benefit the BES. Unless stated in
quantitative way (what and when) the requirement R2 provides no benefit to BES.
M2: The current version of M2 calls for dynamic simulations, studies, or other evidence plus having ACTUAL disturbance monitoring data proving the
Requirement was met. The dynamic simulations/studies can be performed by third-party engineering contractors specializing in these activities to
prove each site meets the first part. However, two questions must be addressed regarding actual data: (1) "How" actual data is acquired if SER, DDR
and/or Fault Recording does not become mandated. NAGF made a similar point in their response.
(2) "When" actual data must be submitted as evidence if we as GOs are not specifically asked for it by some other entity. Without some mandate for
data, we as GOs are not going to know when every voltage disturbance that would have (should have) triggered a ride-through has occurred on the
transmission system.
Attachment 1: Are items 1 thru 10 requirements or they are notes supplementing Tables 1 and 2? Please define.
More description needs to be provided on how to apply items 8, 9, and 10.
Attachment 2: Are items 1 thru 5 requirements or they are notes supplementing Table 3? Please define.
More description needs to be provided on how to apply item 5.
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Russell Ferrell - Luminant - Luminant Energy - 6
Answer
Document Name
Comment
. I support EEI's and Entergy's comments
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Dave Krueger - SERC Reliability Corporation - 10
Answer
Document Name
Comment
For the applicability section, suggest adding "that owns equipment as identified in section 4.2" after "generator owner" similarly to the proposed PRC030-1
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Scott Brame, N/A, Brame Scott
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See comments submitted by the Edison Electric Institute”
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Response
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer
Document Name
Comment
none.
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Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Document Name
Comment
See comments submitted by Edison Electric Institute.
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Patricia Ireland - DTE Energy - 4, Group Name DTE Energy
Answer
Document Name
Comment
No comments at this time
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David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
Document Name
Comment
Ameren agrees with and supports EEI's comments.
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
PRC-024-4:
·
We support creation of new standard PRC-029 to address IBR specific ride through issues, as both the different natures of synchronous and
inverter-based generation and several recent events exhibiting significant IBR ride-through deficiencies and failures the causes of which are not
relevant to synchronous generators. The approach to address IBR issues should be different to that of PRC-024 because there are too many other
factors and causes of IBR ride-through failure not directly related to voltage and frequency protection settings that may and have caused ride-through
deficiencies and failures.
·
PRC-028 was voted out due to issues around definition of IBR criteria and implementation plan. Separate PRC-029 would allow PRC-024 to pass
through the ballot process without many issues.
PRC-029-1:
·
Support inclusion of Ride through requirement in the TERM section, which will get included into NERC Glossary of Terms.
·
In all the requirements IBR is replaced with Facility, except the requirement R2.2 as IBR. In attachment 1 it is mentioned as inverter‐based
resource facility. That is not consistent.
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Michael Dillard - Austin Energy - 5, Group Name Austin Energy
Answer
Document Name
Comment
Austin Energy supports comments posted by NAGF:
PRC-029:
General Comment: The NAGF believes that PRC-029 should allow for frequency ride through (“FRT”) exemptions similar to its treatment of voltage ride
through (“VRT”) exemptions. The justification for allowing VRT exemptions in FERC Order 901 also apply to FRT. We believe the statement in FERC
Order 901, paragraph 193 in response to ACP/SEIA’s comment in paragraph 188 does not preclude the standard drafting team from considering FRT
exemptions due legacy equipment limitations. Here are a few reasons why:
1.
If FERC’s intent was to exclude Frequency Ride Through exemptions while allowing Voltage ride through exemptions, there would be more of a
record established to support this differential treatment.
2.
FERC responded to ACP/SEIA’s comment on ride-through requirements as if they were only asking about voltage ride through requirements.
FERC made no mention of frequency ride through requirements.
3.
Similar to FERC’s rational for the consideration of voltage ride through exemptions, there are also older IBR technologies with hardware that
would need to be physically replaced to meet frequency ride through requirements as well.
4.
NERC and the NERC Standard Drafting Teams have the technical expertise to address complex technical issues such as legacy equipment
limitations that FERC does not have.
Applicability Section, 4.2.2 – Recommend removing this section.
Requirement R1: The NAGF notes that R1 only addresses voltage ride through and should be revised to include frequency ride through as well. In
addition, R1 should address frequency ride through limitations for legacy IBR facilities.
Measurement M1 – The proposed narrative reads more like requirements than measures; recommend to revise the narrative accordingly. In addition,
the NAGF notes that the proposed narrative seems to assume that PRC-028 will be need to be approved/in place for PRC-029 to be a viable standard.
Requirement 2.1.3: The narrative is unclear as to what is expected for this proposed requirement. Request that the narrative be
rewritten/restructured to address this issue. In addition, it is unclear which entity will define the preference for active or reactive power. The NAGF
suggests that the Transmission Planner (TP) should have the authority to define this preference. This recommendation also applies to Requirement 2,
second bullet and Footnote 6.
Requirement R2.5: The NAGF recommends that the narrative be revised to state that active power shall be restored when” the voltage at the high‐side
of the main power transformer returns to the Continuous Operating Region”.
Requirement R4: The draft narrative does not clearly specify who is responsible for approving the exemption. The NAGF requests the narrative be
revised to address this issue.
Measure M4: Recommend replacing the word “seeking: with “submitting” in the first sentence.
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
WECC suggests the DT should ensure that the labeling on the Project page of the Standard is accurate in terms of what is being considered. The
“redline” version is not a true redline from PRC-024-3 it is a redline from a failed version of PRC-024-4 with the language that was voted down shown as
“approved” (i.e., text appearing as not being changed.) This could be misleading. There is no mention of Attachment 2A or Attachment 2C in any of the
Requirements. It is noted that there is a reference to Attachment 2B in the Quebec variance. Consider changing Requirement R2 language to
reference Attachment 2A and incorporate current Attachment 2A language into Attachment 2. And incorporate Attachment 2C language into
Attachment 2B. That provides clarity with a minimal change in Requirement R2 language. In theory, this is a set it and forget it Standard unless
something changes. The data retention should reflect that condition and not be limited. GOs and TOs will have to be able to demonstrate settings
when requested and can not simply say “the settings were done 6 years ago so no evidence is retained”. There have been cases where a GO has
indicated retrieval of settings required a third party because the GO did not have documentation. Absence of a failure (i.e., unit trip that would need to
be reviewed to see if voltage/frequency was the root cause and if the associated relay responded within the “no-trip” zone) is not necessarily a
successful reliability indicator and would require quite a bit of data to demonstrate reliable operation resulting in compliance.
Overall for PRC-024-4 WECC is supportive of the efforts and end results.
PRC-029-1
It is unclear why lower cased “facility” is used. In Footnote 2 “facility” is not used but “plant/resource” is used. In the Technical Rationale “plant/facility”
is used. Please provide consistency in language within the Standard, the Requirements, and Technical Rationale.
Facilities Section 4.2 is extremely unclear in that it simply says “IBR Registration Criteria” for 4.2.2. Additionally, Footnote 2 does not consider any
hybrid resource types (or Facility types or plant types).
R1 indicates “design and operation” which is a valid approach but “design” can be assessed reviewing settings (and simulations, etc.) but “operation”
can only be assessed through a review of time periods where applicable voltage (or frequency) demonstrates a change that calls for operation per the
Tables. The VSL for R1 is written in a manner that requires that level of assessment (e.g., entities would have to find a point in time where .89 Voltage
existed and show they exceeded the minimum Ride-through time.) The VSL is written where a design issue is a lower VSL but the wrong setting would
indicate that the operation could not adhere to Attachment 1. Measurement M1 mentions SER/FR/DDR which are covered in PRC-028-1 (Project 202104). Are those enough to demonstrate operation to Attachment 1 under the criteria set in the Tables? With PRC-028-1 setting data retention levels so
short, the evidence suggested by Measurement M1 will require retention per Evidence Retention requirements in PRC-029-1 to be able to clearly
demonstrate compliance.
If using capitalized “Transmission System” in the definition of “Ride-through” use it capitalized in Requirement 1 bullet 3. PRC-024 had MPT and GSU
used and “defined”. Consistency in use here in PRC-029 (with appropriate changes) to correlate with PRC-024 is appropriate but should be footnoted
in Requirement R1 bullets 3 and 4 first prior to being called out in Requirement R2.1.
Measurement M1 is expansive and some of the details should be in the Technical Rationale rather than in a measure. As is, appears to be not
consistent and should, at a minimum, include the word “shall” where needed as others Standards (including PRC-024) are written in this manner
(e.g.”,….shall have evidence…”). M1 does not mention bullet 2.
Requirement 2 will require a voltage excursion to demonstrate operation adhering to Attachment 1. What criteria constitutes a “voltage excursion”?
Requirement 2.1- Consider adding a comma after “region” to be consistent with similar language in other parts of Requirement R2.
Requirement 2.1.1 The phrase “or available active power, whichever is less” appears to be supportive of the footnote regarding a frequency excursion
but what if the “available active power” is lower than the pre-disturbance level of active power. “Less” could be zero output as the voltage at the MPT
high-side could remain within the continuous operation range with the IBR disconnected.
Requirement 2.1.3 Please verify if that should be ”.95” per unit versus “95” per unit. Since this Requirement is within the Operations Horizon timeline,
the reference to Transmission Planner and Planning Coordinator should be dropped. Furthermore, it is not clear what a GO would operate to if given
conflicting orders by the RC and TOP. Consider limiting the “preference” to the TOP who is to set the system voltage expectations per VAR-001.
Requirement 2.2.- Consider “sub Part” formatting used in other Requirements versus bullets for consistency. Since this Requirement is within the
Operations Horizon timeline, the reference to Transmission Planner and Planning Coordinator should be dropped. Furthermore, it is not clear what a
GO would operate to if given conflicting orders by the RC and TOP. Consider limiting the “requirement” to the TOP who is to set the system voltage
expectations per VAR-001. In this bullet the language says “each IBR” versus “each facility” as called out in other parts of Requirement R2. Is that
correct?
Requirement R4 is a grandfathering clause and assumes each unit after the effective date will meet Requirements 1, 2, and 3. There should not be any
additional implementation timeline built into a Requirement language as this Standard will take time to be approved and there is a proposed 6 month
Implementation Plan. If there is a hardware limitation, it should be known Day 1 of the effective date of Standard and gathering of the limited
information should have already been don ein the 6 months leading to the effective date. There is no requirement for an entity to replace the hardware
limitation. The entire Requirement will result in documentation with no expectation of mitigation. What data does the DT have to support this exemption
language? At a minimum, notification of an issue needs to be provided to the TOP and RC. Suggest a Corrective Action Plan with definitive time
requirements to mitigate the issue (or explain why it can not be mitigated) be instituted here.
Footnote 9 may not be necessary as non-US Jurisdictional applicable government authorities have mechanisms in place to implement any Standard.
Within Requirement R4.1- 4.1.1- Call out specifics for consistency. Leaving as “other” invites inconsistency. Use “Ride-through” as that is a proposed
defined term (versus “ride-through”) in 4.1.2. Be consistent in using “hardware” or “equipment” to avoid confusion throughout Requirement R4.
Suggest removing the phrase “or that the limitation cannot be removed by software updates or setting changes” as this is limited to a hardware
limitation exemption. Requirement R4.1.5 is ambiguous and clarity should be provided. Requirement 4.2 It is not clear why the Planning Coordinator
and Transmission Planner is included here. Model data demonstrating the limitation should be provided through another mechanism. Including the
Regional Entity here is not needed or recommended as Regional Entities are NOT subject to Standards. If the DT wants to include providing
information to the Regional Entity place it in “Additional Compliance” section (similar to FAC-003) and recognize it as a data submittal. Recommend
removal of Regional Entity from the Requirement language.
Measure M4 does not support Requirement R4 with regards to notification timeline in Requirement R4.3, sentence regarding submission of information
in 4.1 should not be limited to the Regional Entity (alternatively that sentence could be removed as Regional Entity is covered in next sentence), and
there is no information regarding the response timeline in 4.2.1. Furthermore, “experience from an actual event” indicates that the GO/TO could not
adhere to the design and operation criteria set—equating to a possible noncompliance. If there is a hardware (or “equipment” depending on where
consistency efforts lead) limitation that should be known in the design phase and addressed at that point
There is no corresponding frequency “hardware” limitation language if a facility can not adhere to Attachment 2.
Evidence Retention Section- Requirement R4 has no obligatory requirement to mitigate the hardware(equipment) limitation. As such, entities should be
obligated to maintain information demonstrating compliance until the issues are mitigated. There should be language within the Requirement to correct
the issue within a certain timeframe. As is, data demonstrating compliance for R4 would not be retained after 5 years and the entity would be held to
performing per R1, R2, and R3 in subsequent compliance monitoring efforts unless tracking (and verification of compliance to R4) existed.
Attachment 1- Consider lowercasing “Through” in Table titles as it is part of the proposed defined single word “Ride-through”. Consider lowercasing
“Continuous Operating Region” as it is not a defined term nor is it capitalized in the Requirement language. Table 1 cannot have “1.1” and “1.10” be in
the Mandatory Operation Region and Continuous Operation Region at the same time (e.g., the mathematical operator shows inclusion.) “1.1” should be
shown a “1.10” for consistency. Footnote 10 is unclear as Type 3 and Type 4 wind turbines are IBRs and the use of “directly” in the footnote could leave
some entities with Type 3 and Type 4 wind turbines to use Table 2. Simply say it is for Type 3 and Type 4 and leave the AC-Connected and directly
connected verbiage out to avoid confusion. Note- Anytime a DT says it is clear the issue gets pushed into the compliance environment where suddenly
no clarity exists. IBR is a definitive example of clear technical understanding but extremely unclear understanding when applying a compliance lens.
“Voltage Source Converter High Voltage Direct Current” is not defined nor explained. There are inconsistencies in how “Voltage Source Converter High
Voltage Direct Current” is displayed—Footnote 1 is lower cased “v” and contains a hyphen after “High”; Bullet 3 does not have a hyphen in “VSC HVDC
but bullet 2, Footnote 1, and Footnote 2 does.
Need to be consistent with the depiction of the Figures (in Attachment 2) in terms of what the boundary line depicts (inclusion or exclusion within the
“Regions”) as entities have struggled in the past versions of PRC-024 (and others). Figure 1 does not depict the 1.1 Voltage point and therefore
appears to not support the Table (consider moving the 1.05 down to the boundary between the “1800 second” section and “no time requirement”
section depiction while adding 1.1 to the upper boundary of the “1800 second” section.
Figure 2 does not reflect 1.05 Voltage point so the “1800 second" section appears to not be depicted appropriately. Consider adding the 1.05 Voltage
point to the y-axis and redraw boundaries for “1800 second” section and “no time requirement” section. 1.05 should be the upper boundary of the “no
time requirement” section. To provide consistency and clarity, Table 2 X-axis values should reflect the table values as Figure 1 reflected those (for
Table 1) (i.e., show .32 and 1.2).
Since this is an Operating Horizon based Standard why would Bullet 5 depend upon the PC or TP? Bullet 5 and Bullet 6 do not use the same language
(use of hyphens, use of neutral, use of ground). Is the intent of Bullet 10 to supersede Bullet 8 (i.e., does not matter is the time associated with the 4
deviations is below the time associated with the voltage?)
Attachment 2- Consider lowercasing “Through” in Table titles as it is part of the proposed defined single word “Ride-through”. Table 3 should reflect
consistency in the System Frequency column. The frequency slot between 58.5 and 58.8 is not covered (suspect the 6th row needs adjustment as it is
referencing the same frequency point—58.8). Additionally, it appears that there may be inconsistency in mathematical operators inclusion or exclusion
of certain ranges. DT needs to confirm where 58.8 resides in terms of allowed time. Consider the Table below with bolded changes. For consistency
with Voltage tables “N/A” versus “may trip” is suggested and for consistency the DT may consider a footnote as Tables 1 and 2 did in Attachment 1
regarding voltage.
System Frequency (Hz)
Minimum Ride-Through Time (sec)
≥64
N/A
< 64 and ≥61.8
6
< 61.8 and ≥ 61.5
299
< 61.5 and > 61.2
660
≤ 61.2 and > 58.8
Continuous
≤ 58.8 and ≥ 58.5
660
< 58.5 and ≥ 57
299
< 57.0 and ≥ 56
6
< 56
N/A
PRC-024 had “MPT” and “GSU” used and “defined”. Consistency in use here in PRC-029 (with appropriate changes) to correlate with PRC-024 is
appropriate.
VSLs- Requirement R1--DT should consider a different method to assign levels. While the Requirement language may say “each” perhaps a
consideration for the VSL should be fleet-based. As written, the DT has created a “zero” tolerance Requirement. If the design is wrong the operation
would be incorrect. Proving that should not take an event to demonstrate (as the compliance argument this will set up is that “there has not been a
period where operation would have occurred”).
Requirement R2 and Requirement R3- Essentially same comments as VSLs for Requirement R1
Requirement R4- The notification timeframe appears to be initially set at 30 calendar days for all the VSLs (with adjustments considering the 30
calendar day foundation) but the Requirement R4 language indicates a foundation of “90 days” (also an issue noted in Measurement M4). With the
timeframes associated
Implementation Plan—The last sentence regarding Requirement R4 needs to be struck or incorporated within the Requirement language. Requirement
R4 says “hardware limitations” and does not specify the “coordinated protection and control settings”. To be clearer the DT should consider changing
Requirement R4 language to “inability to modify coordinated protection and control functions”. There is a gap between the language regarding
provision of a “copy to applicable entities” in the Lower VSL and what is in the Severe VSL. Effectively the Severe VSL covers 15 month plus 1 day to
beyond 24 months. Is that the intent of the DT?
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Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Document Name
Comment
Response from ITC Holdings:
“IBR Registration Criteria” is not an applicable Facility.
The applicabilities of PRC-028, PRC-029, and PRC-030 need to be aligned. E.g. A TO that owns the VSC-HVDC connection for offshore wind is
subject to PRC-029 but not PRC-028 or PRC-030.
R1 has no value as a standalone requirement and should be incorporated into R2. In other words, you can’t violate R1 without also violating R2, so
eliminate R1 or incorporate its subtle value into R2.
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
Minnesota Power supports EEI’s comments.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has the following comments on the PRC-024-4 draft:
•
Requirements R1, R2, and R4 use the term ‘Facility’ when referencing synchronous generator, type 1 or type 2 wind resource, or synchronous
condenser. Requirement R3, however, uses a description of the Facility. Texas RE recommends using the term Facility to be consistent with
the other requirements. Texas RE recommends the following revision (in bold):
R3. Each Generator Owner and Transmission Owner shall document each known regulatory or equipment limitation that prevents an its synchronous
generator, type 1 or type 2 wind resource, or synchronous condenser Facility, with applicable frequency or voltage protection from meeting the
protection setting criteria in Requirements R1 or R2, including (but not limited to) study results, technical incapability identified after experience from
an actual event, or manufacturer’s advice.
‘Technical incapability identified after’ language is added to clarify that the Facility Owner must conduct detailed analysis to ensure that the Facility is
technically incapable of providing the required system support and the specific technical limitations should be documented.
•
Please update footnote 4 (Requirement 2.1) on page 5 of 22 (clean version) - changes in bold font:
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s), or synchronous condenser(s); or (ii) provide
signals to same to trip the same Facilities.
•
In Requirement R4, Texas RE recommends that each Generator Owner and Transmission Owner shall provide its applicable protection settings
to Planning Coordinator and Transmission Planner. The applicable data should be provided to both the Planning Coordinator and Transmission
Planner so the study model(s) used by Planning Coordinator and Transmission Planner can be updated concurrently. Texas RE recommends
the following revision (in bold):
R4. Each Generator Owner and Transmission Owner shall provide its applicable protection settings associated with Requirements R1 and R2 to the
Planning Coordinator or and Transmission Planner that models the associated Facility within 60 calendar days of receipt of a written request for the
data and within 60 calendar days of any change to those previously requested settings unless directed by the requesting Planning Coordinator or
Transmission Planner that the reporting of protection setting changes is not required. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
It is important that the applicable data is provided to the Planning Coordinator and Transmission Planner so that the study model(s) used by PC and TP
can be updated concurrently.
•
Technical Rationale document - Texas RE recommends the Facilities section include the Frequency and Voltage Protection Settings for Type 1
and Type 2 Wind Resources in addition to the Synchronous Generators and Synchronous Condensers in the title document since they were
added to section A 4.2.1.4 of the standard. Texas RE recommends the following revision (in bold):
Facilities (4.2)
Applicability Facilities subparts in Section 4.12.1 were modified to restrict PRC‐024‐4 to synchronous generators and Type 1 and Type 2 Wind
Resources. Section 4.2.2 was added as new subparts to identify which synchronous condensers and equipment.
PRC-029-1 Comments
•
Ride-through definition: Ride-through capability is the ability of the resource to continuously deliver power during a disturbance event. It
appears the phrase ‘continuing to operate’ used in the Ride-through definition is intended to state that the Facility needs to deliver power in
response to system conditions. Texas RE recommends the following revision (in bold):
Ride-through: Remaining connected, synchronized with the Transmission System, and continuing to operate by delivering power in response to
System conditions through the time-frame of a System Disturbance.
Applicability Section 4.2.1: Footnote 2 refers to ‘offshore wind plants connecting via dedicated VSC-HVDC”. Texas RE recommends revising this
footnote to include offshore and on-land VSC-HVDC. Texas RE recommends the following revision (in bold):
For the purpose of this standard, “inverter-based resources” refers to a collection of individual solar photovoltaic (PV), Type 3 and Type 4 wind
turbines, battery energy storage system (BESS), or fuel cells that operate as a single plant/resource. In case of offshore any wind plants connecting
via a dedicated VSC-HVDC, the inverter-based resource includes the VSC-HVDC system.
•
Applicability Section 4.2.2: Texas RE recommends revising the verbiage to “Resource which meets IBR Registration Criteria”.
•
Requirement R1: Texas RE recommends clarifying the first bullet to state that the facility is electrically disconnected in order to clear a fault
within its protection zone as designed. Texas RE recommends the following revision (in bold):
The facility needed to electrically disconnect in order to clear a fault within its zone of protection as designed;
•
Measures: Texas RE noticed the Measures for IBRs in PRC-029-1 are more burdensome than the Measures for synchronous generators in
PRC-024-4. Though Measures are not enforceable, they are instructive in which activities could be used to demonstrate compliance with a
Requirement. For synchronous generators in PRC-024-4, the Measures indicate that a Generator Owner or Transmission Owner can
demonstrate compliance by providing a settings sheet or supporting calculations, or the synchronous generator can instead rely on dynamic
simulation studies. In contrast, the Measures in PRC-029-1 indicate that the IBR shall have dynamic simulations, studies, or other evidence to
demonstrate the design of each Facility, and the Measures also indicate that the IBR shall have evidence of actual disturbance monitoring to
demonstrate performance of the Facility in actual historical Ride-through events. These Measures appear to be more burdensome for IBRs than
for synchronous generators and also appear to suggest obligations exist beyond what is stated in the enforceable Requirement text.
•
Measures: Since the measures are not enforceable, Texas RE encourages the SDT to consider removing shall statements from the measures.
Texas RE recommends using similar verbiage to the measures in the CIP standards, which say “Examples of evidence may include, but are not
limited to…”
•
Measure M1: The first sentence in Measure M1 shows the word “shall” removed, but nothing was put in its place. Is that the intent of the SDT?
•
Requirement Part R2.1.3: Texas RE recommends revising Requirement Part 2.1.3 from passive to active voice so it is clear that the Generator
Owner or Transmission Owner is the entity giving preference. Texas RE recommends the following revision (in bold):
If the facility cannot deliver both active and reactive power due to a current or apparent power limit or reactive power limit, when the applicable voltage
is below 95% per unit and still within the continuous operation region, then the Generator Owner or Transmission Owner shall give preference to
active or reactive power as required by the Transmission Planner, Planning Coordinator Reliability Coordinator, or Transmission Operator.
•
Requirement Part 2.5: If a small number of the inverters or turbines trip offline at a facility during a fault while the voltage remains in the
mandatory operation region, will that facility be in violation of Requirement R 2.5?
•
Requirement R4: Texas RE noticed Requirement R4 does not provide an opportunity for legacy Facilities to identify an equipment limitation
after 12 months from the effective date of PRC-029-1. PRC-029-1 R1 provides an exception for IBRs that document equipment limitations in
accordance with R4. In PRC-029-1 R4, a Facility that existed before the effective date of PRC-029-1 shall identify and document information
supporting identified hardware limitations no later than 12 months from the effective date of PRC-029-1. Is the intention that equipment
limitations identified after this 12-month window will not be eligible for the exception in PRC-029-1 R1? For a Facility that identifies an
equipment limitation in the 13th month or beyond, does the SDT intend for that IBR to still be able to document the equipment limitation and
qualify for the exception in R1, albeit with the obligation to submit a Self-Report for failing to meet the 12-month deadline in R4? Alternatively,
does the SDT intend that an IBR that does not identify an equipment limitation within the 12-month window should never be able to qualify for
the exception in R1?
•
Requirement R4: Texas RE recommends the measures include evidence that the Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and to the Regional Entity the documented information supporting the identified hardware
limitation.
•
Attachment 1: Figure 1: Voltage Ride-Through Requirements for AC-Connected Wind Facilities graphical representation should be corrected to
match Tables 1 and 2. The continuous operating region is between 1.05-0.9 and Continuous Operating Region (1800 seconds) time delay is
greater than 1.05-1.1 voltage level. In Figure 1, Texas RE recommends adding 1.1 above 1.05 in the Continuous Operating Region (1800
seconds). In Figure 2, Texas RE recommends replacing 1 with 1.05.
•
Attachment 2: Frequency Ride – Through Criteria table 3 should be updated to reflect the correct low frequency levels for 660 seconds time
delay.
≤ 58.8 and < 58.8 58.5
•
Page 16 onward: The Mandatory Operation Region and Continuous Operation Region phrases should be lowercase to match changes made to
rest of the standard.
Texas RE noticed the word “facility” is lowercase throughout (redline shows it replaces IBR, e.g. in R1). If the intent is to be consistent the applicability,
Texas RE recommends using the term “applicable facility” to refer back to 4.2 Applicability section.
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John Pearson - ISO New England, Inc. - 2
Answer
Document Name
Comment
ISO New England signs onto comments of the Standard Review Committee of the ISO/RTO Council.
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Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Document Name
Comment
•
•
•
•
Bureau of Reclamation (BOR) notes that PRC-024-4 draft 2 is redlined to the draft 1 (clean version). Draft 2 has accepted all of the redlines
from Draft 1, yet the ballot for Draft 1 was below the two-thirds majority of the weighted Segment votes requirement for approval per Appendix
3A of NERC’s standard process manual V5 dated 11-28-2023.
Recommend SDT provide a separate comment form for each Standard under development.
PRC-029-1 is not applicable to BOR.
BOR recommends an 18-month implementation timeline for both standards.
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Ruchi Shah - AES - AES Corporation - 5
Answer
Document Name
Comment
•
•
•
AES CE fully supports the SEIA working group and other industry comments on allowing exceptions for frequency ride through.
AES CE is concerned by the updated language in several Measures reading “Each Generator Owner and Transmission Owner have evidence
of actual disturbance monitoring…” and believe that the simulations and studies used to demonstrate compliant design should be sufficient,
similar to PRC-024. There will be many plants that do not experience an applicable disturbance before this Standard becomes effective and
therefore cannot demonstrate adherence to ride-through requirements as prescribed. We are also concerned about expectations for this
Measure as time goes on, are we expected to document and record every applicable disturbance and the asset’s performance? Additional
clarification is required if the Drafting Team believes that actual disturbance monitoring language should remain in the Measures.
The required protection is not currently modeled in basic models and will require substantial effort to ensure we can perform as required. AES
CE requests that the Implementation Plan be modified to use a phased-in approach for existing sites to allow adequate time to prepare for
these performance requirements. We suggest that the Implementation Plan for PRC-029 should align or lag the Implementation Plan for PRC028.
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Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Document Name
Comment
PNM agrees with the comments made by EEI.
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Carver Powers - Utility Services, Inc. - 4
Answer
Document Name
Comment
The term “active power” is not defined and appears to be used in conjunction with Real Power. Recommend consistency throughout the standards
when using Real Power vs active power, such as MOD-025, BAL-001, and many others.
Recommend the DT reevaluate the implementation period of 6 months. Recommend making implementation period 18 months or greater to account for
the need for working with OEMs to implement any setting changes and the need for IBR settings reviews conducted by third parties, as necessary.
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Daniel Gacek - Exelon - 1
Answer
Document Name
Comment
Exelon supports the comments submitted by the EEI.
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI offers the following Comment to Draft 2 for PRC-024 and PRC-029.
PRC-024-4 Comments:
EEI has no substantive concerns with any of the proposed changes to PRC-024-4 but point out a minor typo in Requirement R2 (below).
R2. Each Generator Owner and Transmission Owner shall set applicable voltage protection in accordance with PRC-024-4 Attachment 2, such that
the applicable protection does not cause the Facility to which it is applied to trip within the “no trip zone” during a voltage excursion at the high-side of
the GSU or MPT, subject to the following exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
PRC-029-1 Comments:
While EEI appreciates that changes made to address our previous comments for the 1st draft of PRC-029-1, we have some new concerns that need to
be addressed.
Our high level concerns are described in our comments below:
1. The Standard attempts to redefine the approved definition of IBR by adding VSC-HVDC systems after the IBR definition was approved by the
industry.
2. The Standard adds TOs to this Standard solely to address VSC-HVDC systems, yet no technical justification has been provided. Moreover,
these systems were not identified in FERC Order No. 901, or this SAR and they were not clearly identified in the Applicability Section of this
proposed Reliability Standard.
3. EEI is concerned with the inclusion of requirements that are not clearly defined or set by multiple registered entities (i.e., TP, PC, RC, or TOP).
This creates regulatory confusion and places IBR-GOs in a position where they may need to comply with any number of entities without clearly
defining who is responsible. (See Requirement R2, subpart 2.1.3; subpart 2.2 (bullet 2); subpart 2.5) Moreover, the identification of multiple
entities who could be responsible creates a situation where IBR-GOs will have reporting obligations to multiple entities because no single entity
is identified as being responsible. (See requirement R4, subparts 4.2 & 4.2.1; subpart 4.3) We further note that none of the entities identified
(i.e., TP, PC, RC, or TOP) are identified within the Applicability section of this proposed Reliability Standard. All of this can create confusion
and places a considerable burden on the IBR-GOs that needs to be resolved and clarified.
4. Throughout this Reliability Standard there is use of non-glossary terms (i.e., active power vs. Real Power) where glossary terms are available
and should be used. While in other cases glossary terms are used but not capitalized. (e.g., reactive power vs. Reactive Power) Greater
efforts should be made to use NERC Glossary terms where appropriate and capitalize those terms, as required.
Detailed Concerns
Ride-through Definition Comments:
EEI does not support the proposed definition for “Ride-through” as proposed because it is too vague and contains no defined limits, as proposed. We
recommend the following changes:
Ride‐through: Ability to withstand voltage or frequency Disturbances within defined regulatory limits remaining connected, synchronized with
the Transmission System, and continuing to operate.
Applicability Section Comments:
Footnote 1: EEI does not support adding TO that own VSC-HVDC systems because this was not a scope item and is therefore not be included in the
scope of this SAR. Moreover, Footnote 1 conflicts with Footnote 2 which defines VSC-HVDC as an IBR, which is again does not in alignment with the
approved definition of an IBR.
Footnote 2: EEI does not support Footnote 2 because it expands the definition of IBRs beyond what was recently approved by the industry, noting the
expansion of IBRs to include VSC‐HVDC. Furthermore, there was no technical justification for adding VSC-HVDC and the SAR did not include adding
VSC-HVDC systems to this project. For this reason, we ask that the definition of IBR not be expanded through footnotes and suggest that the DT
submit a technical justification for adding VSC-HVDC systems to the applicability section of this Standard, rather than redefining an approved definition
in a footnote.
To address our concerns related to Footnotes 1 & 2 we suggest that if VSC-HVDC systems are to be classified as IBRs, then the approved definition
should be pulled by NERC and resubmitted with those resources added to the definition and resubmitted to the industry for approval. Alternatively,
VSC-HVDC systems could be defined separately, and that definition submitted to the industry for approval. In both cases, a technical justification
should be provided to the industry that defines the issues and risks to BPS reliability that VSC-HVDC systems pose.
EEI suggests that if the DT believes that certain IBR capabilities as identified under Requirement R2 need (or may need) to be specified then they
should identify the entity who should be responsible among the four identified (i.e., TP, PC, RC or TOP); add them to the applicability section of this
Reliability Standard; add clear requirements and adjust the reporting obligations for the IBR-GO under Requirement R4.
Requirement R1 & R2 Comments: EEI does not agree with the inclusion of Transmission Owners because they would only have an obligation under
this Reliability Standard if VSC-HVDC systems were included. Given we do not support the inclusion of VSC-HVDC systems without a technical
justification and modified SAR, we ask that Transmission Owners be removed from Requirement R1.
Additional Requirement R2 Comment: EEI suggests that there should be clearer linkage between Requirement R1 and R2. We are also concerned
that R2 only exempts documented equipment limitations but does not also include the exemptions provided within R1. To address these concerns, we
offer the following edits to Requirement R2:
R2. Each Generator Owner shall ensure the design and operation of the voltage performance of its IBR Facilities adheres to the following conditions
in accordance with Requirement R1. [Violation Risk Factor: High] [Time Horizon: Operations Assessment]
EEI also suggests that the “each facility” be replaced with “IBR Facilities” because the use of the uncapitalized version of facility is too broad, making
compliance requirement unclear.
Measures M1 & M2: EEI is concerned that M1 & M2 contains measures that are overly prescriptive providing little discretion to IBR-GOs in
demonstrating their compliance with Requirements R1 and R2 that seem to align more with a Requirement than a Measure. To address our concerns,
we offer the following suggested changes to M1 and suggest similar changes be made to M2:
M1. Each Generator Owner shall have evidence that supports the Ride-through capability of each of their facilities, as specified in Requirement
R1. (e.g., simulations, studies, recorded data from disturbance monitoring equipment, etc.) If the Generator Owner choose to utilize Ride-through
exemptions that occur within the “must Ride-through zone” and are caused by non-fault initiated phase jumps of greater than 25 electrical degrees, then
each Generator Owner shall also have evidence supporting that exemption. (e.g., studies, simulations or supporting data from disturbance
monitoring equipment)
Requirement R3 & R4: EEI does not support the inclusion of Transmission Owners within Requirements R3 & R4 for the same reasons identified
above.
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Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Document Name
Comment
Regarding PRC-024-4, SMUD has no comments and supports the Standard Drafting Team (SDT) in this latest version of the Standard.
Regarding PRC-029-1, SMUD has the following comments:
1)
The voters in Project 2020-06, Inverter-based Resource Glossary Terms draft #2, approved the definition of IBR on April 8, 2024, which is
different than the definition proposed in Footnote 2 of PRC-029-1. Using the term “inverter-based resources” and defining it with Footnote 2 is
inefficient and would create two definitions for the same resource.
The SDT of PRC-029-1 should coordinate with the SDT of Project 2020-06, and NERC staff, to ensure the definition of IBR and new PRC-029-1 are
submitted to FERC simultaneously thereby eliminating another ballot for PRC-029-1 to add the NERC Glossary Term for IBR into the standard and
eliminate confusion between IBR and “inverter based resources.”
2)
Requirement R2.2, the term “IBR” should be replaced with “facility” to be consistent with the rest of the Standard. As currently written,
Requirement R2.2 states “While voltage at the high-side of the main power transformer is within the mandatory operation region as specified in
Attachment 1, each IBR [emphasis added] shall…”
3)
Requirement R2.1.3 should specify only one entity. As currently written, this sub-requirement gives Transmission Planners, Planning
Coordinators, Reliability Coordinators, or Transmission Operators the ability to require the facility to deliver active or reactive power. The SDT should
make it clear which single entity can set the requirement to avoid any conflicts.
4)
Measure 1 and Measure 2 contain the language “Each Generator Owner and Transmission Owner also have evidence of actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrating that the operation of each
facility did adhere to performance requirements [emphasis added]…”
Some facilities may not have sufficient data from actual system disturbances by the time this Standard becomes mandatory and enforceable. The SDT
should allow for the use of simulations and studies to demonstrate compliant design, similar to PRC-024, in such cases where the facility does not have
evidence of an actual disturbance.
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Kyle Thomas - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Elevate appreciates the opportunity to comment on the draft NERC standards, particularly those pertaining to future IBR NERC Reliability Standards
and FERC Order No. 901 directives.
Adoption of, or Alignment with, IEEE 2800-2022
Elevate continues to strongly encourage NERC to reconsider adoption of IEEE 2800-2022. The unwillingness to adopt IEEE 2800-2022 by NERC
is leading to entirely duplicative efforts that are not serving any additional value as compared to the work conducted in the IEEE 2800-2022
developments. It does not appear that a holistic approach and strategy is being taken to meet the FERC Order No. 901 directives, which is leading to
very low ballot scores, significant rework, and misalignment with industry recommended practices.
The draft NERC PRC-029 is duplicative with IEEE 2800-2022 Clause 7 yet only covers a small fraction of the IBR-specific capability and performance
requirements outlined in that clause. Therefore, there is no clear reliability benefit versus the cost of implementation PRC-029 as compared with IEEE
2800-2022 and the recommendations set forth in the NERC disturbance reports and guidelines.
Elevate strongly recommends a single NERC standard that adopts IEEE 2800-2022 in a uniform and consistent manner. NERC can also issue
a reliability guideline or implementation guidance that supports industry implementation of the standard. Rather than recreate parts of IEEE 2800-2022
inconsistently over multiple different standards, Elevate recommends a singular standard for BPS-connected IBR capability and performance
requirements related to IEEE 2800-2022. Additional NERC standards can be developed where needed in situations where they are not covered directly
with IEEE 2800-2022 (e.g., NERC PRC-030).
Concerns with Draft PRC-029
If the draft PRC-029 standard is to be pursued as currently structured, Elevate would like to highlight the following concerns:
Inconsistencies with PRC-029 and IEEE 2800-2022: There are numerous inconsistencies in the draft standard language and attachment 1 and 2
when compared to IEEE 2800-2022. These should be considered and reviewed for clarity and completeness in the standard. The option to cite IEEE
2800-2022 and use the requirements in the IEEE 2800-2022 directly should be allowed over just the use of Attachment 1/2 (i.e. give each GO/TO the
ability to use either of these guides to base their performance off on).
IEEE 2800 identifies the following items, but the standard does not support. Clarification/review should occur for each of these items:
IEEE 2800 recognizes FRT requirement limitations, but the standard does not.
IEEE 2800 recognizes exceptions for Negative-sequence voltage exceeding thresholds
IEEE 2800 recognizes Volts/Hz limitations, but the standard does not.
IEEE 2800 recognizes 500kV system voltages are actually operated in the range of 525kV and therefore has equipment rated to 550kV. These 500kV
operating conditions should be considered in the standard.
In IEEE 2800 the frequency ride-through criteria defines 10-minute time periods whereas the standard defines them in a 15 minute time period (Table 3
of Attachment 2). This should be clarified and identified.
Attachment 1: Voltage Ride-through criteria has issues that should be corrected. Row 2, voltage (per unit) has an error, the mathematical operand
should be “greater than” for the 1.10 value; this entry should read “=< 1.20 and > 1.10”.
Attachment 1: frequency ride-through criteria should be updated to fully match with IEEE 2800. Creating a different FRT ride-through curve without
adequate technical justification will continue to challenge the industry.
The SDT should consider allowing for FRT and V/Hz exemptions, similar to what is already in place for VRT exemptions. Legacy equipment limitations
apply to FRT, V/Hz, and VRT ride-through requirements, so exemptions should be allowed for both.
The standard should be updated to explicitly state that the voltage ride-through curves are to be interpreted as voltage vs time duration as is stated in
IEEE 2800. This is to ensure that there is no incorrect interpretation that these curves are “envelope” curves. This could be done by adding a new note
to explicitly call out the voltage vs time duration interpretation of the curves.
Alignment with FERC Directive for IBR Registration: BPS-connected/non-BES IBRs should be applicable to this standard, as it aligns with the
FERC order activities and the on-going NERC Registration effort to incorporate the non-registered BPS-connected IBRs that are owned/operated by the
new proposed Category 2 GO and GOP entities. Exclusion of these BPS-connected resources would significantly limit the ability to ensure that all BPSconnected IBRs have adequate voltage and frequency ride-through requirements during BPS/BES disturbances.
Alignment with NERC Glossary Definitions for IBRs: Creating a new definition for “inverter-based resources” is not aligned with the on-going IBR
standard related work throughout NERC. By creating a new definition, it seems counter-productive to have a unique definition of IBRs and IBR units
under the different NERC standards. Having all standards aligned to the new core NERC Glossary definition for IBRs will make all this standard
development work, execution of the standards, and compliance activities more efficient for all entities involved.
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Colin Chilcoat - Invenergy LLC - 6
Answer
Document Name
Comment
Thank you for the opportunity to provide comments and for your work on this project. Invenergy provides the below comments for the Drafting Team to
consider:
R1: In response to industry comments, the SDT indicated that Requirement R5 from Draft 1 was removed, but it appears the phase-angle jump
requirements have simply been reinserted under Requirement R1 in this second draft. As drafted, a facility is expected to ride-through fault-initiated
switching events regardless of the magnitude of voltage phase angle change. Consider that positive sequence phase angle change cannot be
accurately measured during a fault occurrence and clearance. We propose the assessment of ride-through performance during fault occurrence,
clearance, and recovery be based only on the voltage ride-through criteria in Attachment 1 Table 1 and Table 2.
We recommend reverting the “Voltage (per unit)” columns of Table 1 and Table 2 back to their first draft state to remain consistent with Tables 11 and
12 of IEEE 2800.
R2.1.3: The decimal place is missing from “95 per unit.”
R2.2: Consider more clearly defining “maximum capability.” As an alternative, R2.2 could state, “…each IBR shall exchange current, up to the total sum
of the nameplate current rating of online IBR units in the plant to provide voltage support…”
R2.3.1: Consider removal of this requirement. The time it should take a facility to restart current exchange following blocking seems irrelevant if the
other ride-through performance requirements are being met.
Attachment 1: Note 11 from Attachment 1 should be removed. There are many equipment protection settings that are near instantaneous to protect
against current or voltage surges that far exceed the equipment’s maximum rating. A power electronic switch could burn out in a matter of microseconds due to such a surge, before any tripping decision could be made if the filtering length must be at least 16.6 milliseconds.
R3: We recommend reverting the “System Frequency (Hz)” columns of Table 3 back to its first draft state to remain consistent with Tables 15 of IEEE
2800.
The Consideration of Comments document seemed to indicate that the drafting team intended to respond to our previous comment regarding the
expansion of the frequency ride-through range, but none was provided. The proposed 6-second frequency ride-through capability requirement for the
ranges of 61.8Hz to 64Hz and 57Hz to 56Hz does not align with the requirements on the rest of the BES and would expose synchronous generators to
dangerous variations in frequency. Can the drafting team cite more specific reasoning or data to support the expansion of the frequency ride-through
capability requirement to the range of 64Hz to 56Hz, well beyond the IEEE 2800-2022 standard frequency ride-through requirement and the capabilities
of many legacy IBRs?
R4: We recommend the following revision to R4.
R4. Each Generator Owner and Transmission Owner identifying a facility with a signed interconnection agreement by the effective date of PRC-029-1
with known hardware limitations that prevent the facility from meeting ride-through criteria as detailed in Requirements R1, R2, and R3, and requires an
exemption from specific ride-through criteria shall:
Exemptions in R4 should be based on the execution of the interconnection agreement rather than the in-service date of the facility. As drafted, facilities
with executed interconnection agreements, but not yet in-service by the effective date of the standard may need to make significant equipment
modifications and perform interconnection restudies to comply with requirements that did not become effective until after the interconnection agreement
was executed.
Regarding the lack of frequency ride-through exemptions, the limited exception language in FERC Order 901 is not supported by any comments or
other evidence in the record in the original NOPR proceeding, and therefore we believe this to be an inadvertent omission and unjustified application of
Order 901 in the draft language of PRC-029-1. In fact, in the NOPR, FERC proposed to direct NERC “to develop new or modified Reliability Standards
that would require Generator Owners and Generator Operators to ensure that their registered IBR facilities ride through system frequency and voltage
disturbances where technologically feasible.” The drafted frequency ride-through performance requirements are not technologically feasible for many
legacy IBRs.
Further, in Order 901, FERC “encourage[s] 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.” Requirement R3 of PRC-024-3, and the currently drafted version of PRC024-4, allows for exemptions from both the frequency and voltage ride-through requirements due to equipment limitations.
Given the lack of a clear evidentiary record on this point, the drafting team should rely on the discretion FERC has always granted NERC when it comes
to drafting and implementing practical Reliability Standards. Invenergy recommends Requirement R4 be amended to allow limited exemptions from
specific voltage and frequency ride-through criteria for facilities with known hardware limitations that prevent the facility from meeting the ride-through
criteria detailed in Requirements R1, R2, and R3.
Finally, Invenergy has concerns regarding the deviation of this project from its original goal of developing a standard that will require ride-through
performance from all generating resources. As currently drafted, PRC-024-4 imposes fewer ride-through performance responsibilities on synchronous
generators while allowing broader exemptions from its requirements than PRC-029-1. This undue discrimination permits scenarios in which both a
synchronous generator and an IBR could trip offline due to the same system disturbance and only the IBR would be subject to a potential
noncompliance, assuming the synchronous generator did not trip due to its protection system settings.
Implementation Plan: In its Consideration of Comments, the drafting team indicated that the Implementation Plan has been modified such that PRC029-1 shall become effective on the first day of the first calendar quarter that is 12 months after the effective date of the applicable governmental
authority’s order approving PRC-028-1, however the Implementation Plan still lists an implementation timeframe of six months.
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Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
-In R1, suggest the phase jump measurement to align to 2800 definition i.e.,Sub-cycle-to-cycle
-In Attachment 2, frequency ride through table is different with 2800. Suggest to align to 2800, otherwise the OEMs need to design for different specs.
-For R4.1, 12 months is not sufficient for documenting the supporting information for hardware limitation. Recommend a 2-year period for the exception
documentation.
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
Document Name
Comment
PRC-029 R 2.1.3 should be 0.95 per unit not 95 per unit.
Figures 1 and 2 in Attachment 1 of PRC-029 should use the same scale on the horizontal axis, either log or linear.
Please clarify point 10 of attachment 1 of PRC-029: “The facility may trip for more than four deviations of the applicable voltage at the high-side of the
main power transformer outside of the continuous operation region within any 10 second time period.”
The Implementation Plan should be extended to 36 months to allow for monitoring equipment to be installed at sites completed before PRC-029
becomes enforceable, to demonstrate performance and compliance with the standard.
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Kinte Whitehead - Exelon - 3
Answer
Document Name
Comment
Exelon supports the comments submitted by the EEI.
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Chance Back - Muscatine Power and Water - 5
Answer
Document Name
Comment
I support NSRF comments.
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Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Document Name
Comment
AEPC only has minor concerns with PRC-024-4; however, in our opinion, PRC-029-1 still needs some work before we can recommend approval.
Thank you for the opportunity to comment.
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Junji Yamaguchi - Hydro-Quebec (HQ) - 1,5
Answer
Document Name
Comment
It is imperative that the standard drafting teams for this project as well as the 2021-04 (PRC-002 and PRC-028) and 2023-02 (PRC-030 vs PRC-004)
assure a coherent way of addressing the inclusion and exclusion of IBRs in current and upcoming standards.
The following comments are applicable to PRC-029-1
The definition for Inverter Based Resource (IBR) was approved by industry in April under Project 2020-06. We do not agree with inserting the
uncapitalized version of IBR into 4.2 Facilities section because it is unbounded and insufficient to identify the Facilities applicable to this Standard, as
required in the Rules of Procedure (Appendix 3a, Standard Processes Manual). Furthermore, these definitions are the foundation of several ongoing
projects in response to FERC Order 901, where FERC “directs NERC to submit new or modified Reliability Standards that address specific matters
pertaining to the impacts of IBRs on the reliable operation of the BPS.”
The purpose section of PRC-029-1 refers to Inverter‐Based Resources (IBRs) (capitalized, defined term) whereas the facilities section uses the
uncapitalized version.
Section 4.2.2: What IBR Registration Criteria are we referring to? Are we referring to the Category 2 GO/GOP facilities that are still awaiting a FERC
decision? This section is not consistent with project 2021-04.
For requirements R1 through R4, it is unclear which facilities are being referred to. Suggest rewording to “facilities identified in Section 4.2” or adding a
sentence to 4.2 to indicate “For the purpose of this standard, the term “Applicable facilities” refers to the following:”. However, as stated above, it is
unclear what facilities are included in the IBR Registration Criteria.
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Duke Energy offers the following Comments for Draft 2 of PRC-024 and PRC-029 - see Duke Energy, EEI and NAGF comments below.
PRC-024-4 Comments
1-Duke Energy recommends the following R2 word omission be rectified:
R2. Each Generator Owner and Transmission Owner shall…which it is applied “to” trip within…
PRC-029-1 Comments
EEI COMMENTS
Duke Energy agrees with and supports EEI filed comments as summarized below - see official EEI filed comments for additional detailed comments
and proposed resolution(s):
1-The Standard attempts to redefine the approved definition of IBR by adding VSC-HVDC systems after the IBR definition was approved by the
industry. EEI does not support: (a) expansion of the definition of IBRs beyond what was recently approved by the industry, since there is no technical
justification for adding VSC-HVDC and, (b) the SAR did not include adding VSC-HVDC systems to this project. For these reasons, we ask that the
definition of IBR not be expanded, and that the DT submit a technical justification for adding VSC-HVDC systems to the applicability section of this
Standard, rather than redefining an approved definition in a footnote.
2-The Standard adds TOs to this Standard solely to address VSC-HVDC systems although: (a) no technical justification has been provided, and (b)
these systems were not identified in FERC Order No. 901, the SAR, or in the Applicability Section of this proposed Reliability Standard.
3-EEI is concerned with the inclusion of requirements that are not clearly defined or set by multiple registered entities (i.e., TP, PC, RC, or TOP). This
situation creates: (a) regulatory confusion and places IBR-GOs in a position where they may need to comply with any number of entities without clearly
defining who is responsible, (b) IBR-GOs will have reporting obligations to multiple entities because no single entity is identified as being responsible,
and (c) none of the entities identified (i.e., TP, PC, RC, or TOP) are identified within the Applicability section of this proposed Reliability Standard. This
situation will likely create confusion and places considerable regulatory burden on the IBR-GOs and requires resolution and additional clarification.
4-Throughout this Reliability Standard there is use of: (a) non-glossary terms (i.e., active power vs. Real Power) where glossary terms are available and
should be used and (b) glossary terms are used but not capitalized (e.g., reactive power vs. Reactive Power). Greater efforts should be made to use
NERC Glossary terms where appropriate and capitalize those terms, as required.
5-Ride-through Definition:
EEI does not support the proposed definition for “Ride-through” as proposed because it is too vague and contains no defined limits, as proposed. We
recommend the following changes: Reference EEI filed comments for this item.
6-Applicability Section:
(a) Footnote 1: EEI does not support adding TOs that own VSC-HVDC systems because it was not a scope item and is therefore not included in the
scope of this SAR.
(b) Footnote 1 conflicts with Footnote 2 which defines VSC-HVDC as an IBR, which is not in alignment with the approved definition of an IBR.
(c) Footnote 2: EEI does not support Footnote 2 because it expands the definition of IBRs beyond what was recently approved by the industry, noting
the expansion of IBRs to include VSC‐HVDC.
(d) There was no technical justification for adding VSC-HVDC and the SAR did not include adding VSC-HVDC systems to this project.
For these reasons, we ask that the definition of IBR not be expanded through footnotes and suggest that the DT submit a technical justification for
adding VSC-HVDC systems to the applicability section of this Standard, rather than redefining an approved definition in a footnote.
To address our concerns related to Footnotes 1 & 2, we suggest that if VSC-HVDC systems are to be classified as IBRs, then the approved definition
should be pulled by NERC and resubmitted with those resources added to the definition and subsequently resubmitted to the industry for approval.
Alternatively, VSC-HVDC systems could be defined separately, and that definition submitted to the industry for approval. In both cases, a technical
justification should be provided to the industry that defines the issues and risks to BPS reliability that VSC-HVDC systems pose.
EEI suggests that if the DT believes certain IBR capabilities as identified under Requirement R2 need (or may need) to be specified then the DT should
identify the entity who should be responsible among the four identified (i.e., TP, PC, RC or TOP); add them to the applicability section of this Reliability
Standard; and add clear requirements and adjust the reporting obligations for the IBR-GO under Requirement R4.
7-Requirement R1 & R2:
EEI does not agree with the inclusion of Transmission Owners because they would only have an obligation under this Reliability Standard if VSC-HVDC
systems were included. Given we do not support the inclusion of VSC-HVDC systems without a technical justification and modified SAR, we ask
Transmission Owners be removed from Requirement R1.
8-Measures M1 & M2:
EEI is concerned that M1 & M2 contains measures that are overly prescriptive and provide little discretion to IBR-GOs in demonstrating their
compliance with Requirements R1 and R2. As written, M1 and M2 appear to align more with a Requirement than a Measure (see official EEI filed
comments for additional detailed comments and proposed resolution(s)).
9-Requirement R3 & R4: EEI does not support the inclusion of Transmission Owners within Requirements R3 & R4 for the same reasons identified
above.
DUKE ENERGY COMMENTS
Additionally, Duke Energy provides the following additional comments:
10-Amend Standard to include GO specific and comprehensive responsibilities and identify functional entity required to approve exemption(s).
11-R3 does not provide specific Measure information in the Requirement – amend; as stated above, this action must provide definitive compliance
guidance for GOs.
12-R4: Language does not allow for frequency exemptions (voltage exemptions allowed) – amend Requirement to allow for frequency exemptions.
13-R4.2.1 Amend language to require Regional Entity to respond within X calendar days.
14-R3: Amend language as follows: …“and suggest similar changes be made to M2” and M3.
15-R2.1.3: Requirement is duplicative with VAR-002 Reactive/Voltage support – consider removing.
16-Duke Energy recommends the word “ensure” be removed from all Requirements and specific Requirement language obligations be inserted to
identify compliance. Use of the word “ensure” results in global compliance guidance that is not auditable unlike specific compliance Requirement(s).
17-Measurement M1: Consider including a standard Prerequisite Section in Standard that validates design and operation is such that each facility
adheres to Ride-through requirements
18-M4/R4.3 – Resolve 30 calendar days vs. 90 calendar days conflict or clarify differences. Also, add “calendar” days to R4.3.
NAGF COMMENTS
Finally, Duke Energy agrees with and supports NAGF filed comments summarized below - see official NAGF filed comments for additional detailed
comments and proposed resolution(s):
19-Consider removing Applicability 4.2.2 section, IBR Registration Criteria.
20-R2.5 requires clarity – revise narrative to state that active power shall be restored when ”the voltage at the high‐side of the main power transformer
returns to the Continuous Operating Region”.
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Michael Goggin - Grid Strategies LLC - 5
Answer
Document Name
Comment
In the draft of PRC-029, R4 should be modified to allow existing resources with equipment limitations to obtain an exemption from the frequency ridethrough requirements in R3, instead of only allowing an exemption from the voltage ride-through requirements in R1 and R2. This is necessary because
some existing IBR generators cannot meet the stringent frequency ride-through requirements proposed in R3 without deploying significant hardware
modifications or replacement, which goes against the intent of FERC Order 901.
The frequency ride-through requirements are particularly problematic for some existing wind generators. In the Technical Rationale document
accompanying the PRC-029 draft, the drafting team notes that some wind generators are more sensitive to frequency deviations, writing that “All IBR
resources (except for type 3 wind turbines) interface to the grid through fast switching of power electronics devices. These power electronic devices are
much less sensitive to the transmission system frequency excursion than non‐hydraulic turbine synchronous resources.”{C}[1] However, the drafting
team then incorrectly concludes that “Therefore, IBR should be capable of riding through the increased proposed 6‐second frequency ride‐through
requirement without risk of equipment damage or need for frequency protection to operate.” The Technical Rationale document does not offer any
justification for its assumption that Type III wind turbines can meet the frequency ride-through requirements, despite noting that those turbines more
directly interface with the grid and thus are more affected by frequency deviations than other IBRs.
In fact, many existing Type III wind turbines cannot meet the frequency ride-through requirements proposed in this draft of PRC-029. Those resources
were designed to meet the reliability Standards and interconnection requirements that were in effect when they were placed in service, and were not
designed to ride through frequency excursions of the magnitude and duration proposed in the draft Standard. Other types of existing IBR resources
were also not designed to meet the proposed frequency ride-through requirements, and may similarly require extensive equipment modification or
replacement to comply with R3.
Imposing a retroactive requirement on wind generators is particularly problematic as it is not typically feasible to retrofit existing wind turbines to
increase their ability to ride through and withstand mechanical stresses due to frequency changes. In such cases, making existing equipment better
able to withstand frequency changes would require full replacement or extensive modification of hardware, which would come at a significant, and
sometimes prohibitive, cost. Frequency changes can impose mechanical stresses on highly sensitive elements in the wind turbine’s rotating equipment,
including the generator, gearbox, the main shaft, and bearings associated with all of that equipment, and requiring such resources to ride through
frequency changes they were not designed to operate through can damage that equipment. Subjecting Type III wind turbines to this damage may lead
to increased outages or premature failure of these generators, potentially increasing reliability risks.
The easiest solution is to modify R4 to allow existing resources with equipment limitations toobtain an exemption from the frequency ride-through
requirements in R3, which would make PRC-029 consistent with a long precedent of FERC interconnection requirements and NERC Standards only
applying prospectively, including PRC-024. Retroactive requirements impose a much greater financial burden on the generator than prospective
Standards, and set a bad precedent by unfairly penalizing generators that met all requirements that were in effect at the time they were installed.
Retrofit or replacement costs are typically much greater than if the capability were installed at the plant to begin with. In some cases equipment needed
for retrofits may not be available, particularly for models that have been discontinued or manufacturers that are no longer in business, potentially
requiring the replacement of the entire wind turbine. Moreover, existing IBR generators typically sell their output at a fixed price under a long-term power
purchase agreement, and unexpected retrofit or replacement costs cannot typically be recovered once a power purchase agreement has been signed.
These unexpected and unrecoverable costs are far more concerning to lenders and other generation project financiers as they were not accounted for
during the project’s financing. As a result, retroactive requirements set a bad precedent by introducing regulatory uncertainty that makes future
generation investment more uncertain and riskier, and likely more costly by forcing financiers to charge higher risk premiums.
Fortunately, these problems can be fixed by inserting “R3” into the list of permissible exemptions in R4, which would allow existing resources with
equipment limitations to obtain an exemption from the frequency ride-through requirements in R3.
In the Technical Rationale document, the drafting team points to FERC’s directive in Order No. 901 to justify not allowing existing resources to obtain an
exemption from the frequency ride-through requirements in R3: “FERC Order No. 901 states that this provision would be limited to exempting ‘certain
registered IBRs from voltage ride‐through performance requirements.’ This is the reason that no similar provisions are included for exemptions for
frequency or rate‐of‐change‐of‐frequency (ROCOF) ride‐through requirements per R3.”[2]
However, a contextual reading of Order No. 901 indicates FERC was focused on targeting equipment limitation exemptions at existing generators that
would have to physically replace or modify hardware to comply with the Standard, and not focused on limiting such exemptions to voltage ride-through
requirements. Paragraph 193 in its entirety, and particularly the first sentence, explain that FERC’s intent was exempting existing resources that would
have to physically replace or modify hardware: “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.” As a result, FERC continued by directing that “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.”[3]
Allowing existing plants to apply for an equipment limitation exemption for the frequency ride-through requirements in R3 is necessary to ensure some
existing generators do not have to physically replace or modify hardware. As a result, such an exemption is consistent with FERC’s directive and intent
in Order No. 901. As documented in the following footnote, there is ample precedent for NERC and standards drafting teams to exercise their technical
expertise to craft Standards to align content and requirements with technical realities.[4]
Additional context in Order 901 further demonstrates that FERC intended for NERC to include an exemption for existing IBRs that cannot meet
frequency ride-through requirements. At paragraph 190 in Order No. 901, FERC directed NERC to develop Standards that ensure resources “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.” For many existing IBRs that cannot meet the proposed frequency
ride-through requirements, tripping is necessary to protect the IBR equipment, similar to when synchronous generation resources use tripping as
protection from internal faults. As a result, an exemption from R3 for existing resources is consistent with FERC’s intent. Order No. 901 also directed
NERC to consider the “PRC-024-3, Requirement R3 as an example for establishing registered IBR technology exemptions,” and that exemption applies
equally to voltage ride-through and frequency ride-through settings, further suggesting that FERC will allow certain IBRs an exemption from the
frequency ride-through requirements.[5] Finally, Order No. 901 notes that in the notice of proposed rulemaking that led to the order, FERC “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.”[6] FERC then adopted that very proposal,{C}[7] further demonstrating that FERC sought to direct NERC to
only require frequency and voltage ride-through where technologically feasible.
It is likely that FERC Order No. 901 did not explicitly direct NERC to include frequency ride-through exemptions because FERC did not anticipate that
NERC would adopt such an aggressive frequency ride-through requirement that some existing plants cannot meet. The drafting team even notes at
page 7 in the Technical Rationale document that “The proposed 6‐second time frame of the frequency ride‐through capability requirement is beyond the
IEEE 2800 standard frequency ride‐through requirement and beyond frequency ride‐through requirements for synchronous machines under proposed
PRC‐024‐4.” There is nothing in Order No. 901 that suggests that FERC was opposed to existing equipment exemptions for a frequency ride-through
standard that was drafted after FERC issued Order No. 901 and is more stringent than FERC anticipated. A much more reasonable interpretation is that
the logic FERC provided in paragraph 193 of Order No. 901 also applies to a frequency ride-through requirement that some existing resources cannot
meet without physical modification or replacement of equipment. In fact, paragraph 193 makes clear that FERC’s language focuses on an exemption
from voltage ride-through requirements because “a subset of existing registered IBRs… may be unable to implement the voltage ride though
performance requirements directed herein.”
At the end of paragraph 193, FERC also explained that an exemption for existing resources would not harm reliability because “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.” FERC’s reasoning in paragraph 193 also applies to an exemption from frequency
ride-through requirements, but particularly the conclusion that exempting existing plants does not cause reliability concerns and therefore should be
allowed. The NERC drafting team’s technical justification document explicitly explains that the frequency ride-through requirement is “to ensure the
reliability of future grids with high IBR penetration,”{C}[8] based on concerns about declining inertia due to IBRs replacing synchronous resources.
NERC and others have demonstrated that inertia and frequency response will remain more than adequate for the foreseeable future even following
disturbances that are several times larger than current credible contingencies, and that higher IBR penetrations can actually significantly improve
frequency stabilization following disturbances.[9]
As a result, there is no reliability concern from an exemption for the small number of existing resources that cannot meet the requirements without
physical modification or replacement of equipment. Moreover, as FERC notes, these plants will replace that equipment anyway over time as legacy
inverters fail or are replaced with more modern equipment for other reasons, and the draft standard requires replacement equipment to comply with the
Standard. Utility-scale inverters installed at solar and battery installations typically come with warranties of 10 years or less,{C}[10] and those inverters
are typically replaced at least once during the plant’s lifetime. Many existing wind plants are also being repowered with newer turbines, often to allow
the project to receive another 10 years of production tax credits after the initial 10 years of credits have been received. As a result, by the time the
drafting team’s concerns about inertia in a high IBR penetration future might materialize, the vast majority of IBRs that cannot meet the frequency ridethrough requirements will have been replaced with new equipment that is not exempt.
Moreover, the drafting team’s assumption that frequency deviations will be larger on a future low inertia power system is flawed. IBRs can provide fast
frequency response, which stabilizes frequency in the initial seconds following a grid disturbance, before synchronous generators begin to provide their
slower primary frequency response.[11] Thus fast frequency response provides a similar service to inertia in helping to arrest the change in frequency
before primary frequency response is fully deployed, reducing the need for inertia.[12] Fast frequency response is easily provided by batteries due to
their available energy, but can also be provided by curtailed wind or solar resources. Power systems with high IBR penetrations will tend to have some
wind or solar curtailment in a significant share of hours. If allowed to do so, solar an battery resources with spare DC capacity behind the inverter can
also temporarily exceed their interconnection agreement’s AC injection limit to provide fast frequency response.
The replacement of inflexible synchronous resources with more flexible IBRs could also significantly improve primary frequency response, as NERC’s
modeling has demonstrated.{C}[13] NERC has also documented that only about 30% of synchronous generators provide primary frequency response,
and only about 10% provide sustained primary frequency response.[14] Even with less inertia, the fast and accurate frequency response provided by
IBRs will keep frequency more tightly controlled than the slow to nonexistent primary frequency response from synchronous generators. The
replacement of large synchronous generators with smaller IBRs should also reduce the magnitude of frequency deviations following the loss of
generators. If frequency response does begin to emerge as a concern, the more effective solution would be to enforce requirements on synchronous
generators that are supposed to provide it but do not. If necessary, operators would alter real-time dispatch, as ERCOT and some island power systems
occasionally do today, to ensure that inertia and fast frequency response are adequate to ensure under-frequency load shedding or generator tripping
thresholds are not reached. Finally, grid-forming inverters are increasingly being deployed with battery storage and other IBR installations, further
increasing the contributions of IBRs to stabilizing frequency.
At page 8 in the Technical Rationale document, the drafting team argues that “To compensate for the lack of inertia and short circuit contributions,
[IBRs] should have wider tolerances for frequency and voltage excursions to meet the needs of future power systems with a higher percentage of IBR.”
The drafting team also argues that IBRs should have to ride-through much larger frequency deviations than synchronous resources because
“Synchronous resources are more sensitive to frequency deviations than IBR resources.” This logic is flawed for many reasons. Grid operators need all
resources to ride through disturbances, and the contribution of a resource to inertia or short circuit needs is irrelevant to that need. Any concerns about
resources’ inertia and short circuit contributions are outside the drafting team’s scope and authority, and should be addressed by other means (such as
by increasing the deployment of grid-forming IBRs in the localized areas that have short circuit or stability concerns). It is also perverse for the drafting
team to penalize IBRs for being less sensitive to frequency deviations than synchronous generators. As noted below, there are already grounds for
FERC to reject this proposed standard due to undue discrimination against IBRs relative to the far more lenient requirements on synchronous
generators under PRC-024, including an equipment limitation exemption for synchronous generators from the frequency relay setting requirement in
PRC-024, and this only adds to those concerns.
In short, the drafting team’s unfounded concerns about a future power system do not justify withholding an exemption to frequency ride-through
requirements for existing IBR resources that will have been largely replaced by the time any concerns might materialize.
Finally, R4 equipment limitation exemptions should be allowed for resources with signed interconnection agreements as of the effective date of the
Standard, instead of resources that are in-service as of that date. Resource equipment decisions are typically locked down at the time the
interconnection agreement is signed, and a change in requirements after that point can require a costly change in equipment or settings that may also
trigger a material modification and resulting interconnection restudies. The implementation plan for PRC-029 indicates that the effective date for the
Standard will be the first day of the first quarter six months after FERC approval. Many resources take significantly longer than that to move from a
signed interconnection agreement to being placed in service, so it makes more sense to allow R4 equipment limitation exemptions for resources that
have a signed interconnection agreement as of the effective date of the Standard.
The current draft of the PRC-029 Standard is unworkable and will impose massive costs on some existing generators with no benefit for reliability. As
explained above, the drafting team incorrectly ventures that “IBR should be capable of riding through the increased proposed 6‐second frequency
ride‐through requirement without risk of equipment damage or need for frequency protection to operate,” even after noting that some wind turbines use
very different technology. NERC’s rigorous standard development process exists to ensure that errors like this do not make it into final Standards, and
the exceedingly low level of support for the initial draft and the major revisions in the current draft indicate that further revisions will likely be necessary.
It takes time to fine tune highly technical requirements and vet them across the industry to avoid unnecessary and exorbitant costs for existing
resources that cannot meet the standard. If the drafting team and NERC believe Order No. 901’s deadlines do not provide enough time for further
standard revisions and balloting periods to make the frequency ride-through requirement workable for existing resources, adding the letters “R3” to R4
to create an exemption for existing resources is the fastest and easiest way to address those concerns. For the reasons explained above, such an
exemption does not pose any risk to reliability and is consistent with FERC’s directive in Order 901.
Undue discrimination
A major concern with the Standards, as drafted, is that ride through performance is not required for synchronous generators under PRC-024-4, but it is
for IBRs under PRC-029. PRC-024 simply requires protective relays to be set so they do not trip the generator within specified bounds, but it allows a
resource to trip offline for other reasons. PRC-024-4 also allows a plant to trip if protection systems trip auxiliary plant equipment, per section 4.2.3. In
contrast, PRC-029 requires IBRs to remain electrically connected and to continue to exchange current within the specified voltage and frequency
bounds. Said another way, an IBR and a synchronous resource could both trip during the same disturbance, and the IBR would be in violation of PRC029 but the synchronous generator would not be in violation of PRC-024-4, as long as the synchronous generator did not trip due to the settings of its
protection system.
To ensure grid reliability and resilience, all resources including IBRs and synchronous resources should ride through grid disturbances. The failure of
synchronous generators to ride through grid disturbances threatens grid reliability as much or more than the failure of IBRs, as synchronous resources
are often producing at a higher level of output, are more typically relied on as capacity resources, and often take longer to come back online and ramp
up to full output if they trip due to a disturbance.
FERC Order No. 901 directed NERC to treat IBR resources similarly to how NERC Standards treat synchronous generators, writing that the IBR
Standard should “permit IBR tripping only to protect the IBR equipment in scenarios similar to when synchronous generation resources use tripping as
protection from internal faults.”{C}[15] Allowing synchronous generators to trip but requiring IBRs to ride through the same or similar disturbance will be
challenged at FERC as undue discrimination. Providing synchronous generators with an equipment limitation exemption from PRC-024’s relay-setting
requirements but not offering existing IBR resources an exemption from the far more stringent frequency ride-through requirements in PRC-029 is also
undue discrimination.
This disparate treatment of IBRs versus synchronous generators is also at odds with the intent for this project that NERC stated in its February 2023
comments on the FERC proposed rulemaking that led to Order No. 901: “A comprehensive, performance-based ride-through standard is needed to
assure future grid reliability. To that end, NERC re-scoped an existing project, 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 generating resources.”[16]
FERC’s Order No. 901 also noted NERC’s statement that this project would require ride-through performance from all generating resources,[17] so a
failure to require ride-through performance from synchronous generators is contrary to both NERC’s and FERC’s intent.
Providing an exemption in PRC-029 R4 for existing IBRs that cannot meet the frequency ride-through requirement in R3 will result in less disparity with
the treatment of synchronous resources under PRC-024, and is therefore an essential step if NERC wants to reduce the risk of FERC rejecting the
proposed standard due to undue discrimination against IBRs.
{C}[1]{C} Technical Rationale, PRC-029-1 – Frequency and Voltage Ride-Through Requirements for Inverter-Based Generating Resources, at 8,
https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-0291_Technical_Rationale_Redline_to_Last_Posted_06182024.pdf (“Technical Rationale”).
{C}[2]{C} Id., at 10
{C}[3]{C} Reliability Standards to Address Inverter-Based Resources, Order No. 901, 185 FERC ¶ 61,042, P 193 (2023).
{C}[4]{C} For example, Section 215(d)(2) of the FPA requires FERC to give “due weight” to the technical expertise of the ERO when evaluating the
content of a proposed Reliability Standard or modification to a Standard.
Order No. 733-A, P 11: “In this order, we emphasize and affirm that we do not intend to prohibit NERC from exercising its technical expertise to
develop a solution to an identified reliability concern that is equally effective and efficient as the one proposed in Order No. 733.”
Order No. 748, P 43: “In consideration of these ongoing efforts, we will not direct specific modifications to these Reliability Standards and, rather,
accept NERC’s commitment to exercise its technical expertise to study these issues and develop appropriate revisions to applicable Standards as may
be necessary.”
Order No. 896, P 36: “NERC may also consider other approaches that achieve the objectives outlined in this final rule. Further, as recommended by
PJM, we believe there is value in engaging with national labs, RTOs, NOAA, and other agencies and organizations in developing benchmark events.
Considering NERC’s key role, technical expertise, and experience assessing the reliability impacts of various events and conditions, we encourage
NERC to engage with national labs, RTOs, NOAA, and other agencies and organizations as needed.”
Order No. 901, P 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.”
{C}[5]{C} Order 901, P 193
{C}[6]{C} Id. at P 178.
{C}[7]{C} Id. at P 190.
{C}[8]{C} Technical Rationale at 7.
{C}[9]{C} East Interconnection Frequency Response Assessment with Inverter Based Resources, at 7
https://www.energy.gov/sites/prod/files/2018/07/f53/2.1.4%20Frequency%20Response%20Panel%20-%20Velummylum%2C%20NERC.pdf.
{C}[10]{C} Best Practices for Operation and Maintenance of Photovoltaic and Energy Storage Systems, at 55,
https://www.nrel.gov/docs/fy19osti/73822.pdf.
{C}[11]{C}Fast Frequency Response Concepts and Bulk Power System Reliability Needs,
https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/Fast_Frequency_Response_Concepts_an
d_BPS_Reliability_Needs_White_Paper.pdf.
{C}[12]{C} Inertia and the Power Grid: A Guide Without the Spin, https://www.nrel.gov/docs/fy20osti/73856.pdf.
{C}[13]{C} East Interconnection Frequency Response Assessment with Inverter Based Resources, at 7
https://www.energy.gov/sites/prod/files/2018/07/f53/2.1.4%20Frequency%20Response%20Panel%20-%20Velummylum%2C%20NERC.pdf.
{C}[14]{C} https://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/FRI_Report_10-30-12_Master_w-appendices.pdf
{C}[15]{C} Order No. 901, at P190
[16]{C}https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Comments_IBR%20Standards%20NOPR.pdf, at 21-22.
[17]{C} Order No. 901, at P 185
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Rhonda Jones - Invenergy LLC - 5
Answer
Document Name
Comment
Thank you for the opportunity to provide comments and for your work on this project. Invenergy provides the below comments for the Drafting Team to
consider:
R1: In response to industry comments, the SDT indicated that Requirement R5 from Draft 1 was removed, but it appears the phase-angle jump
requirements have simply been reinserted under Requirement R1 in this second draft. As drafted, a facility is expected to ride-through fault-initiated
switching events regardless of the magnitude of voltage phase angle change. Consider that positive sequence phase angle change cannot be
accurately measured during a fault occurrence and clearance. We propose the assessment of ride-through performance during fault occurrence,
clearance, and recovery be based only on the voltage ride-through criteria in Attachment 1 Table 1 and Table 2.
We recommend reverting the “Voltage (per unit)” columns of Table 1 and Table 2 back to their first draft state to remain consistent with
Tables 11 and 12 of IEEE 2800.
R2.1.3: The decimal place is missing from “95 per unit.”
R2.2: Consider more clearly defining “maximum capability.” As an alternative, R2.2 could state, “…each IBR shall exchange current, up to the total sum
of the nameplate current rating of online IBR units in the plant to provide voltage support…”
R2.3.1: Consider removal of this requirement. The time it should take a facility to restart current exchange following blocking seems irrelevant if the
other ride-through performance requirements are being met.
Attachment 1: Note 11 from Attachment 1 should be removed. There are many equipment protection settings that are near instantaneous to protect
against current or voltage surges that far exceed the equipment’s maximum rating. A power electronic switch could burn out in a matter of microseconds due to such a surge, before any tripping decision could be made if the filtering length must be at least 16.6 milliseconds.
R3: We recommend reverting the “System Frequency (Hz)” columns of Table 3 back to its first draft state to remain consistent with Tables 15 of IEEE
2800.
The Consideration of Comments document seemed to indicate that the drafting team intended to respond to our previous comment regarding the
expansion of the frequency ride-through range, but none was provided. The proposed 6-second frequency ride-through capability requirement for the
ranges of 61.8Hz to 64Hz and 57Hz to 56Hz does not align with the requirements on the rest of the BES and would expose synchronous generators to
dangerous variations in frequency. Can the drafting team cite more specific reasoning or data to support the expansion of the frequency ride-through
capability requirement to the range of 64Hz to 56Hz, well beyond the IEEE 2800-2022 standard frequency ride-through requirement and the capabilities
of many legacy IBRs?
R4: We recommend the following revision to R4.
R4. Each Generator Owner and Transmission Owner identifying a facility with a signed interconnection agreement by the effective date of PRC-029-1
with known hardware limitations that prevent the facility from meeting ride-through criteria as detailed in Requirements R1, R2, and R3, and requires an
exemption from specific ride-through criteria shall:
Exemptions in R4 should be based on the execution of the interconnection agreement rather than the in-service date of the facility. As drafted, facilities
with executed interconnection agreements, but not yet in-service by the effective date of the standard may need to make significant equipment
modifications and perform interconnection restudies to comply with requirements that did not become effective until after the interconnection agreement
was executed.
Regarding the lack of frequency ride-through exemptions, the limited exception language in FERC Order 901 is not supported by any comments or
other evidence in the record in the original NOPR proceeding, and therefore we believe this to be an inadvertent omission and unjustified application of
Order 901 in the draft language of PRC-029-1. In fact, in the NOPR, FERC proposed to direct NERC “to develop new or modified Reliability Standards
that would require Generator Owners and Generator Operators to ensure that their registered IBR facilities ride through system frequency and voltage
disturbances where technologically feasible.” The drafted frequency ride-through performance requirements are not technologically feasible for many
legacy IBRs.
Further, in Order 901, FERC “encourage[s] 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.” Requirement R3 of PRC-024-3, and the currently drafted version of PRC024-4, allows for exemptions from both the frequency and voltage ride-through requirements due to equipment limitations.
Given the lack of a clear evidentiary record on this point, the drafting team should rely on the discretion FERC has always granted NERC when it comes
to drafting and implementing practical Reliability Standards. Invenergy recommends Requirement R4 be amended to allow limited exemptions from
specific voltage and frequency ride-through criteria for facilities with known hardware limitations that prevent the facility from meeting the ride-through
criteria detailed in Requirements R1, R2, and R3.
Finally, Invenergy has concerns regarding the deviation of this project from its original goal of developing a standard that will require ride-through
performance from all generating resources. As currently drafted, PRC-024-4 imposes fewer ride-through performance responsibilities on synchronous
generators while allowing broader exemptions from its requirements than PRC-029-1. This undue discrimination permits scenarios in which both a
synchronous generator and an IBR could trip offline due to the same system disturbance and only the IBR would be subject to a potential
noncompliance, assuming the synchronous generator did not trip due to its protection system settings.
Implementation Plan: In its Consideration of Comments, the drafting team indicated that the Implementation Plan has been modified such that PRC029-1 shall become effective on the first day of the first calendar quarter that is 12 months after the effective date of the applicable governmental
authority’s order approving PRC-028-1, however the Implementation Plan still lists an implementation timeframe of six months.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Southern Company supports NAGF comments.
Southern Company suggests that M1 be divided out to be clearer such as:
M1. Each Generator Owner and Transmission Owner shall have evidence of dynamic simulations, studies, or other evidence to demonstrate the design
of each facility will adhere to Ride-through requirements, as specified in Requirement R1.
M1.1 Each Generator Owner and Transmission Owner shall have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder,
Dynamic Disturbance Recorder, and Fault Recorder) to demonstrate that the operation of each facility did adhere to Ride through requirements, as
specified in Requirement R1.
M1.2 If the Generator Owner and Transmission Owner choose to utilize Ride-through exemptions that occur within the “must Ride-through zone” and
are caused by non-fault initiated phase jumps of greater than 25 electrical degrees, then each Generator Owner and Transmission Owner shall also
have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to
demonstrate that the facility failed to Ride-through during a phase jump of greater than or equal to 25 electrical degrees, and documentation from their
Transmission Planner, Reliability Coordinator, Planning Coordinator, or Transmission Operator that a non-fault initiated switching event occurred.
Southern Company suggests adding an exemption for V/Hz to R3 like bullet 4 in R1.
R3 - Frequency Ride-Through Criteria
Southern Company recommends PRC-029-1 adopt Frequency Ride-Through Criteria (Attachment 2, Table 3 in draft 2) consistent with the IEEE2800
standard. Individual Regions should be allowed to adopt more stringent frequency ride-through standards based on their respective system needs and
resource capabilities.
R4 – Exemptions
Any ultimate decision to disallow exemptions for requirements other than voltage, must be grounded in a thorough technical analysis of IBR OEM
capabilities. NERC staff and standard drafting team participants have the necessary technical expertise to make these determinations. Additionally,
there is ample precedent from prior Standard processes for FERC to defer to NERC on such technical issues. Finally, if the more stringent Frequency
Ride-Through criteria in the current draft is preserved, this amplifies the need for consideration of existing equipment frequency ride-through
exemptions. GOs and OEMs have not had adequate time to assess resource capabilities against requirements more stringent than IEEE2800.
Southern Company suggests that Requirement R4.3 be reworded to “...that replace the equipment causing the limitation, such that the limitation no
longer exists, shall document and communicate...” The current wording is being interpreted that the only equipment that can be put back in place of a
failed piece of equipment with a limitation is one without a limitation. Furthermore, R4.3.1 alludes that replacement of equipment with a limitation must
be made with equipment without limitation. This may not be possible due to uniqueness and limits associated with an existing facility design. There is
no allowance for in-kind replacements. If one inverter burns down, there is no provision to replace it with an in-kind spare replacement unit.
Note 7 on page 15 states that you only have to ride-through the voltage deviations if the frequency remains within the “must ride through zone”. Doesn’t
there need to be a corresponding statement made on page 19? In other words, the standard should allow you to trip even if the frequency remained at a
constant 60Hz if the voltage does not remain within the values in Attachment 1.
Southern Company suggests that Requirement R4 also include identified “software limitations” in addition to hardware limitations.
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Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer
Document Name
Comment
TEPC does not have any comments for PRC-024-4.
TEPC agrees with EEI's comments regarding PRC-019-1.
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Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
Answer
Document Name
Comment
Ride-through Definition:
The ISO RTO Council Standards Review Committee (SRC) recommends that the drafting team provide a rationale for the proposed “Ride-through”
definition, as it is not clear what benefits result from creating a formal definition for this term, and the definition that has been proposed contains
ambiguous language.
First, use of the term “synchronized” in a definition intended to apply to IBRs could result in confusion because IBRs are generally considered to be
asynchronous resources (though no mention of IBRs is made in the proposed definition). As a stand-alone term in the NERC glossary, the proposed
definition could reasonably be interpreted to apply only to synchronous machines.
Second, the phrase “continuing to operate” is an inadequate description of desired performance – ride-through should include a concept of performance
that is beneficial (or at the very least not detrimental) to overall grid reliability.
Third, the use of “Transmission System” potentially limits the applicability of the definition to only transmission-connected resources – the SDT may
want to consider instead using a more general term such as “electric system” as was used in the proposed IBR definition.
Finally, defining the term “ride-through” may not be necessary at all. Meeting all of the requirements in PRC-029 essentially constitutes ride-through.
Creating a separate defined term may just cause confusion, as the proposed definition does not clarify the desired (or required) performance associated
with ride-through. The best option may be to leave the term undefined. If the SDT determines that a definition for Ride-though is an absolute necessity,
the SRC proposes the following definition:
“Facilities, including all individual dispersed power producing resources, remaining connected to the electric system and continuing to operate in a
manner that supports grid reliability throughout a System Disturbance, including the period of recovery back to a normal operating condition.”
Comments on Proposed Requirements:
The language in PRC-029-1 Requirement R2, Part 2.1.3 that reads “…according to requirements if required by the [TP, PC, RC, or TOP]” seems
awkward and redundant, as it seems that any requirements that exist will always be required. The SRC recommends that this language be changed
to: “…according to TP, PC, RC, and TOP requirements, if any.” Additionally, if the SDT continues to use a per unit metric for Part 2.1.3, the proposed
“95 per unit” should be replaced with “.95 per unit . . . .”
Regarding PRC-029-1 Requirement R2, Part 2.2, it can be problematic to simply specify reactive/active power priority because not all priority
implementations perform the same way. Part 2.2 does not really prohibit dropping active current to zero even for shallow voltage dips (e.g. 0.7-0.9pu),
but seems to allow the TP, PC, RC, or TOP to specify the desired performance. The SRC requests that the SDT clarify whether this is the intended
meaning, and revise Part 2.2 as necessary to clarify the intended meaning.
PRC-029-1 Requirement R2, Part 2.5 reads “…when the voltage at the high-side of the main power transformer returns from the mandatory operation
region….” The SRC requests that the SDT clarify whether this was intended to read: “when the voltage at the high-side of the main power transformer
returns to the continuous operation region from the mandatory operation region….”
In R2, Part 2.5 “available level (whichever is less)” should be revised to clarify whether “a lower post-disturbance active power level requirement” means
lower than the pre-disturbance level or lower than the available level.
The SRC also notes that the phrase “…pre-disturbance or available level (whichever is lesser)…” in PRC-029-1 Requirement R2, Part 2.5 may be
interpreted as allowing partial tripping/idling for an IBR facility. If the SDT’s intent is that no individual wind turbines/inverters should be allowed to
trip/idle, SRC recommends that this phrase be clarified with a footnote such as: “Reduction in available active power shall only be allowed due to a
reduction in available source power (e.g. wind or solar irradiance). Reduction in available active power shall not occur due to tripping or idling of
individual turbines or inverters within the IBR.”
The SRC requests that the SDT clarify whether Requirement R1 should include an absolute rate of change of voltage criteria similar to the RoCoF
criteria in PRC-029-1 Requirement R3. The SRC also requests clarification of whether the other bulleted exceptions listed in Requirement R1 apply
during frequency excursions (in other words, the SRC requests clarification of whether ride through is required for frequency excursions even if the
thresholds for V/Hz or phase angle jump specified in Requirement R1 are exceeded).
The SRC is concerned that the word “replaced” in PRC-029-1 Requirement R4, Part 4.3.1 may provide a pathway to circumvent the spirit of the
standard (e.g., an entity could refurbish equipment and claim that its exemption should be maintained because equipment wasn’t “replaced”). The SRC
recommends that “replaced, refurbished, or updated” be used instead. At the very least, the Technical Rationale should explain that documented
limitations are expected to be eliminated whenever an IBR is re-powered, upgraded, or updated with significant re-investment.
In PRC-029-1, Attachment 1, Tables 1 and 2 use the term “operation region” while Figures 1 and 2 use the term “operating regions.” If the two terms
are intended to have the same meaning, the SRC recommends that the same term be used in both locations (and throughout the standard). If the two
terms are intended to have different meanings, the SRC recommends that the intended meanings be clarified.
In PRC-029-1, Attachment 1, item 7 references a “must ride-through zone” in Table 3 of Attachment 2. However, Table 3 of Attachment 2 does not
explicitly specify a “must ride-through zone.” The SRC recommends that the SDT clarify whether Attachment 1, item 7 was intended to reference
Figure 3 of Attachment 2, or otherwise clarify the intended meaning. The SRC also requests that the SDT clarify why Attachment 2 does not have a
corollary item specifying that Table 3 is only applicable when voltage is within the “must ride-through zone” specified in Attachment 1. The SDT should
update the Technical Rationale to clarify the intent: whether there is a need to verify or not to verify voltage status for the Table 3 Attachment 2.
The SRC notes that the Technical Rationale for PRC-029-1 contains what appears to be an extraneous “Must Ride-through” heading between the
rational for R2.5 and the rationale for R3. The SRC recommends removal of this extraneous heading.
The SRC notes that the Technical Rationale for PRC-024-4 makes no explicit mention of the addition of type 1 and type 2 wind resources to PRC-024-4
and refers to restricting the applicability of PRC-024-4 to synchronous generators and synchronous condensers, which does not appear to be consistent
with the posted redlines for PRC-024-4. The SRC recommends that PRC-024-4 and the Technical Rationale be harmonized to remove this
discrepancy.
The applicability section for PRC-029-1 references “IBR Registration Criteria,” which presumably is intended to include IBRs connected to the BPS that
are not considered BES Elements (consistent with the pending revisions to the registration criteria for IBRs). The SRC notes that the Technical
Rationale is not very clear on the intent of this structure and requests that a more detailed explanation be included in the Technical Rationale.
Finally, the SRC notes that the addition of type 1 and type 2 wind resources to PRC-024-4 appears to be limited to facilities that meet the BES
definition. The SRC requests that the SDT clarify whether this difference is intentional and, if it is, provide the rationale for the difference (such as if the
revisions to NERC’s registration criteria are not intended to apply to non-BES type 1 or type 2 wind resources) and an explanation of whether the
difference constitutes a potential gap that should be addressed.
Comments on Attachment 1: Voltage Ride-Through Criteria
Attachment 1 lists a minimum ride-through time of 1800 seconds for the continuous operation voltage region between 1.05 pu and 1.1 pu (<= 1.1 and
>1.05) in Tables 1 and 2. The SRC requests that, consistent with IEEE 2800, an exception for 500 kV systems be allowed such that the minimum ridethrough time for 1.05 pu < voltage <= 1.1 pu for 500 kV systems is “Continuous,” because the 1.05 pu < voltage <= 1.1 pu voltage range is within the
normal operation range for some systems, such as PJM’s system.
In addition, in Figures 1 and 2, the SRC requests that the voltage pu values on Y-axis for the “Continuous Operating Region (1800 seconds)” be revised
to be consistent with the values listed in Tables 1 and 2 (1.05 < and <= 1.1).
Finally, the SRC generally supports incorporating as much of the IEEE 2800 language and parameters into PRC-029-1 as possible, and the SRC
encourages the drafting team to lean on IEEE 2800 as much as is feasible.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
Electric Reliability Council of Texas, Inc. (ERCOT) joins the comments submitted by the ISO/RTO Council Standards Review Committee (SRC) and
adopts them as its own. In addition, ERCOT submits the following comments.
ERCOT notes that the proposed Ride-through definition is unclear as to whether ride-through applies to partial trips (individual inverter or turbine trips).
ERCOT believes ride-through should apply both to the IBR facility and to the individual IBR units and requests that this be made clear in any definition
that may be adopted. If a defined term for ride-through is implemented, ERCOT recommends the use of a clarification modeled after the I4 inclusion
(“dispersed power producing resources”) in the BES definition, as detailed in the SRC’s proposed definition:
“Facilities, including all individual dispersed power producing resources, remaining connected to the electric system and continuing to operate in a
manner that supports grid reliability throughout a System Disturbance, including the period of recovery back to a normal operating condition.”
Additionally, ERCOT has identified the following concerns with Requirement R1 as it is currently proposed:
1.) R1 does not clarify whether partial trips (individual IBR unit trips) would be allowed. ERCOT believes individual turbine/inverter trips should not be
permissible under R1 and that R1 should clearly indicate that ride-through does not occur when individual turbines or inverters trip offline.
2.) Requirement R1’s reference to “adhering” to requirements may create the mistaken impression that exceeding the minimum ride-through
requirements is not allowed.
3.) Allowing an exclusion from Requirement R1 for equipment limitations should not result in a unit being exempt from complying with requirements
that are not impacted by the limitation.
4.) The process for obtaining a documented limitation should be reviewed to ensure it is consistent with the directives that FERC included in its recent
Order on EOP-011-2 in Docket No. RD24-5-000.
To address these issues, ERCOT recommends that Requirement R1 be revised to read as follows:
R1. Each Generator Owner or Transmission Owner shall ensure the design and operation is such that each facility meets or exceeds the Ride-through
requirements, in accordance with the “must Ride-through3 zone” as specified in Attachment 1, except for the following: [Violation Risk Factor: High]
[Time Horizon: Operations Assessment]
• The facility needed to electrically disconnect in order to clear a fault;
• The electrical system at the high-side of the main power transformer demonstrated characteristics that exceeded a documented and
confirmed equipment limitation identified and communicated in accordance with Requirement R4; or
• The instantaneous positive sequence voltage phase angle change is more than 25 electrical degrees at the high-side of the main power
transformer and is initiated by a non-fault switching event on the transmission system; or
• The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for
longer than 2 seconds.
3 Includes no tripping associated with phase lock loop loss of synchronism; additionally, individual inverter or turbine tripping is not allowed.
ERCOT also recommends that Requirement R2, Part 2.1 and the surrounding language be reviewed and revised to clarify that the facility should
continue to deliver the pre-disturbance level of current as appropriate, since power depends on voltage. In principle, during a disturbance active power
should only reduce proportionally to voltage such that active current is consistent unless needed for frequency response. Reactive current should
adjust as needed to support voltage (lead or lag as appropriate) up to its current limits. In general, the Requirement should neither incentivize entities to
undersize inverters/converters nor impose onerous requirements to oversize this equipment. This lack of clarity may cause issues in enforcing this
requirement and miss the reliability objective.
In addition, requiring a facility to deliver reactive power “according to its controller settings” is impractical and misses the objective. The requirement
should be to ensure the proper response performance, as each facility operates according to its controller settings, even if those settings happen to be
incorrect.
To address these issues, ERCOT recommends that the following portions of Requirement R2 be revised to read as follows:
R2. Each Generator Owner or Transmission Owner shall ensure the design and operation is such that the voltage performance for each facility adheres
to the following during a voltage excursion, unless a documented equipment limitation exists in accordance with Requirement R4. [Violation Risk Factor:
High] [Time Horizon: Operations Assessment]
2.1.1 Continue to deliver the pre‐disturbance level of active current, unless a different level of current is needed for frequency response.
2.1.2 Continue to deliver reactive current up to its reactive current limit, as appropriate to control voltage to within normal System Voltage Limits.
2.1.3 If the facility cannot meet 2.1.1 and 2.1.2 due to an apparent, active, or reactive current limit, when the applicable voltage is below .95 per unit and
still within the continuous operation region, then preference shall be given to active or reactive current as well as allowed levels of reduction,
according to the Transmission Planner, Planning Coordinator, Reliability Coordinator, and Transmission Operator requirements.
2.6 Individual dispersed power producing resources must Ride-Through.
ERCOT appreciates the SDT’s work on the purpose statement and believes that the purpose statement can be further clarified and simplified if it is
revised to place the focus on PRC-029-1’s intended effect of ensuring the units and facilities ride-through and perform as expected instead of focusing
on “adhering” to requirements.
To achieve this objective, ERCOT recommends that the purpose statement be revised to read as follows: “To ensure that Inverter‐Based Resources
(IBRs) ride‐through, during and after, defined frequency and voltage excursions while performing operationally as expected to support the Bulk-Power
System (BPS).”
ERCOT is aware of an overarching concern that the RoCoF and phase angle jump requirements may be difficult to enforce for partial IBR tripping.
Addressing this concern may be a matter of coordination of DFRs. If individual IBR units trip but the plant does not, DFRs may not trigger. PMUs
would most likely not be fast enough to record the frequency or angle changes to validate performance. The appropriate NERC standard development
teams should coordinate with each other to ensure that individual IBR unit trips trigger DFR recording.
ERCOT requests that the drafting team remove or provide additional explanation regarding the six-month gap between the PRC-028 effective date and
the PRC-029 effective date in the Implementation Plan.
ERCOT also requests that the Implementation Plan be revised to clarify what constitutes being “in operation” (unit synchronization, full commercial
operations, or some other milestone) for purposes of determining whether an IBR may be considered for a potential exemption under the
Implementation Plan.
ERCOT encourages the SDT to review Requirement R4 and the Implementation Plan in their entirety and revise them as necessary to ensure they
align with the directives regarding constraints and exemptions that FERC included in its recent Order on EOP-012-2 in Docket No. RD24-5-000. Each
limitation should be confirmed before it is allowed to go into effect. ERCOT opposes the SDT’s broad approach of allowing exemptions without some
level of confirmation of the impact of the exemption, such as an evaluation of the reliability impact of the exemption by a PC, RC, TP, or TOP. ERCOT
believes that it is important for reliability to specifically require that limitations be modeled and provided to the PC/RC/TP/TOP. This is important enough
that it should be explicitly referenced in the standard and should be required if a limitation is to be allowed/confirmed. Otherwise, the PC/RC/TP/TOP
will receive limitations that cannot be modeled. A description of a limitation may not allow assessments and may limit determination studies that can be
performed, resulting in a gap that reliability entities are expected to address, when the burden should be on generator owners to remove the limitation or
improve the model fidelity. ERCOT believes the SDT’s proposed approach misses the objective of FERC’s directive that the RC/PC/TP/TOP should
ensure that reliability is maintained while any allowed exemptions are in effect. PRC-029-1 should incentivize facility owners to explore whether less
expensive upgrades can remove limitations rather than passing the burden of unmodeled limitations onto reliability entities that do not have the means
to secure the system against limitations they cannot model properly.
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Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Introduction
The Electric Power Research Institute (EPRI)1 respectfully submits these comments (This Response) in response to North American Electric Reliability
Corporation (NERC)’s request for formal comment on Project 2020-02 Modifications to PRC-024 (Generator Ride-through), issued on June 18, 2024.
EPRI closely collaborates with its members inclusive of electric power utilities, Independent System Operators (ISOs), and Regional Transmission
Organizations (RTOs), as well as numerous other stakeholders, domestically and internationally. In its role, EPRI conducts independent research and
development relating to the generation, delivery, and use of electricity for public benefit by working to help make electricity more reliable, affordable
and environmentally safe. EPRI’s comments on this topic are technical in nature based upon EPRI’s research, development, and demonstration
experience over the last 50 years in planning, analyzing, and developing technologies for electric power.
EPRI research and technology transfer deliverables are generally accessible on its website to the public, either for free or for purchase, and
occasionally subject to licensing, export control, and other requirements.2 The publicly available and free-of-charge milestone reports from a U.S.
Department of Energy (DOE)- and EPRI member-funded research project, Adaptive Protection and Validated Models to Enable Deployment of High
Penetrations of Solar PV (“PV-MOD”), substantiate many of the comments made in This Response.3
While not a standards development organization (SDO) itself, EPRI conducts research and demonstration projects in relevant areas as well as
facilitates knowledge transfer and collaboration that SDOs may, at times, use to inform technical and regulatory standards development, such as in
Institute of Electrical and Electronics Engineers (IEEE), International Electrotechnical Commission (IEC), International Council on Large Electric
Systems (CIGRE), and NERC.4
EPRI’s comments in This Response address reliability and NERC’s draft PRC-029 Reliability Standards for IBRs ride-through requirements developed
under project 2020-02. All comments are aimed at providing independent technical information to respond to the draft published by NERC based on
EPRI’s research and development results and associated staff expertise and do not necessarily reflect the opinions of those supporting and working
with EPRI to conduct collaborative research and development. Where appropriate, EPRI’s comments do not only address the specific questions of
the NOPR but also related scope that may help to inform a final order. Some of EPRI’s comments presented in This Response have also been
submitted in response to the previous Federal Energy Regulatory Commission’s (FERC) Notice of Proposed Rulemaking (NOPR) to direct North
American Electric Reliability Corporation (NERC) to develop Reliability Standards for inverter-based resources (IBRs) that cover data sharing, model
validation, planning and operational studies, and performance requirements (RM22-12), issued on November 17, 2022.
EPRI also submitted comments on the initial draft of PRC-029 which was issued on March 27, 2024. This 2nd set of EPRI comments supports the same
direction as the previously submitted comments and offers a technical analysis based on the latest “Draft 2”.5
Conclusion
EPRI appreciates the opportunity to provide NERC with its technical recommendations and comments on these important topics related to Reliability
Standards for IBRs. EPRI looks forward to working with its members, NERC, and other stakeholders on providing further independent technical
information on these important questions.
1 EPRI is a nonprofit corporation organized under the laws of the District of Columbia Nonprofit Corporation Act and recognized as a tax-exempt organization under Section
501(c)(3) of the U.S. Internal Revenue Code of 1996, as amended, and acts in furtherance of its public benefit mission. EPRI was established in 1972 and has principal offices and
laboratories located in Palo Alto, Calif.; Charlotte, N.C.; Knoxville, Tenn.; and Lenox, Mass. EPRI conducts research and development relating to the generation, delivery, and use of
electricity for the benefit of the public. An independent, nonprofit organization, EPRI brings together its scientists and engineers as well as experts from academia and industry to help
address challenges in electricity, including reliability, efficiency, health, safety, and the environment. EPRI also provides technology, policy and economic analyses to inform long-range
research and development planning, as well as supports research in emerging technologies.
2 https://www.epri.com (last accessed, April 22, 2024)
3
PV-MOD Project Website. EPRI. Palo Alto, CA: 2024. [Online] https://www.epri.com/pvmod (last accessed, April 22, 2024)
4 For transparency, we would like to disclose that EPRI collaborates with other organizations such as IEEE, IEC, CIGRE, and NERC; however, EPRI is not a regulatory- or standardsetting organization. EPRI research is often considered in the development of recommendations, guidelines, and best practices that are not determinative.
5 https://www.nerc.com/pa/Stand/Pages/Project_2020-02_Transmission-connected_Resources.aspx
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Wes Baker - Silicon Ranch - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
General
The SDT should consider specifying the grid conditions to which the ride-through requirements apply. The conditions should be bounded to some
degree as the GO does not know the details of the transmission system and the range of operating conditions over the entire life of the plant.
R1
PRC-029 does not have an exception for transient overvoltage. This implies that the plant must ride through an unbounded transient voltage
magnitude, which is unreasonable. Power electronic devices are sensitive to voltage and current. Equipment vendors and plant designers need to
have clear performance requirements to design their equipment and plants to meet and be able to protect their equipment from damage when
conditions are outside of these performance requirements. The SDT should consider adding an exception for transient overvoltage similar to IEEE
2800-2022 Clause 7.2.
R2
R2.1
Requirements for operating within the continuous operating range do not seem to be in scope with a ride-through standard. Additionally, these
requirements are incomplete if the SDT intends to specify how the plant shall perform when voltage and frequency are within the continuous
operating range. The SDT should consider removing R2.1.
R2.2
•
•
•
Given that this requirement is at the IBR plant level, it is unclear how 'maximum capability' is defined. The SDT should consider clarifying in the
standard what the IBR plant's 'maximum capability’technically refers to.
During a mandatory operating range, it is more appropriate to use 'current' rather than 'power' since power is a function of voltage. The SDT
should replace all references to 'power' with 'current' for voltage outside the continuous operating range.
The response of the IBR during HVRT and LVRT is typically dictated by the inverterlevel control based on inverter terminal voltage. The
inverter does not have information about the high side of the main power transformer voltage at the required time scale. Additionally, there
are multiple transformers with different winding configurations (e.g., delta, wye, wye-grounded) between the POI/POM where the PRC-029
requirement applies and the inverter terminal where the control is implemented. Using positive and negative sequence reactive current
consistent with IEEE 2800-2022 Clause 7.2 is more practical than the 'affected phases.' The key is that the IBR should regulate the positive
sequence and negative sequence voltage. This is the resulting effect of the IBR injecting positive and negative sequence reactive current
based on positive and negative sequence voltage, /’;’[‘respectively, and is consistent with how a synchronous machine naturally responds to
asymmetrical disturbance. The SDT should consider making the current injection requirements applicable at the inverter terminal and based
on sequence components consistent with IEEE 2800-2022 Clause 7.2.
R2.3.1
The use of 'positive sequence voltage' with respect to the continuous and mandatory operating range is not consistent with the rest of the standard
which uses max/min of phase-phase or phase-ground fundamental frequency RMS voltage. For consistency, the SDT should change positive sequence
voltage to max/min of phase-phase or phase-ground fundamental frequency RMS voltage.
R2.4
The requirement, as written, may not be practical for assessing compliance/noncompliance for the GO. The voltage at the IBR plant would also
depend on the grid, including neighboring plants. Therefore, the IBR plant itself is unlikely to cause the plant to exceed the high voltage thresholds but
certainly may contribute to the overvoltage. The SDT should consider removing this requirement and lumping it together with R2.2, adding
requirements to the response time consistent with IEEE 2800-2022 Clause 7.2. If the IBR actively regulates the positive and negative sequence voltage
quickly, the effect is as desired and can be readily assessed for compliance.
R3
The frequency ride-through requirements are much more stringent than IEEE 2800-2022 Clause 7.3. The SDT should provide more justification,
beyond what is described in the Technical Rationale, as to why this range of frequency ride-through is required. Additionally, the SDT should ensure
that due diligence has been done with vendors of the various equipment to ensure that this requirement is reasonable, and achievable with available
technology.
Attachment 1
Tables 1 and 2 and numbered item 8
By using voltage bands (e.g., 0.7 <= V < 0.9) and time durations this results in a much more stringent requirement than IEEE 2800-2022 Clause 7. The
SDT should consider removing the voltage bands to align with IEEE 2800-2022 Clause 7. Take this example where the red is a fictitious voltage plot:
Comparison of standards:
• IEEE 2800 Clause 7:
o V < 0.9 pu ~ 8 seconds
o V < 0.7 pu ~ 3 seconds
o There is not an interpretation where the IBR has to ride through this LVRT in
IEEE 2800 Clause 7.
• PRC029 :
o 0.7 <= V < 0.9 pu ~ 5 seconds.
o 0.5 <= V < 0.7 pu ~ 3 seconds.
o PRC-029 as written implies the IBR has to ride-through.
Numbered item 11
The standard should not specify how protection functions must be implemented. Instead, it should describe the required performance. Further, this
requirement implies that the plant must ride through an unbounded voltage magnitude, which is not reasonable. As written, this item does not allow
for tripping caused by excessive transient over-voltage (TOV) events. Power electronic devices are sensitive to voltage and current. Equipment
vendors and plant designers need to have clear performance requirements to design their equipment and plants to meet and be able to protect their
equipment from damage when conditions are outside of these performance requirements
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Comments received from LG&E/KU
Questions
2. Provide any additional comments for the Drafting Team to consider, if desired.
Comments:
All comments below pertain to PRC-029-1.
LG&E/KU agrees with the applicability concerns of EEI and suggests removing TOs and VSC-HVDC systems from this standard.
LG&E/KU also agrees with EEI that the requirements listing the TP, PC, RC, or TOP should clarify responsibility and include the responsible entity in the
applicability of this standard. Alternatively, these listings may be sufficiently replaced with a requirement to adhere to applicable Facility interconnection
requirements (e.g., “preference shall be given to active or reactive power according to applicable Facility interconnection requirements”).
The following additional comments are provided:
Requirement R1
Footnote 3 in Requirement R1 is unnecessary as the term “Ride-through” includes remaining synchronized.
The following edit should be made to Requirement R1 to clarify responsibility is only for Facilities (note “Facility” is a NERC defined term and should be
capitalized) under the responsible entities ownership:
… shall ensure the design and operation is such that each of its IBR Facilities facility adheres to Ride-through requirements, in accordance with the “must
Ride-through3 zone” as specified in Attachment 1, except for …
The following edit is suggested for bullet 1 under Requirement R1:
The facility IBR Facility needed to electrically disconnects in order to clear a fault; or
Measure M1
Measure M1 adds to the scope of Requirement R1. Measures should only describe how compliance with the associated Requirement will be assessed,
not add to the scope of the Requirement itself. For example, Measure M1 strongly suggests that “dynamic simulations” and “studies” are the only
acceptable forms of evidence for determining ride-through capability. However, Requirement R1 does not have any explicit requirement to perform
analysis.
Measure M1 also states disturbance monitoring data is required to demonstrate adherence to Ride-through requirements. It is unclear what is required
here since IBR Facilities will be online and operating normally most of the time. The most recent draft of PRC-030-1 already includes requirements for
analyzing “Ride-through performance” in situations where the IBR Facility significantly reduces active power output (which would include tripping). It is
more appropriate to analyze failed Ride-through than it is to provide immense quantities of data showing the IBR Facility is operating normally.
Measure M1 references only one of the exceptions listed under Requirement R1.
The following edit is suggested for Measure M1 (responsibility issues should also be addressed, as noted previously):
Each Generator Owner and Transmission Owner shall have evidence of dynamic simulations, studies, or other evidence to demonstrate that the design
and operation of each of its IBR Facilities facility will adheres to the Ride-through requirements, as specified in Attachment 1Requirement R1. Each
Generator Owner and Transmission Owner have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance
Recorder, and Fault Recorder) to demonstrate that the operation of each facility did adhere to Ride-through requirements, as specified in Requirement
R1. If the Generator Owner and Transmission Owner choose to utilize If failed Ride-through occurs for conditions exempted in Requirement R1
exemptions that occur within the “must Ride-through zone” and are caused by non-fault initiated phase jumps of greater than 25 electrical degrees,
then each Generator Owner and Transmission Owner shall also have evidence of the conditions actual disturbance monitoring (i.e. Sequence of Event
Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate that the facility failed to Ride-through during a phase jump of
greater than or equal to 25 electrical degrees, and documentation from their Transmission Planner, Reliability Coordinator, Planning Coordinator, or
Transmission Operator that a non-fault initiated switching event occurred.
Requirement R2
Requirement R2 addresses performance during the Ride-through conditions of Requirement R1 and should establish a clear link. There is also
inconsistency in that Requirement R2 only exempts documented equipment limitations and none of the other exemptions in Requirement R1. The
following edit is suggested for Requirement R2:
… shall ensure the design and operation is such that of the voltage performance for of its IBR Facilities each facility adheres to the following during
conditions requiring Ride-through a voltage excursion, unless a documented equipment limitation exists in accordance with Requirement R14.
Each part of Requirement R2 refers to the “voltage at the high-side of the main power transformer”. Attachment 1 already states in item (6) that the
applicable voltage is at the high-side of the main power transformer. Thus, each part of Requirement R2 should be condensed as follows:
While the voltage at the high-side of the main power transformer remains wWithin the continuous operation region as specified in Attachment 1, each
facility IBR Facilities shall:
Requirement R2 part 2.1.2 should be removed. Delivering reactive power “up to its reactive power limit and according to its controller settings” wouldn’t
appear to be anything other than normal operation.
Requirement R2 part 2.1.3 is clearly intended to mirror a similar requirement in IEEE 2800-2022 subclause 7.2.2.2. However it makes two errors, and
unnecessarily restates the voltage is in the continuous operating region (Requirement R2 part 2.1 already includes this condition). Correct as follows:
If the IBR Facility facility cannot deliver both active and reactive power due to a current limit or reactive apparent power limit, when the voltage is
below 0.95 per unit and still within the continuous operation region, then preference shall be given to active or reactive power according to
requirements if required by of the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
It is understood that the DT had “apparent power limit” in the first draft of this standard and has now replaced it with “reactive power limit” following
comments. However, this is an error. The apparent power limit is a limit of the inverter and not the PPC as suggested in some of the comments. IEEE
2800-2022 correctly states the limit is “apparent” power. I.e., an inverter has an MVA limit and there may be times when the inverter is called on to
produce more total MVA (MW and MVAR) than it is able to. It is in this case that the inverter must prioritize MW or MVAR.
The language of Requirement R2 part 2.2 is unnecessarily confusing. Attachment 1 already indicates the boundaries of the mandatory operating region
and they are delineated by RMS voltages. Suggested simplification and clarification:
While voltage at the high-side of the main power transformer is wWithin the mandatory operation region as specified in Attachment 1, each an IBR
Facility shall continue to exchange current, up to the its maximum limit capability to and provide voltage support., on the affected phases during both
symmetrical and asymmetrical voltage disturbances, either under6:• IBR Facilities shall operate in Rreactive power priority by default;, or• in Aactive
power priority if required by the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
Footnote 6 is unnecessary for this standard. Entities that wish to specify the magnitude of current injections during disturbances should do so in their
Facility Interconnection Requirements.
Suggesting the following simplification of Requirement R2 part 2.3.1:
If an IBR Facility facility enters current blocking mode, it shall restart current exchange in less than or equal to five cycles of positive sequence voltage
returning to the a continuous operation region or mandatory operation region.
Suggesting the following simplification of Requirement R2 part 2.5:
Each facility IBR Facilities shall restore active power output to the pre-disturbance or available level (, whichever is lesser), within 1.0 second when the
voltage at the high-side of the main power transformer upon returnings from the mandatory operation region or permissive operation region (including
operating in current block mode), to the continuous operating region as specified in Attachment 1, unless the Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator specifies otherwise requires a lower post-disturbance active power level requirement or
requires a different post-disturbance active power restoration time.
Footnote 7 introduces confusion as it pertains to “frequency excursions” which is taken to mean conditions necessitating Ride-through. In this case,
Requirement R3 and R4 would apply. Suggesting removal of this footnote.
Requirement R3
Suggesting the following simplification of Requirement R3 (to align with suggestions for Requirement R1):
… shall ensure the design and operation is such that each facility of its IBR Facilities adheres to Ride-through requirements during a frequency excursion
event whereby the System frequency remains within the “must Ridethrough zone” according to specified in Attachment 2 and when the absolute rate of
change of frequency (RoCoF)8 magnitude is less than or equal to 5 Hz/second.
Measure M3
Measure M3 oversteps Requirement R3 similar to the M1/R1 discussion above. Suggested revision:
Each Generator Owner and Transmission Owner shall have evidence of dynamic simulations, studies, or other evidence to demonstrate that the design
and operation of each of its IBR Facility facility will adheres to the Ride-through requirements, as specified in Attachment 2 Requirement R3. Each
Generator Owner and Transmission Owner also have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance
Recorder, and Fault Recorder) data to demonstrate the operation of each facility did adhere to If failed Ride-through requirements, as specified in
Requirement R3, during each frequency excursion event measured at the high-side of the main power transformer occurs for RoCoF magnitude greater
than 5 Hz/second, each Generator Owner and Transmission Owner shall have evidence of the condition.
Requirement R4
Requirement R4 is unwisely linked to the effective date of PRC-029-1. This makes sense at the initial effective date, but it excludes IBR Facilities that
come in-service after the effective date. Further, it doesn’t address failure to meet frequency Ride-through requirements. It appears to unnecessarily call
out hardware limitations when software limitations can also be problematic. Finally, it seems to imply an exemption process exists but does not say who
can grant an exemption or what the requirements for exemption are (e.g., is it subject to approval of the technical documentation?). The following
revision is suggested:
If a Each Generator Owner and Transmission Owner identifiesying one of its IBR Facilities facility that is in-service by the effective date of PRC-029-1, has
known hardware limitations that prevent the facility from meeting voltage the Ride-through requirements criteria as detailed in of Requirements R1, R2,
and or R32, and requires an exemption from specific voltage Ride-through criteria the Generator Owner shall:
Below are suggested edits in various parts of Requirement R4 to align with the body of R4 suggested above:
(4.1) Document information supporting the identified hardware limitation no later than 12 months following the effective date of PRC-029-1 after it is
identified.
(4.1.2) Which aspects of voltage or frequency Rride-through requirements that the IBR Facility is would be unable to meet and the capability of the
equipment due to the limitation;
(4.1.4) Supporting technical documentation verifying explaining if the limitation is due to hardware that needs to be physically replaced or that if the
limitation cannot be removed by software updates or setting changes, and;
(4.2) Request an exemption from [whom?] by pProvidinge a copy of the information detailed in Requirement R4.1 to the applicable Planning
Coordinator(s), Transmission Planner(s), Transmission Operator(s), Reliability Coordinator(s), and to the Regional Entity no later than 12 months
following the effective date of PRC-029-1 after the limitation is identified.
(4.2.1) Any response to additional information requested by the applicable Planning Coordinator(s), Transmission Planner(s), Transmission Operator(s),
Reliability Coordinator(s), and to the or Regional Entity shall be provided back to the requestor within 90 days of the request.
(4.3) Each Generator Owner and Transmission Owner with a previously submitted request for exemption that replace the equipment causing corrects
the limitation shall document and communicate such an equipment change the correction to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s) within 90 days of the correction equipment change.
(4.3.1) When existing equipment is replaced an exempted Ride-through limitation is corrected, the exemption for that Ride-through criteria no longer
applies.
Much of Requirement R4 concerns an exemption process which is poorly defined. Other standards, including others currently being developed for IBRs
due to FERC directives, have utilized language requiring “Corrective Action Plans” for certain failures. The DT should consider if alignment with these
standards is appropriate and should revisit the scope of the SAR for this project. Regardless, the DT must address several key issues that it has created by
introducing the exemption language:
• Who grants the exemption?
• How long does the approving entity have to grant or deny an exemption?
• Is an IBR Facility out of compliance if it has requested an exemption but the exemption has not yet been granted?
• Is there still a requirement to fix the issue if you have an exemption?
• What if an IBR Facility is unable to meet the Ride-through requirements without a significant investment (e.g., replacing every inverter with new
models)?
Measure M4
Measure M4 should be substantially revised to reflect the concerns addressed in the comments above.
Attachment 1
Regarding Table 1 of Attachment 1, row 2 appears to use the incorrect operator and should be corrected as follows: “≤ 1.20 and > 1.1”.
Row 4 of Table 1 and Table 2 lists “Continuous” as a time where “∞” would be more appropriate.
It is recommended to remove footnotes 12 and 14 and place “May Ride-through Zone” directly into the table, e.g., “N/A (May Ride-through Zone)”.
Item (2)(b) of Attachment 1 references “hybrid plants consisting of photovoltaic (PV) and BESS” but does not address hybrid plants with other
components. Item (4) says Table 2 applies to hybrid facilities with no wind. IEEE 2800-2022 clarifies that it does not apply to synchronous components of
hybrid plants. PRC-029-1 needs to be more careful in its wording regarding hybrid plants.
Item (6) of Attachment 1 defines the applicable voltage as the high-side of the MPT and does not give the PC/TP/TO/etc. any flexibility to change that.
Some entities with IEEE 2800-2022 requirements have adjusted the Reference Point of Applicability for Ride-through to the POI for various reasons
(including that they may install monitoring equipment at that location rather than at the MPT). PRC-029-1 should not remove the flexibility of
PC/TP/TO/etc. to alter the point of applicability.
Figure 1 of Attachment 1 uses the old “No-Trip Zone” label which is not used anywhere else in PRC-029-1.
Attachment 2
Regarding Table 3 of Attachment 2, “May trip” on rows 1 and 9 should be replaced with “N/A” for consistency with Table 1 and Table 2. It is unclear why
the frequency values are unaligned (and exceed) IEEE 2800-2022 when the voltage Ride-through requirements of PRC-029-1 are aligned with IEEE 28002022. It is not prudent to exceed the requirements of IEEE 2800-2022 when 1) it already significantly exceeds PRC-024-3, and 2) it is recognized as an
industry standard for utilities, developers, OEMs, etc.
Rows 5 and 6 of Table 3 have incorrect operators and row 6 includes an incorrect number (58.8 instead of 58.5).
Finally, item (1) of Attachment 2 defines the applicable frequency at the high-side of the MPT and does not give the PC/TP/TO/etc. any flexibility to
change that. As noted above, some entities with IEEE 2800-2022 based requirements use the POI as the RPA for Ride-through capability.
Response
Consideration of Comments
Project Name:
2020-02 Modifications to PRC-024 (Generator Ride-through) | Draft 2
Comment Period Start Date:
6/18/2024
Comment Period End Date:
7/8/2024
Associated Ballot(s):
2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan AB 2 OT
There were 63 sets of responses, including comments from approximately 138 different people from approximately 91 companies
representing 7 of the Industry Segments as shown in the table on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, let us know immediately. Our goal is to give every comment serious consideration in this
process. If you feel there has been an error or omission, contact Manager of Standards Information, Nasheema Santos (via email) or at (404) 4462564.
RELIABILITY | RESILIENCE | SECURITY
Questions
1. Provide any comments for the drafting team to consider, if desired.
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
2
Organization
Name
MRO
Name
Segment(s)
Anna Martinson 1,2,3,4,5,6
Region
MRO
Group
Name
MRO Group
Group Member
Name
Shonda McCain
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Omaha Public
Power District
(OPPD)
Michael Brytowski Great River
Energy
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
1,3,5,6
MRO
1,3,5,6
MRO
Jamison Cawley
Nebraska Public 1,3,5
Power District
MRO
Jay Sethi
Manitoba
Hydro (MH)
1,3,5,6
MRO
Husam Al-Hadidi
Manitoba
1,3,5,6
Hydro (System
Preformance)
MRO
Kimberly Bentley
Western Area
Power
Adminstration
1,6
MRO
Jaimin Patal
Saskatchewan
Power
Coporation
(SPC)
1
MRO
George Brown
Pattern
Operators LP
5
MRO
Larry Heckert
Alliant Energy
(ALTE)
4
MRO
Terry Harbour
MidAmerican
Energy
Company
(MEC)
1,3
MRO
3
Organization
Name
WEC Energy
Group, Inc.
California ISO
Name
Christine Kane
Segment(s)
Region
3
Darcy O'Connell 2
Group
Name
WEC Energy
Group
WECC
ISO/RTO
Council (IRC)
Standards
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
Group Member
Name
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Dane Rogers
Oklahoma Gas 1,3,5,6
and Electric
(OG&E)
MRO
Seth Shoemaker
Muscatine
1,3,5,6
Power & Water
MRO
Michael Ayotte
ITC Holdings
MRO
Andrew Coffelt
Board of Public 1,3,5,6
Utilities- Kansas
(BPU)
MRO
Peter Brown
Invenergy
MRO
Angela Wheat
Southwestern 1
Power
Administration
MRO
Bobbi Welch
Midcontinent
ISO, Inc.
2
MRO
Christine Kane
WEC Energy
Group
3
RF
Matthew Beilfuss WEC Energy
Group, Inc.
4
RF
Clarice Zellmer
WEC Energy
Group, Inc.
5
RF
David Boeshaar
WEC Energy
Group, Inc.
6
RF
Ali Miremadi
California ISO
2
WECC
Gregory Campoli
New York
Independent
2
NPCC
1
5,6
4
Organization
Name
Name
Segment(s)
Region
Group
Name
Group Member
Name
Review
Committee
FirstEnergy FirstEnergy
Corporation
Mark Garza
4
FE Voter
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
System
Operator
John Pearson
ISO New
England, Inc.
2
NPCC
Helen Lainis
Independent
Electricity
System
Operator
2
NPCC
Elizabeth Davis
PJM
2
Interconnection
RF
Charles Yeung
Southwest
Power Pool,
Inc.
2
MRO
Bobbi Welch
Midcontinent
ISO, Inc.
2
RF
Kennedy Meier
Electric
Reliability
Council of
Texas, Inc.
2
Texas RE
Julie Severino
FirstEnergy FirstEnergy
Corporation
1
RF
Aaron
Ghodooshim
FirstEnergy FirstEnergy
Corporation
3
RF
Robert Loy
FirstEnergy FirstEnergy
Solutions
5
RF
5
Organization
Name
Austin Energy
Southern
Company Southern
Company
Services, Inc.
Name
Segment(s)
Region
Michael Dillard 5
Pamela Hunter 1,3,5,6
Group
Name
Group Member
Name
Mark Garza
FirstEnergyFirstEnergy
1,3,4,5,6
RF
Stacey Sheehan
FirstEnergy FirstEnergy
Corporation
6
RF
Austin Energy
5
Texas RE
Lovita Griffin
Austin Energy
3
Texas RE
Tony Hua
Austin Energy
4
Texas RE
Imane Mrini
Austin Energy
6
Texas RE
Thomas Standifur Austin Energy
1
Texas RE
Matt Carden
Southern
Company Southern
Company
Services, Inc.
1
SERC
Joel Dembowski
Southern
3
Company Alabama Power
Company
SERC
Ron Carlsen
Southern
Company Southern
Company
Generation
6
SERC
Leslie Burke
Southern
Company Southern
5
SERC
Austin Energy Michael Dillard
SERC
Southern
Company
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
6
Organization
Name
Name
Segment(s)
Region
Group
Name
Group Member
Name
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Company
Generation
DTE Energy
Black Hills
Corporation
Patricia Ireland 4
Rachel Schuldt 6
Dominion Sean Bodkin
Dominion
Resources, Inc.
6
DTE Energy
Patricia Ireland
DTE Energy Detroit Edison
4
RF
Karie Barczak
DTE Energy Detroit Edison
Company
3
RF
Adrian Raducea
DTE Energy Detroit Edison
Company
5
RF
Black Hills
Micah Runner
Corporation All Segments Josh Combs
Black Hills
Corporation
1
WECC
Black Hills
Corporation
3
WECC
Rachel Schuldt
Black Hills
Corporation
6
WECC
Carly Miller
Black Hills
Corporation
5
WECC
Sheila Suurmeier
Black Hills
Corporation
5
WECC
Connie Lowe
Dominion 3
Dominion
Resources, Inc.
NA - Not
Applicable
Lou Oberski
Dominion 5
Dominion
Resources, Inc.
NA - Not
Applicable
Dominion
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
7
Organization
Name
Name
Western
Electricity
Coordinating
Council
Steven
Rueckert
Tim Kelley
Tim Kelley
Segment(s)
Region
10
Group
Name
WECC
WECC
SMUD and
BANC
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
Group Member
Name
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Larry Nash
Dominion 1
Dominion
Virginia Power
NA - Not
Applicable
Rachel Snead
Dominion 5
Dominion
Resources, Inc.
NA - Not
Applicable
Steve Rueckert
WECC
10
WECC
Curtis Crews
WECC
10
WECC
Nicole Looney
Sacramento
Municipal
Utility District
3
WECC
Charles Norton
Sacramento
Municipal
Utility District
6
WECC
Wei Shao
Sacramento
Municipal
Utility District
1
WECC
Foung Mua
Sacramento
Municipal
Utility District
4
WECC
Nicole Goi
Sacramento
Municipal
Utility District
5
WECC
Kevin Smith
Balancing
Authority of
Northern
California
1
WECC
8
Organization
Name
Associated
Electric
Cooperative,
Inc.
Name
Todd Bennett
Segment(s)
3
Region
Group
Name
AECI
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
Group Member
Name
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Michael Bax
Central Electric 1
Power
Cooperative
(Missouri)
SERC
Adam Weber
Central Electric 3
Power
Cooperative
(Missouri)
SERC
Gary Dollins
M and A
Electric Power
Cooperative
3
SERC
William Price
M and A
Electric Power
Cooperative
1
SERC
Olivia Olson
Sho-Me Power 1
Electric
Cooperative
SERC
Mark Ramsey
N.W. Electric
Power
Cooperative,
Inc.
1
SERC
Heath Henry
NW Electric
Power
Cooperative,
Inc.
3
SERC
Tony Gott
KAMO Electric
Cooperative
3
SERC
Micah Breedlove
KAMO Electric
Cooperative
1
SERC
9
Organization
Name
Name
Segment(s)
Region
Group
Name
Group Member
Name
Brett Douglas
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Northeast
Missouri
Electric Power
Cooperative
1
SERC
Skyler Wiegmann Northeast
Missouri
Electric Power
Cooperative
3
SERC
Mark Riley
Associated
Electric
Cooperative,
Inc.
1
SERC
Brian Ackermann
Associated
Electric
Cooperative,
Inc.
6
SERC
Chuck Booth
Associated
Electric
Cooperative,
Inc.
5
SERC
Jarrod Murdaugh
Sho-Me Power 3
Electric
Cooperative
SERC
10
1. Provide any comments for the drafting team to consider, if desired.
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
The R1, R2, and R3 design requirement is problematic because of at least two major issues: dynamic modeling deficiencies and lack of standardized
test procedures. IBR dynamic modeling is well proven to be deficient in representing performance of equipment in the field, particularly disturbance
ride-through performance, and even though MOD-026-2 is addressing model verification/validation, it is still only post-interconnection (or postcommissioning). What is needed here is to expand the scope of MOD-026-2 to also encompass pre-interconnection model verification/validation so
that “simulations” and “studies” on IBR plant models evaluating the plant designs are performed on verified and validated dynamic models ahead of
interconnection. Secondly, without well-defined, standardized test procedures to assess ride-through capability, there is little possibility that
simulations and studies on IBR designs will result in uniform across-the-board assurance that IBR equipment and plant designs adequately adhere to
the PRC-029 ride-through requirements. Completion of IEEE 2800.2, which is intended to define the necessary testing and verification procedures,
and selective consideration and use of its content in PRC-029 is necessary just as 2800 itself has been instrumental in formulating the mandatory ridethrough requirements in PRC-029. Without dynamic model verification/validation and well-defined, standardized test procedures, the design
components of R1, R2, and R3 will not achieve the desired outcome and will only result in confusion as to what evidence is actually required from GOs
and TOs.
Need to indicate in association with R1 third bullet that momentary current blocking is an acceptable means of reacting to non-fault initiated phase
jumps greater than 25 degrees.
There is inconsistency throughout the document in instances of both “TO and GO” and “TO or GO”. Please resolve the inconsistencies.
Please clarify what “other evidence” in M1, M2, and M3 would be acceptable to assure compliance. Please also reinsert “shall” in M1, M2, and M3
where it has been removed (to read “Each GO and TO shall have evidence…”). The sentences are not complete without it and measures in other
standards (such as PRC-024-4) read that way.
Figures 1 and 2 in Attachment 1 should be better aligned. One has a log scale on the horizontal axis and the other is linear. There is no valid reason for
these differences, and we recommend they be consistent in the axes used. The only difference between them should be the slight difference in the
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
11
lower boundary of the must ride-through zone reflecting the slight difference between Attachment 1 tables 1 and 2.
There needs to be an exemption for system-related causes of ride-through failure. IBRs should be exempt from ride-through requirements in R1
through R3 if tripping or failure to ride through is attributable to any of the following:
1. Sub-synchronous control interaction or ferro-resonance involving series compensation confirmed by the TOP, RC, TP, or PC
2. Unstable behavior of other nearby IBRs or dynamic devices such as FACTS or HVDC confirmed by the TOP, RC, TP, or PC
3. System short circuit levels during contingencies below the level of IBR stable operation confirmed by the TOP, RC, TP, or PC
4. System-level transient or oscillatory instabilities confirmed by the TOP, RC, TP, or PC
R 2.1.3 should be .95 per unit (with a decimal point) rather than 95 per unit.
Likes
0
Dislikes
0
Response
Thank you for your comments.
Modeling: The team agrees that the other items noted are essential but that those are within the scope of other 901 related projects and not part of
PRC-029.
R1: the bullets under R1 are listed as possible exemptions and are not required to be used for any events
TO: Transmission Owner has been removed from PRC-029.
Measures: Measure M1 is written to provide specific evidence to be used as examples. “Other evidence” is included to provide entities additional
flexibility in how to comply. The word “shall” has been re-inserted.
Attachment 1: The logarithmic scale has been removed from Figure 1.
R2.1.3: 95 pu has been corrected to 0.95 pu.
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company, 3, 1, 5;
Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Document Name
Comment
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
12
1)
Editorial suggestions BOLD and ITALICS for the Measures in below
2) In PRC-029, standard as follows:
4.2 Facilities:
4.2.1. BEPS inverter‐based resources(2)
(2)For the purpose of this standard, “inverter‐based resources” refers to a collection of individual solar photovoltaic (PV), Type 3 and Type 4 wind
turbines, battery energy storage system (BESS), or fuel cells that operate as a single plant/resource. In case of offshore wind plants connecting via a
dedicated VSC‐HVDC, the inverter‐based resource includes the VSC‐HVDC system.
Question for SDT: Should VSC_HVDC be included even if it’s not associated with a windplant (ie Transbay Cable HVDC)?
M1. Is very clunky, below is my attempt to making it read better.
1}·
Replace have with has.
2}·
Reword per the following:
o Has evidence of dynamic simulations, studies, or other evidence to demonstrate the design of each facility will adhere to Ride‐through
requirements, as specified in Requirement R1. As system conditions allow each Generator Owner and Transmission Owner retain evidence of actual
disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) recorded to demonstrate that the
operation of each facility did adhere to Ride‐through requirements, as specified in Requirement R1. If the Generator Owner and Transmission Owner
choose to utilize Ride‐through exemptions that occur within the “must Ride‐through zone” and are caused by non‐fault initiated phase jumps of
greater than 25 electrical degrees, then each Generator Owner and Transmission Owner also retain evidence of actual disturbance monitoring (i.e.
Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate that the facility failed to Ride‐through during a
phase jump of greater than or equal to 25 electrical degrees, and documentation from their Transmission Planner, Reliability Coordinator, Planning
Coordinator, or Transmission Operator that a non‐fault initiated switching event occurred.
M2 .
Each Generator Owner and Transmission Owner has evidence of dynamic simulations, studies, or other evidence to demonstrate the design of each
facility will adhere to requirements, as specified in Requirement R2. Each Generator Owner and Transmission Owner also retain evidence of actual
disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data demonstrating that the operation
of each facility did adhere to performance requirements, as specified in Requirement R2, during each voltage excursion measured at the high‐side of
the main power transformer. The Generator Owner or Transmission Owner have evidence of receiving such performance requirements, (e.g. email
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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exchange, contract information) if the Transmission Planner, Transmission Operator, Reliability Coordinator, Planning Coordinator has required the
Generator Owner or Transmission Owner to follow performance requirements other than those in Requirement R2 (e.g. ramp rates, reactive power
prioritization).
3) Question for SDT: What does this mean? M3 Same comments as M2.
4) Figure -1 “Voltage ride-through requirement for AC-connected wind” on page 20 does not match Attachment 1 Table-1 on page16 for the
requirement of <1.2 and > 1.1 minimum ride-through time of 1 second.
5)
For PRC-029-1, section B (Requirements and Measures)-
R2- Section 2.2:
In section 2.2, footnote 6: mentions that “In either case and if required, the magnitude of active power and reactive current shall be as specified by the
Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.“
Question/comment for SDT: It has not been mentioned how to identify the magnitude of active power and reactive current, and it seems that
Electromagnetic Transient (EMT) studies should be performed to evaluate each IBR and it will result in a significant amount of extra work for PTO to
receive, evaluate and perform EMT studies.
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Thank you for your comments.
2. The team has removed this footnote and hase been advised to refer to the newly proposed definition for IBR. IBR will include the equipment in this
linkage if it is a dedicated connection to the system. Other VSC-HVDC are not included.
Measures. The team has reinserted the word “shall” into the measures; this is shown as “shall have”. The team also agrees that usage of “retain” is
preferable language and have made this change to all measures.
3. The language related to having evidence of other performance requirements was considered necessary for a situation where an entity receives
requirements from a planner or operator that would contradict PRC-029 requirements. The team included this as a means of allowing the GO to
follow requirements as needed by planners/operators and not be in violation of PRC-029 requirements.
4. Thank you for the concern, the figure 1 has been updated to reflect these changes.
5. This work is only required if the established and active power and reactive power does not meet the system requirement. The level of work
required depends on the system needs. The level of detail in the study should be part of the decision decided by the applicable RC or TP as needed.
Ijad Dewan - Ijad Dewan On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Ijad Dewan
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Answer
Document Name
Comment
The Technical Rationale must include reasons for inclusion of Synchronous Condenser to the standard under the applicability section.
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Response
Thank you for your comment.
A conforming change has been made in the updated Technical Rationale and is consistent with the assigned SAR scope.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Dominion Energy supports EEI’s additional comments.
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Response
Thank you for the response, please see the response to EEI’s comment.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
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FirstEnergy requests the DT consider changing PRC-029-1 Requirement 2 R2.5 from active power to apparent.
Entities may incorporate solar sites that automatically change reactive power to attempt to control voltage similar to FirstEnergy’s sites. This change
will inevitably cause changes in active power post event, such that meeting this requirement as written could be difficult. Since changes in reactive
power are desired for voltage control, the requirement should be changed to allow this response. Using apparent power in the requirement versus
active power is one way to achieve this.
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Response
Thank you for the comment.
Apparent power: the team determined no changes were needed as this requirement subpart is focused on active power restoration.
Requirement R2.5 requires that active power return to the pre-disturbance level when voltage recovers to the continuous operating region, unless
otherwise specified by the TP, PC, RC.
Brian Lindsey - Entergy - 1
Answer
Document Name
Comment
•
M1: This seems more like a requirement than a measure for meeting the requirement.
•
R2, M2, M3 and R4: Duplicative of Mod-026 and MOD-027. Also, seems to be dependent on PRC-028 passing and sites having DDRs installed.
•
R2: is not clear. It seems to overlap significantly with VAR-002.
o
Should that be .95 per unit?
•
R3: No provisions for exemptions for frequency limitations.
•
R4.1 thru 4.2: Are we seeking approval from this large list of entities for an exemption or are we documenting the limitation that prevents
from meeting requirement 1? If we have to get approval there is no requirement in this standard that require any of these entities to provide
that approval.
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o
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Recommend limiting who must be notified to just the TP or TP and RC. There needs to be a single point of contact instead multiple
entities.
0
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Response
Thank you for the comments.
Measure M1: M1 is written to provide specific evidence to be used as examples.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. This is a phased-in implementation plan whereas each entity will be required to respond to the full
requirement over time.
Modeling: The team agrees that the other items noted are essential but that those are within the scope of other 901 related projects and not part of
PRC-029
R2: The team identifies VAR-002 as concerned with voltage set points and bandwidths, and is not specific to disturbance Ride-Through, while
Requirement R2 is concerned with an IBR riding through a disturbance. The team identifies no overlap because the scopes are different for each
requirement.
R2: Agree that the per unit should be 0.95 and not 95.
R3: The exemptions allowable within Order No. 901 are only for some voltage requirements.
R4: Requirement R4 has been modified and footnote added to R4 to clarify acceptance by the CEA. Acceptance by the other entities listed is not
required.
Mark Flanary - Midwest Reliability Organization - 10
Answer
Document Name
Comment
The draft PRC-029-1 includes expectations in R1, R2, and R3 for entities to demonstrate ride-through adherence (R1 & R3) and performance (R2)
through two separate means: 1) dynamics simulations/studies and 2) data from actual system events. These two separate expectations are combined
in each requirement but are not clearly delineated within the requirement text. It is only in the measures associated with each requirement that it
becomes clear that both expectations exist. This lack of clarity leads to concerns about the auditability of this standard.
The Standard should clearly specify during which timeframes and under what conditions an entity is expected to show compliance using
simulations/studies vs. data from actual events. For instance, upon commissioning of a new facility, no event data will be available. Should the CEA
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expect to see a study completed for a new facility prior to commercial operation? For existing facilities with extensive recorded event data is it still
necessary to perform simulations and studies to show compliance? How much event data and how serious must the events be for this to be
acceptable?
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Response
Thank you for your comment.
Implementation Plan: The team agrees that additional clarity was needed for the measurability of these requirements. As such, the implementation
plan includes bifurcated implementation information between capability-based elements and performance-based elements. This is a phased-in
implementation plan whereas each entity will be required to respond to the full requirement over time.
Data retention: disturbances identified by planners and operators within PRC-030 would trigger the request to hold data for demonstrating
performance. Additional data requirements are established within PRC-030
Chantal Mazza - Hydro-Quebec (HQ) - 1 - NPCC
Answer
Document Name
Comment
It is imperative that the standard drafting teams for this project as well as the 2021-04 (PRC-002 and PRC-028) and 2023-02 (PRC-030 vs PRC-004)
assure a coherent way of addressing the inclusion and exclusion of IBRs in current and upcoming standards.
The following comments are applicable to PRC-029-1
The definition for Inverter Based Resource (IBR) was approved by industry in April under Project 2020-06. We do not agree with inserting the
uncapitalized version of IBR into 4.2 Facilities section because it is unbounded and insufficient to identify the Facilities applicable to this Standard, as
required in the Rules of Procedure (Appendix 3a, Standard Processes Manual). Furthermore, these definitions are the foundation of several ongoing
projects in response to FERC Order 901, where FERC “directs NERC to submit new or modified Reliability Standards that address specific matters
pertaining to the impacts of IBRs on the reliable operation of the BPS.”
Chapter A, -Section 4.2.2 What is the “IBR registration criteria”? Please add a footnote to describe it.
Requirement R1: 25degrees, 1.1pu-45s and 1.18pu-2s should be moved to attachment 1 to allow for regional variance.
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Requirement -R2-2.1.3 and B-R2-2.2 Can the TP ask for a mix of active/reactive power based on a predetermined ratio (currently only indicated as
active OR reactive).
Requirement -R3: No exemption exists for existing equipment limitation to meet frequency and ROCOF ride-through? (like R4 for voltage) One should
be added.
Requirement -R3. The 5Hz/s value should be moved to Attachment 2 to allow for a regional variance.
Requirement -R3 The 5Hz/s requirement is already indicated in R1. It should not be repeated.
Requirement -R4: Are the phase shift and V/Hz requirements described in R1 considered as being part of the “voltage ride-through criteria”? (or is it
for amplitude only) An exemption should be provided for existing equipment with limitations.
Requirement -R4 and M4 What should be done when the manufacturer does not exist anymore or refuses to collaborate?
Attachment 1: Please explain (footnote) why the ride through requirement for a type-4 wind turbine needs to be different of a PV plant.
The Technical Rationale must include reasons for inclusion of Synchronous Condenser to the standard under the applicability section.
The term “active power” is not defined and appears to be used in conjunction with Real Power. Recommend consistency throughout the standards
when using Real Power vs active power, such as MOD-025, BAL-001, and many others.
Recommend the DT reevaluate the implementation period of 6 months. Recommend making implementation period 18 months or greater to account
for the need for working with OEMs to implement any setting changes and the need for IBR settings reviews conducted by third parties, as necessary.
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Thank you for your comments.
IBR Definitions: While the definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an acceptable
resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove usage of
unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another version of a
definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC-029, will include
this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects associated with
Milestone 3 as determined by those teams.
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Applicability for Sub-BES IBR: This section has been modified to include the registration criteria within the recently approved changes to the NERC
Rules of Procedures. The team was advised to hold on usage of specific language until the changes had been approved.
R1 and regional variants: Regional variants are allowable and should be initiated through that process of Standards Development. Those variations
may be in requirements or the attachments.
R2: The entities listed may specify active and reactive as needed. The “or” is one or both.
R3 exceptions: Exceptions for Provincial authorities are allowable under footnote 12 (“The exemption requests for a non-US Registered Entity should
be implemented in a manner that is consistent with, or under the direction of, the applicable governmental authority or its agency in the non-US
jurisdiction”)
R3/R1: The 5Hz/s rocof is only listed in R3.
R1: the bullets under R1 are listed as possible exemptions and are not required to be used for any events.
R4: individual facts and circumstances may be the basis for determination of compliance and are deferred to the Regional Entity.
Attachment 1 wind: This difference is based on the existing auxiliary limitation of type 4 wind to ride-through the same capability of PV. This also
aligns with IEEE 2800.
Synchronous condensers prc-024: A conforming change has been made in the updated Technical Rationale and is consistent with the SAR.
Active Power: The terms have been replaced with those from the glossary.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
Tri-State has no additional comments for PRC-024-4
Tri-State agrees with MRO NSRF Comments regarding PRC-029-1
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Response
Thank you for your comment.
- The team agrees and has consolidated bullets 1 and 4.
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-
The team believes that the reference to bullet #4 (previously bullet #5) is helpful to eliminate confusion.
The hyphen has been included in the TR.
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
PRC-029-1 Attachment 1
o Footnotes 10 and bullet 1 seem redundant. Consider consolidation with bullet 4.
o Footnotes 11, 13 and bullet 5 seem redundant. Consider consolidation.
Technical Rational for Reliability Standard PRC-029-1
o Requirement R1, paragraph 5 – missing hyphen in “IEEE 2800-2022”.
•
•
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Thank you for your comment.
- The team agrees and has consolidated bullets 1 and 4.
- The team believes that the reference to bullet #4 (previously bullet #5) is helpful to eliminate confusion.
- The hyphen has been included in the TR.
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name
Comment
PRC-024: Black Hills Corporation does not have any further comments for this revision for this standard as part of this project.
PRC-029: Black Hills Corporation agrees with the comments identified by the NAGF. They are as follows:
The NAGF believes that PRC-029 should allow for frequency ride through (“FRT”) exemptions similar to its treatment of voltage ride through (“VRT”)
exemptions. The justification for allowing VRT exemptions in FERC Order 901 also apply to FRT. We believe the statement in FERC Order 901,
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paragraph 193 in response to ACP/SEIA’s comment in paragraph 188 does not preclude the standard drafting team from considering FRT exemptions
due legacy equipment limitations. Here are a few reasons why:
1. If FERC’s intent was to exclude Frequency Ride Through exemptions while allowing Voltage ride through exemptions, there would be more of a
record established to support this differential treatment.
2. FERC responded to ACP/SEIA’s comment on ride-through requirements as if they were only asking about voltage ride through
requirements. FERC made no mention of frequency ride through requirements.
3. Similar to FERC’s rational for the consideration of voltage ride through exemptions, there are also older IBR technologies with hardware that
would need to be physically replaced to meet frequency ride through requirements as well.
4. NERC and the NERC Standard Drafting Teams have the technical expertise to address complex technical issues such as legacy equipment
limitations that FERC does not have.
Applicability Section, 4.2.2 – Recommend removing this section.
Requirement R1: The NAGF notes that R1 only addresses voltage ride through and should be revised to include frequency ride through as well. In
addition, R1 should address frequency ride through limitations for legacy IBR facilities.
Measurement M1 – The proposed narrative reads more like requirements than measures; recommend to revise the narrative accordingly. In addition,
the NAGF notes that the proposed narrative seems to assume that PRC-028 will be need to be approved/in place for PRC-029 to be a viable standard.
Requirement 2.1.3: The narrative is unclear as to what is expected for this proposed requirement. Request that the narrative be
rewritten/restructured to address this issue. In addition, it is unclear which entity will define the preference for active or reactive power. The NAGF
suggests that the Transmission Planner (TP) should have the authority to define this preference. This recommendation also applies to Requirement 2,
second bullet and Footnote 6.
Requirement R2.5: The NAGF recommends that the narrative be revised to state that active power shall be restored when” the voltage at the high‐side
of the main power transformer returns to the Continuous Operating Region”.
Requirement R4: The draft narrative does not clearly specify who is responsible for approving the exemption. The NAGF requests the narrative be
revised to address this issue.
Measure M4: Recommend replacing the word “seeking: with “submitting” in the first sentence.
Additionally, Black Hills Corporation reviewed and agrees with EEI’s high level concerns for PRC-029, which are:
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1. The Standard attempts to redefine the approved definition of IBR by adding VSC-HVDC systems after the IBR definition was approved by the
industry.
2. The Standard adds TOs to this Standard solely to address VSC-HVDC systems, yet no technical justification has been provided. Moreover, these
systems were not identified in FERC Order No. 901, or this SAR and they were not clearly identified in the Applicability Section of this proposed
Reliability Standard.
3. EEI is concerned with the inclusion of requirements that are not clearly defined or set by multiple registered entities (i.e., TP, PC, RC, or
TOP). This creates regulatory confusion and places IBR-GOs in a position where they may need to comply with any number of entities without clearly
defining who is responsible. (See Requirement R2, subpart 2.1.3; subpart 2.2 (bullet 2); subpart 2.5) Moreover, the identification of multiple entities
who could be responsible creates a situation where IBR-GOs will have reporting obligations to multiple entities because no single entity is identified as
being responsible. (See requirement R4, subparts 4.2 & 4.2.1; subpart 4.3) We further note that none of the entities identified (i.e., TP, PC, RC, or
TOP) are identified within the Applicability section of this proposed Reliability Standard. All of this can create confusion and places considerable
burden on the IBR-GOs that needs to be resolved and clarified.
4. Throughout this Reliability Standard there is use of non-glossary terms (i.e., active power vs. Real Power) where glossary terms are available and
should be used. While in other cases glossary terms are used but not capitalized. (e.g., reactive power vs. Reactive Power) Greater efforts should be
made to use NERC Glossary terms where appropriate and capitalize those terms, as required.
Detailed Concerns
Ride-through Definition Comments: EEI does not support the proposed definition for “Ride-through” as proposed because it is too vague and
contains no defined limits, as proposed. We recommend the following changes:
Ride‐through: Ability to withstand voltage or frequency Disturbances within defined regulatory limits remaining connected, synchronized with the
Transmission System, and continuing to operate. (remove: in response to System conditions through the time‐frame of a System Disturbance.)
Applicability Section Comments:
Footnote 1: EEI does not support adding TO that own VSC-HVDC systems because this was not a scope item and is therefore not be included in the
scope of this SAR. Moreover, Footnote 1 conflicts with Footnote 2 which defines VSC-HVDC as an IBR, which is again does not in alignment with the
approved definition of an IBR.
Footnote 2: EEI does not support Footnote 2 because it expands the definition of IBRs beyond what was recently approved by the industry, noting the
expansion of IBRs to include VSC‐HVDC. Furthermore, there was no technical justification for adding VSC-HVDC and the SAR did not include adding
VSC-HVDC systems to this project. For this reason, we ask that the definition of IBR not be expanded through footnotes and suggest that the DT
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submit a technical justification for adding VSC-HVDC systems to the applicability section of this Standard, rather than redefining an approved
definition in a footnote.
To address our concerns related to Footnotes 1 & 2 we suggest that if VSC-HVDC systems are to be classified as IBRs, then the approved definition
should be pulled by NERC and resubmitted with those resources added to the definition and resubmitted to the industry for approval. Alternatively,
VSC-HVDC systems could be defined separately, and that definition submitted to the industry for approval. In both cases, a technical justification
should be provided to the industry that defines the issues and risks to BPS reliability that VSC-HVDC systems pose
EEI suggests that if the DT believes that certain IBR capabilities as identified under Requirement R2 need (or may need) to be specified then they
should identify the entity who should be responsible among the four identified (i.e., TP, PC, RC or TOP); add them to the applicability section of this
Reliability Standard; add clear requirements and adjust the reporting obligations for the IBR-GO under Requirement R4.
Requirement R1 & R2 Comments: EEI does not agree with the inclusion of Transmission Owners because they would only have an obligation under
this Reliability Standard if VSC-HVDC systems were included. Given we do not support the inclusion of VSC-HVDC systems without a technical
justification and modified SAR, we ask that Transmission Owners be removed from Requirement R1.
Measures M1 & M2: EEI is concerned that M1 & M2 contains measures that are overly prescriptive providing little discretion to IBR-GOs in
demonstrating their compliance with Requirements R1 and R2 that seem to align more with a Requirement than a Measure. To address our concerns,
we offer the following suggested changes to M1 and suggest similar changes be made to M2:
M1. Each Generator Owner (remove: and Transmission Owner) shall have evidence (remove: of dynamic simulations, studies, or other evidence to
demonstrate the design of each facility will adhere) that supports the Ride-through capability of each of their facilities, as specified in Requirement
R1. (e.g., simulations, studies, recorded data from disturbance monitoring equipment, etc.) (remove: Each Generator Owner and Transmission Owner
have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) to
demonstrate that the operation of each facility did adhere to Ride-through requirements, as specified in Requirement R1.) If the Generator Owner
and Transmission Owner choose to utilize Ride-through exemptions that occur within the “must Ride-through zone” and are caused by non-faultinitiated phase jumps of greater than 25 electrical degrees, then each Generator Owner (remove: and Transmission Owner) also have evidence
supporting that exemption. (e.g., studies, simulations or supporting data from disturbance monitoring equipment) (remove: of actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate that the facility failed to
Ride-through during a phase jump of greater than or equal to 25 electrical degrees, and documentation from their Transmission Planner, Reliability
Coordinator, Planning Coordinator, or Transmission Operator that a non-fault initiated switching event occurred).
Requirement R3 & R4: EEI does not support the inclusion of Transmission Owners within Requirements R3 & R4 for the same reasons identified
above.
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Response
Thank you for your comments.
Frequency Exemptions: The team has been advised by NERC that only including some voltage-based exemptions were intended with the language of
the Order and this was confirmed.
Applicability Section – This section has been modified to reflect the current IBR definition as well as the approved changes to registration within the
NERC Rules of Procedure. These modifications are consistent with changes to the applicability section within PRC-028 and PRC-030.
R1: R1 only covers voltage requirements and R3 is for the frequency requirements. The structure of PRC-029 and allowable exemptions will not work
to combine these two.
Measures: the measures are written to provide specific examples of evidence needed for compliance. Further the implementation plan has been
revised to bifurcate between capability-based elements and performance-based elements. Essentially this is now a phased-in implementation plan
whereas each entity will be required to respond to the full requirement over time. This will allow entities to align their PRC-028 and the performancebased aspects for PRC-029 compliance.
R2.1.3: For Requirement R 2.1.3, revisions have been made clarify the requirement.
R2.5: Requirement R2.5 requires that active power return to the pre-disturbance level when voltage recovers to the continuous operating region,
unless otherwise specified by the TP,PC, RC.
R4: Modifications to R4 have been made to clarify that the GO will submit the information to the CEA for “acceptance”. Additionally, a footnote has
been added to clarify this “acceptance”.
M4. The modification was made to change “seeking” to “submitting”
IBR Definitions: While the definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an acceptable
resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove usage of
unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another version of a
definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC-029, will include
this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects associated with
Milestone 3 as determined by those teams. Further, regarding sub-BES IBR: the applicability section has been modified to include the registration
criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on usage of specific language until the
changes had been approved.
Transmission Owner: The transmission owner has been removed from PRC-029.
Other Performance Requirements: The language related to having evidence of other performance requirements was considered necessary for a
situation where an entity receives requirements from a planner or operator that would contradict PRC-029 requirements. The team included this as a
means of allowing the GO to follow requirements if needed by planners/operators and not be in violation of PRC-029 requirements. Planners and
operators are not required to provide other performance requirements and are not applicable to this Standard.
Active Power: The terms have been replaced with those from the glossary.
Ride-through definition: The definition for Ride-through has been revised.
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Applicability: As a follow up to the response for Transmission Owner and Other Performance Requirements, the team identifies no obligation or
requirement for entities, other than the GO, for any requirements in PRC-029.
Measures: The measures are written to provide specific examples of evidence needed for compliance. PRC-029 cannot have performance
measurements of actual data removed as that has been directed. The implementation plan has been bifurcated between capability-based and
performance-based requirements to allow entities additional time to align PRC-028 and PRC-029 implementation
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name
Comment
PRC-024-4
No Comments, MH is generally supportive of this proposed standard.
PRC-029-1
Applicability:
The standard switches between BPS (bulk power system) and BES (bulk electric system). For consistency, one term should be used throughout the
standard.
R1: bullet # 3:
MH recommends adding a footnote stating that the facility may operate in current block mode if necessary to avoid tripping for non-fault initiated
phase jumps greater than 25 degrees.
R2:
MH recommends that the defined terms, Real Power and Reactive Power be used throughout the document instead of active power and reactive
power.
R 2.1.3
To SDT: “The voltage is below 95 per unit” should be replaced by “The voltage is below 0.95 per unit”
R 2.1.3 & 2.2
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Allowing multiple entities to place potentially conflicting requirements upon an applicable functional entity is unacceptable. Either a single entity be
tasked with the obligation, or a hierarchy be provided so that an entity is not placed in a multibed conflicted request situation.
M1, M2, M3, and R4
To SDT: Consistently replace “Each Generator Owner and Transmission Owner” with “Each Generator Owner or Transmission Owner”
R3
This requirement requires that Each Generator Owner or Transmission Owner shall ensure the design and operation are such that each facility
adheres to Ride‐through requirements during a frequency excursion but does not require any governor response action or capability. The inverter‐
based resources that “adhere to Ride‐through requirements” but are not based on frequency deviation, would comply with the standard
requirements, which is not ideal. The TP/PC is expected to specify inverter‐based resources performance during abnormal system frequency.
MH recommends:
Each Generator Owner or Transmission Owner shall ensure the design and operation is such that each facility adheres to Ride‐through requirements
and response as specified by TP, RC, TOP, or PC during a frequency excursion.
Implementation plan:
The standard is event-based compliance that requires installing recorded equipment data with higher sampling rates at all applicable legacy IBR
Facilities. Therefore, we suggest that the implementation plan for PRC-029 should be aligned with Project 2021-04 (PRC-028-1) for the legacy IBRs.
Also, MH recommends that the implementation plan of legacy IBR (a facility that is in service by the effective date of PRC‐029‐1) be longer than any
new interconnected IBR (a facility that is in service after the effective date of PRC‐029‐1/ PRC-028-1)
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Response
Thank you for your comments.
Terminology: The BPS/BES terminology has been resolved.
R1: R1 bullet 3: The team agrees and has added this footnote.
Active Power: The terms have been replaced with those from the glossary.
Per Unit errata: 95 pu has been changed to 0.95 per unit
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Other Performance Requirements: The team intends the language for GOs who receive requirements from planner/operators that conflict with PRC029, that those entities would not be in violation of either. The team will include additional language within the technical rationale in regards to if
there are conflicting requirements issued to the GO by planner/operators.
Transmission Owner: The team has removed Transmission Owner from PRC-029
R3: governor response is not in scope for this project.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allow allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation
Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
Constellation feels that the draft 2 added significant technical requirements that would require OEM collaboration and input on their equipment.
Operating at Max capability requires additional analysis from GOs and OEMs to ensure subcomponents in the BOP and WTG side will be able to
operate at these limits.
Further, the added language for the high side transformer volts per hz ( Hz) settings to exceed 1.1 per unit longer than 45 seconds or exceed 1.18 for
longer than 2 seconds will require GO/GOPs to work with the transformer manufacturer to see if these new limits can be met. The volt/hz settings are
set to protect the transformer during over excitation conditions and they are above the provided transformer excitation curve from the manufacturer.
Also, the new ride through voltage limits is set so high that the current WTGs will not be able to ride through without tripping due to equipment
operating conditions. OEMs are still unsure and not incentivized to collaborate in a timely manner to understand capabilities and limitations.
Finally, Constellation asks the DT to address scheduling and implementation plan. The current plan is not reasonable to implement.
Kimberly Turco on behalf of Constellation Segments 5 and 6
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Response
Thank you for your comments.
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Capability: The IBR current capability is different than the current limit. What is required is to operate to the designed current specification including
rated and the short-term overcurrent rating.
Volts per hz: R1 bullet 4 is also an exemption and not a requirement.
Voltage limits: if there are any equipment limitations for voltage, then R4 is intended to address such a hardware-based limitation for legacy IBR.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation.
Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation feels that the draft 2 added significant technical requirements that would require OEM collaboration and input on their equipment.
Operating at Max capability requires additional analysis from GOs and OEMs to ensure subcomponents in the BOP and WTG side will be able to
operate at these limits.
Further, the added language for the high side transformer volts per hz ( Hz) settings to exceed 1.1 per unit longer than 45 seconds or exceed 1.18 for
longer than 2 seconds will require GO/GOPs to work with the transformer manufacturer to see if these new limits can be met. The volt/hz settings are
set to protect the transformer during over excitation conditions and they are above the provided transformer excitation curve from the manufacturer.
Also, the new ride through voltage limits is set so high that the current WTGs will not be able to ride through without tripping due to equipment
operating conditions. OEMs are still unsure and not incentivized to collaborate in a timely manner to understand capabilities and limitations.
Finally, Constellation asks the DT to address scheduling and implementation plan. The current plan is not reasonable to implement.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Response
Thank you for your comments.
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Capability: The IBR current capability is different than the current limit. What is required is to operate to the designed current specification including
rated and the short-term overcurrent rating.
Volts per hz: R1 bullet 4 is also an exemption and not a requirement.
Voltage limits: if there are any equipment limitations for voltage, then R4 is intended to address such a hardware-based limitation for legacy IBR.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation.
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of its members:
PRC-029-1 Comments:
While EEI appreciates that changes made to address our previous comments for the 1st draft of PRC-029-1, we have some new concerns that need to
be addressed.
Our high level concerns are described in our comments below:
1. The Standard attempts to redefine the approved definition of IBR by adding VSC-HVDC systems after the IBR definition was approved by the
industry.
2. The Standard adds TOs to this Standard solely to address VSC-HVDC systems, yet no technical justification has been provided. Moreover, these
systems were not identified in FERC Order No. 901, or this SAR and they were not clearly identified in the Applicability Section of this proposed
Reliability Standard.
3. EEI is concerned with the inclusion of requirements that are not clearly defined or set by multiple registered entities (i.e., TP, PC, RC, or
TOP). This creates regulatory confusion and places IBR-GOs in a position where they may need to comply with any number of entities without clearly
defining who is responsible. (See Requirement R2, subpart 2.1.3; subpart 2.2 (bullet 2); subpart 2.5) Moreover, the identification of multiple entities
who could be responsible creates a situation where IBR-GOs will have reporting obligations to multiple entities because no single entity is identified as
being responsible. (See requirement R4, subparts 4.2 & 4.2.1; subpart 4.3) We further note that none of the entities identified (i.e., TP, PC, RC, or
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TOP) are identified within the Applicability section of this proposed Reliability Standard. All of this can create confusion and places considerable
burden on the IBR-GOs that needs to be resolved and clarified.
4. Throughout this Reliability Standard there is use of non-glossary terms (i.e., active power vs. Real Power) where glossary terms are available and
should be used. While in other cases glossary terms are used but not capitalized. (e.g., reactive power vs. Reactive Power) Greater efforts should be
made to use NERC Glossary terms where appropriate and capitalize those terms, as required.
Detailed Concerns
Ride-through Definition Comments:
EEI does not support the proposed definition for “Ride-through” as proposed because it is too vague and contains no defined limits, as proposed. We
recommend the following changes:
Ride‐through: Ability to withstand voltage or frequency Disturbances within defined regulatory limits remaining connected, synchronized with the
Transmission System, and continuing to operate. in response to System conditions through the time‐frame of a System Disturbance(remove).
Applicability Section Comments:
Footnote 1: EEI does not support adding TO that own VSC-HVDC systems because this was not a scope item and is therefore not be included in the
scope of this SAR. Moreover, Footnote 1 conflicts with Footnote 2 which defines VSC-HVDC as an IBR, which is again does not in alignment with the
approved definition of an IBR.
Footnote 2: EEI does not support Footnote 2 because it expands the definition of IBRs beyond what was recently approved by the industry, noting the
expansion of IBRs to include VSC‐HVDC. Furthermore, there was no technical justification for adding VSC-HVDC and the SAR did not include adding
VSC-HVDC systems to this project. For this reason, we ask that the definition of IBR not be expanded through footnotes and suggest that the DT
submit a technical justification for adding VSC-HVDC systems to the applicability section of this Standard, rather than redefining an approved
definition in a footnote.
To address our concerns related to Footnotes 1 & 2 we suggest that if VSC-HVDC systems are to be classified as IBRs, then the approved definition
should be pulled by NERC and resubmitted with those resources added to the definition and resubmitted to the industry for approval. Alternatively,
VSC-HVDC systems could be defined separately, and that definition submitted to the industry for approval. In both cases, a technical justification
should be provided to the industry that defines the issues and risks to BPS reliability that VSC-HVDC systems pose
EEI suggests that if the DT believes that certain IBR capabilities as identified under Requirement R2 need (or may need) to be specified then they
should identify the entity who should be responsible among the four identified (i.e., TP, PC, RC or TOP); add them to the applicability section of this
Reliability Standard; add clear requirements and adjust the reporting obligations for the IBR-GO under Requirement R4.
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Requirement R1 & R2 Comments: EEI does not agree with the inclusion of Transmission Owners because they would only have an obligation under
this Reliability Standard if VSC-HVDC systems were included. Given we do not support the inclusion of VSC-HVDC systems without a technical
justification and modified SAR, we ask that Transmission Owners be removed from Requirement R1.
Measures M1 & M2: EEI is concerned that M1 & M2 contains measures that are overly prescriptive providing little discretion to IBR-GOs in
demonstrating their compliance with Requirements R1 and R2 that seem to align more with a Requirement than a Measure. To address our concerns,
we offer the following suggested changes to M1 and suggest similar changes be made to M2:
M1. Each Generator Owner shall have evidence that supports the Ride-through capability of each of their facilities, as specified in Requirement R1.
(e.g., simulations, studies, recorded data from disturbance monitoring equipment, etc.) If the Generator Owner and Transmission Owner choose to
utilize Ride-through exemptions that occur within the “must Ride-through zone” and are caused by non-fault initiated phase jumps of greater than 25
electrical degrees, then each Generator Owner also have evidence supporting that exemption. (e.g., studies, simulations or supporting data from
disturbance monitoring equipment)
Requirement R3 & R4: EEI does not support the inclusion of Transmission Owners within Requirements R3 & R4 for the same reasons identified
above.
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Response
IBR Definitions: While the definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an acceptable
resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove usage of
unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another version of a
definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC-029, will include
this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects associated with
Milestone 3 as determined by those teams. Further, regarding sub-BES IBR: the applicability section has been modified to include the registration
criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on usage of specific language until the
changes had been approved.
Transmission Owner: The transmission owner has been removed from PRC-029.
Other Performance Requirements: The language related to having evidence of other performance requirements was considered necessary for a
situation where an entity receives requirements from a planner or operator that would contradict PRC-029 requirements. The team included this as a
means of allowing the GO to follow requirements if needed by planners/operators and not be in violation of PRC-029 requirements. Planners and
operators are not required to provide other performance requirements and are not applicable to this Standard.
Active Power: The terms have been replaced with those from the glossary.
Ride-through definition: The definition for Ride-through has been revised.
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Applicability: As a follow up to the response for Transmission Owner and Other Performance Requirements, the team identifies no obligation or
requirement for entities, other than the GO, for any requirements in PRC-029.
Measures: The measures are written to provide specific examples of evidence needed for compliance. PRC-029 cannot have performance
measurements of actual data removed as that has been directed. The implementation plan has been bifurcated between capability-based and
performance-based requirements to allow entities additional time to align PRC-028 and PRC-029 implementation.
David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
Document Name
Comment
Vistra supports comments made by EEI and Entergy.
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Thank you. Please refer to the responses to EEI and Entergy.
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 1
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Response
Thank you. Please refer to the responses to EEI and MRO NSRF.
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Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by the NAGF.
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AECI supports comments provided by the NAGF.
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
Comment
PRC-029:
General Comment: The NAGF believes that PRC-029 should allow for frequency ride through (“FRT”) exemptions similar to its treatment of voltage ride
through (“VRT”) exemptions. The justification for allowing VRT exemptions in FERC Order 901 also apply to FRT. We believe the statement in FERC
Order 901, paragraph 193 in response to ACP/SEIA’s comment in paragraph 188 does not preclude the standard drafting team from considering FRT
exemptions due legacy equipment limitations. Here are a few reasons why:
1. If FERC’s intent was to exclude Frequency Ride Through exemptions while allowing Voltage ride through exemptions, there would be more of a
record established to support this differential treatment.
2. FERC responded to ACP/SEIA’s comment on ride-through requirements as if they were only asking about voltage ride through
requirements. FERC made no mention of frequency ride through requirements.
3. Similar to FERC’s rational for the consideration of voltage ride through exemptions, there are also older IBR technologies with hardware that
would need to be physically replaced to meet frequency ride through requirements as well.
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4. NERC and the NERC Standard Drafting Teams have the technical expertise to address complex technical issues such as legacy equipment
limitations that FERC does not have.
Applicability Section, 4.2.2 – Recommend removing this section.
Requirement R1: The NAGF notes that R1 only addresses voltage ride through and should be revised to include frequency ride through as well. In
addition, R1 should address frequency ride through limitations for legacy IBR facilities.
Measurement M1 – The proposed narrative reads more like requirements than measures; recommend to revise the narrative accordingly. In addition,
the NAGF notes that the proposed narrative seems to assume that PRC-028 will be need to be approved/in place for PRC-029 to be a viable standard.
Requirement 2.1.3: The narrative is unclear as to what is expected for this proposed requirement. Request that the narrative be
rewritten/restructured to address this issue. In addition, it is unclear which entity will define the preference for active or reactive power. The NAGF
suggests that the Transmission Planner (TP) should have the authority to define this preference. This recommendation also applies to Requirement 2,
second bullet and Footnote 6.
Requirement R2.5: The NAGF recommends that the narrative be revised to state that active power shall be restored when” the voltage at the high‐side
of the main power transformer returns to the Continuous Operating Region”.
Requirement R4: The draft narrative does not clearly specify who is responsible for approving the exemption. The NAGF requests the narrative be
revised to address this issue.
Measure M4: Recommend replacing the word “seeking: with “submitting” in the first sentence.
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Scott Brame, N/A, Brame Scott
0
Response
Thank you for your comments.
Frequency Exemptions: The team has been advised by NERC that only including some voltage-based exemptions were intended with the language of
the Order and this was confirmed.
Applicability Section – This section has been modified to reflect the current IBR definition as well as the approved changes to registration within the
NERC Rules of Procedure. These modifications are consistent with changes to the applicability section within PRC-028 and PRC-030.
R1: R1 only covers voltage requirements and R3 is for the frequency requirements. The structure of PRC-029 and allowable exemptions will not work
to combine these two.
Measures: the measures are written to provide specific examples of evidence needed for compliance. Further the implementation plan has been
revised to bifurcate between capability-based elements and performance-based elements. Essentially this is now a phased-in implementation plan
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whereas each entity will be required to respond to the full requirement over time. This will allow entities to align their PRC-028 and the performancebased aspects for PRC-029 compliance.
R2.1.3: For Requirement R 2.1.3, revisions have been made clarify the requirement.
R2.5: Requirement R2.5 requires that active power return to the pre-disturbance level when voltage recovers to the continuous operating region,
unless otherwise specified by the TP,PC, RC.
R4: Modifications to R4 have been made to clarify that the GO will submit the information to the CEA for “acceptance”. Additionally, a footnote has
been added to clarify this “acceptance”.
M4. The modification was made to change “seeking” to “submitting”
Karen Demos - NextEra Energy - Florida Power and Light Co. - 1,3,6
Answer
Document Name
Comment
Support NEE comments submitted
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Response
Thank you for your comment. Please refer to the response to NEE.
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
Comment
PRC-024-4
No Comments, MRO NSRF is generally supportive of this proposed standard.
PRC-029-1
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MRO NSRF recommends that the defined terms, Real Power and Reactive Power be used throughout the document instead of active power and
reactive power.
Section 4, footnote 2 – MRO NSRF does not support using a definition for “inverter based resources” that differs from the what is currently being
proposed by the standard drafting team responsible for developing the Glossary of Terms definition for this term. There must be alignment between
standards prior to any of them being able to move forward.
Measure 1 – This measure is overly prescriptive and does not allow the applicable functional entity sufficient flexibility to demonstrate compliance
with Requirement 1. MRO NSRF would recommend the standard drafting team review measures from PRC-024 and align with the approach taken
there.
Measure 2 – This measure is overly prescriptive and does not allow the applicable functional entity sufficient flexibility to demonstrate compliance
with Requirement 2. MRO NSRF would recommend the standard drafting team review measures from PRC-024 and align with the approach taken
there.
Requirement 2.1.3 – This requirement is unclear in its intent. Additionally, allowing multiple entities to place potentially conflicting requirements upon
an applicable functional entity is unacceptable. Either a single entity be tasked with the obligation, or a hierarchy be provided so that an entity is not
placed in a “catch-22” situation.
Requirement 4 – MRO NSRF Recommends the following modifications to improve clarity:
Each Generator Owner and Transmission Owner identifying a facility that is in-service by the effective date of PRC-029-1, that has known hardware
limitations which prevent the facility from meeting voltage Ride-through criteria as detailed in Requirements R1 and R2, and requires an exemption
from specific voltage Ride-through criteria shall:
Measure 4 – MRO NSRF recommends changing “seeking” to “documenting” or “submitting”.
Additional comments:
1. The standard switches between BPS (bulk power system) and BES (bulk electric system). For consistency, one term should be used throughout the
standard.
2. R1 bullet # 3: MRO NSRF recommends adding a footnote stating that the facility may operate in current block mode if necessary to avoid tripping
for non-fault initiated phase jumps greater than 25 degrees
3. M1, M2, M3, and R4: consistent replace “Each Generator Owner and Transmission Owner” with “Each Generator Owner or Transmission Owner”
4. R2, 2.1.3: “The voltage is below 95 per unit” should be replaced by “The voltage is below 0.95 per unit”
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Lincoln Electric System, 3, Christensen Sam
0
Response
Thank you for your comments.
Active Power: The terms have been replaced with those from the glossary.
IBR Definitions: While the definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an acceptable
resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove usage of
unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another version of a
definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC-029, will include
this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects associated with
Milestone 3 as determined by those teams.
Measures: The measures are written to provide specific evidence to be used as examples and allow for other evidence for entity-specific flexibility.
These measures cannot align with PRC-024 and that standard is focused on equipment settings and PRC-029 must evaluate actual performance.
Other Performance Requirements: The language related to having evidence of other performance requirements was considered necessary for a
situation where an entity receives requirements from a planner or operator that would contradict PRC-029 requirements. The team included this as a
means of allowing the GO to follow requirements as needed by planners/operators and not be in violation of PRC-029 requirements. Additional
language has been added to the technical rationale for clarity.
M4. The modification was made to change “seeking” to “submitting”
Terminology: The BPS/BES terminology has been resolved.
R1: R1 bullet 3: The team agrees and has added this footnote.
Per Unit errata: 95 pu has been changed to 0.95 per unit
Richard Vendetti - NextEra Energy - 5
Answer
Document Name
Comment
R1 “The instantaneous positive sequence voltage phase angle change is more than 25 electrical degrees at the high-side of the main power
transformer and is initiated by a non-fault switching event on the transmission system” - How is the GO of IBR going to identify the cause of the
fault?
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R1 “The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for
longer than 2 seconds.” – What is the technical rationale behind the 45 second and 2 seconds? This is a very specific scenario as described in the
“Technical Rationale”. Requests incorporating language that suggests where it applies.
M1 M1 requires multiple data requirements. It is not clear in language. Interpretation is that GO / TO should have evidence that design can meet as
well as performance based evidence that it does or does not perform. The amount and time frame to collect evidence is not provided. Is the
expectation that this data is only required for a specific event upon the data request?
The language in R2 requirements does not explicitly state that changes in resource availability (i.e wind or sun) will also affect the active and reactive
current or recovery of the IBR.
R2.5 “Each facility shall restore active power output to the pre-disturbance or available level (whichever is lesser) within 1.0 second when the voltage
at the high-side of the main power transformer returns from the mandatory operation region or permissive operation region (including operating in
current block mode)” Recommend language updated to “continuous operating region”. IBR units will be limited in capabilities until transient has
ended and IBR equipment is no longer sitting at its equipment limiters”
It is not understood why requirement R1 exists when R2 has all the details. The standard appears to be first written as the test criteria for model
validation. Secondly, as a standard to provide data that plant performance matches model. A standard practice guide on the method to demonstrate
compliance through dynamic simulations, studies or other evidence is necessary before full adoption of new standard.
Attachment 1
Overall there are concerns with the PRC-029 implementation timeline for any requirement where the OEM has not had time to fully assess the new
requirement and utilize the new IEEE2800 testing standard. New standard implementation needs to give GO/TO time to fully assess new requirements;
in particular with the multiple disturbance criteria or method OEMs calculate values.
There is no R6
R3/M3 – All Measurement requirements should be confirmed as inclusion into the PRC-028 standard (RoCoF, V/Hz, Phase Angle, etc)
There is no instruction regarding requirement if IBR cannot meet R3 due to Equipment Limitation
R4 Implementation timeline is too short to assess all facilities with additional requirements in PRC-029. There is also not enough time to allow for OEM
responses. Recommend tracking an implementation guideline similar to PRC-028 and PRC-030 to meet FERC deadline.
There is no instruction on process to report a new limitation after the full implementation of R4 when a piece of equipment within the IBR may
temporarily limit the capability
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R4.3 Each Generator Owner and Transmission Owner with a previously submitted request for exemption that replace the equipment causing the
limitation shall document and communicate such an equipment change to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s) within 90 days of the equipment change
The language should be clear to state “full replacement”. Should not be misinterpreted to include subcomponent replacement.
There is no R5
The Implementation timeline of this standard is the most concerning given the additional requirements generating new review of all facilities and the
need to receive additional feedback from OEMs without new testing standard.
The performance data collection requirements will need to align with implementation timeline of PRC-028 at each facility.
A practice guide is highly recommended to demonstrate method and expectation for compliance.
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Thank you for your comments.
R1: The non-fault switching event occurrence is considered a potential exemption for tripping within the must Ride-through zone R1 and is not
required. If the exemption must be utilized by the GO, then the required measurement to support the exemption would need to be collected from
the RC, TP, or PC.
Volts/Hz: Additional information has been added to the Technical Rationale.
M1/M2: The Implementation Plan has been modified to include bifurcated implementation information between capability-based elements and
performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to the full
requirement over time.
R2: The team agrees this was intended and has included additional language to clarify changes to fuel sources.
R1/R2: R1 requires ride-through within the must Ride-through zone. R2 includes additional performance requirements beyond tripping/momentary
cessation/failing to Ride-through.
R3: The measurement data needed to derive these characteristics are confirmed to be in PRC-028.
R3: Frequency exemptions are not included as allowable exemptions within FERC Order No. 901.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation.
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R4: Temporary capability limitations would be communicated through normal mechanisms (e.g., GADS) and would not qualify as exemptions from
Ride-through.
Equipment replacement: replacement for maintenance in-kind does not remove the limitation. Additional language was added to 4.3.1 to clarify this.
Practice Guides: Practice Guides are not developed by Drafting Teams.
Robert Follini - Avista - Avista Corporation - 3
Answer
Document Name
Comment
Avista supports the development of a new Reliability Standard to address gaps in Inverter-Based Resource Performance but has concerns with
numerous definitions/verbiage.
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Response
Thank you for your comment.
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
Document Name
Comment
R1: Revise text as follows: “…each facility adheres to voltage Ride-through requirements…”
WEC also disagrees with M1 and agrees with the comments made by NAGF and EEI.
R2: WEC disagrees with text “…shall ensure the design and operation is such…”. The requirement must state what TO and GO must do. Otherwise,
this requirement is open-ended without a measurable statement. The “…shall ensure” has no quantitative meaning and it does not benefit the BES
stability.
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2.1: The proposed “continuous operating region” range conflicts with acceptable continuous operating ranges by Transmission Operators. Many
Transmission Operators classify continuous operating range from 0.95 and 1.05 pu, and consider voltage ranges from 0.9 to 0.95 pu and 1.05 to 1.1 pu
as abnormal voltage ranges.
2.1.1: Continue to deliver the pre-disturbance level of active power or available active power, whichever is less. Please explain and list what entity
must do to ensure this requirement is met.
2.1.2: Continue to deliver reactive power up to its reactive power limit and according to its controller settings. Please explain and list what entity must
do to ensure this requirement is met.
2.1.3: What document governs a TP, PC, RC or TO to specify active/reactive power prioritization.
2.3: Term “current block mode” may not be understood and its meaning could be misinterpreted. Does it mean mandatory cessation? Please explain
and at least define it in footnotes. Assuming this means momentary cessation, it looks like this requirement will allow momentary cessation if
necessary to avoid tripping, OR, per 2.3.1 entity can enter current cessation for 5 cycles. It seems the statement contradicts itself.
2.5: WEC owns and operates multiple IBR sites and it is in our experience that the limitation to the one second requirement will come from the power
plant controller. The ramp rate capabilities of the power plant controllers are far slower than inverter ramp rates and are typically in minutes range.
WEC also had an instance where the power plant controller ramp rate increase was denied by the Transmission Operator/Planner. Applying one
second requirement will simply be impractical and most entities will take equipment limitation exception that will not benefit the BES. Unless stated in
quantitative way (what and when) the requirement R2 provides no benefit to BES.
M2: The current version of M2 calls for dynamic simulations, studies, or other evidence plus having ACTUAL disturbance monitoring data proving the
Requirement was met. The dynamic simulations/studies can be performed by third-party engineering contractors specializing in these activities to
prove each site meets the first part. However, two questions must be addressed regarding actual data: (1) "How" actual data is acquired if SER, DDR
and/or Fault Recording does not become mandated. NAGF made a similar point in their response.
(2) "When" actual data must be submitted as evidence if we as GOs are not specifically asked for it by some other entity. Without some mandate for
data, we as GOs are not going to know when every voltage disturbance that would have (should have) triggered a ride-through has occurred on the
transmission system.
Attachment 1: Are items 1 thru 10 requirements or they are notes supplementing Tables 1 and 2? Please define.
More description needs to be provided on how to apply items 8, 9, and 10.
Attachment 2: Are items 1 thru 5 requirements or they are notes supplementing Table 3? Please define.
More description needs to be provided on how to apply item 5.
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Thank you for your comments.
R1: Please refer to the responses to NAGF and EEI
R2: Please refer to the measure M2 for additional specificity and examples for objectively evaluating compliance.
R2.1: Language is included to allow GOs the ability to respond to other planner/operator performance requirements as noted and avoid
noncompliance with PRC-029.
R2.1.1/R2.1.2: The team advises to monitor the relevant quantities (for example: active current, active power, reactive current, reactive power, and
the mode of operation). Additionally, a footnote was added to 2.1.1. Finally, refer to data requirements in PRC-028.
R2.1.3: There is no obligation or requirement for planners or operators to supply other performance requirements. The language related to having
evidence of other performance requirements was considered necessary for a situation where an entity receives requirements from a planner or
operator that would contradict PRC-029 requirements. The team included this as a means of allowing the GO to follow requirements as needed by
planners/operators and not be in violation of PRC-029 requirements.
R2.3: The team has included this specific instance of allowing current block mode which would cause momentary cessation. This allowance is
restricted to this instance to prevent tripping and is explained in more detail within the Technical Rationale.
R2.5: Language to allow different ramp rate requirements from planners/operators is already included. Also, for legacy equipment that cannot meet
the requirements within PRC-029 due to hardware-based limitations, this would be covered in R4. Finally, R2.5 only refers to ramp rates after
recovery from the mandatory operation region or permissive operation region to the continuous operation region.
Implementation Plan: Implementation Plan has been modified to include bifurcated implementation information between capability-based elements
and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to the full
requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029 implementation.
Further, the disturbances identified by planners and operators within PRC-030, would trigger the request to hold data for demonstrating
performance. Additional data requirements are established within PRC-030.
Attachments 1 and 2: The notes supplement information in regards to the tables and are not stand-alone requirements. The same interpretive
method for the voltage and frequency -vs- time limits is applied within PRC-024.
Russell Ferrell - Luminant - Luminant Energy - 6
Answer
Document Name
Comment
. I support EEI's and Entergy's comments
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Response
Thank you for your comment. Please refer to the responses to EEI and Entergy.
Dave Krueger - SERC Reliability Corporation - 10
Answer
Document Name
Comment
For the applicability section, suggest adding "that owns equipment as identified in section 4.2" after "generator owner" similarly to the proposed PRC030-1
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Scott Brame, N/A, Brame Scott
0
Response
Thank you for your comment.
GOs would not be expected to comply for assets they do not own. Further, PRC-028, PRC-029, and PRC-030 have revised their applicability to use the
new proposed IBR definition and the approved registration criteria changes to the NERC Rules of Procedure.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See comments submitted by the Edison Electric Institute”
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Thank you for your comment. Please refer to the response to EEI.
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas Johnson,
Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer
Document Name
Comment
none.
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Response
Thank you.
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Document Name
Comment
See comments submitted by Edison Electric Institute.
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Response
Thank you for your comment. Please refer to the response to EEI.
Patricia Ireland - DTE Energy - 4, Group Name DTE Energy
Answer
Document Name
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Comment
No comments at this time
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Response
Thank you.
David Jendras Sr - Ameren - Ameren Services - 1,3,6
Answer
Document Name
Comment
Ameren agrees with and supports EEI's comments.
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Response
Thank you for your comment. Please refer to the response to EEI.
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
PRC-024-4:
·
We support creation of new standard PRC-029 to address IBR specific ride through issues, as both the different natures of synchronous and
inverter-based generation and several recent events exhibiting significant IBR ride-through deficiencies and failures the causes of which are not
relevant to synchronous generators. The approach to address IBR issues should be different to that of PRC-024 because there are too many other
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factors and causes of IBR ride-through failure not directly related to voltage and frequency protection settings that may and have caused ride-through
deficiencies and failures.
·
PRC-028 was voted out due to issues around definition of IBR criteria and implementation plan. Separate PRC-029 would allow PRC-024 to pass
through the ballot process without many issues.
PRC-029-1:
·
Support inclusion of Ride through requirement in the TERM section, which will get included into NERC Glossary of Terms.
In all the requirements IBR is replaced with Facility, except the requirement R2.2 as IBR. In attachment 1 it is mentioned as inverter‐based
·
resource facility. That is not consistent.
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Thank you for your comments.
The terms for facility have all been modified to IBR to coincide with the new proposed definition of IBR from Project 2020-06.
Michael Dillard - Austin Energy - 5, Group Name Austin Energy
Answer
Document Name
Comment
Austin Energy supports comments posted by NAGF:
PRC-029:
General Comment: The NAGF believes that PRC-029 should allow for frequency ride through (“FRT”) exemptions similar to its treatment of voltage ride
through (“VRT”) exemptions. The justification for allowing VRT exemptions in FERC Order 901 also apply to FRT. We believe the statement in FERC
Order 901, paragraph 193 in response to ACP/SEIA’s comment in paragraph 188 does not preclude the standard drafting team from considering FRT
exemptions due legacy equipment limitations. Here are a few reasons why:
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1. If FERC’s intent was to exclude Frequency Ride Through exemptions while allowing Voltage ride through exemptions, there would be more of a
record established to support this differential treatment.
2. FERC responded to ACP/SEIA’s comment on ride-through requirements as if they were only asking about voltage ride through
requirements. FERC made no mention of frequency ride through requirements.
3. Similar to FERC’s rational for the consideration of voltage ride through exemptions, there are also older IBR technologies with hardware that
would need to be physically replaced to meet frequency ride through requirements as well.
4. NERC and the NERC Standard Drafting Teams have the technical expertise to address complex technical issues such as legacy equipment
limitations that FERC does not have.
Applicability Section, 4.2.2 – Recommend removing this section.
Requirement R1: The NAGF notes that R1 only addresses voltage ride through and should be revised to include frequency ride through as well. In
addition, R1 should address frequency ride through limitations for legacy IBR facilities.
Measurement M1 – The proposed narrative reads more like requirements than measures; recommend to revise the narrative accordingly. In addition,
the NAGF notes that the proposed narrative seems to assume that PRC-028 will be need to be approved/in place for PRC-029 to be a viable standard.
Requirement 2.1.3: The narrative is unclear as to what is expected for this proposed requirement. Request that the narrative be
rewritten/restructured to address this issue. In addition, it is unclear which entity will define the preference for active or reactive power. The NAGF
suggests that the Transmission Planner (TP) should have the authority to define this preference. This recommendation also applies to Requirement 2,
second bullet and Footnote 6.
Requirement R2.5: The NAGF recommends that the narrative be revised to state that active power shall be restored when” the voltage at the high‐side
of the main power transformer returns to the Continuous Operating Region”.
Requirement R4: The draft narrative does not clearly specify who is responsible for approving the exemption. The NAGF requests the narrative be
revised to address this issue.
Measure M4: Recommend replacing the word “seeking: with “submitting” in the first sentence.
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Thank you for your comment.
Frequency/R3/Attachment 2 Exemptions: In Order No. 901, FERC directed NERC to determine whether the ride-through standard should provide for
a limited and documented exemption for certain registered IBRs from voltage ride through performance requirements, and only for voltage ride
through performance for those existing IBRs that are unable to modify their settings without physical modification of equipment. See Order No. 901
at P 193. The drafting team determined that such an exemption was appropriate and it is included in Requirement R4. The drafting team does not
have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901. The drafting team does believe additional monitoring would be appropriate to determine how many entities would
be affected by such an exemption and whether such an exemption would be consistent with overall Bulk-Power System reliability. To the extent such
monitoring suggests that further exclusions would be appropriate, a future drafting team could make those changes in an expeditious manner. The
affected entities could work with ERO Enterprise staff to address any compliance-related concerns in the interim. For this draft, however, the drafting
team is pursuing a more conservative approach in line with the specific exemptions identified in Order No. 901.
Applicability Section – This section has been modified to reflect the current IBR definition as well as the approved changes to registration within the
NERC Rules of Procedure. These modifications are consistent with changes to the applicability section within PRC-028 and PRC-030.
R1: R1 only covers voltage requirements and R3 is for the frequency requirements. The structure of PRC-029 and allowable exemptions will not work
to combine these two.
Measures: the measures are written to provide specific examples of evidence needed for compliance. Further the implementation plan has been
revised to bifurcate between capability-based elements and performance-based elements. Essentially this is now a phased-in implementation plan
whereas each entity will be required to respond to the full requirement over time. This will allow entities to align their PRC-028 and the performancebased aspects for PRC-029 compliance.
R2.1.3: For Requirement R 2.1.3, revisions have been made clarify the requirement.
R2.5: Requirement R2.5 requires that active power return to the pre-disturbance level when voltage recovers to the continuous operating region,
unless otherwise specified by the TP,PC, RC.
R4: Modifications to R4 have been made to clarify that the GO will submit the information to the CEA for “acceptance”. Additionally, a footnote has
been added to clarify this “acceptance”.
M4. The modification was made to change “seeking” to “submitting”.
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
WECC suggests the DT should ensure that the labeling on the Project page of the Standard is accurate in terms of what is being considered. The
“redline” version is not a true redline from PRC-024-3 it is a redline from a failed version of PRC-024-4 with the language that was voted down shown
as “approved” (i.e., text appearing as not being changed.) This could be misleading. There is no mention of Attachment 2A or Attachment 2C in any
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of the Requirements. It is noted that there is a reference to Attachment 2B in the Quebec variance. Consider changing Requirement R2 language to
reference Attachment 2A and incorporate current Attachment 2A language into Attachment 2. And incorporate Attachment 2C language into
Attachment 2B. That provides clarity with a minimal change in Requirement R2 language. In theory, this is a set it and forget it Standard unless
something changes. The data retention should reflect that condition and not be limited. GOs and TOs will have to be able to demonstrate settings
when requested and can not simply say “the settings were done 6 years ago so no evidence is retained”. There have been cases where a GO has
indicated retrieval of settings required a third party because the GO did not have documentation. Absence of a failure (i.e., unit trip that would need
to be reviewed to see if voltage/frequency was the root cause and if the associated relay responded within the “no-trip” zone) is not necessarily a
successful reliability indicator and would require quite a bit of data to demonstrate reliable operation resulting in compliance.
Overall for PRC-024-4 WECC is supportive of the efforts and end results.
PRC-029-1
It is unclear why lower cased “facility” is used. In Footnote 2 “facility” is not used but “plant/resource” is used. In the Technical Rationale
“plant/facility” is used. Please provide consistency in language within the Standard, the Requirements, and Technical Rationale.
Facilities Section 4.2 is extremely unclear in that it simply says “IBR Registration Criteria” for 4.2.2. Additionally, Footnote 2 does not consider any
hybrid resource types (or Facility types or plant types).
R1 indicates “design and operation” which is a valid approach but “design” can be assessed reviewing settings (and simulations, etc.) but “operation”
can only be assessed through a review of time periods where applicable voltage (or frequency) demonstrates a change that calls for operation per the
Tables. The VSL for R1 is written in a manner that requires that level of assessment (e.g., entities would have to find a point in time where .89 Voltage
existed and show they exceeded the minimum Ride-through time.) The VSL is written where a design issue is a lower VSL but the wrong setting would
indicate that the operation could not adhere to Attachment 1. Measurement M1 mentions SER/FR/DDR which are covered in PRC-028-1 (Project
2021-04). Are those enough to demonstrate operation to Attachment 1 under the criteria set in the Tables? With PRC-028-1 setting data retention
levels so short, the evidence suggested by Measurement M1 will require retention per Evidence Retention requirements in PRC-029-1 to be able to
clearly demonstrate compliance.
If using capitalized “Transmission System” in the definition of “Ride-through” use it capitalized in Requirement 1 bullet 3. PRC-024 had MPT and GSU
used and “defined”. Consistency in use here in PRC-029 (with appropriate changes) to correlate with PRC-024 is appropriate but should be footnoted
in Requirement R1 bullets 3 and 4 first prior to being called out in Requirement R2.1.
Measurement M1 is expansive and some of the details should be in the Technical Rationale rather than in a measure. As is, appears to be not
consistent and should, at a minimum, include the word “shall” where needed as others Standards (including PRC-024) are written in this manner
(e.g.”,….shall have evidence…”). M1 does not mention bullet 2.
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Requirement 2 will require a voltage excursion to demonstrate operation adhering to Attachment 1. What criteria constitutes a “voltage
excursion”? Requirement 2.1- Consider adding a comma after “region” to be consistent with similar language in other parts of Requirement R2.
Requirement 2.1.1 The phrase “or available active power, whichever is less” appears to be supportive of the footnote regarding a frequency excursion
but what if the “available active power” is lower than the pre-disturbance level of active power. “Less” could be zero output as the voltage at the MPT
high-side could remain within the continuous operation range with the IBR disconnected.
Requirement 2.1.3 Please verify if that should be ”.95” per unit versus “95” per unit. Since this Requirement is within the Operations Horizon
timeline, the reference to Transmission Planner and Planning Coordinator should be dropped. Furthermore, it is not clear what a GO would operate
to if given conflicting orders by the RC and TOP. Consider limiting the “preference” to the TOP who is to set the system voltage expectations per VAR001.
Requirement 2.2.- Consider “sub Part” formatting used in other Requirements versus bullets for consistency. Since this Requirement is within the
Operations Horizon timeline, the reference to Transmission Planner and Planning Coordinator should be dropped. Furthermore, it is not clear what a
GO would operate to if given conflicting orders by the RC and TOP. Consider limiting the “requirement” to the TOP who is to set the system voltage
expectations per VAR-001. In this bullet the language says “each IBR” versus “each facility” as called out in other parts of Requirement R2. Is that
correct?
Requirement R4 is a grandfathering clause and assumes each unit after the effective date will meet Requirements 1, 2, and 3. There should not be
any additional implementation timeline built into a Requirement language as this Standard will take time to be approved and there is a proposed 6
month Implementation Plan. If there is a hardware limitation, it should be known Day 1 of the effective date of Standard and gathering of the limited
information should have already been don ein the 6 months leading to the effective date. There is no requirement for an entity to replace the
hardware limitation. The entire Requirement will result in documentation with no expectation of mitigation. What data does the DT have to support
this exemption language? At a minimum, notification of an issue needs to be provided to the TOP and RC. Suggest a Corrective Action Plan with
definitive time requirements to mitigate the issue (or explain why it can not be mitigated) be instituted here.
Footnote 9 may not be necessary as non-US Jurisdictional applicable government authorities have mechanisms in place to implement any Standard.
Within Requirement R4.1- 4.1.1- Call out specifics for consistency. Leaving as “other” invites inconsistency. Use “Ride-through” as that is a proposed
defined term (versus “ride-through”) in 4.1.2. Be consistent in using “hardware” or “equipment” to avoid confusion throughout Requirement
R4. Suggest removing the phrase “or that the limitation cannot be removed by software updates or setting changes” as this is limited to a hardware
limitation exemption. Requirement R4.1.5 is ambiguous and clarity should be provided. Requirement 4.2 It is not clear why the Planning Coordinator
and Transmission Planner is included here. Model data demonstrating the limitation should be provided through another mechanism. Including the
Regional Entity here is not needed or recommended as Regional Entities are NOT subject to Standards. If the DT wants to include providing
information to the Regional Entity place it in “Additional Compliance” section (similar to FAC-003) and recognize it as a data submittal. Recommend
removal of Regional Entity from the Requirement language.
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Measure M4 does not support Requirement R4 with regards to notification timeline in Requirement R4.3, sentence regarding submission of
information in 4.1 should not be limited to the Regional Entity (alternatively that sentence could be removed as Regional Entity is covered in next
sentence), and there is no information regarding the response timeline in 4.2.1. Furthermore, “experience from an actual event” indicates that the
GO/TO could not adhere to the design and operation criteria set—equating to a possible noncompliance. If there is a hardware (or “equipment”
depending on where consistency efforts lead) limitation that should be known in the design phase and addressed at that point
There is no corresponding frequency “hardware” limitation language if a facility can not adhere to Attachment 2.
Evidence Retention Section- Requirement R4 has no obligatory requirement to mitigate the hardware(equipment) limitation. As such, entities should
be obligated to maintain information demonstrating compliance until the issues are mitigated. There should be language within the Requirement to
correct the issue within a certain timeframe. As is, data demonstrating compliance for R4 would not be retained after 5 years and the entity would be
held to performing per R1, R2, and R3 in subsequent compliance monitoring efforts unless tracking (and verification of compliance to R4) existed.
Attachment 1- Consider lowercasing “Through” in Table titles as it is part of the proposed defined single word “Ride-through”. Consider lowercasing
“Continuous Operating Region” as it is not a defined term nor is it capitalized in the Requirement language. Table 1 cannot have “1.1” and “1.10” be
in the Mandatory Operation Region and Continuous Operation Region at the same time (e.g., the mathematical operator shows inclusion.) “1.1”
should be shown a “1.10” for consistency. Footnote 10 is unclear as Type 3 and Type 4 wind turbines are IBRs and the use of “directly” in the footnote
could leave some entities with Type 3 and Type 4 wind turbines to use Table 2. Simply say it is for Type 3 and Type 4 and leave the AC-Connected and
directly connected verbiage out to avoid confusion. Note- Anytime a DT says it is clear the issue gets pushed into the compliance environment where
suddenly no clarity exists. IBR is a definitive example of clear technical understanding but extremely unclear understanding when applying a
compliance lens.
“Voltage Source Converter High Voltage Direct Current” is not defined nor explained. There are inconsistencies in how “Voltage Source Converter
High Voltage Direct Current” is displayed—Footnote 1 is lower cased “v” and contains a hyphen after “High”; Bullet 3 does not have a hyphen in “VSC
HVDC but bullet 2, Footnote 1, and Footnote 2 does.
Need to be consistent with the depiction of the Figures (in Attachment 2) in terms of what the boundary line depicts (inclusion or exclusion within the
“Regions”) as entities have struggled in the past versions of PRC-024 (and others). Figure 1 does not depict the 1.1 Voltage point and therefore
appears to not support the Table (consider moving the 1.05 down to the boundary between the “1800 second” section and “no time requirement”
section depiction while adding 1.1 to the upper boundary of the “1800 second” section.
Figure 2 does not reflect 1.05 Voltage point so the “1800 second" section appears to not be depicted appropriately. Consider adding the 1.05 Voltage
point to the y-axis and redraw boundaries for “1800 second” section and “no time requirement” section. 1.05 should be the upper boundary of the
“no time requirement” section. To provide consistency and clarity, Table 2 X-axis values should reflect the table values as Figure 1 reflected those (for
Table 1) (i.e., show .32 and 1.2).
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Since this is an Operating Horizon based Standard why would Bullet 5 depend upon the PC or TP? Bullet 5 and Bullet 6 do not use the same language
(use of hyphens, use of neutral, use of ground). Is the intent of Bullet 10 to supersede Bullet 8 (i.e., does not matter is the time associated with the 4
deviations is below the time associated with the voltage?)
Attachment 2- Consider lowercasing “Through” in Table titles as it is part of the proposed defined single word “Ride-through”. Table 3 should reflect
consistency in the System Frequency column. The frequency slot between 58.5 and 58.8 is not covered (suspect the 6th row needs adjustment as it is
referencing the same frequency point—58.8). Additionally, it appears that there may be inconsistency in mathematical operators inclusion or
exclusion of certain ranges. DT needs to confirm where 58.8 resides in terms of allowed time. Consider the Table below with bolded changes. For
consistency with Voltage tables “N/A” versus “may trip” is suggested and for consistency the DT may consider a footnote as Tables 1 and 2 did in
Attachment 1 regarding voltage.
System Frequency (Hz)
Minimum Ride-Through Time (sec)
≥64
N/A
< 64 and ≥61.8
6
< 61.8 and ≥ 61.5
299
< 61.5 and > 61.2
660
≤ 61.2 and > 58.8
Continuous
≤ 58.8 and ≥ 58.5
660
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< 58.5 and ≥ 57
299
< 57.0 and ≥ 56
6
< 56
N/A
PRC-024 had “MPT” and “GSU” used and “defined”. Consistency in use here in PRC-029 (with appropriate changes) to correlate with PRC-024 is
appropriate.
VSLs- Requirement R1--DT should consider a different method to assign levels. While the Requirement language may say “each” perhaps a
consideration for the VSL should be fleet-based. As written, the DT has created a “zero” tolerance Requirement. If the design is wrong the operation
would be incorrect. Proving that should not take an event to demonstrate (as the compliance argument this will set up is that “there has not been a
period where operation would have occurred”).
Requirement R2 and Requirement R3- Essentially same comments as VSLs for Requirement R1
Requirement R4- The notification timeframe appears to be initially set at 30 calendar days for all the VSLs (with adjustments considering the 30
calendar day foundation) but the Requirement R4 language indicates a foundation of “90 days” (also an issue noted in Measurement M4). With the
timeframes associated
Implementation Plan—The last sentence regarding Requirement R4 needs to be struck or incorporated within the Requirement
language. Requirement R4 says “hardware limitations” and does not specify the “coordinated protection and control settings”. To be clearer the DT
should consider changing Requirement R4 language to “inability to modify coordinated protection and control functions”. There is a gap between
the language regarding provision of a “copy to applicable entities” in the Lower VSL and what is in the Severe VSL. Effectively the Severe VSL covers
15 month plus 1 day to beyond 24 months. Is that the intent of the DT?
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PRC-024-4
Project Page: The redline of PRC-024-4 is the redline of the standard since last posted. A redline of the standard since last approved (version 3) was
not provided. Both redlines will be provided during the next ballot.
Attachment 2: The team identifies attachments 2A, 2B, 2C to be part of attachment 2. The team will continue to evaluate changes to demonstration
of performance of ride-through within phase II of addressing the current SAR.
PRC-029-1
Plant/facility: The terminology has been changed to IBR to coincide with the new proposed definition for IBR. Additionally, this section has been
modified to include the registration criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on
usage of specific language until the changes had been approved.
Applicability for Sub-BES IBR: This section has been modified to include the registration criteria within the recently approved changes to the NERC
Rules of Procedures. The team was advised to hold on usage of specific language until the changes had been approved.
Measures: The SER/FR/DDR data are necessary to demonstrate compliance with the operational performance aspects of PRC-029. Additional review
of design documents, simulations, etc. is necessary to demonstrate compliance with the design capability-based aspects of PRC-029.
Ride-through definition: The definition for Ride-through has been revised.
Measures. The team has reinserted the word “shall” into the measures; this is shown as “shall have”. The team also agrees that usage of “retain” is
preferable language and have made this change to all measures.
Data retention and identifying excursions: disturbances identified by planners and operators within PRC-030 would trigger the request to hold data
for demonstrating performance. Additional data requirements are established within PRC-030.
R2.1.1: Additionally, a footnote was added to 2.1.1 to clarify returning to available power.
R2.1.3: 95 pu has been corrected to 0.95 pu. There is no obligation or requirement for planners or operators to supply other performance
requirements. The language related to having evidence of other performance requirements was considered necessary for a situation where an entity
receives requirements from a planner or operator that would contradict PRC-029 requirements. The team included this as a means of allowing the GO
to follow requirements as needed by planners/operators and not be in violation of PRC-029 requirements.
R2.1: Language is included to allow GOs the ability to respond to other planner/operator performance requirements as noted and avoid
noncompliance with PRC-029.
R2.2: Bullets are used when there is more than one option (OR) and are appropriate for this instance. Numbers are used when each subpart must be
performed (AND). “facility” has been removed.
Implementation Plan: Implementation Plan has been modified to include bifurcated implementation information between capability-based elements
and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to the full
requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029 implementation.
Further, the disturbances identified by planners and operators within PRC-030, would trigger the request to hold data for demonstrating
performance. Additional data requirements are established within PRC-030.
R4: The 4.1.1 has the word “other” removed. The uppercase “Ride-through” term was corrected. Usage of “hardware” -vs- “equipment” has been
corrected throughout. The team sees the language regarding software limitations or settings to be clarifying language. R4.1.5 appears to be clear to
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the team. If additional information is needed, that would be requested through R4.2. R4 does not require model data to be provided. The Regional
Entity has been changed to the CEA. The team has been advised that inclusion of CEA here is appropriate and has precedent.
M4: The measure has been adjusted to include R4.2.1 response times and R4.3 response times from the entity. Requirements cannot be directed to
Regional Entities in Standards. Concerns regarding acceptability of information that identifies a hardware based limitation will be resolved through
the CEA acceptance. The VSL/VRF tables have been updated accordingly.
Frequency/R3/Attachment 2 Exemptions: In Order No. 901, FERC directed NERC to determine whether the ride-through standard should provide for
a limited and documented exemption for certain registered IBRs from voltage ride through performance requirements, and only for voltage ride
through performance for those existing IBRs that are unable to modify their settings without physical modification of equipment. See Order No. 901
at P 193. The drafting team determined that such an exemption was appropriate and it is included in Requirement R4. The drafting team does not
have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901. The drafting team does believe additional monitoring would be appropriate to determine how many entities would
be affected by such an exemption and whether such an exemption would be consistent with overall Bulk-Power System reliability. To the extent such
monitoring suggests that further exclusions would be appropriate, a future drafting team could make those changes in an expeditious manner. The
affected entities could work with ERO Enterprise staff to address any compliance-related concerns in the interim. For this draft, however, the drafting
team is pursuing a more conservative approach in line with the specific exemptions identified in Order No. 901.
CAPs: Exemptions from R4 are limited to those with hardware-based limitations only. Corrective action plans – or other terms to mitigate the
limitation may be identified as part of PRC-030 analysis, or other planning/operational studies that evaluate the system.
M1: R1 bullet 2 refers to equipment limitations according to R4. The measure for R4 is detailed in M4.
Attachment 1 bullet 4 (previously #5): TO has been added.
Attachment 1 bullets 4 and 5 (previously 5 and 6): have been adjusted to use the same usage of hyphens.
Attachment 1 Bullets 7 and 9 (previously 8 and 10): Yes, this is correct.
Attachment 2 table #3: The table values and operands have been corrected.
Plant/facility: The terminology has been changed to IBR to coincide with the new proposed definition for IBR. Additionally, this section has been
modified to include the registration criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on
usage of specific language until the changes had been approved.
Main power transformer: The footnote for the main power transformer has been moved to the first occurrence of its usage in PRC-029. The standard
does not use GSU.
VSL for percentage of fleet: The severity level is based on the occurrence of the noncompliance. Also, the impact to the system is dependent on a
number of other influencing factors (i.e., loading, local system strength, etc.). Extent of condition analysis is conducted in later stages of the CMEP.
Measure 4 and VSL table: These have been corrected to the correct response times.
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Document Name
Comment
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Response from ITC Holdings:
“IBR Registration Criteria” is not an applicable Facility.
The applicabilities of PRC-028, PRC-029, and PRC-030 need to be aligned. E.g. A TO that owns the VSC-HVDC connection for offshore wind is subject
to PRC-029 but not PRC-028 or PRC-030.
R1 has no value as a standalone requirement and should be incorporated into R2. In other words, you can’t violate R1 without also violating R2, so
eliminate R1 or incorporate its subtle value into R2.
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Response
Thank you for your comment
sub-BES IBR: The applicability section has been modified to include the registration criteria within the recently approved changes to the NERC Rules of
Procedures. The team was advised to hold on usage of specific language until the changes had been approved.
Alignment: This issue has been addressed.
R1/R2: R1 requires ride-through within the must Ride-through zone. R2 includes additional performance requirements beyond tripping/momentary
cessation/failing to Ride-through.
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
Minnesota Power supports EEI’s comments.
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Thank you for your comment. Please see the response to EEI.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has the following comments on the PRC-024-4 draft:
•
Requirements R1, R2, and R4 use the term ‘Facility’ when referencing synchronous generator, type 1 or type 2 wind resource, or synchronous
condenser. Requirement R3, however, uses a description of the Facility. Texas RE recommends using the term Facility to be consistent with
the other requirements. Texas RE recommends the following revision (in bold):
R3. Each Generator Owner and Transmission Owner shall document each known regulatory or equipment limitation that prevents an its synchronous
generator, type 1 or type 2 wind resource, or synchronous condenser Facility, with applicable frequency or voltage protection from meeting the
protection setting criteria in Requirements R1 or R2, including (but not limited to) study results, technical incapability identified after experience
from an actual event, or manufacturer’s advice.
‘Technical incapability identified after’ language is added to clarify that the Facility Owner must conduct detailed analysis to ensure that the Facility is
technically incapable of providing the required system support and the specific technical limitations should be documented.
•
Please update footnote 4 (Requirement 2.1) on page 5 of 22 (clean version) - changes in bold font:
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s), or synchronous condenser(s); or (ii) provide
signals to same to trip the same Facilities.
•
In Requirement R4, Texas RE recommends that each Generator Owner and Transmission Owner shall provide its applicable protection settings
to Planning Coordinator and Transmission Planner. The applicable data should be provided to both the Planning Coordinator and
Transmission Planner so the study model(s) used by Planning Coordinator and Transmission Planner can be updated concurrently. Texas RE
recommends the following revision (in bold):
R4. Each Generator Owner and Transmission Owner shall provide its applicable protection settings associated with Requirements R1 and R2 to the
Planning Coordinator or and Transmission Planner that models the associated Facility within 60 calendar days of receipt of a written request for the
data and within 60 calendar days of any change to those previously requested settings unless directed by the requesting Planning Coordinator or
Transmission Planner that the reporting of protection setting changes is not required. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
It is important that the applicable data is provided to the Planning Coordinator and Transmission Planner so that the study model(s) used by PC and
TP can be updated concurrently.
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•
Technical Rationale document - Texas RE recommends the Facilities section include the Frequency and Voltage Protection Settings for Type 1
and Type 2 Wind Resources in addition to the Synchronous Generators and Synchronous Condensers in the title document since they were
added to section A 4.2.1.4 of the standard. Texas RE recommends the following revision (in bold):
Facilities (4.2)
Applicability Facilities subparts in Section 4.12.1 were modified to restrict PRC‐024‐4 to synchronous generators and Type 1 and Type 2 Wind
Resources. Section 4.2.2 was added as new subparts to identify which synchronous condensers and equipment.
PRC-029-1 Comments
•
Ride-through definition: Ride-through capability is the ability of the resource to continuously deliver power during a disturbance event. It
appears the phrase ‘continuing to operate’ used in the Ride-through definition is intended to state that the Facility needs to deliver power in
response to system conditions. Texas RE recommends the following revision (in bold):
Ride-through: Remaining connected, synchronized with the Transmission System, and continuing to operate by delivering power in response to
System conditions through the time-frame of a System Disturbance.
Applicability Section 4.2.1: Footnote 2 refers to ‘offshore wind plants connecting via dedicated VSC-HVDC”. Texas RE recommends revising this
footnote to include offshore and on-land VSC-HVDC. Texas RE recommends the following revision (in bold):
For the purpose of this standard, “inverter-based resources” refers to a collection of individual solar photovoltaic (PV), Type 3 and Type 4 wind
turbines, battery energy storage system (BESS), or fuel cells that operate as a single plant/resource. In case of offshore any wind plants connecting via
a dedicated VSC-HVDC, the inverter-based resource includes the VSC-HVDC system.
•
•
Applicability Section 4.2.2: Texas RE recommends revising the verbiage to “Resource which meets IBR Registration Criteria”.
Requirement R1: Texas RE recommends clarifying the first bullet to state that the facility is electrically disconnected in order to clear a fault
within its protection zone as designed. Texas RE recommends the following revision (in bold):
The facility needed to electrically disconnect in order to clear a fault within its zone of protection as designed;
•
Measures: Texas RE noticed the Measures for IBRs in PRC-029-1 are more burdensome than the Measures for synchronous
generators in PRC-024-4. Though Measures are not enforceable, they are instructive in which activities could be used to demonstrate
compliance with a Requirement. For synchronous generators in PRC-024-4, the Measures indicate that a Generator Owner or Transmission
Owner can demonstrate compliance by providing a settings sheet or supporting calculations, or the synchronous generator can instead rely
on dynamic simulation studies. In contrast, the Measures in PRC-029-1 indicate that the IBR shall have dynamic simulations, studies, or other
evidence to demonstrate the design of each Facility, and the Measures also indicate that the IBR shall have evidence of actual disturbance
monitoring to demonstrate performance of the Facility in actual historical Ride-through events. These Measures appear to be more
burdensome for IBRs than for synchronous generators and also appear to suggest obligations exist beyond what is stated in the enforceable
Requirement text.
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•
Measures: Since the measures are not enforceable, Texas RE encourages the SDT to consider removing shall statements from the
measures. Texas RE recommends using similar verbiage to the measures in the CIP standards, which say “Examples of evidence may include,
but are not limited to…”
Measure M1: The first sentence in Measure M1 shows the word “shall” removed, but nothing was put in its place. Is that the intent
of the SDT?
•
Requirement Part R2.1.3: Texas RE recommends revising Requirement Part 2.1.3 from passive to active voice so it is clear that the
Generator Owner or Transmission Owner is the entity giving preference. Texas RE recommends the following revision (in bold):
•
If the facility cannot deliver both active and reactive power due to a current or apparent power limit or reactive power limit, when the applicable
voltage is below 95% per unit and still within the continuous operation region, then the Generator Owner or Transmission Owner shall give
preference to active or reactive power as required by the Transmission Planner, Planning Coordinator Reliability Coordinator, or Transmission
Operator.
•
Requirement Part 2.5: If a small number of the inverters or turbines trip offline at a facility during a fault while the voltage remains in
the mandatory operation region, will that facility be in violation of Requirement R 2.5?
•
Requirement R4: Texas RE noticed Requirement R4 does not provide an opportunity for legacy Facilities to identify an equipment
limitation after 12 months from the effective date of PRC-029-1. PRC-029-1 R1 provides an exception for IBRs that document equipment
limitations in accordance with R4. In PRC-029-1 R4, a Facility that existed before the effective date of PRC-029-1 shall identify and document
information supporting identified hardware limitations no later than 12 months from the effective date of PRC-029-1. Is the intention that
equipment limitations identified after this 12-month window will not be eligible for the exception in PRC-029-1 R1? For a Facility that
identifies an equipment limitation in the 13th month or beyond, does the SDT intend for that IBR to still be able to document the equipment
limitation and qualify for the exception in R1, albeit with the obligation to submit a Self-Report for failing to meet the 12-month deadline in
R4? Alternatively, does the SDT intend that an IBR that does not identify an equipment limitation within the 12-month window should never
be able to qualify for the exception in R1?
•
Requirement R4: Texas RE recommends the measures include evidence that the Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and to the Regional Entity the documented information supporting the identified
hardware limitation.
Attachment 1: Figure 1: Voltage Ride-Through Requirements for AC-Connected Wind Facilities graphical representation should be
corrected to match Tables 1 and 2. The continuous operating region is between 1.05-0.9 and Continuous Operating Region (1800 seconds)
time delay is greater than 1.05-1.1 voltage level. In Figure 1, Texas RE recommends adding 1.1 above 1.05 in the Continuous Operating
Region (1800 seconds). In Figure 2, Texas RE recommends replacing 1 with 1.05.
•
•
Attachment 2: Frequency Ride – Through Criteria table 3 should be updated to reflect the correct low frequency levels for 660 seconds time
delay.
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≤ 58.8 and < 58.8 58.5
Page 16 onward: The Mandatory Operation Region and Continuous Operation Region phrases should be lowercase to match changes made to
rest of the standard.
•
Texas RE noticed the word “facility” is lowercase throughout (redline shows it replaces IBR, e.g. in R1). If the intent is to be consistent the
applicability, Texas RE recommends using the term “applicable facility” to refer back to 4.2 Applicability section.
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Response
Thank you for your comment.
PRC-024
Facility: The team agrees and has modified R3 to use “Facility”, consistent with R1 and R2.
Equipment limitations: R3 already requires equipment limitations be documented and that information regarding the limitation much by
communicated.
Footnote 4: This footnote has been corrected as suggested.
R4: The team identifies that the information is available upon written request.
TR PRC-024: The technical rationale will be revised to include type 1, type 2 wind.
PRC-029
R1 – bullet 1: The team identifies that existing language is sufficient.
Measures: Measures M1-M3 have been revised to address using examples to achieve objectives.
R2.1.3: Active voice language has been included.
R2.5: If partial tripping prevents the IBR from returning to pre-disturbance active/available power level, it would result in potential noncompliance.
Footnote #10 has been added for clarity.
R4: The purpose of this requirement is to identify the extent of legacy Facilities requiring an exemption (and the associated reliability impacts) as soon
as is reasonably feasible. Entities should exercise all due diligence to identify their equipment limitations within this 12-month period. However, to
the extent an entity determines that they have an equipment limitation after this 12 month period, they may still apply for the exemption, subject to
any compliance implications for failing to apply within the 12-month period.
Attachment 2: This table has been corrected.
Terminology: The operation region names have been addressed. Usage of “facility” has been replaced with the proposed term “IBR”.
John Pearson - ISO New England, Inc. - 2
Answer
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Document Name
Comment
ISO New England signs onto comments of the Standard Review Committee of the ISO/RTO Council.
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Response
Thank you for your comments. Please see the response to the ISO/RTO Council.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Document Name
Comment
•
•
•
•
Likes
Bureau of Reclamation (BOR) notes that PRC-024-4 draft 2 is redlined to the draft 1 (clean version). Draft 2 has accepted all of the redlines
from Draft 1, yet the ballot for Draft 1 was below the two-thirds majority of the weighted Segment votes requirement for approval per
Appendix 3A of NERC’s standard process manual V5 dated 11-28-2023.
Recommend SDT provide a separate comment form for each Standard under development.
PRC-029-1 is not applicable to BOR.
BOR recommends an 18-month implementation timeline for both standards.
0
Dislikes
0
Response
Thank you for your comment.
Project Page: The redline of PRC-024-4 is the redline of the standard since last posted. A redline of the standard since last approved (version 3) was
not provided.
Comment forms: The team will take this under advisement for the next ballot.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation.
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Ruchi Shah - AES - AES Corporation - 5
Answer
Document Name
Comment
•
•
•
Likes
AES CE fully supports the SEIA working group and other industry comments on allowing exceptions for frequency ride through.
AES CE is concerned by the updated language in several Measures reading “Each Generator Owner and Transmission Owner have evidence of
actual disturbance monitoring…” and believe that the simulations and studies used to demonstrate compliant design should be sufficient,
similar to PRC-024. There will be many plants that do not experience an applicable disturbance before this Standard becomes effective and
therefore cannot demonstrate adherence to ride-through requirements as prescribed. We are also concerned about expectations for this
Measure as time goes on, are we expected to document and record every applicable disturbance and the asset’s performance? Additional
clarification is required if the Drafting Team believes that actual disturbance monitoring language should remain in the Measures.
The required protection is not currently modeled in basic models and will require substantial effort to ensure we can perform as required.
AES CE requests that the Implementation Plan be modified to use a phased-in approach for existing sites to allow adequate time to prepare
for these performance requirements. We suggest that the Implementation Plan for PRC-029 should align or lag the Implementation Plan for
PRC-028.
0
Dislikes
0
Response
Thank you for your comments.
Frequency/R3/Attachment 2 Exemptions: In Order No. 901, FERC directed NERC to determine whether the ride-through standard should provide for
a limited and documented exemption for certain registered IBRs from voltage ride through performance requirements, and only for voltage ride
through performance for those existing IBRs that are unable to modify their settings without physical modification of equipment. See Order No. 901
at P 193. The drafting team determined that such an exemption was appropriate and it is included in Requirement R4. The drafting team does not
have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901. The drafting team does believe additional monitoring would be appropriate to determine how many entities would
be affected by such an exemption and whether such an exemption would be consistent with overall Bulk-Power System reliability. To the extent such
monitoring suggests that further exclusions would be appropriate, a future drafting team could make those changes in an expeditious manner. The
affected entities could work with ERO Enterprise staff to address any compliance-related concerns in the interim. For this draft, however, the drafting
team is pursuing a more conservative approach in line with the specific exemptions identified in Order No. 901.
Measures: the measures are written to provide specific examples of evidence needed for compliance. Further the implementation plan has been
revised to bifurcate between capability-based elements and performance-based elements. Essentially this is now a phased-in implementation plan
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whereas each entity will be required to respond to the full requirement over time. This will allow entities to align their PRC-028 and the performancebased aspects for PRC-029 compliance.
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Document Name
Comment
PNM agrees with the comments made by EEI.
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Thank you for your comment. Please refer to the response to EEI.
Carver Powers - Utility Services, Inc. - 4
Answer
Document Name
Comment
The term “active power” is not defined and appears to be used in conjunction with Real Power. Recommend consistency throughout the standards
when using Real Power vs active power, such as MOD-025, BAL-001, and many others.
Recommend the DT reevaluate the implementation period of 6 months. Recommend making implementation period 18 months or greater to account
for the need for working with OEMs to implement any setting changes and the need for IBR settings reviews conducted by third parties, as necessary.
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Response
Thank you for your comment.
Active Power: The terms have been replaced with those from the glossary.
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Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation.
Daniel Gacek - Exelon - 1
Answer
Document Name
Comment
Exelon supports the comments submitted by the EEI.
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Response
Thank you. Please see the response to EEI.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
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Response
Thank you. Please see the response to the NPCC Regional Standards Committee
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
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Document Name
Comment
EEI offers the following Comment to Draft 2 for PRC-024 and PRC-029.
PRC-024-4 Comments:
EEI has no substantive concerns with any of the proposed changes to PRC-024-4 but point out a minor typo in Requirement R2 (below).
R2. Each Generator Owner and Transmission Owner shall set applicable voltage protection in accordance with PRC-024-4 Attachment 2, such that
the applicable protection does not cause the Facility to which it is applied to trip within the “no trip zone” during a voltage excursion at the high-side
of the GSU or MPT, subject to the following exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
PRC-029-1 Comments:
While EEI appreciates that changes made to address our previous comments for the 1st draft of PRC-029-1, we have some new concerns that need to
be addressed.
Our high level concerns are described in our comments below:
1. The Standard attempts to redefine the approved definition of IBR by adding VSC-HVDC systems after the IBR definition was approved by the
industry.
2. The Standard adds TOs to this Standard solely to address VSC-HVDC systems, yet no technical justification has been provided. Moreover,
these systems were not identified in FERC Order No. 901, or this SAR and they were not clearly identified in the Applicability Section of this
proposed Reliability Standard.
3. EEI is concerned with the inclusion of requirements that are not clearly defined or set by multiple registered entities (i.e., TP, PC, RC, or
TOP). This creates regulatory confusion and places IBR-GOs in a position where they may need to comply with any number of entities without
clearly defining who is responsible. (See Requirement R2, subpart 2.1.3; subpart 2.2 (bullet 2); subpart 2.5) Moreover, the identification of
multiple entities who could be responsible creates a situation where IBR-GOs will have reporting obligations to multiple entities because no
single entity is identified as being responsible. (See requirement R4, subparts 4.2 & 4.2.1; subpart 4.3) We further note that none of the
entities identified (i.e., TP, PC, RC, or TOP) are identified within the Applicability section of this proposed Reliability Standard. All of this can
create confusion and places a considerable burden on the IBR-GOs that needs to be resolved and clarified.
4. Throughout this Reliability Standard there is use of non-glossary terms (i.e., active power vs. Real Power) where glossary terms are available
and should be used. While in other cases glossary terms are used but not capitalized. (e.g., reactive power vs. Reactive Power) Greater
efforts should be made to use NERC Glossary terms where appropriate and capitalize those terms, as required.
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Detailed Concerns
Ride-through Definition Comments:
EEI does not support the proposed definition for “Ride-through” as proposed because it is too vague and contains no defined limits, as proposed. We
recommend the following changes:
Ride‐through: Ability to withstand voltage or frequency Disturbances within defined regulatory limits remaining connected, synchronized with the
Transmission System, and continuing to operate.
Applicability Section Comments:
Footnote 1: EEI does not support adding TO that own VSC-HVDC systems because this was not a scope item and is therefore not be included in the
scope of this SAR. Moreover, Footnote 1 conflicts with Footnote 2 which defines VSC-HVDC as an IBR, which is again does not in alignment with the
approved definition of an IBR.
Footnote 2: EEI does not support Footnote 2 because it expands the definition of IBRs beyond what was recently approved by the industry, noting the
expansion of IBRs to include VSC‐HVDC. Furthermore, there was no technical justification for adding VSC-HVDC and the SAR did not include adding
VSC-HVDC systems to this project. For this reason, we ask that the definition of IBR not be expanded through footnotes and suggest that the DT
submit a technical justification for adding VSC-HVDC systems to the applicability section of this Standard, rather than redefining an approved
definition in a footnote.
To address our concerns related to Footnotes 1 & 2 we suggest that if VSC-HVDC systems are to be classified as IBRs, then the approved definition
should be pulled by NERC and resubmitted with those resources added to the definition and resubmitted to the industry for approval. Alternatively,
VSC-HVDC systems could be defined separately, and that definition submitted to the industry for approval. In both cases, a technical justification
should be provided to the industry that defines the issues and risks to BPS reliability that VSC-HVDC systems pose.
EEI suggests that if the DT believes that certain IBR capabilities as identified under Requirement R2 need (or may need) to be specified then they
should identify the entity who should be responsible among the four identified (i.e., TP, PC, RC or TOP); add them to the applicability section of this
Reliability Standard; add clear requirements and adjust the reporting obligations for the IBR-GO under Requirement R4.
Requirement R1 & R2 Comments: EEI does not agree with the inclusion of Transmission Owners because they would only have an obligation under
this Reliability Standard if VSC-HVDC systems were included. Given we do not support the inclusion of VSC-HVDC systems without a technical
justification and modified SAR, we ask that Transmission Owners be removed from Requirement R1.
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Additional Requirement R2 Comment: EEI suggests that there should be clearer linkage between Requirement R1 and R2. We are also concerned
that R2 only exempts documented equipment limitations but does not also include the exemptions provided within R1. To address these concerns,
we offer the following edits to Requirement R2:
R2. Each Generator Owner shall ensure the design and operation of the voltage performance of its IBR Facilities adheres to the following conditions
in accordance with Requirement R1. [Violation Risk Factor: High] [Time Horizon: Operations Assessment]
EEI also suggests that the “each facility” be replaced with “IBR Facilities” because the use of the uncapitalized version of facility is too broad, making
compliance requirement unclear.
Measures M1 & M2: EEI is concerned that M1 & M2 contains measures that are overly prescriptive providing little discretion to IBR-GOs in
demonstrating their compliance with Requirements R1 and R2 that seem to align more with a Requirement than a Measure. To address our concerns,
we offer the following suggested changes to M1 and suggest similar changes be made to M2:
M1. Each Generator Owner shall have evidence that supports the Ride-through capability of each of their facilities, as specified in Requirement R1.
(e.g., simulations, studies, recorded data from disturbance monitoring equipment, etc.) If the Generator Owner choose to utilize Ride-through
exemptions that occur within the “must Ride-through zone” and are caused by non-fault initiated phase jumps of greater than 25 electrical degrees,
then each Generator Owner shall also have evidence supporting that exemption. (e.g., studies, simulations or supporting data from disturbance
monitoring equipment)
Requirement R3 & R4: EEI does not support the inclusion of Transmission Owners within Requirements R3 & R4 for the same reasons identified
above.
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Response
Thank you for your comment.
PRC-024
R2: The errata has been corrected.
PRC-029
IBR Definitions: While the definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an acceptable
resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove usage of
unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another version of a
definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC-029, will include
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this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects associated with
Milestone 3 as determined by those teams. Further, regarding sub-BES IBR: the applicability section has been modified to include the registration
criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on usage of specific language until the
changes had been approved.
Transmission Owner: The transmission owner has been removed from PRC-029.
Other Performance Requirements: The language related to having evidence of other performance requirements was considered necessary for a
situation where an entity receives requirements from a planner or operator that would contradict PRC-029 requirements. The team included this as a
means of allowing the GO to follow requirements if needed by planners/operators and not be in violation of PRC-029 requirements. Planners and
operators are not required to provide other performance requirements and are not applicable to this Standard. The language reads that as long as an
entity is able to demonstrate that deviations from PRC-029 performance are due to other requirements provided by any of the listed entities, that the
GO would not be in noncompliance.
Applicability: As a follow up to the response for Transmission Owner and Other Performance Requirements, the team identifies no obligation or
requirement for entities, other than the GO, for any requirements in PRC-029.
Active Power: The terms have been replaced with those from the glossary.
Ride-through definition: The definition for Ride-through has been revised.
R1/R2: R1 requires ride-through within the must Ride-through zone. R2 includes additional performance requirements beyond tripping/momentary
cessation/failing to Ride-through.
Measures: the measures are written to provide specific examples of evidence needed for compliance. Further the implementation plan has been
revised to bifurcate between capability-based elements and performance-based elements. Essentially this is now a phased-in implementation plan
whereas each entity will be required to respond to the full requirement over time. This will allow entities to align their PRC-028 and the performancebased aspects for PRC-029 compliance.
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal Utility
District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3, 6, 4, 1, 5;
Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim Kelley, Group
Name SMUD and BANC
Answer
Document Name
Comment
Regarding PRC-024-4, SMUD has no comments and supports the Standard Drafting Team (SDT) in this latest version of the Standard.
Regarding PRC-029-1, SMUD has the following comments:
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1) The voters in Project 2020-06, Inverter-based Resource Glossary Terms draft #2, approved the definition of IBR on April 8, 2024, which is
different than the definition proposed in Footnote 2 of PRC-029-1. Using the term “inverter-based resources” and defining it with Footnote 2 is
inefficient and would create two definitions for the same resource.
The SDT of PRC-029-1 should coordinate with the SDT of Project 2020-06, and NERC staff, to ensure the definition of IBR and new PRC-029-1 are
submitted to FERC simultaneously thereby eliminating another ballot for PRC-029-1 to add the NERC Glossary Term for IBR into the standard and
eliminate confusion between IBR and “inverter based resources.”
2) Requirement R2.2, the term “IBR” should be replaced with “facility” to be consistent with the rest of the Standard. As currently written,
Requirement R2.2 states “While voltage at the high-side of the main power transformer is within the mandatory operation region as specified in
Attachment 1, each IBR [emphasis added] shall…”
3) Requirement R2.1.3 should specify only one entity. As currently written, this sub-requirement gives Transmission Planners, Planning
Coordinators, Reliability Coordinators, or Transmission Operators the ability to require the facility to deliver active or reactive power. The SDT should
make it clear which single entity can set the requirement to avoid any conflicts.
4) Measure 1 and Measure 2 contain the language “Each Generator Owner and Transmission Owner also have evidence of actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrating that the operation of each
facility did adhere to performance requirements [emphasis added]…”
Some facilities may not have sufficient data from actual system disturbances by the time this Standard becomes mandatory and enforceable. The SDT
should allow for the use of simulations and studies to demonstrate compliant design, similar to PRC-024, in such cases where the facility does not
have evidence of an actual disturbance.
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Response
Thank you for your comments.
IBR Definitions: While the definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an acceptable
resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove usage of
unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another version of a
definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC-029, will include
this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects associated with
Milestone 3 as determined by those teams. Further, regarding sub-BES IBR: the applicability section has been modified to include the registration
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criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on usage of specific language until the
changes had been approved.
Plant/facility: The terminology has been changed to IBR to coincide with the new proposed definition for IBR. Additionally, this section has been
modified to include the registration criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on
usage of specific language until the changes had been approved.
R2.1.3: There is no obligation or requirement for planners or operators to supply other performance requirements. The language related to having
evidence of other performance requirements was considered necessary for a situation where an entity receives requirements from a planner or
operator that would contradict PRC-029 requirements. The team included this as a means of allowing the GO to follow requirements as needed by
any planner/operator and not be in violation of PRC-029 requirements.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation.
Kyle Thomas - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Elevate appreciates the opportunity to comment on the draft NERC standards, particularly those pertaining to future IBR NERC Reliability Standards
and FERC Order No. 901 directives.
Adoption of, or Alignment with, IEEE 2800-2022
Elevate continues to strongly encourage NERC to reconsider adoption of IEEE 2800-2022. The unwillingness to adopt IEEE 2800-2022 by NERC is
leading to entirely duplicative efforts that are not serving any additional value as compared to the work conducted in the IEEE 2800-2022
developments. It does not appear that a holistic approach and strategy is being taken to meet the FERC Order No. 901 directives, which is leading to
very low ballot scores, significant rework, and misalignment with industry recommended practices.
The draft NERC PRC-029 is duplicative with IEEE 2800-2022 Clause 7 yet only covers a small fraction of the IBR-specific capability and performance
requirements outlined in that clause. Therefore, there is no clear reliability benefit versus the cost of implementation PRC-029 as compared with IEEE
2800-2022 and the recommendations set forth in the NERC disturbance reports and guidelines.
Elevate strongly recommends a single NERC standard that adopts IEEE 2800-2022 in a uniform and consistent manner. NERC can also issue a
reliability guideline or implementation guidance that supports industry implementation of the standard. Rather than recreate parts of IEEE 2800-2022
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inconsistently over multiple different standards, Elevate recommends a singular standard for BPS-connected IBR capability and performance
requirements related to IEEE 2800-2022. Additional NERC standards can be developed where needed in situations where they are not covered
directly with IEEE 2800-2022 (e.g., NERC PRC-030).
Concerns with Draft PRC-029
If the draft PRC-029 standard is to be pursued as currently structured, Elevate would like to highlight the following concerns:
Inconsistencies with PRC-029 and IEEE 2800-2022: There are numerous inconsistencies in the draft standard language and attachment 1 and 2 when
compared to IEEE 2800-2022. These should be considered and reviewed for clarity and completeness in the standard. The option to cite IEEE 28002022 and use the requirements in the IEEE 2800-2022 directly should be allowed over just the use of Attachment 1/2 (i.e. give each GO/TO the ability
to use either of these guides to base their performance off on).
IEEE 2800 identifies the following items, but the standard does not support. Clarification/review should occur for each of these items:
IEEE 2800 recognizes FRT requirement limitations, but the standard does not.
IEEE 2800 recognizes exceptions for Negative-sequence voltage exceeding thresholds
IEEE 2800 recognizes Volts/Hz limitations, but the standard does not.
IEEE 2800 recognizes 500kV system voltages are actually operated in the range of 525kV and therefore has equipment rated to 550kV. These 500kV
operating conditions should be considered in the standard.
In IEEE 2800 the frequency ride-through criteria defines 10-minute time periods whereas the standard defines them in a 15 minute time period (Table
3 of Attachment 2). This should be clarified and identified.
Attachment 1: Voltage Ride-through criteria has issues that should be corrected. Row 2, voltage (per unit) has an error, the mathematical operand
should be “greater than” for the 1.10 value; this entry should read “=< 1.20 and > 1.10”.
Attachment 1: frequency ride-through criteria should be updated to fully match with IEEE 2800. Creating a different FRT ride-through curve without
adequate technical justification will continue to challenge the industry.
The SDT should consider allowing for FRT and V/Hz exemptions, similar to what is already in place for VRT exemptions. Legacy equipment limitations
apply to FRT, V/Hz, and VRT ride-through requirements, so exemptions should be allowed for both.
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The standard should be updated to explicitly state that the voltage ride-through curves are to be interpreted as voltage vs time duration as is stated in
IEEE 2800. This is to ensure that there is no incorrect interpretation that these curves are “envelope” curves. This could be done by adding a new note
to explicitly call out the voltage vs time duration interpretation of the curves.
Alignment with FERC Directive for IBR Registration: BPS-connected/non-BES IBRs should be applicable to this standard, as it aligns with the FERC
order activities and the on-going NERC Registration effort to incorporate the non-registered BPS-connected IBRs that are owned/operated by the new
proposed Category 2 GO and GOP entities. Exclusion of these BPS-connected resources would significantly limit the ability to ensure that all BPSconnected IBRs have adequate voltage and frequency ride-through requirements during BPS/BES disturbances.
Alignment with NERC Glossary Definitions for IBRs: Creating a new definition for “inverter-based resources” is not aligned with the on-going IBR
standard related work throughout NERC. By creating a new definition, it seems counter-productive to have a unique definition of IBRs and IBR units
under the different NERC standards. Having all standards aligned to the new core NERC Glossary definition for IBRs will make all this standard
development work, execution of the standards, and compliance activities more efficient for all entities involved.
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Response
Thank you for your comments.
IEEE-2800: PRC-029 and IEEE-2800 do not have any contradictory requirements. Requirements within the NERC PRC-029 address the scope of the
SAR and assigned directives from FERC Order No. 901. While some language between this draft aligns with IEEE-2800, NERC Standards are
mandatory and enforceable requirements; in contrast to IEEE-2800.
Rules of Procedure regarding Standards Development: The team has been advised that NERC Standards cannot rely on information external to the
Standard or would be in violation of the NERC Rules of Procedure.
Frequency: Alignment with IEEE-2800 regarding frequency exemptions would directly contradict assigned FERC directives. In Order No. 901, FERC
directed NERC to determine whether the ride-through standard should provide for a limited and documented exemption for certain registered IBRs
from voltage ride through performance requirements, and only for voltage ride through performance for those existing IBRs that are unable to
modify their settings without physical modification of equipment. See Order No. 901 at P 193. The drafting team determined that such an
exemption was appropriate and it is included in Requirement R4. The drafting team does not have sufficient data at this time to determine
whether additional frequency-based exemptions are appropriate and consistent with the overall reliability goals of Order No. 901. The drafting
team does believe additional monitoring would be appropriate to determine how many entities would be affected by such an exemption and
whether such an exemption would be consistent with overall Bulk-Power System reliability. To the extent such monitoring suggests that further
exclusions would be appropriate, a future drafting team could make those changes in an expeditious manner. The affected entities could work with
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ERO Enterprise staff to address any compliance-related concerns in the interim. For this draft, however, the drafting team is pursuing a more
conservative approach in line with the specific exemptions identified in Order No. 901.
Applicability Section – This section has been modified to reflect the current IBR definition as well as the approved changes to registration within
the NERC Rules of Procedure. These modifications are consistent with changes to the applicability section within PRC-028 and PRC-030.
IBR Definitions: While the previous definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an
acceptable resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove
usage of unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another
version of a definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC029, include this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects
associated with Milestone 3 as determined by those teams. Further, regarding sub-BES IBR: the applicability section has been modified to include
the registration criteria within the recently approved changes to the NERC Rules of Procedures. The team had been advised to hold on usage of
specific language until the changes were approved.
Colin Chilcoat - Invenergy LLC - 6
Answer
Document Name
Comment
Thank you for the opportunity to provide comments and for your work on this project. Invenergy provides the below comments for the Drafting Team
to consider:
R1: In response to industry comments, the SDT indicated that Requirement R5 from Draft 1 was removed, but it appears the phase-angle jump
requirements have simply been reinserted under Requirement R1 in this second draft. As drafted, a facility is expected to ride-through fault-initiated
switching events regardless of the magnitude of voltage phase angle change. Consider that positive sequence phase angle change cannot be
accurately measured during a fault occurrence and clearance. We propose the assessment of ride-through performance during fault occurrence,
clearance, and recovery be based only on the voltage ride-through criteria in Attachment 1 Table 1 and Table 2.
We recommend reverting the “Voltage (per unit)” columns of Table 1 and Table 2 back to their first draft state to remain consistent with Tables 11
and 12 of IEEE 2800.
R2.1.3: The decimal place is missing from “95 per unit.”
R2.2: Consider more clearly defining “maximum capability.” As an alternative, R2.2 could state, “…each IBR shall exchange current, up to the total
sum of the nameplate current rating of online IBR units in the plant to provide voltage support…”
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R2.3.1: Consider removal of this requirement. The time it should take a facility to restart current exchange following blocking seems irrelevant if the
other ride-through performance requirements are being met.
Attachment 1: Note 11 from Attachment 1 should be removed. There are many equipment protection settings that are near instantaneous to protect
against current or voltage surges that far exceed the equipment’s maximum rating. A power electronic switch could burn out in a matter of microseconds due to such a surge, before any tripping decision could be made if the filtering length must be at least 16.6 milliseconds.
R3: We recommend reverting the “System Frequency (Hz)” columns of Table 3 back to its first draft state to remain consistent with Tables 15 of IEEE
2800.
The Consideration of Comments document seemed to indicate that the drafting team intended to respond to our previous comment regarding the
expansion of the frequency ride-through range, but none was provided. The proposed 6-second frequency ride-through capability requirement for
the ranges of 61.8Hz to 64Hz and 57Hz to 56Hz does not align with the requirements on the rest of the BES and would expose synchronous generators
to dangerous variations in frequency. Can the drafting team cite more specific reasoning or data to support the expansion of the frequency ridethrough capability requirement to the range of 64Hz to 56Hz, well beyond the IEEE 2800-2022 standard frequency ride-through requirement and the
capabilities of many legacy IBRs?
R4: We recommend the following revision to R4.
R4. Each Generator Owner and Transmission Owner identifying a facility with a signed interconnection agreement by the effective date of PRC-029-1
with known hardware limitations that prevent the facility from meeting ride-through criteria as detailed in Requirements R1, R2, and R3, and requires
an exemption from specific ride-through criteria shall:
Exemptions in R4 should be based on the execution of the interconnection agreement rather than the in-service date of the facility. As drafted,
facilities with executed interconnection agreements, but not yet in-service by the effective date of the standard may need to make significant
equipment modifications and perform interconnection restudies to comply with requirements that did not become effective until after the
interconnection agreement was executed.
Regarding the lack of frequency ride-through exemptions, the limited exception language in FERC Order 901 is not supported by any comments or
other evidence in the record in the original NOPR proceeding, and therefore we believe this to be an inadvertent omission and unjustified application
of Order 901 in the draft language of PRC-029-1. In fact, in the NOPR, FERC proposed to direct NERC “to develop new or modified Reliability Standards
that would require Generator Owners and Generator Operators to ensure that their registered IBR facilities ride through system frequency and
voltage disturbances where technologically feasible.” The drafted frequency ride-through performance requirements are not technologically feasible
for many legacy IBRs.
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Further, in Order 901, FERC “encourage[s] 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.” Requirement R3 of PRC-024-3, and the currently drafted version of PRC024-4, allows for exemptions from both the frequency and voltage ride-through requirements due to equipment limitations.
Given the lack of a clear evidentiary record on this point, the drafting team should rely on the discretion FERC has always granted NERC when it comes
to drafting and implementing practical Reliability Standards. Invenergy recommends Requirement R4 be amended to allow limited exemptions from
specific voltage and frequency ride-through criteria for facilities with known hardware limitations that prevent the facility from meeting the ridethrough criteria detailed in Requirements R1, R2, and R3.
Finally, Invenergy has concerns regarding the deviation of this project from its original goal of developing a standard that will require ride-through
performance from all generating resources. As currently drafted, PRC-024-4 imposes fewer ride-through performance responsibilities on synchronous
generators while allowing broader exemptions from its requirements than PRC-029-1. This undue discrimination permits scenarios in which both a
synchronous generator and an IBR could trip offline due to the same system disturbance and only the IBR would be subject to a potential
noncompliance, assuming the synchronous generator did not trip due to its protection system settings.
Implementation Plan: In its Consideration of Comments, the drafting team indicated that the Implementation Plan has been modified such that PRC029-1 shall become effective on the first day of the first calendar quarter that is 12 months after the effective date of the applicable governmental
authority’s order approving PRC-028-1, however the Implementation Plan still lists an implementation timeframe of six months.
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Response
Thank you for your comments.
Phase angle: The team has clarified language in R1 that there is a potential exemption for phase angle jumps greater than 25 degrees during non-fault
switching events.
Attachment 1 tables: The tables have been adjusted as suggested.
R2.1.3: 95 per unit has been corrected to 0.95 per unit
R2.3.1: The team identifies this requirement as still needed to guarantee the IBR exits out of the current block mode when the high side of the main
transformer voltage recovers back to the mandatory or continuous operation regions. Additionally, clarity has been added to the Technical Rationale.
R2.2: The team believes that the usage of maximum capability is clear.
R2.3: The team has included this specific instance of allowing current block mode which would cause momentary cessation and is not required to be
used.
Attachment 1 notes: Some notes have been modified for clarity.
R3: Table 3 has been revised.
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R4: Exemptions in R4 are based on confirmed expectations from FERC regarding the “existing” or “legacy” IBR. The team was advised that IBR that
have not yet been built or Interconnected would not meet that expectation.
Frequency-based requirements exemptions: In Order No. 901, FERC directed NERC to determine whether the ride-through standard should provide
for a limited and documented exemption for certain registered IBRs from voltage ride through performance requirements, and only for voltage ride
through performance for those existing IBRs that are unable to modify their settings without physical modification of equipment. See Order No. 901
at P 193. The drafting team determined that such an exemption was appropriate and it is included in Requirement R4. The drafting team does not
have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901. The drafting team does believe additional monitoring would be appropriate to determine how many entities would
be affected by such an exemption and whether such an exemption would be consistent with overall Bulk-Power System reliability. To the extent such
monitoring suggests that further exclusions would be appropriate, a future drafting team could make those changes in an expeditious manner. The
affected entities could work with ERO Enterprise staff to address any compliance-related concerns in the interim. For this draft, however, the drafting
team is pursuing a more conservative approach in line with the specific exemptions identified in Order No. 901.
Scope: The team identifies that additional measures to create performance-based measures for phase II of this project will determine any additional
changes regarding synchronous generators.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation. The time for capability-based implementation has been corrected to 12 months as identified.
Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
-In R1, suggest the phase jump measurement to align to 2800 definition i.e.,Sub-cycle-to-cycle
-In Attachment 2, frequency ride through table is different with 2800. Suggest to align to 2800, otherwise the OEMs need to design for different
specs.
-For R4.1, 12 months is not sufficient for documenting the supporting information for hardware limitation. Recommend a 2-year period for the
exception documentation.
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Response
Thank you for your comment.
Additional information has been included in the Technical Rationale regarding phase jump measurements.
Table 3 has been revised.
The 12 month implementation plan for documenting known hardware-based limitations is considered reasonable for known/existing IBR.
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
Document Name
Comment
PRC-029 R 2.1.3 should be 0.95 per unit not 95 per unit.
Figures 1 and 2 in Attachment 1 of PRC-029 should use the same scale on the horizontal axis, either log or linear.
Please clarify point 10 of attachment 1 of PRC-029: “The facility may trip for more than four deviations of the applicable voltage at the high-side of the
main power transformer outside of the continuous operation region within any 10 second time period.”
The Implementation Plan should be extended to 36 months to allow for monitoring equipment to be installed at sites completed before PRC-029
becomes enforceable, to demonstrate performance and compliance with the standard.
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Response
Thank you for your comments.
R2.1.3: 95 per unit has been corrected to 0.95 per unit.
Attachment 1: The logarithmic scale has been removed from Figure 1.
Attachment 1 note #9 (previously note #10): provides an exemption to allow for tripping when more than four deviations outside of the continuous
operation region.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation.
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Kinte Whitehead - Exelon - 3
Answer
Document Name
Comment
Exelon supports the comments submitted by the EEI.
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Response
Thank you for your comments. Please refer to the responses to EEI.
Chance Back - Muscatine Power and Water - 5
Answer
Document Name
Comment
I support NSRF comments.
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Response
Thank you for your comments. Please refer to the responses to NSRF.
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Document Name
Comment
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AEPC only has minor concerns with PRC-024-4; however, in our opinion, PRC-029-1 still needs some work before we can recommend approval.
Thank you for the opportunity to comment.
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Response
Thank you.
Junji Yamaguchi - Hydro-Quebec (HQ) - 1,5
Answer
Document Name
Comment
It is imperative that the standard drafting teams for this project as well as the 2021-04 (PRC-002 and PRC-028) and 2023-02 (PRC-030 vs PRC-004)
assure a coherent way of addressing the inclusion and exclusion of IBRs in current and upcoming standards.
The following comments are applicable to PRC-029-1
The definition for Inverter Based Resource (IBR) was approved by industry in April under Project 2020-06. We do not agree with inserting the
uncapitalized version of IBR into 4.2 Facilities section because it is unbounded and insufficient to identify the Facilities applicable to this Standard, as
required in the Rules of Procedure (Appendix 3a, Standard Processes Manual). Furthermore, these definitions are the foundation of several ongoing
projects in response to FERC Order 901, where FERC “directs NERC to submit new or modified Reliability Standards that address specific matters
pertaining to the impacts of IBRs on the reliable operation of the BPS.”
The purpose section of PRC-029-1 refers to Inverter‐Based Resources (IBRs) (capitalized, defined term) whereas the facilities section uses the
uncapitalized version.
Section 4.2.2: What IBR Registration Criteria are we referring to? Are we referring to the Category 2 GO/GOP facilities that are still awaiting a FERC
decision? This section is not consistent with project 2021-04.
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For requirements R1 through R4, it is unclear which facilities are being referred to. Suggest rewording to “facilities identified in Section 4.2” or adding
a sentence to 4.2 to indicate “For the purpose of this standard, the term “Applicable facilities” refers to the following:”. However, as stated above, it
is unclear what facilities are included in the IBR Registration Criteria.
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Response
Thank you for your comments.
IBR Definitions: While the definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an acceptable
resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove usage of
unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another version of a
definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC-029, will include
this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects associated with
Milestone 3 as determined by those teams.
sub-BES IBR: the applicability section has been modified to include the registration criteria within the recently approved changes to the NERC Rules of
Procedures. The team was advised to hold on usage of specific language until the changes had been approved.
Plant/facility: The terminology has been changed to IBR to coincide with the new proposed definition for IBR. Additionally, this section has been
modified to include the registration criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on
usage of specific language until the changes had been approved.
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Duke Energy offers the following Comments for Draft 2 of PRC-024 and PRC-029 - see Duke Energy, EEI and NAGF comments below.
PRC-024-4 Comments
1-Duke Energy recommends the following R2 word omission be rectified:
R2. Each Generator Owner and Transmission Owner shall…which it is applied “to” trip within…
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PRC-029-1 Comments
EEI COMMENTS
Duke Energy agrees with and supports EEI filed comments as summarized below - see official EEI filed comments for additional detailed comments
and proposed resolution(s):
1-The Standard attempts to redefine the approved definition of IBR by adding VSC-HVDC systems after the IBR definition was approved by the
industry. EEI does not support: (a) expansion of the definition of IBRs beyond what was recently approved by the industry, since there is no technical
justification for adding VSC-HVDC and, (b) the SAR did not include adding VSC-HVDC systems to this project. For these reasons, we ask that the
definition of IBR not be expanded, and that the DT submit a technical justification for adding VSC-HVDC systems to the applicability section of this
Standard, rather than redefining an approved definition in a footnote.
2-The Standard adds TOs to this Standard solely to address VSC-HVDC systems although: (a) no technical justification has been provided, and (b) these
systems were not identified in FERC Order No. 901, the SAR, or in the Applicability Section of this proposed Reliability Standard.
3-EEI is concerned with the inclusion of requirements that are not clearly defined or set by multiple registered entities (i.e., TP, PC, RC, or TOP). This
situation creates: (a) regulatory confusion and places IBR-GOs in a position where they may need to comply with any number of entities without
clearly defining who is responsible, (b) IBR-GOs will have reporting obligations to multiple entities because no single entity is identified as being
responsible, and (c) none of the entities identified (i.e., TP, PC, RC, or TOP) are identified within the Applicability section of this proposed Reliability
Standard. This situation will likely create confusion and places considerable regulatory burden on the IBR-GOs and requires resolution and additional
clarification.
4-Throughout this Reliability Standard there is use of: (a) non-glossary terms (i.e., active power vs. Real Power) where glossary terms are available and
should be used and (b) glossary terms are used but not capitalized (e.g., reactive power vs. Reactive Power). Greater efforts should be made to use
NERC Glossary terms where appropriate and capitalize those terms, as required.
5-Ride-through Definition:
EEI does not support the proposed definition for “Ride-through” as proposed because it is too vague and contains no defined limits, as proposed. We
recommend the following changes: Reference EEI filed comments for this item.
6-Applicability Section:
(a) Footnote 1: EEI does not support adding TOs that own VSC-HVDC systems because it was not a scope item and is therefore not included in the
scope of this SAR.
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(b) Footnote 1 conflicts with Footnote 2 which defines VSC-HVDC as an IBR, which is not in alignment with the approved definition of an IBR.
(c) Footnote 2: EEI does not support Footnote 2 because it expands the definition of IBRs beyond what was recently approved by the industry, noting
the expansion of IBRs to include VSC‐HVDC.
(d) There was no technical justification for adding VSC-HVDC and the SAR did not include adding VSC-HVDC systems to this project.
For these reasons, we ask that the definition of IBR not be expanded through footnotes and suggest that the DT submit a technical justification for
adding VSC-HVDC systems to the applicability section of this Standard, rather than redefining an approved definition in a footnote.
To address our concerns related to Footnotes 1 & 2, we suggest that if VSC-HVDC systems are to be classified as IBRs, then the approved definition
should be pulled by NERC and resubmitted with those resources added to the definition and subsequently resubmitted to the industry for
approval. Alternatively, VSC-HVDC systems could be defined separately, and that definition submitted to the industry for approval. In both cases, a
technical justification should be provided to the industry that defines the issues and risks to BPS reliability that VSC-HVDC systems pose.
EEI suggests that if the DT believes certain IBR capabilities as identified under Requirement R2 need (or may need) to be specified then the DT should
identify the entity who should be responsible among the four identified (i.e., TP, PC, RC or TOP); add them to the applicability section of this Reliability
Standard; and add clear requirements and adjust the reporting obligations for the IBR-GO under Requirement R4.
7-Requirement R1 & R2:
EEI does not agree with the inclusion of Transmission Owners because they would only have an obligation under this Reliability Standard if VSC-HVDC
systems were included. Given we do not support the inclusion of VSC-HVDC systems without a technical justification and modified SAR, we ask
Transmission Owners be removed from Requirement R1.
8-Measures M1 & M2:
EEI is concerned that M1 & M2 contains measures that are overly prescriptive and provide little discretion to IBR-GOs in demonstrating their
compliance with Requirements R1 and R2. As written, M1 and M2 appear to align more with a Requirement than a Measure (see official EEI filed
comments for additional detailed comments and proposed resolution(s)).
9-Requirement R3 & R4: EEI does not support the inclusion of Transmission Owners within Requirements R3 & R4 for the same reasons identified
above.
DUKE ENERGY COMMENTS
Additionally, Duke Energy provides the following additional comments:
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10-Amend Standard to include GO specific and comprehensive responsibilities and identify functional entity required to approve exemption(s).
11-R3 does not provide specific Measure information in the Requirement – amend; as stated above, this action must provide definitive compliance
guidance for GOs.
12-R4: Language does not allow for frequency exemptions (voltage exemptions allowed) – amend Requirement to allow for frequency exemptions.
13-R4.2.1 Amend language to require Regional Entity to respond within X calendar days.
14-R3: Amend language as follows: …“and suggest similar changes be made to M2” and M3.
15-R2.1.3: Requirement is duplicative with VAR-002 Reactive/Voltage support – consider removing.
16-Duke Energy recommends the word “ensure” be removed from all Requirements and specific Requirement language obligations be inserted to
identify compliance. Use of the word “ensure” results in global compliance guidance that is not auditable unlike specific compliance Requirement(s).
17-Measurement M1: Consider including a standard Prerequisite Section in Standard that validates design and operation is such that each facility
adheres to Ride-through requirements
18-M4/R4.3 – Resolve 30 calendar days vs. 90 calendar days conflict or clarify differences. Also, add “calendar” days to R4.3.
NAGF COMMENTS
Finally, Duke Energy agrees with and supports NAGF filed comments summarized below - see official NAGF filed comments for additional detailed
comments and proposed resolution(s):
19-Consider removing Applicability 4.2.2 section, IBR Registration Criteria.
20-R2.5 requires clarity – revise narrative to state that active power shall be restored when ”the voltage at the high‐side of the main power
transformer returns to the Continuous Operating Region”.
Likes
0
Dislikes
0
Response
Thank you for your comments.
PRC-024-4
R2: The errata has been corrected.
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PRC-029-1
IBR Definitions: While the definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an acceptable
resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove usage of
unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another version of a
definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC-029, will include
this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects associated with
Milestone 3 as determined by those teams. Further, regarding sub-BES IBR: the applicability section has been modified to include the registration
criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on usage of specific language until the
changes had been approved.
Transmission Owner: The transmission owner has been removed from PRC-029.
Other Performance Requirements: The language related to having evidence of other performance requirements was considered necessary for a
situation where an entity receives requirements from a planner or operator that would contradict PRC-029 requirements. The team included this as a
means of allowing the GO to follow requirements if needed by planners/operators and not be in violation of PRC-029 requirements. Planners and
operators are not required to provide other performance requirements and are not applicable to this Standard. The language reads that as long as an
entity is able to demonstrate that deviations from PRC-029 performance are due to other requirements provided by any of the listed entities, that the
GO would not be in noncompliance.
Active Power: The terms have been replaced with those from the glossary.
Ride-through definition: The definition for Ride-through has been revised.
Applicability Section – footnotes: The footnotes have been revised to address the above changes.
Measures: the measures are now written to provide specific examples of evidence needed for compliance. Further the implementation plan has been
revised to bifurcate between capability-based elements and performance-based elements. Essentially this is now a phased-in implementation plan
whereas each entity will be required to respond to the full requirement over time. This will allow entities to align their PRC-028 and the performancebased aspects for PRC-029 compliance.
R4 acceptance: Additional information has been provided to R4 to clarify the acceptance expected. Requirements cannot be written towards Regional
Entities. As written, an entity who submits the documentation as required and responds to additional requests as required would be compliant. An
entity would not be determined to be noncompliant while the CEA (previously Regional Entity) processes that submittal.
R2.1.3: There is no obligation or requirement for planners or operators to supply other performance requirements. The language related to having
evidence of other performance requirements was considered necessary for a situation where an entity receives requirements from a planner or
operator that would contradict PRC-029 requirements. The team included this as a means of allowing the GO to follow requirements as needed by
any planners/operators and not be in violation of PRC-029 requirements.
“Ensure”: Usage of the term “ensure” has been removed from requirements and measures as suggested.
M4: Calendar days have been corrected as identified.
NAGF: Please refer to responses to NAGF
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sub-BES IBR: the applicability section has been modified to include the registration criteria within the recently approved changes to the NERC Rules of
Procedures. The team was advised to hold on usage of specific language until the changes had been approved.
R2.5: Language to allow different ramp rate requirements from planners/operators is already included. Also, for legacy equipment that cannot meet
the requirements within PRC-029 due to hardware-based limitations, this would be covered in R4. Finally, R2.5 only refers to ramp rates after
recovery from the mandatory operation region or permissive operation region to the continuous operation region.
Michael Goggin - Grid Strategies LLC - 5
Answer
Document Name
Comment
In the draft of PRC-029, R4 should be modified to allow existing resources with equipment limitations to obtain an exemption from the frequency
ride-through requirements in R3, instead of only allowing an exemption from the voltage ride-through requirements in R1 and R2. This is necessary
because some existing IBR generators cannot meet the stringent frequency ride-through requirements proposed in R3 without deploying significant
hardware modifications or replacement, which goes against the intent of FERC Order 901.
The frequency ride-through requirements are particularly problematic for some existing wind generators. In the Technical Rationale document
accompanying the PRC-029 draft, the drafting team notes that some wind generators are more sensitive to frequency deviations, writing that “All IBR
resources (except for type 3 wind turbines) interface to the grid through fast switching of power electronics devices. These power electronic devices
are much less sensitive to the transmission system frequency excursion than non‐hydraulic turbine synchronous resources.”{C}[1] However, the
drafting team then incorrectly concludes that “Therefore, IBR should be capable of riding through the increased proposed 6‐second frequency ride‐
through requirement without risk of equipment damage or need for frequency protection to operate.” The Technical Rationale document does not
offer any justification for its assumption that Type III wind turbines can meet the frequency ride-through requirements, despite noting that those
turbines more directly interface with the grid and thus are more affected by frequency deviations than other IBRs.
In fact, many existing Type III wind turbines cannot meet the frequency ride-through requirements proposed in this draft of PRC-029. Those resources
were designed to meet the reliability Standards and interconnection requirements that were in effect when they were placed in service, and were not
designed to ride through frequency excursions of the magnitude and duration proposed in the draft Standard. Other types of existing IBR resources
were also not designed to meet the proposed frequency ride-through requirements, and may similarly require extensive equipment modification or
replacement to comply with R3.
Imposing a retroactive requirement on wind generators is particularly problematic as it is not typically feasible to retrofit existing wind turbines to
increase their ability to ride through and withstand mechanical stresses due to frequency changes. In such cases, making existing equipment better
able to withstand frequency changes would require full replacement or extensive modification of hardware, which would come at a significant, and
sometimes prohibitive, cost. Frequency changes can impose mechanical stresses on highly sensitive elements in the wind turbine’s rotating
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equipment, including the generator, gearbox, the main shaft, and bearings associated with all of that equipment, and requiring such resources to ride
through frequency changes they were not designed to operate through can damage that equipment. Subjecting Type III wind turbines to this damage
may lead to increased outages or premature failure of these generators, potentially increasing reliability risks.
The easiest solution is to modify R4 to allow existing resources with equipment limitations toobtain an exemption from the frequency ride-through
requirements in R3, which would make PRC-029 consistent with a long precedent of FERC interconnection requirements and NERC Standards only
applying prospectively, including PRC-024. Retroactive requirements impose a much greater financial burden on the generator than prospective
Standards, and set a bad precedent by unfairly penalizing generators that met all requirements that were in effect at the time they were installed.
Retrofit or replacement costs are typically much greater than if the capability were installed at the plant to begin with. In some cases equipment
needed for retrofits may not be available, particularly for models that have been discontinued or manufacturers that are no longer in business,
potentially requiring the replacement of the entire wind turbine. Moreover, existing IBR generators typically sell their output at a fixed price under a
long-term power purchase agreement, and unexpected retrofit or replacement costs cannot typically be recovered once a power purchase agreement
has been signed. These unexpected and unrecoverable costs are far more concerning to lenders and other generation project financiers as they were
not accounted for during the project’s financing. As a result, retroactive requirements set a bad precedent by introducing regulatory uncertainty that
makes future generation investment more uncertain and riskier, and likely more costly by forcing financiers to charge higher risk premiums.
Fortunately, these problems can be fixed by inserting “R3” into the list of permissible exemptions in R4, which would allow existing resources with
equipment limitations to obtain an exemption from the frequency ride-through requirements in R3.
In the Technical Rationale document, the drafting team points to FERC’s directive in Order No. 901 to justify not allowing existing resources to obtain
an exemption from the frequency ride-through requirements in R3: “FERC Order No. 901 states that this provision would be limited to exempting
‘certain registered IBRs from voltage ride‐through performance requirements.’ This is the reason that no similar provisions are included for
exemptions for frequency or rate‐of‐change‐of‐frequency (ROCOF) ride‐through requirements per R3.”[2]
However, a contextual reading of Order No. 901 indicates FERC was focused on targeting equipment limitation exemptions at existing generators that
would have to physically replace or modify hardware to comply with the Standard, and not focused on limiting such exemptions to voltage ridethrough requirements. Paragraph 193 in its entirety, and particularly the first sentence, explain that FERC’s intent was exempting existing resources
that would have to physically replace or modify hardware: “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.” As a result, FERC continued by directing that “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.”[3]
Allowing existing plants to apply for an equipment limitation exemption for the frequency ride-through requirements in R3 is necessary to ensure
some existing generators do not have to physically replace or modify hardware. As a result, such an exemption is consistent with FERC’s directive and
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intent in Order No. 901. As documented in the following footnote, there is ample precedent for NERC and standards drafting teams to exercise their
technical expertise to craft Standards to align content and requirements with technical realities.[4]
Additional context in Order 901 further demonstrates that FERC intended for NERC to include an exemption for existing IBRs that cannot meet
frequency ride-through requirements. At paragraph 190 in Order No. 901, FERC directed NERC to develop Standards that ensure resources “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.” For many existing IBRs that cannot meet the proposed frequency
ride-through requirements, tripping is necessary to protect the IBR equipment, similar to when synchronous generation resources use tripping as
protection from internal faults. As a result, an exemption from R3 for existing resources is consistent with FERC’s intent. Order No. 901 also directed
NERC to consider the “PRC-024-3, Requirement R3 as an example for establishing registered IBR technology exemptions,” and that exemption applies
equally to voltage ride-through and frequency ride-through settings, further suggesting that FERC will allow certain IBRs an exemption from the
frequency ride-through requirements.[5] Finally, Order No. 901 notes that in the notice of proposed rulemaking that led to the order, FERC “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.”[6] FERC then adopted that very proposal,{C}[7] further demonstrating that FERC sought to
direct NERC to only require frequency and voltage ride-through where technologically feasible.
It is likely that FERC Order No. 901 did not explicitly direct NERC to include frequency ride-through exemptions because FERC did not anticipate that
NERC would adopt such an aggressive frequency ride-through requirement that some existing plants cannot meet. The drafting team even notes at
page 7 in the Technical Rationale document that “The proposed 6‐second time frame of the frequency ride‐through capability requirement is beyond
the IEEE 2800 standard frequency ride‐through requirement and beyond frequency ride‐through requirements for synchronous machines under
proposed PRC‐024‐4.” There is nothing in Order No. 901 that suggests that FERC was opposed to existing equipment exemptions for a frequency ridethrough standard that was drafted after FERC issued Order No. 901 and is more stringent than FERC anticipated. A much more reasonable
interpretation is that the logic FERC provided in paragraph 193 of Order No. 901 also applies to a frequency ride-through requirement that some
existing resources cannot meet without physical modification or replacement of equipment. In fact, paragraph 193 makes clear that FERC’s language
focuses on an exemption from voltage ride-through requirements because “a subset of existing registered IBRs… may be unable to implement the
voltage ride though performance requirements directed herein.”
At the end of paragraph 193, FERC also explained that an exemption for existing resources would not harm reliability because “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.” FERC’s reasoning in paragraph 193 also applies to an exemption from
frequency ride-through requirements, but particularly the conclusion that exempting existing plants does not cause reliability concerns and therefore
should be allowed. The NERC drafting team’s technical justification document explicitly explains that the frequency ride-through requirement is “to
ensure the reliability of future grids with high IBR penetration,”{C}[8] based on concerns about declining inertia due to IBRs replacing synchronous
resources. NERC and others have demonstrated that inertia and frequency response will remain more than adequate for the foreseeable future even
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following disturbances that are several times larger than current credible contingencies, and that higher IBR penetrations can actually significantly
improve frequency stabilization following disturbances.[9]
As a result, there is no reliability concern from an exemption for the small number of existing resources that cannot meet the requirements without
physical modification or replacement of equipment. Moreover, as FERC notes, these plants will replace that equipment anyway over time as legacy
inverters fail or are replaced with more modern equipment for other reasons, and the draft standard requires replacement equipment to comply with
the Standard. Utility-scale inverters installed at solar and battery installations typically come with warranties of 10 years or less,{C}[10] and those
inverters are typically replaced at least once during the plant’s lifetime. Many existing wind plants are also being repowered with newer turbines,
often to allow the project to receive another 10 years of production tax credits after the initial 10 years of credits have been received. As a result, by
the time the drafting team’s concerns about inertia in a high IBR penetration future might materialize, the vast majority of IBRs that cannot meet the
frequency ride-through requirements will have been replaced with new equipment that is not exempt.
Moreover, the drafting team’s assumption that frequency deviations will be larger on a future low inertia power system is flawed. IBRs can provide
fast frequency response, which stabilizes frequency in the initial seconds following a grid disturbance, before synchronous generators begin to
provide their slower primary frequency response.[11] Thus fast frequency response provides a similar service to inertia in helping to arrest the change
in frequency before primary frequency response is fully deployed, reducing the need for inertia.[12] Fast frequency response is easily provided by
batteries due to their available energy, but can also be provided by curtailed wind or solar resources. Power systems with high IBR penetrations will
tend to have some wind or solar curtailment in a significant share of hours. If allowed to do so, solar an battery resources with spare DC capacity
behind the inverter can also temporarily exceed their interconnection agreement’s AC injection limit to provide fast frequency response.
The replacement of inflexible synchronous resources with more flexible IBRs could also significantly improve primary frequency response, as NERC’s
modeling has demonstrated.{C}[13] NERC has also documented that only about 30% of synchronous generators provide primary frequency response,
and only about 10% provide sustained primary frequency response.[14] Even with less inertia, the fast and accurate frequency response provided by
IBRs will keep frequency more tightly controlled than the slow to nonexistent primary frequency response from synchronous generators. The
replacement of large synchronous generators with smaller IBRs should also reduce the magnitude of frequency deviations following the loss of
generators. If frequency response does begin to emerge as a concern, the more effective solution would be to enforce requirements on synchronous
generators that are supposed to provide it but do not. If necessary, operators would alter real-time dispatch, as ERCOT and some island power
systems occasionally do today, to ensure that inertia and fast frequency response are adequate to ensure under-frequency load shedding or
generator tripping thresholds are not reached. Finally, grid-forming inverters are increasingly being deployed with battery storage and other IBR
installations, further increasing the contributions of IBRs to stabilizing frequency.
At page 8 in the Technical Rationale document, the drafting team argues that “To compensate for the lack of inertia and short circuit contributions,
[IBRs] should have wider tolerances for frequency and voltage excursions to meet the needs of future power systems with a higher percentage of
IBR.” The drafting team also argues that IBRs should have to ride-through much larger frequency deviations than synchronous resources because
“Synchronous resources are more sensitive to frequency deviations than IBR resources.” This logic is flawed for many reasons. Grid operators need all
resources to ride through disturbances, and the contribution of a resource to inertia or short circuit needs is irrelevant to that need. Any concerns
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about resources’ inertia and short circuit contributions are outside the drafting team’s scope and authority, and should be addressed by other means
(such as by increasing the deployment of grid-forming IBRs in the localized areas that have short circuit or stability concerns). It is also perverse for
the drafting team to penalize IBRs for being less sensitive to frequency deviations than synchronous generators. As noted below, there are already
grounds for FERC to reject this proposed standard due to undue discrimination against IBRs relative to the far more lenient requirements on
synchronous generators under PRC-024, including an equipment limitation exemption for synchronous generators from the frequency relay setting
requirement in PRC-024, and this only adds to those concerns.
In short, the drafting team’s unfounded concerns about a future power system do not justify withholding an exemption to frequency ride-through
requirements for existing IBR resources that will have been largely replaced by the time any concerns might materialize.
Finally, R4 equipment limitation exemptions should be allowed for resources with signed interconnection agreements as of the effective date of the
Standard, instead of resources that are in-service as of that date. Resource equipment decisions are typically locked down at the time the
interconnection agreement is signed, and a change in requirements after that point can require a costly change in equipment or settings that may
also trigger a material modification and resulting interconnection restudies. The implementation plan for PRC-029 indicates that the effective date for
the Standard will be the first day of the first quarter six months after FERC approval. Many resources take significantly longer than that to move from
a signed interconnection agreement to being placed in service, so it makes more sense to allow R4 equipment limitation exemptions for resources
that have a signed interconnection agreement as of the effective date of the Standard.
The current draft of the PRC-029 Standard is unworkable and will impose massive costs on some existing generators with no benefit for reliability. As
explained above, the drafting team incorrectly ventures that “IBR should be capable of riding through the increased proposed 6‐second frequency
ride‐through requirement without risk of equipment damage or need for frequency protection to operate,” even after noting that some wind turbines
use very different technology. NERC’s rigorous standard development process exists to ensure that errors like this do not make it into final Standards,
and the exceedingly low level of support for the initial draft and the major revisions in the current draft indicate that further revisions will likely be
necessary. It takes time to fine tune highly technical requirements and vet them across the industry to avoid unnecessary and exorbitant costs for
existing resources that cannot meet the standard. If the drafting team and NERC believe Order No. 901’s deadlines do not provide enough time for
further standard revisions and balloting periods to make the frequency ride-through requirement workable for existing resources, adding the letters
“R3” to R4 to create an exemption for existing resources is the fastest and easiest way to address those concerns. For the reasons explained above,
such an exemption does not pose any risk to reliability and is consistent with FERC’s directive in Order 901.
Undue discrimination
A major concern with the Standards, as drafted, is that ride through performance is not required for synchronous generators under PRC-024-4, but it
is for IBRs under PRC-029. PRC-024 simply requires protective relays to be set so they do not trip the generator within specified bounds, but it allows a
resource to trip offline for other reasons. PRC-024-4 also allows a plant to trip if protection systems trip auxiliary plant equipment, per section 4.2.3.
In contrast, PRC-029 requires IBRs to remain electrically connected and to continue to exchange current within the specified voltage and frequency
bounds. Said another way, an IBR and a synchronous resource could both trip during the same disturbance, and the IBR would be in violation of PRCConsideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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029 but the synchronous generator would not be in violation of PRC-024-4, as long as the synchronous generator did not trip due to the settings of its
protection system.
To ensure grid reliability and resilience, all resources including IBRs and synchronous resources should ride through grid disturbances. The failure of
synchronous generators to ride through grid disturbances threatens grid reliability as much or more than the failure of IBRs, as synchronous resources
are often producing at a higher level of output, are more typically relied on as capacity resources, and often take longer to come back online and
ramp up to full output if they trip due to a disturbance.
FERC Order No. 901 directed NERC to treat IBR resources similarly to how NERC Standards treat synchronous generators, writing that the IBR
Standard should “permit IBR tripping only to protect the IBR equipment in scenarios similar to when synchronous generation resources use tripping as
protection from internal faults.”{C}[15] Allowing synchronous generators to trip but requiring IBRs to ride through the same or similar disturbance will
be challenged at FERC as undue discrimination. Providing synchronous generators with an equipment limitation exemption from PRC-024’s relaysetting requirements but not offering existing IBR resources an exemption from the far more stringent frequency ride-through requirements in PRC029 is also undue discrimination.
This disparate treatment of IBRs versus synchronous generators is also at odds with the intent for this project that NERC stated in its February 2023
comments on the FERC proposed rulemaking that led to Order No. 901: “A comprehensive, performance-based ride-through standard is needed to
assure future grid reliability. To that end, NERC re-scoped an existing project, 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 generating
resources.”[16] FERC’s Order No. 901 also noted NERC’s statement that this project would require ride-through performance from all generating
resources,[17] so a failure to require ride-through performance from synchronous generators is contrary to both NERC’s and FERC’s intent.
Providing an exemption in PRC-029 R4 for existing IBRs that cannot meet the frequency ride-through requirement in R3 will result in less disparity
with the treatment of synchronous resources under PRC-024, and is therefore an essential step if NERC wants to reduce the risk of FERC rejecting the
proposed standard due to undue discrimination against IBRs.
{C}[1]{C} Technical Rationale, PRC-029-1 – Frequency and Voltage Ride-Through Requirements for Inverter-Based Generating Resources, at 8,
https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-0291_Technical_Rationale_Redline_to_Last_Posted_06182024.pdf (“Technical Rationale”).
{C}[2]{C} Id., at 10
{C}[3]{C} Reliability Standards to Address Inverter-Based Resources, Order No. 901, 185 FERC ¶ 61,042, P 193 (2023).
{C}[4]{C} For example, Section 215(d)(2) of the FPA requires FERC to give “due weight” to the technical expertise of the ERO when evaluating the
content of a proposed Reliability Standard or modification to a Standard.
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Order No. 733-A, P 11: “In this order, we emphasize and affirm that we do not intend to prohibit NERC from exercising its technical expertise to
develop a solution to an identified reliability concern that is equally effective and efficient as the one proposed in Order No. 733.”
Order No. 748, P 43: “In consideration of these ongoing efforts, we will not direct specific modifications to these Reliability Standards and, rather,
accept NERC’s commitment to exercise its technical expertise to study these issues and develop appropriate revisions to applicable Standards as may
be necessary.”
Order No. 896, P 36: “NERC may also consider other approaches that achieve the objectives outlined in this final rule. Further, as recommended by
PJM, we believe there is value in engaging with national labs, RTOs, NOAA, and other agencies and organizations in developing benchmark events.
Considering NERC’s key role, technical expertise, and experience assessing the reliability impacts of various events and conditions, we encourage
NERC to engage with national labs, RTOs, NOAA, and other agencies and organizations as needed.”
Order No. 901, P 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.”
{C}[5]{C} Order 901, P 193
{C}[6]{C} Id. at P 178.
{C}[7]{C} Id. at P 190.
{C}[8]{C} Technical Rationale at 7.
{C}[9]{C} East Interconnection Frequency Response Assessment with Inverter Based Resources, at 7
https://www.energy.gov/sites/prod/files/2018/07/f53/2.1.4%20Frequency%20Response%20Panel%20-%20Velummylum%2C%20NERC.pdf.
{C}[10]{C} Best Practices for Operation and Maintenance of Photovoltaic and Energy Storage Systems, at 55,
https://www.nrel.gov/docs/fy19osti/73822.pdf.
{C}[11]{C}Fast Frequency Response Concepts and Bulk Power System Reliability Needs,
https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/Fast_Frequency_Response_Concepts_and
_BPS_Reliability_Needs_White_Paper.pdf.
{C}[12]{C} Inertia and the Power Grid: A Guide Without the Spin, https://www.nrel.gov/docs/fy20osti/73856.pdf.
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{C}[13]{C} East Interconnection Frequency Response Assessment with Inverter Based Resources, at 7
https://www.energy.gov/sites/prod/files/2018/07/f53/2.1.4%20Frequency%20Response%20Panel%20-%20Velummylum%2C%20NERC.pdf.
{C}[14]{C} https://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/FRI_Report_10-30-12_Master_w-appendices.pdf
{C}[15]{C} Order No. 901, at P190
[16]{C}https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Comments_IBR%20Standards%20NOPR.pdf, at 21-22.
[17]{C} Order No. 901, at P 185
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Response
Thank you for your comment.
Frequency/R3/Attachment 2 Exemptions: In Order No. 901, FERC directed NERC to determine whether the ride-through standard should provide for
a limited and documented exemption for certain registered IBRs from voltage ride through performance requirements, and only for voltage ride
through performance for those existing IBRs that are unable to modify their settings without physical modification of equipment. See Order No. 901
at P 193. The drafting team determined that such an exemption was appropriate and it is included in Requirement R4. The drafting team does not
have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901. The drafting team does believe additional monitoring would be appropriate to determine how many entities would
be affected by such an exemption and whether such an exemption would be consistent with overall Bulk-Power System reliability. To the extent such
monitoring suggests that further exclusions would be appropriate, a future drafting team could make those changes in an expeditious manner. The
affected entities could work with ERO Enterprise staff to address any compliance-related concerns in the interim. For this draft, however, the drafting
team is pursuing a more conservative approach in line with the specific exemptions identified in Order No. 901.
On the assertion of discrimination, IBR ride-through continues to be the problem, not synchronous generation ride-through. Synchronous generators
have a hundred years of reliable performance, their limitations are well-known and understood, being physics-based, and their performance is
predictable. Not so with IBRs which are being seen dropping off during minor system disturbances due to all manner of causes that have not been
predicable.
Rhonda Jones - Invenergy LLC - 5
Answer
Document Name
Comment
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Thank you for the opportunity to provide comments and for your work on this project. Invenergy provides the below comments for the Drafting Team
to consider:
R1: In response to industry comments, the SDT indicated that Requirement R5 from Draft 1 was removed, but it appears the phase-angle jump
requirements have simply been reinserted under Requirement R1 in this second draft. As drafted, a facility is expected to ride-through fault-initiated
switching events regardless of the magnitude of voltage phase angle change. Consider that positive sequence phase angle change cannot be
accurately measured during a fault occurrence and clearance. We propose the assessment of ride-through performance during fault occurrence,
clearance, and recovery be based only on the voltage ride-through criteria in Attachment 1 Table 1 and Table 2.
We recommend reverting the “Voltage (per unit)” columns of Table 1 and Table 2 back to their first draft state to remain consistent with Tables 11
and 12 of IEEE 2800.
R2.1.3: The decimal place is missing from “95 per unit.”
R2.2: Consider more clearly defining “maximum capability.” As an alternative, R2.2 could state, “…each IBR shall exchange current, up to the total
sum of the nameplate current rating of online IBR units in the plant to provide voltage support…”
R2.3.1: Consider removal of this requirement. The time it should take a facility to restart current exchange following blocking seems irrelevant if the
other ride-through performance requirements are being met.
Attachment 1: Note 11 from Attachment 1 should be removed. There are many equipment protection settings that are near instantaneous to protect
against current or voltage surges that far exceed the equipment’s maximum rating. A power electronic switch could burn out in a matter of microseconds due to such a surge, before any tripping decision could be made if the filtering length must be at least 16.6 milliseconds.
R3: We recommend reverting the “System Frequency (Hz)” columns of Table 3 back to its first draft state to remain consistent with Tables 15 of IEEE
2800.
The Consideration of Comments document seemed to indicate that the drafting team intended to respond to our previous comment regarding the
expansion of the frequency ride-through range, but none was provided. The proposed 6-second frequency ride-through capability requirement for
the ranges of 61.8Hz to 64Hz and 57Hz to 56Hz does not align with the requirements on the rest of the BES and would expose synchronous generators
to dangerous variations in frequency. Can the drafting team cite more specific reasoning or data to support the expansion of the frequency ridethrough capability requirement to the range of 64Hz to 56Hz, well beyond the IEEE 2800-2022 standard frequency ride-through requirement and the
capabilities of many legacy IBRs?
R4: We recommend the following revision to R4.
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R4. Each Generator Owner and Transmission Owner identifying a facility with a signed interconnection agreement by the effective date of PRC-029-1
with known hardware limitations that prevent the facility from meeting ride-through criteria as detailed in Requirements R1, R2, and R3, and requires
an exemption from specific ride-through criteria shall:
Exemptions in R4 should be based on the execution of the interconnection agreement rather than the in-service date of the facility. As drafted,
facilities with executed interconnection agreements, but not yet in-service by the effective date of the standard may need to make significant
equipment modifications and perform interconnection restudies to comply with requirements that did not become effective until after the
interconnection agreement was executed.
Regarding the lack of frequency ride-through exemptions, the limited exception language in FERC Order 901 is not supported by any comments or
other evidence in the record in the original NOPR proceeding, and therefore we believe this to be an inadvertent omission and unjustified application
of Order 901 in the draft language of PRC-029-1. In fact, in the NOPR, FERC proposed to direct NERC “to develop new or modified Reliability Standards
that would require Generator Owners and Generator Operators to ensure that their registered IBR facilities ride through system frequency and
voltage disturbances where technologically feasible.” The drafted frequency ride-through performance requirements are not technologically feasible
for many legacy IBRs.
Further, in Order 901, FERC “encourage[s] 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.” Requirement R3 of PRC-024-3, and the currently drafted version of PRC024-4, allows for exemptions from both the frequency and voltage ride-through requirements due to equipment limitations.
Given the lack of a clear evidentiary record on this point, the drafting team should rely on the discretion FERC has always granted NERC when it comes
to drafting and implementing practical Reliability Standards. Invenergy recommends Requirement R4 be amended to allow limited exemptions from
specific voltage and frequency ride-through criteria for facilities with known hardware limitations that prevent the facility from meeting the ridethrough criteria detailed in Requirements R1, R2, and R3.
Finally, Invenergy has concerns regarding the deviation of this project from its original goal of developing a standard that will require ride-through
performance from all generating resources. As currently drafted, PRC-024-4 imposes fewer ride-through performance responsibilities on synchronous
generators while allowing broader exemptions from its requirements than PRC-029-1. This undue discrimination permits scenarios in which both a
synchronous generator and an IBR could trip offline due to the same system disturbance and only the IBR would be subject to a potential
noncompliance, assuming the synchronous generator did not trip due to its protection system settings.
Implementation Plan: In its Consideration of Comments, the drafting team indicated that the Implementation Plan has been modified such that PRC029-1 shall become effective on the first day of the first calendar quarter that is 12 months after the effective date of the applicable governmental
authority’s order approving PRC-028-1, however the Implementation Plan still lists an implementation timeframe of six months.
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Thank you for your comment.
R1: the bullets under R1 are listed as possible exemptions and are not required to be used to demonstrate performance.
Attachment 1: Language regarding the usage of RMS voltage is provided in the notes for consistency.
R2.1.3: 95 per unit has been corrected to 0.95 per unit.
Attachment 1 notes: Some notes have been modified for clarity.
R3 – Table 3 has been revised.
R4: Exemptions in R4 are based on confirmed expectations from FERC regarding the “existing” or “legacy” IBR. The team was advised that IBR that
have not yet been built or Interconnected would not meet that expectation.
Frequency/R3/Attachment 2 Exemptions: In Order No. 901, FERC directed NERC to determine whether the ride-through standard should provide for
a limited and documented exemption for certain registered IBRs from voltage ride through performance requirements, and only for voltage ride
through performance for those existing IBRs that are unable to modify their settings without physical modification of equipment. See Order No. 901
at P 193. The drafting team determined that such an exemption was appropriate and it is included in Requirement R4. The drafting team does not
have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901. The drafting team does believe additional monitoring would be appropriate to determine how many entities would
be affected by such an exemption and whether such an exemption would be consistent with overall Bulk-Power System reliability. To the extent such
monitoring suggests that further exclusions would be appropriate, a future drafting team could make those changes in an expeditious manner. The
affected entities could work with ERO Enterprise staff to address any compliance-related concerns in the interim. For this draft, however, the drafting
team is pursuing a more conservative approach in line with the specific exemptions identified in Order No. 901.
On the assertion of discrimination, IBR ride-through continues to be the problem, not synchronous generation ride-through. Synchronous generators
have a hundred years of reliable performance, their limitations are well-known and understood, being physics-based, and their performance is
predictable. Not so with IBRs which are being seen dropping off during minor system disturbances due to all manner of causes that have not been
predicable.
Implementation Plan: The Implementation Plan has been modified to include bifurcated implementation information between capability-based
elements and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to
the full requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029
implementation. The correction to 12 months has been addressed as identified.
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
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Southern Company supports NAGF comments.
Southern Company suggests that M1 be divided out to be clearer such as:
M1. Each Generator Owner and Transmission Owner shall have evidence of dynamic simulations, studies, or other evidence to demonstrate the
design of each facility will adhere to Ride-through requirements, as specified in Requirement R1.
M1.1 Each Generator Owner and Transmission Owner shall have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder,
Dynamic Disturbance Recorder, and Fault Recorder) to demonstrate that the operation of each facility did adhere to Ride through requirements, as
specified in Requirement R1.
M1.2 If the Generator Owner and Transmission Owner choose to utilize Ride-through exemptions that occur within the “must Ride-through zone” and
are caused by non-fault initiated phase jumps of greater than 25 electrical degrees, then each Generator Owner and Transmission Owner shall also
have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to
demonstrate that the facility failed to Ride-through during a phase jump of greater than or equal to 25 electrical degrees, and documentation from
their Transmission Planner, Reliability Coordinator, Planning Coordinator, or Transmission Operator that a non-fault initiated switching event
occurred.
Southern Company suggests adding an exemption for V/Hz to R3 like bullet 4 in R1.
R3 - Frequency Ride-Through Criteria
Southern Company recommends PRC-029-1 adopt Frequency Ride-Through Criteria (Attachment 2, Table 3 in draft 2) consistent with the IEEE2800
standard. Individual Regions should be allowed to adopt more stringent frequency ride-through standards based on their respective system needs
and resource capabilities.
R4 – Exemptions
Any ultimate decision to disallow exemptions for requirements other than voltage, must be grounded in a thorough technical analysis of IBR OEM
capabilities. NERC staff and standard drafting team participants have the necessary technical expertise to make these determinations. Additionally,
there is ample precedent from prior Standard processes for FERC to defer to NERC on such technical issues. Finally, if the more stringent Frequency
Ride-Through criteria in the current draft is preserved, this amplifies the need for consideration of existing equipment frequency ride-through
exemptions. GOs and OEMs have not had adequate time to assess resource capabilities against requirements more stringent than IEEE2800.
Southern Company suggests that Requirement R4.3 be reworded to “...that replace the equipment causing the limitation, such that the limitation no
longer exists, shall document and communicate...” The current wording is being interpreted that the only equipment that can be put back in place of
a failed piece of equipment with a limitation is one without a limitation. Furthermore, R4.3.1 alludes that replacement of equipment with a limitation
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must be made with equipment without limitation. This may not be possible due to uniqueness and limits associated with an existing facility
design. There is no allowance for in-kind replacements. If one inverter burns down, there is no provision to replace it with an in-kind spare
replacement unit.
Note 7 on page 15 states that you only have to ride-through the voltage deviations if the frequency remains within the “must ride through zone”.
Doesn’t there need to be a corresponding statement made on page 19? In other words, the standard should allow you to trip even if the frequency
remained at a constant 60Hz if the voltage does not remain within the values in Attachment 1.
Southern Company suggests that Requirement R4 also include identified “software limitations” in addition to hardware limitations.
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Response
Thank you for your comments.
Frequency/R3/Attachment 2 Exemptions: In Order No. 901, FERC directed NERC to determine whether the ride-through standard should provide for
a limited and documented exemption for certain registered IBRs from voltage ride through performance requirements, and only for voltage ride
through performance for those existing IBRs that are unable to modify their settings without physical modification of equipment. See Order No. 901
at P 193. The drafting team determined that such an exemption was appropriate and it is included in Requirement R4. The drafting team does not
have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901. The drafting team does believe additional monitoring would be appropriate to determine how many entities would
be affected by such an exemption and whether such an exemption would be consistent with overall Bulk-Power System reliability. To the extent such
monitoring suggests that further exclusions would be appropriate, a future drafting team could make those changes in an expeditious manner. The
affected entities could work with ERO Enterprise staff to address any compliance-related concerns in the interim. For this draft, however, the drafting
team is pursuing a more conservative approach in line with the specific exemptions identified in Order No. 901.
Equipment replacement: replacement for maintenance in-kind does not remove the limitation. Additional language was added to 4.3.1 to clarify this.
Frequency and may trip zone: A footnote was added to R1 to clarify this instance “Except if this would occur during a frequency excursion. The active
power response should recover in accordance with the primary frequency controller.” The team identifies the inclusion for R1 to allow for tripping
due to voltage excursions not simultaneously ongoing a frequency excursion.
Software limitations: IBR, with software-based limitations alone, would not qualify for allowable exemptions per FERC Order 901.
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer
Document Name
Comment
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TEPC does not have any comments for PRC-024-4.
TEPC agrees with EEI's comments regarding PRC-019-1.
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Thank you for your comments, please see responses to EEI.
Darcy O'Connell - California ISO - 2, Group Name ISO/RTO Council (IRC) Standards Review Committee
Answer
Document Name
Comment
Ride-through Definition:
The ISO RTO Council Standards Review Committee (SRC) recommends that the drafting team provide a rationale for the proposed “Ride-through”
definition, as it is not clear what benefits result from creating a formal definition for this term, and the definition that has been proposed contains
ambiguous language.
First, use of the term “synchronized” in a definition intended to apply to IBRs could result in confusion because IBRs are generally considered to be
asynchronous resources (though no mention of IBRs is made in the proposed definition). As a stand-alone term in the NERC glossary, the proposed
definition could reasonably be interpreted to apply only to synchronous machines.
Second, the phrase “continuing to operate” is an inadequate description of desired performance – ride-through should include a concept of
performance that is beneficial (or at the very least not detrimental) to overall grid reliability.
Third, the use of “Transmission System” potentially limits the applicability of the definition to only transmission-connected resources – the SDT may
want to consider instead using a more general term such as “electric system” as was used in the proposed IBR definition.
Finally, defining the term “ride-through” may not be necessary at all. Meeting all of the requirements in PRC-029 essentially constitutes ride-through.
Creating a separate defined term may just cause confusion, as the proposed definition does not clarify the desired (or required) performance
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associated with ride-through. The best option may be to leave the term undefined. If the SDT determines that a definition for Ride-though is an
absolute necessity, the SRC proposes the following definition:
“Facilities, including all individual dispersed power producing resources, remaining connected to the electric system and continuing to operate in a
manner that supports grid reliability throughout a System Disturbance, including the period of recovery back to a normal operating condition.”
Comments on Proposed Requirements:
The language in PRC-029-1 Requirement R2, Part 2.1.3 that reads “…according to requirements if required by the [TP, PC, RC, or TOP]” seems
awkward and redundant, as it seems that any requirements that exist will always be required. The SRC recommends that this language be changed
to: “…according to TP, PC, RC, and TOP requirements, if any.” Additionally, if the SDT continues to use a per unit metric for Part 2.1.3, the proposed
“95 per unit” should be replaced with “.95 per unit . . . .”
Regarding PRC-029-1 Requirement R2, Part 2.2, it can be problematic to simply specify reactive/active power priority because not all priority
implementations perform the same way. Part 2.2 does not really prohibit dropping active current to zero even for shallow voltage dips (e.g. 0.70.9pu), but seems to allow the TP, PC, RC, or TOP to specify the desired performance. The SRC requests that the SDT clarify whether this is the
intended meaning, and revise Part 2.2 as necessary to clarify the intended meaning.
PRC-029-1 Requirement R2, Part 2.5 reads “…when the voltage at the high-side of the main power transformer returns from the mandatory operation
region….” The SRC requests that the SDT clarify whether this was intended to read: “when the voltage at the high-side of the main power transformer
returns to the continuous operation region from the mandatory operation region….”
In R2, Part 2.5 “available level (whichever is less)” should be revised to clarify whether “a lower post-disturbance active power level requirement”
means lower than the pre-disturbance level or lower than the available level.
The SRC also notes that the phrase “…pre-disturbance or available level (whichever is lesser)…” in PRC-029-1 Requirement R2, Part 2.5 may be
interpreted as allowing partial tripping/idling for an IBR facility. If the SDT’s intent is that no individual wind turbines/inverters should be allowed to
trip/idle, SRC recommends that this phrase be clarified with a footnote such as: “Reduction in available active power shall only be allowed due to a
reduction in available source power (e.g. wind or solar irradiance). Reduction in available active power shall not occur due to tripping or idling of
individual turbines or inverters within the IBR.”
The SRC requests that the SDT clarify whether Requirement R1 should include an absolute rate of change of voltage criteria similar to the RoCoF
criteria in PRC-029-1 Requirement R3. The SRC also requests clarification of whether the other bulleted exceptions listed in Requirement R1 apply
during frequency excursions (in other words, the SRC requests clarification of whether ride through is required for frequency excursions even if the
thresholds for V/Hz or phase angle jump specified in Requirement R1 are exceeded).
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The SRC is concerned that the word “replaced” in PRC-029-1 Requirement R4, Part 4.3.1 may provide a pathway to circumvent the spirit of the
standard (e.g., an entity could refurbish equipment and claim that its exemption should be maintained because equipment wasn’t “replaced”). The
SRC recommends that “replaced, refurbished, or updated” be used instead. At the very least, the Technical Rationale should explain that
documented limitations are expected to be eliminated whenever an IBR is re-powered, upgraded, or updated with significant re-investment.
In PRC-029-1, Attachment 1, Tables 1 and 2 use the term “operation region” while Figures 1 and 2 use the term “operating regions.” If the two terms
are intended to have the same meaning, the SRC recommends that the same term be used in both locations (and throughout the standard). If the two
terms are intended to have different meanings, the SRC recommends that the intended meanings be clarified.
In PRC-029-1, Attachment 1, item 7 references a “must ride-through zone” in Table 3 of Attachment 2. However, Table 3 of Attachment 2 does not
explicitly specify a “must ride-through zone.” The SRC recommends that the SDT clarify whether Attachment 1, item 7 was intended to reference
Figure 3 of Attachment 2, or otherwise clarify the intended meaning. The SRC also requests that the SDT clarify why Attachment 2 does not have a
corollary item specifying that Table 3 is only applicable when voltage is within the “must ride-through zone” specified in Attachment 1. The SDT
should update the Technical Rationale to clarify the intent: whether there is a need to verify or not to verify voltage status for the Table 3 Attachment
2.
The SRC notes that the Technical Rationale for PRC-029-1 contains what appears to be an extraneous “Must Ride-through” heading between the
rational for R2.5 and the rationale for R3. The SRC recommends removal of this extraneous heading.
The SRC notes that the Technical Rationale for PRC-024-4 makes no explicit mention of the addition of type 1 and type 2 wind resources to PRC-024-4
and refers to restricting the applicability of PRC-024-4 to synchronous generators and synchronous condensers, which does not appear to be
consistent with the posted redlines for PRC-024-4. The SRC recommends that PRC-024-4 and the Technical Rationale be harmonized to remove this
discrepancy.
The applicability section for PRC-029-1 references “IBR Registration Criteria,” which presumably is intended to include IBRs connected to the BPS that
are not considered BES Elements (consistent with the pending revisions to the registration criteria for IBRs). The SRC notes that the Technical
Rationale is not very clear on the intent of this structure and requests that a more detailed explanation be included in the Technical Rationale.
Finally, the SRC notes that the addition of type 1 and type 2 wind resources to PRC-024-4 appears to be limited to facilities that meet the BES
definition. The SRC requests that the SDT clarify whether this difference is intentional and, if it is, provide the rationale for the difference (such as if
the revisions to NERC’s registration criteria are not intended to apply to non-BES type 1 or type 2 wind resources) and an explanation of whether the
difference constitutes a potential gap that should be addressed.
Comments on Attachment 1: Voltage Ride-Through Criteria
Attachment 1 lists a minimum ride-through time of 1800 seconds for the continuous operation voltage region between 1.05 pu and 1.1 pu (<= 1.1 and
>1.05) in Tables 1 and 2. The SRC requests that, consistent with IEEE 2800, an exception for 500 kV systems be allowed such that the minimum rideConsideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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through time for 1.05 pu < voltage <= 1.1 pu for 500 kV systems is “Continuous,” because the 1.05 pu < voltage <= 1.1 pu voltage range is within the
normal operation range for some systems, such as PJM’s system.
In addition, in Figures 1 and 2, the SRC requests that the voltage pu values on Y-axis for the “Continuous Operating Region (1800 seconds)” be revised
to be consistent with the values listed in Tables 1 and 2 (1.05 < and <= 1.1).
Finally, the SRC generally supports incorporating as much of the IEEE 2800 language and parameters into PRC-029-1 as possible, and the SRC
encourages the drafting team to lean on IEEE 2800 as much as is feasible.
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Thank you for your comments.
Ride-through definition: The definition for Ride-through has been revised. Usage of “Transmission System” has been removed. The term is
considered necessary to tie the PRC-029 criteria to the PRC-030 analysis requirements.
IBR definition: Project 2020-06 is moving forward with another version of a definition of IBR that removes the embedded usage of another term. The
next drafts of Milestone 2 related projects, including PRC-029, will include this new term as proposed by 2020-06. Additional definitions for parts
within an IBR plant/facility will be developed by projects associated with Milestone 3 as determined by those teams.
R2.1.3/R2.2: The use of “if required” is not intended to only refer to a NERC requirement. The language related to having evidence of other
performance requirements was considered necessary for a situation where an entity receives requirements from a planner or operator that would
contradict PRC-029 requirements. The team included this as a means of allowing the GO to follow requirements if needed by planners/operators and
not be in violation of PRC-029 requirements. Planners and operators are not required to provide other performance requirements and are not
applicable to this Standard. The language reads that as long as an entity is able to demonstrate that deviations from PRC-029 performance are due to
other requirements provided by any of the listed entities, that the GO would not be in noncompliance.
R2.1.3: 95 pu has been corrected to 0.95 pu.
R2.5: The modification has been made as suggested. Footnote 10 was added to clarify pre-disturbance power and available power.
Frequency and may trip zone: A footnote was added to R1 to clarify this instance “Except if this would occur during a frequency excursion. The active
power response should recover in accordance with the primary frequency controller.” The team identifies the inclusion for R1 to allow for tripping
due to voltage excursions not simultaneously ongoing a frequency excursion.
Equipment replacement: replacement for maintenance in-kind does not remove the limitation. Additional language was added to 4.3.1 to clarify this.
Attachment 1. Note 6 (previously note 7) has been updated to reflect the reference to Figure 3 rather than Table 3.
PRC-029 Technical Rationale: The extraneous heading has been removed.
PRC-024 Technical Rationale: The TR has been updated to include Type 1 and Type 2 Wind.
Attachment 1 Tables: The tables have been corrected for consistency within the standard.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
Electric Reliability Council of Texas, Inc. (ERCOT) joins the comments submitted by the ISO/RTO Council Standards Review Committee (SRC) and
adopts them as its own. In addition, ERCOT submits the following comments.
ERCOT notes that the proposed Ride-through definition is unclear as to whether ride-through applies to partial trips (individual inverter or turbine
trips). ERCOT believes ride-through should apply both to the IBR facility and to the individual IBR units and requests that this be made clear in any
definition that may be adopted. If a defined term for ride-through is implemented, ERCOT recommends the use of a clarification modeled after the I4
inclusion (“dispersed power producing resources”) in the BES definition, as detailed in the SRC’s proposed definition:
“Facilities, including all individual dispersed power producing resources, remaining connected to the electric system and continuing to operate in a
manner that supports grid reliability throughout a System Disturbance, including the period of recovery back to a normal operating condition.”
Additionally, ERCOT has identified the following concerns with Requirement R1 as it is currently proposed:
1.) R1 does not clarify whether partial trips (individual IBR unit trips) would be allowed. ERCOT believes individual turbine/inverter trips should not
be permissible under R1 and that R1 should clearly indicate that ride-through does not occur when individual turbines or inverters trip offline.
2.) Requirement R1’s reference to “adhering” to requirements may create the mistaken impression that exceeding the minimum ride-through
requirements is not allowed.
3.) Allowing an exclusion from Requirement R1 for equipment limitations should not result in a unit being exempt from complying with
requirements that are not impacted by the limitation.
4.) The process for obtaining a documented limitation should be reviewed to ensure it is consistent with the directives that FERC included in its
recent Order on EOP-011-2 in Docket No. RD24-5-000.
To address these issues, ERCOT recommends that Requirement R1 be revised to read as follows:
R1. Each Generator Owner or Transmission Owner shall ensure the design and operation is such that each facility meets or exceeds the Ride-through
requirements, in accordance with the “must Ride-through3 zone” as specified in Attachment 1, except for the following: [Violation Risk Factor: High]
[Time Horizon: Operations Assessment]
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• The facility needed to electrically disconnect in order to clear a fault;
• The electrical system at the high-side of the main power transformer demonstrated characteristics that exceeded a documented and
confirmed equipment limitation identified and communicated in accordance with Requirement R4; or
• The instantaneous positive sequence voltage phase angle change is more than 25 electrical degrees at the high-side of the main power
transformer and is initiated by a non-fault switching event on the transmission system; or
• The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for longer than 45 seconds or exceed 1.18 per unit
for longer than 2 seconds.
3 Includes no tripping associated with phase lock loop loss of synchronism; additionally, individual inverter or turbine tripping is not allowed.
ERCOT also recommends that Requirement R2, Part 2.1 and the surrounding language be reviewed and revised to clarify that the facility should
continue to deliver the pre-disturbance level of current as appropriate, since power depends on voltage. In principle, during a disturbance active
power should only reduce proportionally to voltage such that active current is consistent unless needed for frequency response. Reactive current
should adjust as needed to support voltage (lead or lag as appropriate) up to its current limits. In general, the Requirement should neither incentivize
entities to undersize inverters/converters nor impose onerous requirements to oversize this equipment. This lack of clarity may cause issues in
enforcing this requirement and miss the reliability objective.
In addition, requiring a facility to deliver reactive power “according to its controller settings” is impractical and misses the objective. The requirement
should be to ensure the proper response performance, as each facility operates according to its controller settings, even if those settings happen to
be incorrect.
To address these issues, ERCOT recommends that the following portions of Requirement R2 be revised to read as follows:
R2. Each Generator Owner or Transmission Owner shall ensure the design and operation is such that the voltage performance for each facility
adheres to the following during a voltage excursion, unless a documented equipment limitation exists in accordance with Requirement R4. [Violation
Risk Factor: High] [Time Horizon: Operations Assessment]
2.1.1 Continue to deliver the pre‐disturbance level of active current, unless a different level of current is needed for frequency response.
2.1.2 Continue to deliver reactive current up to its reactive current limit, as appropriate to control voltage to within normal System Voltage Limits.
2.1.3 If the facility cannot meet 2.1.1 and 2.1.2 due to an apparent, active, or reactive current limit, when the applicable voltage is below .95 per unit
and still within the continuous operation region, then preference shall be given to active or reactive current as well as allowed levels of reduction,
according to the Transmission Planner, Planning Coordinator, Reliability Coordinator, and Transmission Operator requirements.
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2.6 Individual dispersed power producing resources must Ride-Through.
ERCOT appreciates the SDT’s work on the purpose statement and believes that the purpose statement can be further clarified and simplified if it is
revised to place the focus on PRC-029-1’s intended effect of ensuring the units and facilities ride-through and perform as expected instead of focusing
on “adhering” to requirements.
To achieve this objective, ERCOT recommends that the purpose statement be revised to read as follows: “To ensure that Inverter‐Based Resources
(IBRs) ride‐through, during and after, defined frequency and voltage excursions while performing operationally as expected to support the Bulk-Power
System (BPS).”
ERCOT is aware of an overarching concern that the RoCoF and phase angle jump requirements may be difficult to enforce for partial IBR
tripping. Addressing this concern may be a matter of coordination of DFRs. If individual IBR units trip but the plant does not, DFRs may not
trigger. PMUs would most likely not be fast enough to record the frequency or angle changes to validate performance. The appropriate NERC
standard development teams should coordinate with each other to ensure that individual IBR unit trips trigger DFR recording.
ERCOT requests that the drafting team remove or provide additional explanation regarding the six-month gap between the PRC-028 effective date
and the PRC-029 effective date in the Implementation Plan.
ERCOT also requests that the Implementation Plan be revised to clarify what constitutes being “in operation” (unit synchronization, full commercial
operations, or some other milestone) for purposes of determining whether an IBR may be considered for a potential exemption under the
Implementation Plan.
ERCOT encourages the SDT to review Requirement R4 and the Implementation Plan in their entirety and revise them as necessary to ensure they align
with the directives regarding constraints and exemptions that FERC included in its recent Order on EOP-012-2 in Docket No. RD24-5-000. Each
limitation should be confirmed before it is allowed to go into effect. ERCOT opposes the SDT’s broad approach of allowing exemptions without some
level of confirmation of the impact of the exemption, such as an evaluation of the reliability impact of the exemption by a PC, RC, TP, or TOP. ERCOT
believes that it is important for reliability to specifically require that limitations be modeled and provided to the PC/RC/TP/TOP. This is important
enough that it should be explicitly referenced in the standard and should be required if a limitation is to be allowed/confirmed. Otherwise, the
PC/RC/TP/TOP will receive limitations that cannot be modeled. A description of a limitation may not allow assessments and may limit determination
studies that can be performed, resulting in a gap that reliability entities are expected to address, when the burden should be on generator owners to
remove the limitation or improve the model fidelity. ERCOT believes the SDT’s proposed approach misses the objective of FERC’s directive that the
RC/PC/TP/TOP should ensure that reliability is maintained while any allowed exemptions are in effect. PRC-029-1 should incentivize facility owners to
explore whether less expensive upgrades can remove limitations rather than passing the burden of unmodeled limitations onto reliability entities that
do not have the means to secure the system against limitations they cannot model properly.
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Response
Thank you for your comments.
Please refer to the responses to the ISO/RTO Council Standards Review Committee.
R2.5: If partial tripping prevents the IBR from returning to pre-disturbance active/available power level, it would result in potential noncompliance.
Footnote #10 has been added for clarity.
IBR Definitions: While the definition for IBR was approved, it included the term IBR Unit, which was not approved and did not have an acceptable
resolution to industry and the team. As such the language was considered to be unenforceable. The teams were advised to remove usage of
unapproved terms until a clear path forward with the definitions could be assured. Project 2020-06 is moving forward with another version of a
definition of IBR that removes the embedded usage of another term. The next drafts of Milestone 2 related projects, including PRC-029, will include
this new term as proposed by 2020-06. Additional definitions for parts within an IBR plant/facility will be developed by projects associated with
Milestone 3 as determined by those teams. Further, regarding sub-BES IBR: the applicability section has been modified to include the registration
criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on usage of specific language until the
changes had been approved.
.
1) Evaluation of plant performance: The team is establishing plant/facility level ride-through requirements, consistent with the availability of
disturbance monitoring data established within PRC-028. Further, Requirement R2 requires that the plant/facility must return to predisturbance values. Should the plant experience tripping of a portion of it’s individual inverters, the overall plant would not be able to achieve
compliance with R2. PRC-030 also includes mechanisms for the entities with a wider-area view to request data, analyze performance, and
establish corrective action plans. Language in R1 has been modified to clarify that the ride through must ride-through zone is a minimum
requirement and that the plant should not be designed or operated to deliberately trip or stop exchanging current at the boundary
2) R1: use of ”adhering” has been modified
3) Equipment replacement: replacement for maintenance in-kind does not remove the limitation. Additional language was added to 4.3.1 to
clarify this.
4) R4: Language was modified in R4 regarding submittal of information for acceptance. A footnote has been added clarifying acceptance criteria.
R2: The language in R2.1 referring to active/reactive power is consistent with IEEE2800 terminology.
R2.1.1/R2.1.2: The team advises to monitor the relevant quantities (for example: active current, active power, reactive current, reactive power, and
the mode of operation). Additionally, a footnote was added to 2.1.1 to clarify returning to available power. Finally, refer to data requirements in PRC028.
Purpose: The purpose statement has been revised.
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Partial tripping: As addressed above.
Implementation Plan: Implementation Plan has been modified to include bifurcated implementation information between capability-based elements
and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to the full
requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029 implementation.
Further, the disturbances identified by planners and operators within PRC-030, would trigger the request to hold data for demonstrating
performance. Additional data requirements are established within PRC-030.
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
IV. EPRI Comments on Draft 2 of PRC-029-1
The work and efforts of this standard drafting team are much appreciated. Thank you for considering EPRI comments on the Initial Draft as submitted
previously. The new Draft 2 appears to be improved regarding internal consistency and alignment with requirements specified in voluntary industry
standards, for example, IEEE 2800-2022. However, further improvements and alignment could be considered as follows:
General comments:
•
Standard does not specify grid conditions for which ride-through requirements apply. During its lifetime, a plant may experience many
different operational conditions, along with changes to the grid, and may fail to ride-through an event if plant was operating in a grid condition vastly
different from that which it was designed for. The standard could include an exception for such situations based on leading industry practices, or a
requirement for the TP, PC, etc. to specify such an exception.
•
IEEE 2800-2022 allows for an exception for “self-protection” when negative-sequence voltage is greater than specified duration and threshold
within continuous operation region. There is no such exception in draft PRC-029. Such an exception may be necessary for type III WTG based plants.
Ride-through definition:
•
The term “synchronized” is used in the definition. The standard allows current blocking in the permissive operation region. One reason to
allow current blocking was that injected current in permissive operation region may not be in synchronism with the grid because IBR has lost track of
system voltage. The use of phrase “remaining synchronized” conflicts with the intent of current blocking allowance in the permissive operation
region.
•
The definition uses “Transmission System”. The NERC glossary of terms includes definition of “Transmission” and “System” but not
“Transmission System”. Is the intent here is to refer to defined terms “Transmission” and “System”? At some point, this standard would apply to IBRs
interconnecting to sub-transmission system. Definition of "Transmission" could include "sub-transmission" system. However, the SDT is encouraged
to think about any unintended consequences of specifically calling out “Transmission System” in the definition.
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•
The definition states “… through the time-frame of a System Disturbance”. The actual System Disturbance could be longer than specified time
limits in this standard. So, the definition could specifically mention “within defined time limits”. Perhaps replace “through the time-frame of a System
Disturbance” with “within defined time limits”.
•
Consider adopting definition from IEEE 2800, which is from IEEE 1547, and well understood by the industry.
Purpose statement:
•
Strike “as expected” and “defined” to read as follows: To ensure that Inverter-Based Resources (IBRs) adhere to Ride-through requirements as
expected to support of the Bulk Power System (BPS) during and after defined frequency and voltage excursions.
Requirement R1:
Consider revising as following: Each GO and TO shall ensure design and operation operate is such that each facility adheres to Ride-through
requirements… The same changes could be extended to other requirements.
Add “or” at end of first exception.
Requirement R2, Part 2.1
•
Why is it necessary to specify performance requirement when voltage is in the continuous operation region? The standard remains silent on
performance expectation for frequency ride-through requirements. For performance requirement for voltage ride-through mandatory operation
region is also very brief. The intent of this standard is to focus on ride-through during voltage and frequency disturbances. If there is a desire to
address performance then one option could be to simply state that performance shall be as specified by TP, PC, etc. That is in Part 2.1.3 anyway.
•
Part 2.1.2: remove “and according to its controller settings”. It is not incorrect but “according to its controller settings” inherently apply to all
performance requirements.
Part 2.1.3: This is sub-part of 2.1 but does not read correctly. When sub-part 2.1.3 is read immediately after part 2.1, it reads “….in Attachment 1,
each facility shall → if the facility cannot deliver….” Revise for better readability.
Furthermore, this requirement in IEEE 2800 was necessary and was tied to reactive power capability requirement as shown in Figure 8 of IEEE 2800.
Given PRC-029 does not include reactive power capability requirements, perhaps PRC-029 could remain silent.
Replace “95 per unit” with “0.95 per unit”
Requirement R2, Part 2.2
•
Part 2.2 applies at the high-side of the main power transformer. The IBR is required to exchange current, up to the maximum capability. How
is the “maximum capability” of an IBR determined? There could be some explanation, perhaps with examples, in the technical rationale document.
The phrase “provide voltage support on affected phases during both symmetrical and unsymmetrical voltage disturbances” is confusing. It is
understood that intent is to require to inject “unbalanced current” or “negative-sequence” current during asymmetrical faults. However, as written,
injection of balanced reactive current into an unbalanced fault meets the requirement to provide voltage support on affected phases, in addition to
unaffected phase. The standard does not prohibit voltage support on unaffected phases. The voltage support on unaffected phase is usually
problematic. But the requirement, as written, does not prohibit this.
During a L-G fault, current in a faulted phase is dependent on transformer winding configuration. Does this requirement, unintentionally, specify
specific transformer configuration?
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During mandatory operation, voltage is abnormal and could be almost zero for close-in faults. As such, “current” over “power” is more appropriate.
Power is faulted and unfaulted phases could be different as well. Replace active and reactive power with active and reactive current, respectively.
Requirement R2, Part 2.3.1
•
Per language in attachment 1, permissive operation is allowed when line-to-ground or line-to-line voltage is below 10%. But per Part 2.3.1,
IBR is required to restart current exchange when positive-sequence voltage enters continuous or mandatory operation region. This is conflicting. For
example, for a line-to-ground fault on high-side terminals of main power transformer, the positive-sequence voltage would be more than 10%, i.e., in
the mandatory operation region.
Requirement R2, Part 2.4
•
The intent of this requirement is understood. However, if there are multiple plants in the area, then one plant misbehaving may cause
overvoltage on high-side terminals of main power transformer of other plants in the area. Also, the post-fault dynamics greatly depend on system
operating condition (peak, shoulder, off-peak, etc.) along with transmission outages, status of capacitor banks, etc. The Generator Owner usually does
not have system data to evaluate post-fault system dynamics and to determine if plant’s behavior is or not a contributing factor to overvoltage.
Footnotes 5 and 7: Both footnotes are an exception to requirements. Are exceptions allowed in footnote?
Footnote 6: Uses “shall” and hence is a requirement. Move it to the main body of the standard. Additionally, uses “active power” and “reactive
current”. Replace “active power” with “active current”.
Requirement R3
•
Consider revising as following for better readability: Each GO and TO shall design and operate each IBR facility to Ride-through frequency
excursion event where the System frequency remains within the “must Ride-through zone” according to Attachment 2 and the absolute rate of
change of frequency (ROCOF) magnitude is less than or equal to 5 Hz/second.
•
The proposed frequency ride-through requirement is more stringent than the applicable requirement in IEEE Std 2800-2022. The justification
provided in the technical rationale is based on engineering judgement with no provided substantiating studies. Furthermore, the PRC-006 requires
the design of UFLS program to keep frequency withing certain bounds. Requiring IBRs to ride-through a slightly more frequency deviation compared
to frequency deviation band allowed in PRC-006 seems reasonable. However, the proposed frequency ride-through requirement is much more
stringent. Consider aligning with IEEE Std 2800 frequency ride-through requirement as a minimum requirement and let regions specify more stringent
requirements where justified.
•
The standard does not allow exception for frequency ride-through requirements. For plants in commercial operation before the effective date
of this standard, installed equipment (wind-turbine generator, inverter, etc.) was never tested to determine if it would be able to ride-through
proposed frequency ride-through requirements. The SDT points to directive in FERC order 901 and states that order 901 does not allow exception for
frequency ride-through. However, order 901 does not require frequency ride-through requirements as stringent as the ones proposed.
Footnote 8 Could be simplified as following: The ROCOF is an average rate of change of frequency over an averaging window of at least 0.1 second.
Requirement R4, Part 4.3
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•
Part 4.1 and 4.2 refer to exemption for a plant but part 4.3 refers to equipment in plant. If few of many wind-turbine generators in a plant are
replaced, then plant still has limitation because most of the wind-turbine generators still have limited capability. Perhaps some clarification could be
added that if all equipment with limitation is replaced then only exemption to facility does not apply.
Violation Severity Levels
R1, R2, and R3: The lower VSL for each of these requirements is for failure to demonstrate the capability to ride-through. Two reasons for which this
could arise:
(1) Plant is capable to ride-through but is not demonstrated in design evaluation or interconnection studies.
(2) Plant is not capable to ride-through and is demonstrated in design evaluation or interconnection studies.
Reason (1) is not a problem for grid reliability, it is just that studies are not adequate to demonstrate ride-through capability, and hence lower VSL is
justified. But reason (2) is not any different from a case in severe VSL where an entity fails to demonstrate that facility adhered to ride-through
requirements (based on actual system disturbance event data).
Attachment 1
•
Clarify that cumulative window, for voltage band where ride-through duration is 1800-second, is 3600-second. Also, consider clarifying that
1800-second ride-through duration is only applicable to nominal voltages other than 500 kV.
•
Numbered item #3: states that applicable voltage is “… on the AC side of the transformer(s) that is (are) used to connect…..”. Both sides of
transformer are AC, one is on DC-AC converter side and another on AC grid side. As written, voltage on either side of transformer is applicable. Please
clarify that applicable voltage is on AC “grid” side of the transformer.
•
Numbered item #6: Consider revising as following - The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of phase to
neutral ground or phase to phase fundamental frequency root mean square (RMS) voltage at the high side of the main power transformer.
•
Numbered item #8: The interpretation of ride-through curves/points needs further clarification. Would a wind-based IBR plant be required to
ride-through an event where at t=0 voltage drops from nominal to zero, then @t=0.16 s voltage rises to 25%, @t=1.2 s voltage rises to 50%, @t=2.5 s
voltage rises to 70%, @t=3 s voltage rises to 90%? The item (8) is also tied to item (12), where a combined “area” is stated. Does must ride-through
zone represent an “area” (represented by deviation in voltage multiplied by time duration)?
•
Numbered item 11: Please clarify if this statement applies to protection applied to high side of main power transformer only OR everywhere
in the plant.
Attachment 2:
Table 3 - It should be considered to read like following: > 64
<= 64 and > 61.8
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<= 61.8 and > 61.5
<= 61.5 and > 61.2
<= 61.2 and >= 58.8
< 58.8 and >= 58.5
•
•
Consider adding a statement that frequency ride-through requirements apply only when voltage is in the must ride-through zone.
Numbered item 3: What is meant by control settings? Is the intent to state protection settings instead?
Likes
0
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Response
Thank you for your comments.
General:
Need statement on Grid Condition
The SDT Requirement R2 specifies the applicability of the standard for the specific system condition as per the TP, PC requirements based on the
system wide studies. Operation outside of the normal system condition is not within the scope of this standard, which should be covered in other
standards such as modeling and interconnection standard, e.g., FAC standard and/or MOD standards. And the SDT decided to keep silent on these IBR
stability issues.
Need statement on self-protection for negative-sequence
Same to the above comment, the SDT determined that this issue is system dependent and should be covered the TP, PC studies. For legacy units
which can’t meet this requirement, the GO should follow Requirement R4 to request an exemption. Considering the fact that this standard is only
applicable to GO, including this requirement may expand the applicability to other entities such as TP, PC, which is not aligned with IBR standard at
this point. For the self-protection based on the negative-sequence current, the SDT suggested to propose a new SRA to address the IBR protection
requirement.
Ride-through definition: The definition for Ride-through has been revised to reflect industry comments.
Purpose statement: The purpose statement has been revised to reflect industry comments.
R1: Language to “ensure” has been removed. The “or” was added to the first sub-bullet.
R2: The performance aspects of R2 are to assure adequate levels of ride-through characteristics during voltage excursions.
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Need statement on “according to its controller settings
This requirement is aligned with the IEEE 2800-2022 7.2.2.2.
R2.1.3: There is no obligation or requirement for planners or operators to supply other performance requirements. The language related to having
evidence of other performance requirements was considered necessary for a situation where an entity receives requirements from a planner or
operator that would contradict PRC-029 requirements. The team included this as a means of allowing the GO to follow requirements as needed by
any planners/operators and not be in violation of PRC-029 requirements. – The 95 per unit has been corrected to 0.95 per unit.
Need responses for all of R2.2 above.
The SDT agrees to add some examples to clarify the Maximum Capability and Negative Sequence Current during the unbalance fault condition in the
next version of TR.
Need responses for all of R2.3.1 above.
Thanks for your comment. The SDT decided that, in the next version, a footnote or a note to Attachment 1 will be added to clarify that the permissive
operation region is defined based on the positive sequence voltage below 0.1 pu. This requirement is aligned with the FERC Order 901.
Need responses for all of R2.4 above.
This requirement is intended to avoid a self-tripping caused by the control, the measurements from the tripping event will be used to analyze the
tripping is caused by the IBR controller itself or the system condition. The scope of using measurements to determine the ride-through compliance is
covered by the Standard PRC-030. If the tripping is related to the system condition, there will be no compliance violation.
Footnotes 5 and 7: Footnotes may be used to provide additional clarification or breakdown. This practice is allowable.
Footnote 9 (previously footnote 6): Need response
This footnote states that ‘if required’, which means this is not a mandatory requirement for the TP, PC to provide these requirements. The SDT deem
real power is clear to the industry. More clarifications will be added to the next version of TR.
Need responses for all of R3 above.
The SDT disagrees with the proposed language, removing ‘ensure’ since the GO normally don’t explicitly design the IBR plants. But the GO should
ensure the design to meet the requirements.
Regarding the more stringent frequency requirement, please refer to the TR for more clarification.
Frequency/R3/Attachment 2 Exemptions: In Order No. 901, FERC directed NERC to determine whether the ride-through standard should provide for
a limited and documented exemption for certain registered IBRs from voltage ride through performance requirements, and only for voltage ride
through performance for those existing IBRs that are unable to modify their settings without physical modification of equipment. See Order No. 901
at P 193. The drafting team determined that such an exemption was appropriate and it is included in Requirement R4. The drafting team does not
have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901. The drafting team does believe additional monitoring would be appropriate to determine how many entities would
be affected by such an exemption and whether such an exemption would be consistent with overall Bulk-Power System reliability. To the extent such
monitoring suggests that further exclusions would be appropriate, a future drafting team could make those changes in an expeditious manner. The
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affected entities could work with ERO Enterprise staff to address any compliance-related concerns in the interim. For this draft, however, the drafting
team is pursuing a more conservative approach in line with the specific exemptions identified in Order No. 901.
Footnote 12 (previously footnote 8):
Need response
The SDT decided to add more clarification to the next version of TR on the ROCOF calculation.
Equipment replacement: replacement equipment that does not remove the limitation of the IBR (plant) does not satisfy the requirement. new
language was added to 4.3.1 to clarify this.
VSLs: Any root cause analysis for failing to demonstrate design evaluation would be facts and circumstances that are applied during the CMEP. Similar
to determination of extent of condition, the facts would be considered by CMEP staff.
Attachment 1: Need response
The SDT decided to incorporate these suggestions in the next version as appropriate.
Attachment 2: Need response
The Table 3 has been modified. Please check the latest draft.
Wes Baker - Silicon Ranch - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
General
The SDT should consider specifying the grid conditions to which the ride-through requirements apply. The conditions should be bounded to some
degree as the GO does not know the details of the transmission system and the range of operating conditions over the entire life of the plant.
R1
PRC-029 does not have an exception for transient overvoltage. This implies that the plant must ride through an unbounded transient voltage
magnitude, which is unreasonable. Power electronic devices are sensitive to voltage and current. Equipment vendors and plant designers need to
have clear performance requirements to design their equipment and plants to meet and be able to protect their equipment from damage when
conditions are outside of these performance requirements. The SDT should consider adding an exception for transient overvoltage similar to IEEE
2800-2022 Clause 7.2.
R2
R2.1
Requirements for operating within the continuous operating range do not seem to be in scope with a ride-through standard. Additionally, these
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requirements are incomplete if the SDT intends to specify how the plant shall perform when voltage and frequency are within the continuous
operating range. The SDT should consider removing R2.1.
R2.2
•
•
•
Given that this requirement is at the IBR plant level, it is unclear how 'maximum capability' is defined. The SDT should consider clarifying in the
standard what the IBR plant's 'maximum capability’technically refers to.
During a mandatory operating range, it is more appropriate to use 'current' rather than 'power' since power is a function of voltage. The SDT
should replace all references to 'power' with 'current' for voltage outside the continuous operating range.
The response of the IBR during HVRT and LVRT is typically dictated by the inverterlevel control based on inverter terminal voltage. The
inverter does not have information about the high side of the main power transformer voltage at the required time scale. Additionally, there
are multiple transformers with different winding configurations (e.g., delta, wye, wye-grounded) between the POI/POM where the PRC-029
requirement applies and the inverter terminal where the control is implemented. Using positive and negative sequence reactive current
consistent with IEEE 2800-2022 Clause 7.2 is more practical than the 'affected phases.' The key is that the IBR should regulate the positive
sequence and negative sequence voltage. This is the resulting effect of the IBR injecting positive and negative sequence reactive current
based on positive and negative sequence voltage, /’;’[‘respectively, and is consistent with how a synchronous machine naturally responds to
asymmetrical disturbance. The SDT should consider making the current injection requirements applicable at the inverter terminal and based
on sequence components consistent with IEEE 2800-2022 Clause 7.2.
R2.3.1
The use of 'positive sequence voltage' with respect to the continuous and mandatory operating range is not consistent with the rest of the standard
which uses max/min of phase-phase or phase-ground fundamental frequency RMS voltage. For consistency, the SDT should change positive sequence
voltage to max/min of phase-phase or phase-ground fundamental frequency RMS voltage.
R2.4
The requirement, as written, may not be practical for assessing compliance/noncompliance for the GO. The voltage at the IBR plant would also
depend on the grid, including neighboring plants. Therefore, the IBR plant itself is unlikely to cause the plant to exceed the high voltage thresholds but
certainly may contribute to the overvoltage. The SDT should consider removing this requirement and lumping it together with R2.2, adding
requirements to the response time consistent with IEEE 2800-2022 Clause 7.2. If the IBR actively regulates the positive and negative sequence voltage
quickly, the effect is as desired and can be readily assessed for compliance.
R3
The frequency ride-through requirements are much more stringent than IEEE 2800-2022 Clause 7.3. The SDT should provide more justification,
beyond what is described in the Technical Rationale, as to why this range of frequency ride-through is required. Additionally, the SDT should ensure
that due diligence has been done with vendors of the various equipment to ensure that this requirement is reasonable, and achievable with available
technology.
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Attachment 1
Tables 1 and 2 and numbered item 8
By using voltage bands (e.g., 0.7 <= V < 0.9) and time durations this results in a much more stringent requirement than IEEE 2800-2022 Clause 7. The
SDT should consider removing the voltage bands to align with IEEE 2800-2022 Clause 7. Take this example where the red is a fictitious voltage plot:
Comparison of standards:
• IEEE 2800 Clause 7:
o V < 0.9 pu ~ 8 seconds
o V < 0.7 pu ~ 3 seconds
o There is not an interpretation where the IBR has to ride through this LVRT in
IEEE 2800 Clause 7.
• PRC029 :
o 0.7 <= V < 0.9 pu ~ 5 seconds.
o 0.5 <= V < 0.7 pu ~ 3 seconds.
o PRC-029 as written implies the IBR has to ride-through.
Numbered item 11
The standard should not specify how protection functions must be implemented. Instead, it should describe the required performance. Further, this
requirement implies that the plant must ride through an unbounded voltage magnitude, which is not reasonable. As written, this item does not allow
for tripping caused by excessive transient over-voltage (TOV) events. Power electronic devices are sensitive to voltage and current. Equipment
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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115
vendors and plant designers need to have clear performance requirements to design their equipment and plants to meet and be able to protect their
equipment from damage when conditions are outside of these performance requirements
Likes
0
Dislikes
0
Response
Thanks for your comments. Table 1 and Table 2 have been revised and the previous graphs associated to Table 1 and Table 2 have been removed.
Additional voltage examples will be added to the next version of TR.
The Note 11 is not to specify the protection setting, rather its purpose to avoid the instantaneous tripping without any filter.
Comments received from LG&E/KU
Questions
1. Provide any additional comments for the Drafting Team to consider, if desired.
Comments:
All comments below pertain to PRC-029-1.
LG&E/KU agrees with the applicability concerns of EEI and suggests removing TOs and VSC-HVDC systems from this standard.
LG&E/KU also agrees with EEI that the requirements listing the TP, PC, RC, or TOP should clarify responsibility and include the responsible entity in the
applicability of this standard. Alternatively, these listings may be sufficiently replaced with a requirement to adhere to applicable Facility
interconnection requirements (e.g., “preference shall be given to active or reactive power according to applicable Facility interconnection
requirements”).
The following additional comments are provided:
Requirement R1
Footnote 3 in Requirement R1 is unnecessary as the term “Ride-through” includes remaining synchronized.
The following edit should be made to Requirement R1 to clarify responsibility is only for Facilities (note “Facility” is a NERC defined term and should be
capitalized) under the responsible entities ownership:
… shall ensure the design and operation is such that each of its IBR Facilities facility adheres to Ride-through requirements, in accordance with the
“must Ride-through3 zone” as specified in Attachment 1, except for …
The following edit is suggested for bullet 1 under Requirement R1:
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
116
The facility IBR Facility needed to electrically disconnects in order to clear a fault; or
Measure M1
Measure M1 adds to the scope of Requirement R1. Measures should only describe how compliance with the associated Requirement will be assessed,
not add to the scope of the Requirement itself. For example, Measure M1 strongly suggests that “dynamic simulations” and “studies” are the only
acceptable forms of evidence for determining ride-through capability. However, Requirement R1 does not have any explicit requirement to perform
analysis.
Measure M1 also states disturbance monitoring data is required to demonstrate adherence to Ride-through requirements. It is unclear what is required
here since IBR Facilities will be online and operating normally most of the time. The most recent draft of PRC-030-1 already includes requirements for
analyzing “Ride-through performance” in situations where the IBR Facility significantly reduces active power output (which would include tripping). It is
more appropriate to analyze failed Ride-through than it is to provide immense quantities of data showing the IBR Facility is operating normally.
Measure M1 references only one of the exceptions listed under Requirement R1.
The following edit is suggested for Measure M1 (responsibility issues should also be addressed, as noted previously):
Each Generator Owner and Transmission Owner shall have evidence of dynamic simulations, studies, or other evidence to demonstrate that the
design and operation of each of its IBR Facilities facility will adheres to the Ride-through requirements, as specified in Attachment 1Requirement
R1. Each Generator Owner and Transmission Owner have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic
Disturbance Recorder, and Fault Recorder) to demonstrate that the operation of each facility did adhere to Ride-through requirements, as specified
in Requirement R1. If the Generator Owner and Transmission Owner choose to utilize If failed Ride-through occurs for conditions exempted in
Requirement R1 exemptions that occur within the “must Ride-through zone” and are caused by non-fault initiated phase jumps of greater than 25
electrical degrees, then each Generator Owner and Transmission Owner shall also have evidence of the conditions actual disturbance monitoring
(i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate that the facility failed to Ride-through
during a phase jump of greater than or equal to 25 electrical degrees, and documentation from their Transmission Planner, Reliability Coordinator,
Planning Coordinator, or Transmission Operator that a non-fault initiated switching event occurred.
Requirement R2
Requirement R2 addresses performance during the Ride-through conditions of Requirement R1 and should establish a clear link. There is also
inconsistency in that Requirement R2 only exempts documented equipment limitations and none of the other exemptions in Requirement R1. The
following edit is suggested for Requirement R2:
… shall ensure the design and operation is such that of the voltage performance for of its IBR Facilities each facility adheres to the following during
conditions requiring Ride-through a voltage excursion, unless a documented equipment limitation exists in accordance with Requirement R14.
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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117
Each part of Requirement R2 refers to the “voltage at the high-side of the main power transformer”. Attachment 1 already states in item (6) that the
applicable voltage is at the high-side of the main power transformer. Thus, each part of Requirement R2 should be condensed as follows:
While the voltage at the high-side of the main power transformer remains wWithin the continuous operation region as specified in Attachment 1,
each facility IBR Facilities shall:
Requirement R2 part 2.1.2 should be removed. Delivering reactive power “up to its reactive power limit and according to its controller settings”
wouldn’t appear to be anything other than normal operation.
Requirement R2 part 2.1.3 is clearly intended to mirror a similar requirement in IEEE 2800-2022 subclause 7.2.2.2. However it makes two errors, and
unnecessarily restates the voltage is in the continuous operating region (Requirement R2 part 2.1 already includes this condition). Correct as follows:
If the IBR Facility facility cannot deliver both active and reactive power due to a current limit or reactive apparent power limit, when the voltage is
below 0.95 per unit and still within the continuous operation region, then preference shall be given to active or reactive power according to
requirements if required by of the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
It is understood that the DT had “apparent power limit” in the first draft of this standard and has now replaced it with “reactive power limit” following
comments. However, this is an error. The apparent power limit is a limit of the inverter and not the PPC as suggested in some of the comments. IEEE
2800-2022 correctly states the limit is “apparent” power. I.e., an inverter has an MVA limit and there may be times when the inverter is called on to
produce more total MVA (MW and MVAR) than it is able to. It is in this case that the inverter must prioritize MW or MVAR.
The language of Requirement R2 part 2.2 is unnecessarily confusing. Attachment 1 already indicates the boundaries of the mandatory operating region
and they are delineated by RMS voltages. Suggested simplification and clarification:
While voltage at the high-side of the main power transformer is wWithin the mandatory operation region as specified in Attachment 1, each an IBR
Facility shall continue to exchange current, up to the its maximum limit capability to and provide voltage support., on the affected phases during
both symmetrical and asymmetrical voltage disturbances, either under6:• IBR Facilities shall operate in Rreactive power priority by default;, or• in
Aactive power priority if required by the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
Footnote 6 is unnecessary for this standard. Entities that wish to specify the magnitude of current injections during disturbances should do so in their
Facility Interconnection Requirements.
Suggesting the following simplification of Requirement R2 part 2.3.1:
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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118
If an IBR Facility facility enters current blocking mode, it shall restart current exchange in less than or equal to five cycles of positive sequence
voltage returning to the a continuous operation region or mandatory operation region.
Suggesting the following simplification of Requirement R2 part 2.5:
Each facility IBR Facilities shall restore active power output to the pre-disturbance or available level (, whichever is lesser), within 1.0 second when
the voltage at the high-side of the main power transformer upon returnings from the mandatory operation region or permissive operation region
(including operating in current block mode), to the continuous operating region as specified in Attachment 1, unless the Transmission Planner,
Planning Coordinator, Reliability Coordinator, or Transmission Operator specifies otherwise requires a lower post-disturbance active power level
requirement or requires a different post-disturbance active power restoration time.
Footnote 7 introduces confusion as it pertains to “frequency excursions” which is taken to mean conditions necessitating Ride-through. In this case,
Requirement R3 and R4 would apply. Suggesting removal of this footnote.
Requirement R3
Suggesting the following simplification of Requirement R3 (to align with suggestions for Requirement R1):
… shall ensure the design and operation is such that each facility of its IBR Facilities adheres to Ride-through requirements during a frequency
excursion event whereby the System frequency remains within the “must Ridethrough zone” according to specified in Attachment 2 and when the
absolute rate of change of frequency (RoCoF)8 magnitude is less than or equal to 5 Hz/second.
Measure M3
Measure M3 oversteps Requirement R3 similar to the M1/R1 discussion above. Suggested revision:
Each Generator Owner and Transmission Owner shall have evidence of dynamic simulations, studies, or other evidence to demonstrate that the
design and operation of each of its IBR Facility facility will adheres to the Ride-through requirements, as specified in Attachment 2 Requirement
R3. Each Generator Owner and Transmission Owner also have evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic
Disturbance Recorder, and Fault Recorder) data to demonstrate the operation of each facility did adhere to If failed Ride-through requirements, as
specified in Requirement R3, during each frequency excursion event measured at the high-side of the main power transformer occurs for RoCoF
magnitude greater than 5 Hz/second, each Generator Owner and Transmission Owner shall have evidence of the condition.
Requirement R4
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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119
Requirement R4 is unwisely linked to the effective date of PRC-029-1. This makes sense at the initial effective date, but it excludes IBR Facilities that
come in-service after the effective date. Further, it doesn’t address failure to meet frequency Ride-through requirements. It appears to unnecessarily
call out hardware limitations when software limitations can also be problematic. Finally, it seems to imply an exemption process exists but does not say
who can grant an exemption or what the requirements for exemption are (e.g., is it subject to approval of the technical documentation?). The following
revision is suggested:
If a Each Generator Owner and Transmission Owner identifiesying one of its IBR Facilities facility that is in-service by the effective date of PRC-0291, has known hardware limitations that prevent the facility from meeting voltage the Ride-through requirements criteria as detailed in of
Requirements R1, R2, and or R32, and requires an exemption from specific voltage Ride-through criteria the Generator Owner shall:
Below are suggested edits in various parts of Requirement R4 to align with the body of R4 suggested above:
(4.1) Document information supporting the identified hardware limitation no later than 12 months following the effective date of PRC-029-1 after it
is identified.
(4.1.2) Which aspects of voltage or frequency Rride-through requirements that the IBR Facility is would be unable to meet and the capability of the
equipment due to the limitation;
(4.1.4) Supporting technical documentation verifying explaining if the limitation is due to hardware that needs to be physically replaced or that if
the limitation cannot be removed by software updates or setting changes, and;
(4.2) Request an exemption from [whom?] by pProvidinge a copy of the information detailed in Requirement R4.1 to the applicable Planning
Coordinator(s), Transmission Planner(s), Transmission Operator(s), Reliability Coordinator(s), and to the Regional Entity no later than 12 months
following the effective date of PRC-029-1 after the limitation is identified.
(4.2.1) Any response to additional information requested by the applicable Planning Coordinator(s), Transmission Planner(s), Transmission
Operator(s), Reliability Coordinator(s), and to the or Regional Entity shall be provided back to the requestor within 90 days of the request.
(4.3) Each Generator Owner and Transmission Owner with a previously submitted request for exemption that replace the equipment causing
corrects the limitation shall document and communicate such an equipment change the correction to the associated Planning Coordinator(s),
Transmission Planner(s), Transmission Operator(s), and Reliability Coordinator(s) within 90 days of the correction equipment change.
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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120
(4.3.1) When existing equipment is replaced an exempted Ride-through limitation is corrected, the exemption for that Ride-through criteria no
longer applies.
Much of Requirement R4 concerns an exemption process which is poorly defined. Other standards, including others currently being developed for IBRs
due to FERC directives, have utilized language requiring “Corrective Action Plans” for certain failures. The DT should consider if alignment with these
standards is appropriate and should revisit the scope of the SAR for this project. Regardless, the DT must address several key issues that it has created
by introducing the exemption language:
• Who grants the exemption?
• How long does the approving entity have to grant or deny an exemption?
• Is an IBR Facility out of compliance if it has requested an exemption but the exemption has not yet been granted?
• Is there still a requirement to fix the issue if you have an exemption?
• What if an IBR Facility is unable to meet the Ride-through requirements without a significant investment (e.g., replacing every inverter with new
models)?
Measure M4
Measure M4 should be substantially revised to reflect the concerns addressed in the comments above.
Attachment 1
Regarding Table 1 of Attachment 1, row 2 appears to use the incorrect operator and should be corrected as follows: “≤ 1.20 and > 1.1”.
Row 4 of Table 1 and Table 2 lists “Continuous” as a time where “∞” would be more appropriate.
It is recommended to remove footnotes 12 and 14 and place “May Ride-through Zone” directly into the table, e.g., “N/A (May Ride-through Zone)”.
Item (2)(b) of Attachment 1 references “hybrid plants consisting of photovoltaic (PV) and BESS” but does not address hybrid plants with other
components. Item (4) says Table 2 applies to hybrid facilities with no wind. IEEE 2800-2022 clarifies that it does not apply to synchronous components
of hybrid plants. PRC-029-1 needs to be more careful in its wording regarding hybrid plants.
Item (6) of Attachment 1 defines the applicable voltage as the high-side of the MPT and does not give the PC/TP/TO/etc. any flexibility to change that.
Some entities with IEEE 2800-2022 requirements have adjusted the Reference Point of Applicability for Ride-through to the POI for various reasons
(including that they may install monitoring equipment at that location rather than at the MPT). PRC-029-1 should not remove the flexibility of
PC/TP/TO/etc. to alter the point of applicability.
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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121
Figure 1 of Attachment 1 uses the old “No-Trip Zone” label which is not used anywhere else in PRC-029-1.
Attachment 2
Regarding Table 3 of Attachment 2, “May trip” on rows 1 and 9 should be replaced with “N/A” for consistency with Table 1 and Table 2. It is unclear why
the frequency values are unaligned (and exceed) IEEE 2800-2022 when the voltage Ride-through requirements of PRC-029-1 are aligned with IEEE 28002022. It is not prudent to exceed the requirements of IEEE 2800-2022 when 1) it already significantly exceeds PRC-024-3, and 2) it is recognized as an
industry standard for utilities, developers, OEMs, etc.
Rows 5 and 6 of Table 3 have incorrect operators and row 6 includes an incorrect number (58.8 instead of 58.5).
Finally, item (1) of Attachment 2 defines the applicable frequency at the high-side of the MPT and does not give the PC/TP/TO/etc. any flexibility to
change that. As noted above, some entities with IEEE 2800-2022 based requirements use the POI as the RPA for Ride-through capability.
Response
Thank you for your comments.
TO: Transmission Owner has been removed from PRC-029.
Other Performance Requirements: The language related to having evidence of other performance requirements was considered necessary for a
situation where an entity receives requirements from a planner or operator that would contradict PRC-029 requirements. The team included this as a
means of allowing the GO to follow requirements if needed by planners/operators and not be in violation of PRC-029 requirements. Planners and
operators are not required to provide other performance requirements and are not applicable to this Standard. The language reads that as long as an
entity is able to demonstrate that deviations from PRC-029 performance are due to other requirements provided by any of the listed entities, that the
GO would not be in noncompliance.
Footnote 3: Phase lock loop clarification was determined to be helpful to include.
Plant/facility: The terminology has been changed to IBR to coincide with the new proposed definition for IBR. Additionally, this section has been
modified to include the registration criteria within the recently approved changes to the NERC Rules of Procedures. The team was advised to hold on
usage of specific language until the changes had been approved.
Measures: the measures are now written to provide specific examples of evidence needed for compliance. Further the implementation plan has been
revised to bifurcate between capability-based elements and performance-based elements. Essentially this is now a phased-in implementation plan
whereas each entity will be required to respond to the full requirement over time. This will allow entities to align their PRC-028 and the performancebased aspects for PRC-029 compliance.
R1/R2: R1 requires ride-through within the must Ride-through zone. R2 includes additional performance requirements beyond tripping/momentary
cessation/failing to Ride-through.
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
122
R2.1.1/R2.1.2: The team advises to monitor the relevant quantities (for example: active current, active power, reactive current, reactive power, and
the mode of operation). Additionally, a footnote was added to 2.1.1. Finally, refer to data requirements in PRC-028.
R2.1.3: 95 pu has been corrected to 0.95 pu.
R2.2: Language was revised for clarity
Previous footnote 6: See response to Other Performance Requirements above.
Implementation Plan: Implementation Plan has been modified to include bifurcated implementation information between capability-based elements
and performance-based elements. Essentially this is a phased-in implementation plan whereas each entity will be required to respond to the full
requirement over time. This approach allows for entities to align their PRC-028 and the performance-based aspects of their PRC-029 implementation.
Further, the disturbances identified by planners and operators within PRC-030, would trigger the request to hold data for demonstrating
performance. Additional data requirements are established within PRC-030.
R4 acceptance: Additional information has been provided to R4 to clarify the acceptance expected. Requirements cannot be written towards Regional
Entities. As written, an entity who submits the documentation as required and responds to additional requests as required would be compliant. An
entity would not be determined to be noncompliant while the CEA (previously Regional Entity) processes that submittal.
Attachments 1 and 2: Tables, figures, and notes have been reflected to address these comments and others from industry.
End of Report
Consideration of Comments | Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
August 19. 2024
123
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Project 2020-02 Modifications to PRC-024 (Generator Ridethrough) | PRC-024-4 and PRC-029-1
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Additional ballots for Project 2020-02 Modifications to PRC-024 (Generator Ride-through) and nonbinding polls of the associated Violation Risk Factors and Violation Severity Levels are open through 8
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North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Ballot Open Reminder
Project 2020-02 Modifications to PRC-024 (Generator Ride-through | June 28, 2024
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Project 2020-02 Modifications to PRC-024 (Generator Ridethrough) | PRC-024-4 and PRC-029-1
Formal Comment Period Open through July 8, 2024
Now Available
A 20-day formal comment period for Project 2020-02 Modifications to PRC-024 (Generator Ridethrough), is open through 8 p.m. Eastern, Monday, July 8, 2024.
The Standards Committee approved waivers to the Standard Processes Manual at their December 2023
meeting. These waivers were sought by NERC Standards staff for reduced formal comment and ballot
periods. This will assist the drafting teams in expediting the standards development process due to firm
timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket No. RM22-12-000
on October 19, 2023.
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period are reflected in these drafts of the standards and other documents.
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or at 404-960-0568 Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
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Atlanta, GA 30326
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Standards Announcement | Formal Comment Period Open
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/334)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 AB 2 ST
Voting Start Date: 6/28/2024 1:41:54 PM
Voting End Date: 7/8/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 233
Total Ballot Pool: 271
Quorum: 85.98
Quorum Established Date: 7/8/2024 4:35:50 PM
Weighted Segment Value: 82.7
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
75
1
42
0.778
12
0.222
0
11
10
Segment:
2
8
0.7
6
0.6
1
0.1
0
0
1
Segment:
3
55
1
36
0.766
11
0.234
0
3
5
Segment:
4
14
0.9
9
0.9
0
0
0
1
4
Segment:
5
68
1
39
0.796
10
0.204
0
7
12
Segment:
6
46
1
26
0.722
10
0.278
0
4
6
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.4
4
0.4
0
0
0
1
0
Totals:
271
6
162
4.962
44
1.038
0
27
38
Segment
BALLOT POOL MEMBERS
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Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Affirmative
N/A
1
Ameren - Ameren
Services
Tamara Evey
None
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Negative
Comments
Submitted
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
Affirmative
N/A
None
N/A
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
Tim Kelley
Ballot
NERC
Memo
Affirmative
N/A
Adrian Andreoiu
Abstain
N/A
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Affirmative
N/A
1
Black Hills Corporation
Micah Runner
Affirmative
N/A
1
Bonneville Power
Administration
Kamala RogersHolliday
Abstain
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
None
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Affirmative
N/A
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Affirmative
N/A
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Affirmative
N/A
1
Evergy
Kevin Frick
Affirmative
N/A
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Affirmative
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
1
Glencoe Light and Power
Commission
Terry Volkmann
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
Carly Miller
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
1
Hydro One Networks, Inc.
Emma Halilovic
1
IDACORP - Idaho Power
Company
Sean Steffensen
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
1
International
Transmission Company
Holdings Corporation
Michael Moltane
1
JEA
1
Designated
Proxy
NERC
Memo
Abstain
N/A
None
N/A
Denise Sanchez
Affirmative
N/A
Gail Elliott
Affirmative
N/A
Joseph McClung
Affirmative
N/A
KAMO Electric
Cooperative
Micah Breedlove
Negative
Third-Party
Comments
1
Lakeland Electric
Larry Watt
None
N/A
1
Lincoln Electric System
Josh Johnson
None
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
Abstain
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Third-Party
Comments
1
Manitoba Hydro
Nazra Gladu
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Affirmative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Negative
Third-Party
Comments
1
National Grid USA
Michael Jones
Affirmative
N/A
1
NB Power Corporation
Jeffrey Streifling
Abstain
N/A
Negative
Comments
Submitted
1
NextEra Energy - Florida
Silvia Mitchell
Power and Light Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ijad Dewan
Ballot
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Negative
Third-Party
Comments
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug Peterchuck
Affirmative
N/A
1
Oncor Electric Delivery
Byron Booker
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Affirmative
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Negative
Third-Party
Comments
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Affirmative
N/A
1
Public Utility District No. 1
of Chelan County
Diane E Landry
Affirmative
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
Abstain
N/A
None
N/A
1
Seminole Electric
Kristine Ward
Cooperative, Inc.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Broc Bruton
Bob Cardle
Segment
Organization
Voter
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
1
Sho-Me Power Electric
Cooperative
1
Designated
Proxy
NERC
Memo
Affirmative
N/A
Olivia Olson
Negative
Third-Party
Comments
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
None
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Affirmative
N/A
1
Western Area Power
Administration
Ben Hammer
Affirmative
N/A
1
Xcel Energy, Inc.
Eric Barry
Affirmative
N/A
2
California ISO
Darcy O'Connell
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Affirmative
N/A
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Affirmative
N/A
Affirmative
N/A
2
New York Independent
Gregory Campoli
System
Operator
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB02
Jennifer Lapaix
Ballot
Jennie Wike
Segment
Organization
Voter
2
PJM Interconnection,
L.L.C.
Thomas Foster
2
Southwest Power Pool,
Inc. (RTO)
3
Designated
Proxy
NERC
Memo
Affirmative
N/A
Joshua Phillips
None
N/A
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
Comments
Submitted
3
Austin Energy
Lovita Griffin
Affirmative
N/A
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Affirmative
N/A
3
Black Hills Corporation
Josh Combs
Affirmative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Third-Party
Comments
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
None
N/A
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Affirmative
N/A
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
None
N/A
3
Edison International Romel Aquino
Southern California
EdisonMachine
Company
© 2024 - NERC Ver 4.2.1.0
Name: ATLVPEROWEB02
Elizabeth Davis
Ballot
Carly Miller
Segment
Organization
Voter
3
Entergy
James Keele
3
Evergy
Marcus Moor
3
Eversource Energy
3
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Affirmative
N/A
Vicki O'Leary
Affirmative
N/A
Exelon
Kinte Whitehead
Affirmative
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Affirmative
N/A
3
Great River Energy
Michael
Brytowski
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Affirmative
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
Abstain
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
Third-Party
Comments
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
Affirmative
N/A
3
Nebraska Public Power
District
Tony Eddleman
Affirmative
N/A
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Affirmative
N/A
Negative
Third-Party
Comments
3
NW Electric Power
Heath Henry
Cooperative, Inc.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Omaha Public Power
District
David Heins
Affirmative
N/A
3
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
3
Pacific Gas and Electric
Company
Sandra Ellis
Affirmative
N/A
3
Platte River Power
Authority
Richard Kiess
None
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
James Frank
Negative
Third-Party
Comments
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Affirmative
N/A
3
Public Utility District No. 1
of Chelan County
Joyce Gundry
Affirmative
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Marc Sedor
None
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
Third-Party
Comments
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
Comments
Submitted
Abstain
N/A
3
Tennessee Valley
Ian Grant
Authority
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB02
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Tri-State G and T
Association, Inc.
Ryan Walter
Affirmative
N/A
3
WEC Energy Group, Inc.
Christine Kane
Affirmative
N/A
3
Xcel Energy, Inc.
Nicholas Friebel
Affirmative
N/A
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Affirmative
N/A
4
Austin Energy
Tony Hua
Affirmative
N/A
4
Buckeye Power, Inc.
Jason Procuniar
None
N/A
4
CMS Energy Consumers Energy
Company
Aric Root
Affirmative
N/A
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Affirmative
N/A
4
Georgia System
Operations Corporation
Katrina Lyons
None
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Affirmative
N/A
4
Oklahoma Municipal
Power Authority
Michael Watt
None
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Affirmative
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Ken Habgood
None
N/A
4
Utility Services, Inc.
Carver Powers
Affirmative
N/A
4
Western Power Pool
Kevin Conway
Abstain
N/A
5
AEP
Thomas Foltz
Affirmative
N/A
Negative
Comments
Submitted
5
AES - AES Corporation
Ruchi Shah
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ryan Strom
Scott Brame
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
American Municipal
Power
Amy Ritts
None
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
Comments
Submitted
5
Austin Energy
Michael Dillard
Affirmative
N/A
5
Avista - Avista
Corporation
Glen Farmer
None
N/A
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Affirmative
N/A
5
Bonneville Power
Administration
Juergen Bermejo
Abstain
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
None
N/A
5
CMS Energy Consumers Energy
Company
David
Greyerbiehl
Affirmative
N/A
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Affirmative
N/A
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
Affirmative
N/A
5 - NERC Ver 4.2.1.0
Decatur
EnergyName:
CenterATLVPEROWEB02
Megan Melham
© 2024
Machine
LLC
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
None
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
None
N/A
5
Evergy
Jeremy Harris
Affirmative
N/A
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Affirmative
N/A
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
None
N/A
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Affirmative
N/A
5
Invenergy LLC
Rhonda Jones
Negative
Comments
Submitted
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Affirmative
N/A
5
Los Angeles Department
of Water and Power
Robert Kerrigan
Abstain
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Affirmative
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Manitoba Hydro
Kristy-Lee Young
Affirmative
N/A
Affirmative
N/A
5
Muscatine Power and
Chance Back
Water
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
David Campbell
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
National Grid USA
Robin Berry
Affirmative
N/A
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Abstain
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
None
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Affirmative
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
Affirmative
N/A
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Affirmative
N/A
5
Pacific Gas and Electric
Company
Tyler Brun
Affirmative
N/A
5
Pattern Operators LP
George E Brown
Affirmative
N/A
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Negative
Third-Party
Comments
5
PSEG Nuclear LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District No. 1
of Chelan County
Rebecca Zahler
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Affirmative
N/A
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
None
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Abstain
N/A
5
Tennessee Valley
Authority
Darren Boehm
Abstain
N/A
5
TransAlta Corporation
Ashley Scheelar
None
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
Affirmative
N/A
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Affirmative
N/A
5
Vistra Energy
Daniel
Roethemeyer
Affirmative
N/A
5
WEC Energy Group, Inc.
Michelle Hribar
None
N/A
5
Xcel Energy, Inc.
Gerry Huitt
None
N/A
6
AEP
Mathew Miller
Affirmative
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Affirmative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Negative
Comments
Submitted
6
Austin Energy
Imane Mrini
None
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
Affirmative
N/A
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
6
Black Hills Corporation
Rachel Schuldt
Adam Burlock
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Bonneville Power
Administration
Tanner Brier
Abstain
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Affirmative
N/A
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Affirmative
N/A
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
6
Edison International Southern California
Edison Company
Stephanie Kenny
Affirmative
N/A
6
Entergy
Julie Hall
Affirmative
N/A
6
Evergy
Tiffany Lake
Affirmative
N/A
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Affirmative
N/A
6
Great River Energy
Brian Meloy
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Invenergy LLC
Colin Chilcoat
Negative
Comments
Submitted
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Affirmative
N/A
6
Los Angeles Department
of Water and Power
Anton Vu
None
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Affirmative
N/A
6
Manitoba Hydro
Brandin Stoesz
Affirmative
N/A
6
Muscatine Power and
Water
Nicholas Burns
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Negative
Comments
Submitted
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Abstain
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Affirmative
N/A
6
Omaha Public Power
District
Shonda McCain
Affirmative
N/A
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
Third-Party
Comments
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
Affirmative
N/A
6
Public Utility District No. 1
of Chelan County
Anne Kronshage
Affirmative
N/A
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Affirmative
N/A
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
None
N/A
6
Snohomish County PUD
No. 1
John Liang
Affirmative
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
Abstain
N/A
6
Tennessee Valley
Armando
Authority
Rodriguez
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Dane Rogers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
WEC Energy Group, Inc.
David Boeshaar
None
N/A
6
Xcel Energy, Inc.
Steve Szablya
Affirmative
N/A
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Affirmative
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
Greg Sorenson
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/334)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 AB 2 ST
Voting Start Date: 6/28/2024 1:42:11 PM
Voting End Date: 7/8/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 228
Total Ballot Pool: 267
Quorum: 85.39
Quorum Established Date: 7/8/2024 4:38:40 PM
Weighted Segment Value: 35.45
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
74
1
15
0.306
34
0.694
0
15
10
Segment:
2
8
0.7
3
0.3
4
0.4
0
0
1
Segment:
3
54
1
12
0.267
33
0.733
0
4
5
Segment:
4
14
0.9
4
0.4
5
0.5
0
1
4
Segment:
5
67
1
15
0.319
32
0.681
0
8
12
Segment:
6
45
1
8
0.235
26
0.765
0
4
7
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.4
3
0.3
1
0.1
0
1
0
Totals:
267
6
60
2.127
135
3.873
0
33
39
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren
Services
Tamara Evey
None
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Negative
Comments
Submitted
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
Negative
Comments
Submitted
None
N/A
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
NERC
Memo
Negative
Comments
Submitted
Adrian Andreoiu
Abstain
N/A
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
Abstain
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
None
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Third-Party
Comments
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Third-Party
Comments
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Negative
Comments
Submitted
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Abstain
N/A
1
Exelon
Daniel Gacek
Negative
Comments
Submitted
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
Abstain
N/A
1
Georgia Transmission
Greg Davis
Corporation
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Tim Kelley
Ballot
Carly Miller
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Glencoe Light and Power
Commission
Terry Volkmann
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Emma Halilovic
Abstain
N/A
1
IDACORP - Idaho Power
Company
Sean Steffensen
None
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Denise Sanchez
Affirmative
N/A
1
International
Transmission Company
Holdings Corporation
Michael Moltane
Gail Elliott
Affirmative
N/A
1
JEA
Joseph McClung
Affirmative
N/A
1
KAMO Electric
Cooperative
Micah Breedlove
Negative
Third-Party
Comments
1
Lakeland Electric
Larry Watt
None
N/A
1
Lincoln Electric System
Josh Johnson
None
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
Abstain
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Third-Party
Comments
1
Manitoba Hydro
Nazra Gladu
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Negative
Comments
Submitted
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Negative
Third-Party
Comments
1
National Grid USA
Michael Jones
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Third-Party
Comments
Ijad Dewan
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
NB Power Corporation
Jeffrey Streifling
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Negative
Comments
Submitted
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Negative
Third-Party
Comments
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug Peterchuck
Negative
Third-Party
Comments
1
Oncor Electric Delivery
Byron Booker
Abstain
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Negative
Third-Party
Comments
1
Pacific Gas and Electric
Company
Marco Rios
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Negative
Third-Party
Comments
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Negative
Third-Party
Comments
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Negative
Comments
Submitted
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
Abstain
N/A
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Broc Bruton
Bob Cardle
Segment
Organization
Voter
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
1
Sho-Me Power Electric
Cooperative
1
Designated
Proxy
Ballot
NERC
Memo
None
N/A
Affirmative
N/A
Olivia Olson
Negative
Third-Party
Comments
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
None
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Negative
Comments
Submitted
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Negative
Comments
Submitted
1
Western Area Power
Administration
Ben Hammer
Negative
Third-Party
Comments
1
Xcel Energy, Inc.
Eric Barry
Negative
Third-Party
Comments
2
California ISO
Darcy O'Connell
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Affirmative
N/A
2
ISO New England, Inc.
John Pearson
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Jennifer Lapaix
Jennie Wike
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
2
Midcontinent ISO, Inc.
Bobbi Welch
Affirmative
N/A
2
New York Independent
System Operator
Gregory Campoli
Negative
Third-Party
Comments
2
PJM Interconnection,
L.L.C.
Thomas Foster
Negative
Third-Party
Comments
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
None
N/A
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
Comments
Submitted
3
Austin Energy
Lovita Griffin
Negative
Comments
Submitted
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Third-Party
Comments
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
None
N/A
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Negative
Third-Party
Comments
Affirmative
N/A
3
DTE Energy - Detroit
Marvin Johnson
EdisonMachine
Company
© 2024 - NERC Ver 4.2.1.0
Name: ATLVPEROWEB02
Elizabeth Davis
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
None
N/A
3
Entergy
James Keele
Negative
Comments
Submitted
3
Evergy
Marcus Moor
Negative
Comments
Submitted
3
Eversource Energy
Vicki O'Leary
Abstain
N/A
3
Exelon
Kinte Whitehead
Negative
Comments
Submitted
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Affirmative
N/A
3
Great River Energy
Michael
Brytowski
Negative
Third-Party
Comments
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Negative
Third-Party
Comments
3
Los Angeles Department
of Water and Power
Fausto Serratos
Abstain
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
Third-Party
Comments
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Negative
Third-Party
Comments
3
Muscatine Power and
Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Nebraska Public Power
District
Tony Eddleman
Negative
Third-Party
Comments
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Negative
Third-Party
Comments
3
NW Electric Power
Cooperative, Inc.
Heath Henry
Negative
Third-Party
Comments
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Negative
Third-Party
Comments
3
Omaha Public Power
District
David Heins
Negative
Third-Party
Comments
3
OTP - Otter Tail Power
Company
Wendi Olson
Negative
Third-Party
Comments
3
Pacific Gas and Electric
Company
Sandra Ellis
Affirmative
N/A
3
Platte River Power
Authority
Richard Kiess
None
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Negative
Comments
Submitted
3
PPL - Louisville Gas and
Electric Co.
James Frank
Negative
Third-Party
Comments
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Negative
Third-Party
Comments
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Negative
Comments
Submitted
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Marc Sedor
None
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
Third-Party
Comments
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Ryan Walter
Negative
Comments
Submitted
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Nicholas Friebel
Negative
Third-Party
Comments
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Negative
Third-Party
Comments
4
Austin Energy
Tony Hua
Negative
Comments
Submitted
4
Buckeye Power, Inc.
Jason Procuniar
None
N/A
4
CMS Energy Consumers Energy
Company
Aric Root
Negative
Third-Party
Comments
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Affirmative
N/A
4
Georgia System
Operations Corporation
Katrina Lyons
None
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Negative
Third-Party
Comments
4
Oklahoma Municipal
Power Authority
Michael Watt
None
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ryan Strom
Scott Brame
Segment
Organization
Voter
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
4
Sacramento Municipal
Utility District
Foung Mua
4
Seminole Electric
Cooperative, Inc.
4
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Negative
Comments
Submitted
Ken Habgood
None
N/A
Utility Services, Inc.
Carver Powers
Affirmative
N/A
4
Western Power Pool
Kevin Conway
Abstain
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
AES - AES Corporation
Ruchi Shah
Negative
Comments
Submitted
5
Ameren - Ameren
Missouri
Sam Dwyer
Negative
Comments
Submitted
5
American Municipal
Power
Amy Ritts
None
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
Comments
Submitted
5
Austin Energy
Michael Dillard
Negative
Comments
Submitted
5
Avista - Avista
Corporation
Glen Farmer
None
N/A
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
5
Bonneville Power
Administration
Juergen Bermejo
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
None
N/A
5
CMS Energy Consumers Energy
Company
David
Greyerbiehl
Negative
Third-Party
Comments
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Negative
Third-Party
Comments
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Negative
Third-Party
Comments
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Third-Party
Comments
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
None
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
None
N/A
5
Evergy
Jeremy Harris
Negative
Comments
Submitted
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Affirmative
N/A
5
Great River Energy
Jacalynn Bentz
Negative
Third-Party
Comments
None
N/A
5
Greybeard Compliance
Mike Gabriel
Services,
LLC Name: ATLVPEROWEB02
© 2024 - NERC Ver 4.2.1.0
Machine
David Campbell
Hayden Maples
Segment
Organization
Voter
5
Grid Strategies LLC
Michael Goggin
5
Imperial Irrigation District
Tino Zaragoza
5
Invenergy LLC
5
Designated
Proxy
Ballot
NERC
Memo
Negative
Comments
Submitted
Affirmative
N/A
Rhonda Jones
Negative
Comments
Submitted
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Negative
Third-Party
Comments
5
Los Angeles Department
of Water and Power
Robert Kerrigan
Abstain
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Affirmative
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Manitoba Hydro
Kristy-Lee Young
Affirmative
N/A
5
Muscatine Power and
Water
Chance Back
Negative
Comments
Submitted
5
National Grid USA
Robin Berry
Negative
Third-Party
Comments
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Abstain
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Negative
Third-Party
Comments
5
NRG - NRG Energy, Inc.
Patricia Lynch
None
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Negative
Third-Party
Comments
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
Negative
Third-Party
Comments
5
Omaha Public Power
Kayleigh
District
Wilkerson
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Negative
Comments
Submitted
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Negative
Third-Party
Comments
5
Pacific Gas and Electric
Company
Tyler Brun
Affirmative
N/A
5
Pattern Operators LP
George E Brown
Negative
Third-Party
Comments
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Negative
Third-Party
Comments
5
PSEG Nuclear LLC
Tim Kucey
Negative
Third-Party
Comments
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Negative
Comments
Submitted
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
None
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Abstain
N/A
5
Tennessee Valley
Authority
Darren Boehm
Abstain
N/A
5
TransAlta Corporation
Ashley Scheelar
None
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
Negative
Comments
Submitted
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Bob Cardle
Adam Burlock
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
David Vickers
Negative
Comments
Submitted
5
Vistra Energy
Daniel
Roethemeyer
5
WEC Energy Group, Inc.
Michelle Hribar
None
N/A
5
Xcel Energy, Inc.
Gerry Huitt
None
N/A
6
AEP
Mathew Miller
Negative
Comments
Submitted
6
Ameren - Ameren
Services
Robert Quinlivan
Negative
Comments
Submitted
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Affirmative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Negative
Comments
Submitted
6
Austin Energy
Imane Mrini
None
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
None
N/A
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Abstain
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Third-Party
Comments
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
Negative
Comments
Submitted
6
Edison International Stephanie Kenny
Southern California
Edison Company
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Segment
Organization
Voter
6
Entergy
Julie Hall
6
Evergy
Tiffany Lake
6
FirstEnergy - FirstEnergy
Corporation
6
Designated
Proxy
Ballot
NERC
Memo
Negative
Comments
Submitted
Negative
Comments
Submitted
Stacey Sheehan
Affirmative
N/A
Great River Energy
Brian Meloy
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Invenergy LLC
Colin Chilcoat
Negative
Comments
Submitted
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Negative
Third-Party
Comments
6
Los Angeles Department
of Water and Power
Anton Vu
None
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Negative
Comments
Submitted
6
Manitoba Hydro
Brandin Stoesz
Affirmative
N/A
6
Muscatine Power and
Water
Nicholas Burns
Negative
Comments
Submitted
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Negative
Comments
Submitted
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Abstain
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Negative
Third-Party
Comments
6
Omaha Public Power
District
Shonda McCain
Negative
Third-Party
Comments
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Dane Rogers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
Third-Party
Comments
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
Negative
Third-Party
Comments
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Negative
Comments
Submitted
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
None
N/A
6
Snohomish County PUD
No. 1
John Liang
Affirmative
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
Abstain
N/A
6
WEC Energy Group, Inc.
David Boeshaar
None
N/A
6
Xcel Energy, Inc.
Steve Szablya
Negative
Third-Party
Comments
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Affirmative
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/334)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan AB 2 OT
Voting Start Date: 6/28/2024 1:42:27 PM
Voting End Date: 7/8/2024 8:00:00 PM
Ballot Type: OT
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 233
Total Ballot Pool: 271
Quorum: 85.98
Quorum Established Date: 7/8/2024 4:38:19 PM
Weighted Segment Value: 48.59
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
75
1
22
0.423
30
0.577
0
13
10
Segment:
2
8
0.7
5
0.5
2
0.2
0
0
1
Segment:
3
55
1
16
0.356
29
0.644
0
5
5
Segment:
4
14
0.7
5
0.5
2
0.2
0
3
4
Segment:
5
68
1
20
0.426
27
0.574
0
9
12
Segment:
6
46
1
11
0.314
24
0.686
0
5
6
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.4
3
0.3
1
0.1
0
1
0
Totals:
271
5.8
82
2.818
115
2.982
0
36
38
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren
Services
Tamara Evey
None
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Negative
Comments
Submitted
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
Abstain
N/A
None
N/A
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
NERC
Memo
Negative
Comments
Submitted
Adrian Andreoiu
Abstain
N/A
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Affirmative
N/A
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
Abstain
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
None
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Third-Party
Comments
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Affirmative
N/A
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Negative
Comments
Submitted
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Affirmative
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
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Tim Kelley
Ballot
Carly Miller
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Glencoe Light and Power
Commission
Terry Volkmann
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Emma Halilovic
Abstain
N/A
1
IDACORP - Idaho Power
Company
Sean Steffensen
None
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Denise Sanchez
Affirmative
N/A
1
International
Transmission Company
Holdings Corporation
Michael Moltane
Gail Elliott
Affirmative
N/A
1
JEA
Joseph McClung
Affirmative
N/A
1
KAMO Electric
Cooperative
Micah Breedlove
Negative
Third-Party
Comments
1
Lakeland Electric
Larry Watt
None
N/A
1
Lincoln Electric System
Josh Johnson
None
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
Abstain
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Third-Party
Comments
1
Manitoba Hydro
Nazra Gladu
Negative
Comments
Submitted
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Negative
Comments
Submitted
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Negative
Third-Party
Comments
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ijad Dewan
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
National Grid USA
Michael Jones
Negative
Third-Party
Comments
1
NB Power Corporation
Jeffrey Streifling
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Negative
Comments
Submitted
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Negative
Third-Party
Comments
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug Peterchuck
Negative
Third-Party
Comments
1
Oncor Electric Delivery
Byron Booker
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Negative
Third-Party
Comments
1
Pacific Gas and Electric
Company
Marco Rios
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Negative
Third-Party
Comments
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Abstain
N/A
1
Public Utility District No. 1
of Chelan County
Diane E Landry
Affirmative
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
Negative
Comments
Submitted
1
Sacramento Municipal
Wei Shao
Utility District
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Broc Bruton
Bob Cardle
Tim Kelley
Segment
Organization
Voter
1
Salt River Project
Laura Somak
1
SaskPower
1
Designated
Proxy
NERC
Memo
Affirmative
N/A
Wayne
Guttormson
Abstain
N/A
Seminole Electric
Cooperative, Inc.
Kristine Ward
None
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Negative
Third-Party
Comments
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
None
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Negative
Comments
Submitted
1
U.S. Bureau of
Reclamation
Richard Jackson
Negative
Comments
Submitted
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Affirmative
N/A
1
Western Area Power
Administration
Ben Hammer
Negative
Third-Party
Comments
1
Xcel Energy, Inc.
Eric Barry
Negative
Third-Party
Comments
2
California ISO
Darcy O'Connell
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
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Israel Perez
Ballot
Jennifer Lapaix
Jennie Wike
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
2
Independent Electricity
System Operator
Helen Lainis
Affirmative
N/A
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Affirmative
N/A
2
New York Independent
System Operator
Gregory Campoli
Negative
Third-Party
Comments
2
PJM Interconnection,
L.L.C.
Thomas Foster
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
None
N/A
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
Comments
Submitted
3
Austin Energy
Lovita Griffin
Abstain
N/A
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Affirmative
N/A
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Third-Party
Comments
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
None
N/A
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
Negative
Third-Party
Comments
3
Con Ed - Consolidated
Peter Yost
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Edison Co. of New York
Elizabeth Davis
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
None
N/A
3
Entergy
James Keele
Negative
Comments
Submitted
3
Evergy
Marcus Moor
Negative
Comments
Submitted
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
3
Exelon
Kinte Whitehead
Affirmative
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Affirmative
N/A
3
Great River Energy
Michael
Brytowski
Negative
Third-Party
Comments
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Negative
Third-Party
Comments
3
Los Angeles Department
of Water and Power
Fausto Serratos
Abstain
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
Third-Party
Comments
3
Manitoba Hydro
Mike Smith
Negative
Comments
Submitted
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Negative
Third-Party
Comments
3
Muscatine Power and
Water
Seth Shoemaker
Affirmative
N/A
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3
National Grid USA
Brian Shanahan
Affirmative
N/A
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Nebraska Public Power
District
Tony Eddleman
Negative
Third-Party
Comments
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Negative
Third-Party
Comments
3
NW Electric Power
Cooperative, Inc.
Heath Henry
Negative
Third-Party
Comments
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Negative
Third-Party
Comments
3
Omaha Public Power
District
David Heins
Negative
Third-Party
Comments
3
OTP - Otter Tail Power
Company
Wendi Olson
Negative
Third-Party
Comments
3
Pacific Gas and Electric
Company
Sandra Ellis
Affirmative
N/A
3
Platte River Power
Authority
Richard Kiess
None
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Negative
Comments
Submitted
3
PPL - Louisville Gas and
Electric Co.
James Frank
Negative
Third-Party
Comments
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Abstain
N/A
3
Public Utility District No. 1
of Chelan County
Joyce Gundry
Affirmative
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Negative
Comments
Submitted
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Marc Sedor
None
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
Third-Party
Comments
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Ryan Walter
Negative
Comments
Submitted
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Nicholas Friebel
Negative
Third-Party
Comments
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Abstain
N/A
4
Austin Energy
Tony Hua
Abstain
N/A
4
Buckeye Power, Inc.
Jason Procuniar
None
N/A
4
CMS Energy Consumers Energy
Company
Aric Root
Affirmative
N/A
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Affirmative
N/A
4
Georgia System
Operations Corporation
Katrina Lyons
None
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Negative
Third-Party
Comments
4
Oklahoma Municipal
Power Authority
Michael Watt
None
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ryan Strom
Scott Brame
Segment
Organization
Voter
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
4
Sacramento Municipal
Utility District
Foung Mua
4
Seminole Electric
Cooperative, Inc.
4
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Negative
Comments
Submitted
Ken Habgood
None
N/A
Utility Services, Inc.
Carver Powers
Affirmative
N/A
4
Western Power Pool
Kevin Conway
Abstain
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
AES - AES Corporation
Ruchi Shah
Negative
Comments
Submitted
5
Ameren - Ameren
Missouri
Sam Dwyer
Negative
Comments
Submitted
5
American Municipal
Power
Amy Ritts
None
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
Comments
Submitted
5
Austin Energy
Michael Dillard
Abstain
N/A
5
Avista - Avista
Corporation
Glen Farmer
None
N/A
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
5
Bonneville Power
Administration
Juergen Bermejo
Abstain
N/A
None
N/A
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Department
ASM Mostafa
© 2024
Machine
Name: of
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Water Resources
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
None
N/A
5
CMS Energy Consumers Energy
Company
David
Greyerbiehl
Affirmative
N/A
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Negative
Third-Party
Comments
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Affirmative
N/A
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
None
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
None
N/A
5
Evergy
Jeremy Harris
Negative
Comments
Submitted
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Affirmative
N/A
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
None
N/A
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
5
Imperial Irrigation District
Tino Zaragoza
David Campbell
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Invenergy LLC
Rhonda Jones
Negative
Comments
Submitted
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Negative
Third-Party
Comments
5
Los Angeles Department
of Water and Power
Robert Kerrigan
Abstain
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Affirmative
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Manitoba Hydro
Kristy-Lee Young
Negative
Comments
Submitted
5
Muscatine Power and
Water
Chance Back
Negative
Comments
Submitted
5
National Grid USA
Robin Berry
Affirmative
N/A
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Abstain
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Negative
Third-Party
Comments
5
NRG - NRG Energy, Inc.
Patricia Lynch
None
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Affirmative
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
Negative
Third-Party
Comments
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Negative
Comments
Submitted
Negative
Third-Party
Comments
5
OTP - Otter Tail Power
Stacy Wahlund
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Company
Scott Brame
Segment
Organization
Voter
5
Pacific Gas and Electric
Company
Tyler Brun
5
Pattern Operators LP
5
Designated
Proxy
NERC
Memo
Affirmative
N/A
George E Brown
Negative
Third-Party
Comments
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Negative
Third-Party
Comments
5
PSEG Nuclear LLC
Tim Kucey
Abstain
N/A
5
Public Utility District No. 1
of Chelan County
Rebecca Zahler
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Negative
Comments
Submitted
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
None
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Abstain
N/A
5
Tennessee Valley
Authority
Darren Boehm
Abstain
N/A
5
TransAlta Corporation
Ashley Scheelar
None
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
Negative
Comments
Submitted
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Negative
Comments
Submitted
5
Vistra Energy
Daniel
Roethemeyer
Negative
Comments
Submitted
None
N/A
5
WEC Energy Group, Inc.
Michelle Hribar
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Bob Cardle
Ballot
Adam Burlock
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Xcel Energy, Inc.
Gerry Huitt
None
N/A
6
AEP
Mathew Miller
Negative
Comments
Submitted
6
Ameren - Ameren
Services
Robert Quinlivan
Negative
Comments
Submitted
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Affirmative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Negative
Comments
Submitted
6
Austin Energy
Imane Mrini
None
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
Affirmative
N/A
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Abstain
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Third-Party
Comments
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Affirmative
N/A
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
6
Edison International Southern California
Edison Company
Stephanie Kenny
Negative
Comments
Submitted
6
Entergy
Julie Hall
Negative
Comments
Submitted
Negative
Comments
Submitted
6
Evergy
Tiffany Lake
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Affirmative
N/A
6
Great River Energy
Brian Meloy
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Invenergy LLC
Colin Chilcoat
Negative
Comments
Submitted
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Negative
Comments
Submitted
6
Los Angeles Department
of Water and Power
Anton Vu
None
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Negative
Comments
Submitted
6
Manitoba Hydro
Brandin Stoesz
Negative
Comments
Submitted
6
Muscatine Power and
Water
Nicholas Burns
Affirmative
N/A
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Negative
Comments
Submitted
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Abstain
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Negative
Third-Party
Comments
6
Omaha Public Power
District
Shonda McCain
Negative
Third-Party
Comments
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Dane Rogers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
Third-Party
Comments
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
Abstain
N/A
6
Public Utility District No. 1
of Chelan County
Anne Kronshage
Affirmative
N/A
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Negative
Comments
Submitted
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
None
N/A
6
Snohomish County PUD
No. 1
John Liang
Affirmative
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
Abstain
N/A
6
WEC Energy Group, Inc.
David Boeshaar
None
N/A
6
Xcel Energy, Inc.
Steve Szablya
Negative
Third-Party
Comments
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Affirmative
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Negative
Comments
Submitted
© 2024
- NERC
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© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
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BALLOT RESULTS
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 | Non-binding Poll AB 2 NB
Voting Start Date: 6/28/2024 1:42:43 PM
Voting End Date: 7/8/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 211
Total Ballot Pool: 254
Quorum: 83.07
Quorum Established Date: 7/8/2024 4:55:08 PM
Weighted Segment Value: 76.51
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
1
71
1
35
0.778
10
0.222
14
12
Segment:
2
7
0.3
2
0.2
1
0.1
3
1
Segment:
3
52
1
29
0.744
10
0.256
7
6
Segment:
4
14
0.8
7
0.7
1
0.1
2
4
Segment:
5
63
1
32
0.78
9
0.22
10
12
Segment:
6
42
1
19
0.704
8
0.296
7
8
Segment:
7
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
Segment:
9
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
10
5
0.3
3
0.3
0
0
2
0
Totals:
254
5.4
127
4.206
39
1.194
45
43
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Abstain
N/A
1
Ameren - Ameren
Services
Tamara Evey
None
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Negative
Comments
Submitted
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
None
N/A
1
Avista - Avista
Corporation
Mike Magruder
None
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
BC Hydro and Power
Authority
Adrian Andreoiu
Abstain
N/A
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Affirmative
N/A
1
Black Hills Corporation
Micah Runner
Affirmative
N/A
1
Bonneville Power
Administration
Kamala RogersHolliday
Abstain
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
None
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Affirmative
N/A
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Affirmative
N/A
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Affirmative
N/A
1
Evergy
Kevin Frick
Affirmative
N/A
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Affirmative
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
1
Glencoe Light and Power
Commission
Terry Volkmann
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
Abstain
N/A
1
Hydro One Networks, Inc.
Emma Halilovic
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Carly Miller
Hayden Maples
Stephen
Stafford
Ijad Dewan
Segment
Organization
Voter
1
IDACORP - Idaho Power
Company
Sean Steffensen
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
1
International Transmission
Company Holdings
Corporation
Michael Moltane
1
JEA
1
Designated
Proxy
Ballot
NERC
Memo
None
N/A
Denise Sanchez
Affirmative
N/A
Gail Elliott
Affirmative
N/A
Joseph McClung
Affirmative
N/A
KAMO Electric
Cooperative
Micah Breedlove
Negative
Comments
Submitted
1
Lakeland Electric
Larry Watt
None
N/A
1
Lincoln Electric System
Josh Johnson
None
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Comments
Submitted
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Affirmative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Negative
Comments
Submitted
1
National Grid USA
Michael Jones
Affirmative
N/A
1
NB Power Corporation
Jeffrey Streifling
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Abstain
N/A
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Negative
Comments
Submitted
Affirmative
N/A
1
OGE Energy - Oklahoma
Terri Pyle
Gas and Electric Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Andy Fuhrman
Segment
Organization
Voter
1
Omaha Public Power
District
Doug Peterchuck
1
Oncor Electric Delivery
Byron Booker
1
Pacific Gas and Electric
Company
Marco Rios
1
PNM Resources - Public
Service Company of New
Mexico
1
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Broc Bruton
Affirmative
N/A
Bob Cardle
Affirmative
N/A
Lynn Goldstein
Affirmative
N/A
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
None
N/A
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Abstain
N/A
1
Public Utility District No. 1
of Chelan County
Diane E Landry
Affirmative
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
Abstain
N/A
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
None
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Abstain
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Negative
Comments
Submitted
Southern Company Matt Carden
Southern Company
Services, Inc.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Comments
Submitted
1
Jennifer Lapaix
Segment
Organization
Voter
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
1
Tallahassee Electric (City
of Tallahassee, FL)
1
Designated
Proxy
Ballot
NERC
Memo
Abstain
N/A
None
N/A
Scott Langston
Abstain
N/A
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Affirmative
N/A
1
Western Area Power
Administration
Ben Hammer
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Abstain
N/A
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Abstain
N/A
2
New York Independent
System Operator
Gregory Campoli
Abstain
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
None
N/A
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Affirmative
N/A
Negative
Comments
Submitted
3 - NERC Ver 4.2.1.0
Associated
Electric
Todd Bennett
© 2024
Machine
Name: ATLVPEROWEB02
Cooperative, Inc.
Jennie Wike
Elizabeth Davis
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Austin Energy
Lovita Griffin
Abstain
N/A
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Affirmative
N/A
3
Black Hills Corporation
Josh Combs
Affirmative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Comments
Submitted
3
CMS Energy - Consumers
Energy Company
Karl Blaszkowski
None
N/A
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Affirmative
N/A
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
None
N/A
3
Entergy
James Keele
Affirmative
N/A
3
Evergy
Marcus Moor
Affirmative
N/A
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
3
Exelon
Kinte Whitehead
Affirmative
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Affirmative
N/A
3
Great River Energy
Michael
Brytowski
Affirmative
N/A
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Carly Miller
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Abstain
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
Abstain
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
Comments
Submitted
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
Affirmative
N/A
3
Nebraska Public Power
District
Tony Eddleman
Abstain
N/A
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
Heath Henry
Negative
Comments
Submitted
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Omaha Public Power
District
David Heins
Affirmative
N/A
3
Pacific Gas and Electric
Company
Sandra Ellis
Affirmative
N/A
3
Platte River Power
Authority
Richard Kiess
None
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Affirmative
N/A
None
N/A
3
PPL - Louisville Gas and
James Frank
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Electric Co.
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Abstain
N/A
3
Public Utility District No. 1
of Chelan County
Joyce Gundry
Affirmative
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Marc Sedor
None
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
Comments
Submitted
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Ryan Walter
Affirmative
N/A
3
WEC Energy Group, Inc.
Christine Kane
Affirmative
N/A
4
Alliant Energy Corporation
Services, Inc.
Larry Heckert
Affirmative
N/A
4
Austin Energy
Tony Hua
Abstain
N/A
4
Buckeye Power, Inc.
Jason Procuniar
None
N/A
4
CMS Energy - Consumers
Energy Company
Aric Root
Negative
Comments
Submitted
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Affirmative
N/A
4
Georgia System
Operations Corporation
Katrina Lyons
None
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ryan Strom
Segment
Organization
Voter
4
North Carolina Electric
Membership Corporation
Richard McCall
4
Oklahoma Municipal
Power Authority
4
Designated
Proxy
NERC
Memo
Affirmative
N/A
Michael Watt
None
N/A
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Affirmative
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Ken Habgood
None
N/A
4
Utility Services, Inc.
Carver Powers
Affirmative
N/A
4
Western Power Pool
Kevin Conway
Abstain
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
AES - AES Corporation
Ruchi Shah
Negative
Comments
Submitted
5
Ameren - Ameren
Missouri
Sam Dwyer
Abstain
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
Comments
Submitted
5
Austin Energy
Michael Dillard
Abstain
N/A
5
Avista - Avista
Corporation
Glen Farmer
None
N/A
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Ballot
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Bonneville Power
Administration
Juergen Bermejo
Abstain
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
None
N/A
5
CMS Energy - Consumers
Energy Company
David
Greyerbiehl
Negative
Comments
Submitted
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Affirmative
N/A
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Affirmative
N/A
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
None
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
None
N/A
5
Evergy
Jeremy Harris
Affirmative
N/A
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Affirmative
N/A
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
None
N/A
5
Greybeard Compliance
Mike Gabriel
Services,
LLC Name: ATLVPEROWEB02
© 2024 - NERC Ver 4.2.1.0
Machine
David Campbell
Hayden Maples
Segment
Organization
Voter
5
Grid Strategies LLC
Michael Goggin
5
Imperial Irrigation District
Tino Zaragoza
5
JEA
5
Designated
Proxy
Ballot
NERC
Memo
Negative
Comments
Submitted
Affirmative
N/A
John Babik
Affirmative
N/A
Lincoln Electric System
Brittany Millard
Abstain
N/A
5
Los Angeles Department
of Water and Power
Robert Kerrigan
None
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Affirmative
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Muscatine Power and
Water
Chance Back
Affirmative
N/A
5
National Grid USA
Robin Berry
Affirmative
N/A
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Abstain
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Comments
Submitted
5
North Carolina Electric
Membership Corporation
Reid Cashion
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
None
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Affirmative
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
Affirmative
N/A
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Segment
Organization
Voter
5
Pacific Gas and Electric
Company
Tyler Brun
5
Pattern Operators LP
5
Designated
Proxy
NERC
Memo
Affirmative
N/A
George E Brown
Affirmative
N/A
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
None
N/A
5
PSEG Nuclear LLC
Tim Kucey
Abstain
N/A
5
Public Utility District No. 1
of Chelan County
Rebecca Zahler
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Affirmative
N/A
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
None
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Abstain
N/A
5
Tennessee Valley
Authority
Darren Boehm
None
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
Affirmative
N/A
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Affirmative
N/A
5
Vistra Energy
Daniel
Roethemeyer
Affirmative
N/A
5
WEC Energy Group, Inc.
Michelle Hribar
None
N/A
6
AEP
Mathew Miller
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Bob Cardle
Ballot
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Ameren - Ameren
Services
Robert Quinlivan
Abstain
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Affirmative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Negative
Comments
Submitted
6
Austin Energy
Imane Mrini
None
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
Affirmative
N/A
6
Black Hills Corporation
Rachel Schuldt
Affirmative
N/A
6
Bonneville Power
Administration
Tanner Brier
Abstain
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Affirmative
N/A
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Affirmative
N/A
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
6
Edison International Southern California
Edison Company
Stephanie Kenny
Affirmative
N/A
6
Entergy
Julie Hall
Affirmative
N/A
6
Evergy
Tiffany Lake
Affirmative
N/A
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Affirmative
N/A
6
Great River Energy
Brian Meloy
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
None
N/A
6
Lakeland Electric
Paul Shipps
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Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Lincoln Electric System
Eric Ruskamp
Abstain
N/A
6
Los Angeles Department
of Water and Power
Anton Vu
None
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Affirmative
N/A
6
Muscatine Power and
Water
Nicholas Burns
Affirmative
N/A
6
New York Power Authority
Shelly Dineen
Negative
Comments
Submitted
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Negative
Comments
Submitted
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Abstain
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Affirmative
N/A
6
Omaha Public Power
District
Shonda McCain
Affirmative
N/A
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
None
N/A
6
PSEG - PSEG Energy
Resources and Trade LLC
Laura Wu
Abstain
N/A
6
Public Utility District No. 1
of Chelan County
Anne Kronshage
Affirmative
N/A
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Affirmative
N/A
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
None
N/A
6
Seminole Electric
Bret Galbraith
Cooperative, Inc.
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Dane Rogers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Snohomish County PUD
No. 1
John Liang
Affirmative
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
None
N/A
6
WEC Energy Group, Inc.
David Boeshaar
None
N/A
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Affirmative
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Abstain
N/A
Greg Sorenson
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BALLOT RESULTS
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 | Non-binding Poll AB 2 NB
Voting Start Date: 6/28/2024 1:43:04 PM
Voting End Date: 7/8/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 207
Total Ballot Pool: 251
Quorum: 82.47
Quorum Established Date: 7/8/2024 5:03:47 PM
Weighted Segment Value: 29.03
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
1
71
1
11
0.275
29
0.725
19
12
Segment:
2
7
0.2
0
0
2
0.2
4
1
Segment:
3
51
1
10
0.27
27
0.73
8
6
Segment:
4
14
0.8
4
0.4
4
0.4
2
4
Segment:
5
62
1
12
0.308
27
0.692
11
12
Segment:
6
41
1
5
0.2
20
0.8
7
9
Segment:
7
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
Segment:
9
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
10
5
0.4
3
0.3
1
0.1
1
0
Totals:
251
5.4
45
1.753
110
3.647
52
44
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Abstain
N/A
1
Ameren - Ameren
Services
Tamara Evey
None
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Negative
Comments
Submitted
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
Comments
Submitted
1
Austin Energy
Thomas
Standifur
None
N/A
1
Avista - Avista
Corporation
Mike Magruder
None
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
BC Hydro and Power
Authority
Adrian Andreoiu
Abstain
N/A
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
Abstain
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
None
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Comments
Submitted
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Comments
Submitted
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Negative
Comments
Submitted
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Abstain
N/A
1
Exelon
Daniel Gacek
Negative
Comments
Submitted
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Abstain
N/A
Negative
Comments
Submitted
1
Glencoe Light and Power
Terry Volkmann
Commission
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Carly Miller
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
1
Great River Energy
Gordon Pietsch
1
Hydro One Networks, Inc.
Emma Halilovic
1
IDACORP - Idaho Power
Company
Sean Steffensen
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
1
International Transmission
Company Holdings
Corporation
Michael Moltane
1
JEA
1
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Abstain
N/A
None
N/A
Denise Sanchez
Affirmative
N/A
Gail Elliott
Affirmative
N/A
Joseph McClung
Affirmative
N/A
KAMO Electric
Cooperative
Micah Breedlove
Negative
Comments
Submitted
1
Lakeland Electric
Larry Watt
None
N/A
1
Lincoln Electric System
Josh Johnson
None
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
Abstain
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
Comments
Submitted
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Negative
Comments
Submitted
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Negative
Comments
Submitted
1
National Grid USA
Michael Jones
Negative
Comments
Submitted
1
NB Power Corporation
Jeffrey Streifling
Abstain
N/A
Abstain
N/A
1
NextEra Energy - Florida
Silvia Mitchell
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Power and Light Co.
Ijad Dewan
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Negative
Comments
Submitted
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Negative
Comments
Submitted
1
Omaha Public Power
District
Doug Peterchuck
Negative
Comments
Submitted
1
Oncor Electric Delivery
Byron Booker
Broc Bruton
Abstain
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Bob Cardle
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
None
N/A
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Abstain
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Negative
Comments
Submitted
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
Abstain
N/A
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
None
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Abstain
N/A
Negative
Comments
Submitted
1
Sho-Me Power Electric
Olivia Olson
Cooperative
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Jennifer Lapaix
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
None
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Negative
Comments
Submitted
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Negative
Comments
Submitted
1
Western Area Power
Administration
Ben Hammer
Negative
Comments
Submitted
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Abstain
N/A
2
ISO New England, Inc.
John Pearson
Negative
Comments
Submitted
2
Midcontinent ISO, Inc.
Bobbi Welch
Abstain
N/A
2
New York Independent
System Operator
Gregory Campoli
Abstain
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Abstain
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
None
N/A
Negative
Comments
Submitted
3
APS - Arizona Public
Jessica Lopez
Service
Co.
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB02
Jennie Wike
Elizabeth Davis
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
Comments
Submitted
3
Austin Energy
Lovita Griffin
Abstain
N/A
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
Comments
Submitted
3
CMS Energy - Consumers
Energy Company
Karl Blaszkowski
None
N/A
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Negative
Comments
Submitted
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
None
N/A
3
Entergy
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Negative
Comments
Submitted
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Evergy
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Negative
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Submitted
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Abstain
N/A
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JEA
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Heath Henry
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James Frank
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Marc Sedor
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Christine Kane
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Larry Heckert
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Tony Hua
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None
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Jason Procuniar
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Mark Garza
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Georgia System
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Katrina Lyons
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Michael Watt
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Public Utility District No. 1
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John D.
Martinsen
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Ken Habgood
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Utility Services, Inc.
Carver Powers
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Andrew Smith
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Associated Electric
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Chuck Booth
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Michael Dillard
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None
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Glen Farmer
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Sheila Suurmeier
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Bonneville Power
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Juergen Bermejo
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California Department of
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ASM Mostafa
None
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Choctaw Generation
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Rob Watson
None
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CMS Energy - Consumers
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Colorado Springs Utilities
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Con Ed - Consolidated
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Constellation
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Dairyland Power
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Negative
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Decatur Energy Center
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Megan Melham
Negative
Comments
Submitted
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Mohamad
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Duke Energy
Dale Goodwine
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Selene Willis
Negative
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Enel Green Power
Natalie Johnson
None
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Services, Inc.
Gail Golden
None
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Evergy
Jeremy Harris
5
FirstEnergy - FirstEnergy
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Matthew
Augustin
Affirmative
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Great River Energy
Jacalynn Bentz
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Greybeard Compliance
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Mike Gabriel
None
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Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Affirmative
N/A
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JEA
John Babik
Affirmative
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Lincoln Electric System
Brittany Millard
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Los Angeles Department
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Robert Kerrigan
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Teresa Krabe
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LLC
C. A. Campbell
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Muscatine Power and
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National Grid USA
Robin Berry
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NB Power Corporation New Brunswick Power
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Fon Hiew
Abstain
N/A
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New York Power Authority
Zahid Qayyum
Negative
Comments
Submitted
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North Carolina Electric
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Reid Cashion
Negative
Comments
Submitted
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Patricia Lynch
None
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Patrick Wells
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Ontario Power Generation
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Constantin
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OTP - Otter Tail Power
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Stacy Wahlund
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George E Brown
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Melanie Wong
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Jennifer Wright
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Southern Company Southern Company
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Karen Weaver
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Darren Boehm
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Sergio Banuelos
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U.S. Bureau of
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Anton Vu
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Martin Sidor
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Charles Norton
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John Liang
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6
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Tennessee Valley
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Armando
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WEC Energy Group, Inc.
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Rachel Coyne
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Western Electricity
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Steven Rueckert
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 3 of PRC-029-1 is posted for a formal comment and additional ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization
Request (SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
25-day formal comment period and initial ballot
March 27 – April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
Anticipated Actions
Date
15-day formal comment period and additional ballot
July 22 – August 12, 2024
Final Ballot
August 26 – September 6, 2024
Board adoption
October 8, 2024
Draft 3 of PRC-029-1
July 2024
Page 1 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Ride-through: The entire plant/facility remaining connected to the Bulk Power System and
continuing in its entirety to operate through System Disturbances.
The term Inverter-based Resource (IBR) refers to proposed definitions being developed under
the Project 2020-06 Verifications of Models and Data for Generators. As of this posting, the
proposed definition of an IBR is:
IBR: A plant/facility consisting of individual devices that are capable of exporting Real Power
through a power electronic interface(s) such as inverter or converter, and that are operated
together as a single resource at a common point of interconnection to the electric system. IBRs
include, but are not limited to, plants/facilities with solar photovoltaic (PV), Type 3 and Type 4
wind, battery energy storage system (BESS), and fuel cell devices.
Draft 3 of PRC-029-1
July 2024
Page 2 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
A. Introduction
1. Title:
Frequency and Voltage Ride-through Requirements for Inverter-based
Resources
2. Number:
PRC-029-1
3. Purpose:
To ensure that IBRs Ride-through to support the Bulk Power System (BPS)
during and after defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.2
Facilities:
4.2.1. The Elements associated with (1) Bulk Electric System (BES) IBRs; and (2)
Non-BES IBRs that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system
designed primarily for delivering such capacity to a common point of
connection at a voltage greater than or equal to 60 kV.
Effective Date: See Implementation Plan for Project 2020-02 – PRC-029-1
Standard-only Definition: None
Draft 3 of PRC-029-1
July 2024
Page 3 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
B. Requirements and Measures
R1.
Each Generator Owner shall ensure the design and operation is such that each IBR
meet or exceed Ride-through requirements, in accordance with the “must Ridethrough 1 zone” as specified in Attachment 1, except for the following: [Violation Risk
Factor: High] [Time Horizon: Operations Assessment]
•
The IBR needed to electrically disconnect in order to clear a fault; or
•
The voltage at the high-side of the main power transformer 2 went outside an
accepted hardware limitation, in accordance with Requirement R4; or
•
The instantaneous positive sequence voltage phase angle change is more than
25 electrical degrees at the high-side of the main power transformer and is
initiated by a non-fault switching event on the transmission system 3; or
•
The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than
2 seconds.
M1. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R1. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner
shall retain evidence of actual disturbance monitoring (i.e. Sequence of Event
Recorder, Dynamic Disturbance Recorder, and Fault Recorder) to demonstrate that
the operation of each IBR did adhere to Ride-through requirements, as specified in
Requirement R1. If the Generator Owner choose to utilize Ride-through exemptions
that occur within the “must Ride-through zone” and are caused by non-fault initiated
phase jumps of greater than 25 electrical degrees, then each Generator Owner shall
also retain evidence of actual disturbance monitoring (i.e. Sequence of Event
Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate
that the IBR failed to Ride-through during a phase jump of greater than or equal to 25
electrical degrees, and documentation from their Transmission Planner, Reliability
Coordinator, Planning Coordinator, or Transmission Operator that a non-fault initiated
switching event occurred.
R2. Each Generator Owner shall ensure the design and operation is such that the voltage
performance for each IBR adheres to the following during a voltage excursion, unless a
documented hardware limitation exists in accordance with Requirement R4. [Violation
Risk Factor: High] [Time Horizon: Operations Assessment]
Includes no tripping associated with phase lock loop loss of synchronism
For the purpose of this standard, the main power transformer is the power transformer that steps up voltage from the
collection system voltage to the nominal transmission/interconnecting system voltage for IBRs. In case of IBR connecting via a
dedicated Voltage Source Converter High Voltage Direct Current (VSC-HVDC), the main power transformer is the main power
transformer on the receiving end.
3 Current blocking mode may be used for non-fault initiated phase jumps greater than 25 degrees in order to prevent tripping.
1
2
Draft 3 of PRC-029-1
July 2024
Page 4 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
2.1.
While the voltage at the high-side of the main power transformer remains
within the continuous operation region as specified in Attachment 1, each IBR
shall:
2.1.1 Continue to deliver the pre-disturbance level of Real Power or available
Real Power 4, whichever is less. 5
2.1.2 Continue to deliver Reactive Rower up to its Reactive Power limit and
according to its controller settings.
2.1.3 Prioritize Real Power or Reactive Power when the voltage is less than
0.95 per unit, the voltage is within the continuous operating region, and
the IBR cannot deliver both Real Power and Reactive Power due to a
current limit or Reactive Power limit, unless otherwise specified
through other mechanisms by an associated Transmission Planner,
Planning Coordinator, Reliability Coordinator, or Transmission
Operator.
2.2.
2.3.
While voltage at the high-side of the main power transformer is within the
mandatory operation region as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support,
on the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under 6:
•
Reactive Power priority by default; or
•
Real Power priority if required through other mechanisms by an
associated Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator.
While voltage at the high-side of the main power transformer is within the
permissive operation region, as specified in Attachment 1, each IBR may
operate in current blocking mode if necessary to avoid tripping. Otherwise,
each IBR shall follow the requirements for the mandatory operation region in
Requirement R2.2.
2.3.1
2.4.
If a IBR enters current blocking mode, it shall restart current
exchange in less than or equal to five cycles of positive sequence
voltage returning to a continuous operation region or mandatory
operation region.
Each IBR shall not itself cause voltage at the high-side of the main power
transformer to exceed the applicable high voltage thresholds and time
“Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
5 Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
6 In either case and if required, the magnitude of Real Power and reactive current shall be as specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
4
Draft 3 of PRC-029-1
July 2024
Page 5 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
durations in its response as voltage recovers from the mandatory or permissive
operation regions to the continuous operation region.
2.5.
Each IBR shall restore Real Power output to the pre-disturbance or available
level 7 (whichever is lesser) within 1.0 second when the voltage at the high-side
of the main power transformer returns from the mandatory operation region
or permissive operation region (including operating in current blocking mode)
to the continuous operation region, as specified in Attachment 1, unless an
associated Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator requires a lower post-disturbance Real Power level
requirement or requires a different post-disturbance Real Power restoration
time through other mechanisms. 8
M2. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to requirements, as specified in Requirement R2. Examples of evidence may
include, but are not limited to dynamic simulations, studies, plant protection settings,
and control settings design evaluation. Each Generator Owner shall also retain
evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic
Disturbance Recorder, and Fault Recorder) data to demonstrate that the operation of
each IBR did adhere to performance requirements, as specified in Requirement R2,
during each voltage excursion measured at the high-side of the main power
transformer. In regard to R2.1.3, R2.2, and R2.5, the Generator Owner shall retain
evidence of receiving such performance requirements, (e.g. email exchange, contract
information) if the Transmission Planner, Transmission Operator, Reliability
Coordinator, or Planning Coordinator has required the Generator Owner through
other mechanisms to follow performance requirements other than those in
Requirement R2 (e.g. ramp rates, Reactive Power prioritization).
R3. Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements during a frequency excursion event
whereby the System frequency remains within the “must Ride-through zone”
according to Attachment 2 and the absolute rate of change of frequency (RoCoF) 9
magnitude is less than or equal to 5 Hz/second. [Violation Risk Factor: High] [Time
Horizon: Operations Assessment]
M3. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R3. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner
shall also retain evidence of actual disturbance monitoring (i.e. Sequence of Event
Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate
the operation of each IBR did adhere to Ride-through requirements, as specified in
“Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
8 Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
9 Rate of change of frequency (RoCoF) is calculated as the average rate of change for multiple calculated system frequencies for
a time period of greater than or equal to 0.1 second. RoCoF is not calculated during the fault occurrence and clearance.
7
Draft 3 of PRC-029-1
July 2024
Page 6 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Requirement R3, during each frequency excursion event measured at the high-side of
the main power transformer.
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of
PRC-029-1, has known hardware limitations that prevent the IBR from meeting voltage
Ride-through criteria as detailed in Requirements R1 and R2, and requires an
exemption from specific voltage Ride-through criteria shall: 10 Lower] [Time Horizon:
Long-term Planning]
4.1.
Document information supporting the identified hardware limitation no later
than 12 months following the effective date of PRC-029-1. This documentation
shall include:
4.1.1 Identifying information of the IBR (name and facility #);
4.1.2 Which aspects of voltage Ride-through requirements that the IBR
would be unable to meet and the capability of the hardware due to the
limitation;
4.1.3 Identify the specific piece(s) of hardware causing the limitation;
4.1.4 Supporting technical documentation verifying the limitation is due to
hardware that needs to be physically replaced or that the limitation
cannot be removed by software updates or setting changes, and;
4.1.5 Information regarding any plans to remedy the hardware limitation
(such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the
associated Planning Coordinator(s), Transmission Planner(s), Transmission
Operator(s), Reliability Coordinator(s), and the CEA no later than 12 months
following the effective date of PRC-029-1.
4.2.1
4.2.2
4.3.
Any response to additional information requested by the associated
Planning Coordinator(s), Transmission Planner(s), Transmission
Operator(s), Reliability Coordinator(s), and the CEA shall be provided
back to the requestor within 90 days of the request.
Provide a copy of the acceptance of an hardware limitation by the
CEA to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s). 11
Each Generator Owner with a previously accepted limitation that replace the
hardware causing the limitation shall document and communicate such a
hardware change to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s) within 90
days of the hardware change.
The exemption requests for a non-US Registered Entity should be implemented in a manner that is consistent with, or under
the direction of, the applicable governmental authority or its agency in the non-US jurisdiction.
11 Acceptance by the CEA is verification that the information provided includes all information listed in Requirement R4.1.
10
Draft 3 of PRC-029-1
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
4.3.1
When existing hardware causing the limitation is replaced, the
exemption for that Ride-through criteria no longer applies.
M4. Each Generator Owner submitting for an exemption for an IBR that is in-service by the
effective date of PRC-029-1, shall have evidence of submission to the CEA consistent
with the information listed in Requirement R4.1. Each Generator Owner shall have
evidence of communicated copies of each submission in accordance with Requirement
R4.2 and to the associated entities described in Requirement R4.2. Acceptable types of
evidence for submittals include but are not limited to, meeting minutes, agreements,
copies of procedures or protocols in effect, or email correspondence. Acceptable
types of evidence for a hardware limitation may include but is not limited to
documentation that contains study results, experience from an actual event, or
manufacturer’s advice. Each Generator Owner that receives a request for additional
information under Requirement R4.2.1 shall have evidence of providing that
information within 90 calendar days. Each Generator Owner that replaces hardware at
an IBR that is directly associated with an accepted exemption and that hardware is the
cause for the limitation, shall have evidence of communicating the hardware change
to the associated entities described in Requirement R4.3 within 90 calendar days of
the hardware replacement.
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
Each Generator Owner shall retain evidence with Requirements R1, R2, and
R3 in this standard for 36 calendar months or the date of the last audit,
whichever is greater.
•
Each Generator Owner shall retain evidence with Requirement R4 in this
standard for five calendar years or the date of the last audit, whichever is
greater.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Draft 3 of PRC-029-1
July 2024
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Generator Owner failed to
demonstrate the design
capability of each applicable
IBR to Ride-through in
accordance with Attachment
1, except for those conditions
identified in Requirement R1.
N/A
N/A
The Generator Owner failed to
demonstrate each applicable
IBR adhered to Ride-through
requirements in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
R2.
The Generator Owner failed to
demonstrate the design
capability of each applicable
IBR to adhere to performance
requirements during voltage
excursions, as specified in
Requirement R2.
N/A
N/A
The Generator Owner failed to
demonstrate each applicable
IBR adhered to performance
requirements during voltage
excursions, as specified in
Requirement R2.
R3.
The Generator Owner failed to
demonstrate the design
capability of each applicable
IBR to Ride-through in
accordance with Attachment
2.
N/A
N/A
The Generator Owner failed to
demonstrate each applicable
IBR adhered to Ride-through
requirements in accordance
with Attachment 2.
R4.
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
The Generator Owner failed to
document complete
information for IBR identified
with known hardware
limitations that prevent the
IBR from meeting voltage
Draft 3 of PRC-029-1
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), Reliability
Coordinator(s), and CEA more
than 90 calendar days but less
than or equal to 120 calendar
days after the change to the
hardware.
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 120 calendar days but
less than or equal to 150
calendar days after the change
to the hardware.
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 150 calendar days but
less than or equal to 180
calendar days after the change
to the hardware.
Ride-through criteria as
detailed in Requirements R1 or
R2.
OR
OR
OR
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 12 months but less than
or equal to 15 months after
the effective date of
Requirement R4.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
120 days but less than or equal
to 150 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
150 days but less than or equal
to 180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
90 days but less than or equal
to 120 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
Draft 3 of PRC-029-1
July 2024
OR
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s),Reliability
Coordinator(s), and CEA more
than 180 calendar days after
the change to the hardware.
OR
The Generator Owner failed to
provide a copy to the
applicable entities as detailed
in Requirement R4.2 within 24
months after the effective
date of Requirement R4.
OR
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Version History
Version
Date
Initial Draft
3/27/24
Draft
Draft 2
6/4/24
Revised following initial comment review
Draft 3
7/22/24
Revised following additional comment review
Draft 3 of PRC-029-1
July 2024
Action
Change
Tracking
Page 13 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-through Requirements for AC-Connected Wind IBR
12
Voltage
(per unit) 13
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 14
N/A
≥ 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
3.00
< 0.70
Mandatory Operation Region
2.50
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.16
< 0.10
Permissive Operation Region
0.16
Table 2: Voltage Ride-through Requirements for All Other IBR
Voltage
(per unit) 15
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 16
N/A
> 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
6.00
< 0.70
Mandatory Operation Region
3.00
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.32
< 0.10
Permissive Operation Region
0.32
Type 3 and type 4 wind resources directly connected to the AC Transmission System.
Refer to bullet #4 below.
14 These conditions are referred to as the “may Ride-through zone”.
15 Refer to bullet #4 below.
16 These conditions are referred to as the “may Ride-through zone”.
12
13
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
1. Table 1 applies to type 3 and type 4 wind IBR or hybrid IBR that include wind, unless
connected via a dedicated VSC-HVDC transmission facility.
2. Table 2 applies to all other IBR types not covered in Table 1; including, but not
limited to, the following facilities:
a. IBR, regardless of their energy resource, interconnecting via a dedicated VSCHVDC transmission facility.
b. Other IBR or hybrid IBR consisting of photovoltaic (PV) and BESS.
3. The applicable voltage for VSC-HVDC system with a dedicated connection to an IBR
is on the AC side of the transformer(s) that is (are) used to connect the VSC-HVDC
system to the interconnected transmission system.
4. The voltage base for per unit calculation is the nominal phase-to-ground or
phase-to-phase transmission system voltage unless otherwise defined by the
Planning Coordinator, Transmission Planner, or Transmission Owner.
5. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase-to-neutral or phase-to-phase fundamental root mean square (RMS) voltage at
the high-side of the main power transformer.
6. Tables 1 and 2 are only applicable when the frequency is within the “must
Ride-through zone” as specified in Figure 1 of Attachment 2.
7. At any given voltage value, each IBR shall Ride-through unless the time duration at
that voltage has exceeded the specified minimum Ride-through time duration. If the
voltage is continuously varying over time, it is necessary to add the duration within
each band of Tables 1 and 2 over any 10 second time period.
8. The specified duration of the mandatory operation regions and the permissive
operation regions in Tables 1 and 2 is cumulative over one or more disturbances
within any 10 second time period.
9. The IBR may trip for more than four deviations of the applicable voltage at the highside of the main power transformer outside of the continuous operation region
within any 10 second time period.
10. Instantaneous trip settings based on instantaneously calculated voltage
measurements with less than filtering lengths of one cycle (16.6 millisecond) are not
permissible.
11. The “must Ride-through zone” is the combined area of the mandatory operating
regions, the continuous operating regions, and the permissive operating region. All
area outside of these operating regions is referred to as the “may Ride-through
zone”.
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 2: Frequency Ride-Through Criteria
Table 3: Frequency Ride-through Capability Requirements
System Frequency (Hz)
Minimum Ride-Through
Time (sec)
> 64.0
May trip
≥ 61.8
6
≥ 61.5
299
> 61.2
660
≤ 61.2 and > 58.8
Continuous
≤ 58.8
660
≤ 58.5
299
≤ 57.0
6
< 56.0
May trip
1. Frequency measurements are taken at the high-side of the main power transformer.
2. Frequency is measured over a period of time (typically 3-6 cycles) to calculate system
frequency at the high-side of the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency value, each IBR shall Ride-through unless the time duration at
that frequency has exceeded the specified minimum ride-through time duration.
5. The specified durations of Table 3 are cumulative over one or more disturbances within
a 15-minute time period.
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Figure 1: PRC-029 Frequency Ride-through Requirements
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 3 of PRC‐029‐1 is posted for a formal comment and additional ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
25‐day formal comment period and initial ballot
March 27 – April 22, 2024
15‐day formal comment period and additional ballot
June 18 – July 8, 2024
Anticipated Actions
Date
15‐day formal comment period and additional ballot
July 22 – August 12, 2024
Final Ballot
August 26 – September 6,
2024
Board adoption
October 8, 2024
Draft 3 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Ride‐through: The entire plant/facility Rremaining connected, synchronized with to the
Transmission Bulk Power System, and continuing in its entirety to operate in response to
System conditions through the time‐frame of a System Disturbances.
The term Inverter‐based Resource (IBR) refers to proposed definitions being developed under
the Project 2020‐06 Verifications of Models and Data for Generators. As of this posting, the
proposed definition of an IBR is:
IBR: A plant/facility consisting of individual devices that are capable of exporting Real Power
through a power electronic interface(s) such as inverter or converter, and that are operated
together as a single resource at a common point of interconnection to the electric system. IBRs
include, but are not limited to, plants/facilities with solar photovoltaic (PV), Type 3 and Type 4
wind, battery energy storage system (BESS), and fuel cell devices.
Draft 3 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
A. Introduction
1. Title:
Resources
Frequency and Voltage Ride‐through Requirements for Inverter‐Based
2. Number:
PRC‐029‐1
3. Purpose:
To ensure that Inverter‐Based Resources (IBRs) adhere to Ride‐through
requirements as expected to support the Bulk Power System (BPS) during and after
defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.1.2. Transmission Owner1
4.2
Facilities:
4.2.1. The Elements associated with (1) Bulk Electric System (BES) IBRs inverter‐
based resources2and (2) Non‐BES IBRs that either have or contribute to
an aggregate nameplate capacity of greater than or equal to 20 MVA,
connected through a system designed primarily for delivering such
capacity to a common point of connection at a voltage greater than or
equal to 60 kV.
4.2.2. IBR Registration Criteria
Effective Date: See Implementation Plan for Project 2020‐02 – PRC‐029‐1
Standard‐Only Definition: None
For owners of Voltage Source Converter – High‐voltage Direct Current (VSC‐HVDC) transmission facilities that are
dedicated connections for IBR to the BPS
2
For the purpose of this standard, “inverter‐based resources” refers to a collection of individual solar photovoltaic
(PV), Type 3 and Type 4 wind turbines, battery energy storage system (BESS), or fuel cells that operate as a single
plant/resource. In case of offshore wind plants connecting via a dedicated VSC‐HVDC, the inverter‐based resource
includes the VSC‐HVDC system.
1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
B. Requirements and Measures
R1.
Each Generator Owner or Transmission Owner shall ensure the design and operation
is such that each facility IBR meet or exceed adheres to Ride‐through requirements, in
accordance with the “must Ride‐through3 zone” as specified in Attachment 1, except
for the following: [Violation Risk Factor: High] [Time Horizon: Operations Assessment]
• The facility IBR needed to electrically disconnect in order to clear a fault; or
•
The voltage at the high side of the main power transformer4 went outside an
acceptedA documented equipment hardware limitation, exists in accordance
with Requirement R4; or
•
The instantaneous positive sequence voltage phase angle change is more than
25 electrical degrees at the high‐side of the main power transformer and is
initiated by a non‐fault switching event on the transmission system5; or
•
The Volts per Hz (V/Hz) at the high‐side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than
2 seconds.
M1. Each Generator Owner and Transmission Ownershall have evidence of dynamic
simulations, studies, or other evidence to demonstrate the design of each facility will
adhere to Ride‐through requirements, as specified in Requirement R1. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner
and Transmission Owner shall have retain evidence of actual disturbance monitoring
(i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder)
to demonstrate that the operation of each facility IBR did adhere to Ride‐through
requirements, as specified in Requirement R1. If the Generator Owner and
Transmission Owner choose to utilize Ride‐through exemptions that occur within the
“must Ride‐through zone” and are caused by non‐fault initiated phase jumps of
greater than 25 electrical degrees, then each Generator Owner and Transmission
Owner shall also have retain evidence of actual disturbance monitoring (i.e. Sequence
of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to
demonstrate that the facility IBR failed to Ride‐through during a phase jump of
greater than or equal to 25 electrical degrees, and documentation from their
Transmission Planner, Reliability Coordinator, Planning Coordinator, or Transmission
Operator that a non‐fault initiated switching event occurred.
R2. Each Generator Owner or Transmission Owner shall ensure the design and operation
is such that the voltage performance for each facility IBR adheres to the following
during a voltage excursion, unless a documented equipment hardware limitation
3 Includes no tripping associated with phase lock loop loss of synchronism
4
For the purpose of this standard, the main power transformer is the power transformer that steps up voltage from the
collection system voltage to the nominal transmission/interconnecting system voltage for IBRs. In case of IBR connecting via a
dedicated Voltage Source Converter High Voltage Direct Current (VSC‐HVDC), the main power transformer is the main power
transformer on the receiving end.
5
Current blocking mode may be used for non‐fault initiated phase jumps greater than 25 degrees in order to prevent tripping.
Draft 3 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
exists in accordance with Requirement R4. [Violation Risk Factor: High] [Time Horizon:
Operations Assessment]
2.1.
While the voltage at the high‐side of the main power transformer6 remains
within the continuous operation region as specified in Attachment 1, each
facility IBR shall:
2.1.1 Continue to deliver the pre‐disturbance level of active Real pPower or
available active Real pPower7, whichever is less.8
2.1.2 Continue to deliver Rreactive pPower up to its rReactive pPower limit
and according to its controller settings.
2.1.3 Prioritize Real Power or Reactive Power If the facility cannot deliver
both active and reactive power due to a current limit or reactive power
limit, when the voltage is less thanbelow 0.95 per unit, the voltage is
and still within the continuous operation region, and the IBR cannot
deliver both Real Power and Reactive Power due to a current limit,
unless otherwise specified through other mechanisms by an
associatedthen preference shall be given to active or reactive power
according to requirements if required by the Transmission Planner,
Planning Coordinator, Reliability Coordinator, or Transmission
Operator.
2.2.
2.3.
While voltage at the high‐side of the main power transformer is within the
mandatory operation region as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support,
on the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under9:
Reactive Ppower priority by default; or
Active Real pPower priority if required through other mechanisms by
anthe associated Transmission Planner, Planning Coordinator,
Reliability Coordinator, or Transmission Operator.
While voltage at the high‐side of the main power transformer is within the
permissive operation region, as specified in Attachment 1, each facility IBR may
operate in current block mode if necessary to avoid tripping. Otherwise, each
For the purpose of this standard, the main power transformer is the power transformer that steps up voltage
from the collection system voltage to the nominal transmission/interconnecting system voltage for inverter‐based
resources. In case of offshore wind plants connecting via a dedicated VSC‐HVDC, the main power transformer is
the onshore main power transformer.
6
7 “Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
8 Except if this would occur during a frequency excursion. The active Real pPower response should recover in accordance with
the primary frequency controller.
9 In either case and if required, the magnitude of active Real pPower and reactive current shall be as specified by the
Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
Draft 3 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
facility IBR shall follow the requirements for the mandatory operation region in
Requirement R2.2.
2.3.1
If a facility IBR enters current block mode, it shall restart current
exchange in less than or equal to five cycles of positive sequence
voltage returning to a continuous operation region or mandatory
operation region.
2.4.
Each facility IBR shall not itself cause voltage at the high‐side of the main
power transformer to exceed the applicable high voltage thresholds and time
durations in its response as voltage recovers from the mandatory or permissive
operation regions to the continuous operation region.
2.5.
Each facility IBR shall restore activeReal pPower output to the pre‐disturbance
or available level10 (whichever is lesser) within 1.0 second when the voltage at
the high‐side of the main power transformer returns from the mandatory
operation region or permissive operation region (including operating in current
block mode) to the continuous operation region, as specified in Attachment 1,
unless the an associated Transmission Planner, Planning Coordinator,
Reliability Coordinator, or Transmission Operator requires a lower post‐
disturbance active Real pPower level requirement or requires a different post‐
disturbance active Real pPower restoration time through other mechanisms.11
M2. Each Generator Owner and Transmission Owner shall have evidence of dynamic
simulations, studies, or other evidence to demonstrate the design of each facility IBR
will adhere to requirements, as specified in Requirement R2. Examples of evidence
may include, but are not limited to dynamic simulations, studies, plant protection
settings, and control settings design evaluation. Each Generator Owner and
Transmission Owner shall also retainhave evidence of actual disturbance monitoring
(i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder)
data to demonstrateing that the operation of each facility IBR did adhere to
performance requirements, as specified in Requirement R2, during each voltage
excursion measured at the high‐side of the main power transformer. The Generator
Owner or Transmission Owner shall retainhave evidence of receiving such
performance requirements, (e.g. email exchange, contract information) if the
Transmission Planner, Transmission Operator, Reliability Coordinator, or Planning
Coordinator has required the Generator Owner through other mechanismsor
Transmission Owner to follow performance requirements other than those in
Requirement R2 (e.g. ramp rates, reactive power prioritization).
R3. Each Generator Owner or Transmission Owner shall ensure the design and operation
is such that each facility IBR meets or exceedsadheres to Ride‐through requirements
during a frequency excursion event whereby the System frequency remains within the
“must Ride‐through zone” according to Attachment 2 and the absolute rate of change
10 “Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
11 Except if this would occur during a frequency excursion. The active power response should recover in accordance with the
primary frequency controller.
Draft 3 of PRC‐029‐1
July 2024
Page 6 of 20
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
of frequency (RoCoF)12 magnitude is less than or equal to 5 Hz/second. [Violation Risk
Factor: High] [Time Horizon: Operations Assessment]
M3. Each Generator Owner and Transmission Owner shall have evidence of dynamic
simulations, studies, or other evidence to demonstrate the design of each facility IBR
will adhere to Ride‐through requirements, as specified in Requirement R3. Examples
of evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner and
Transmission Owner shall also have retain evidence of actual disturbance monitoring
(i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder)
data to demonstrate the operation of each facility IBR did adhere to Ride‐through
requirements, as specified in Requirement R3, during each frequency excursion event
measured at the high‐side of the main power transformer.
R4. Each Generator Owner and Transmission Owner identifying an facility IBR that is in‐
service by the effective date of PRC‐029‐1, has known hardware limitations that
prevent the facility IBR from meeting voltage Ride‐through criteria as detailed in
Requirements R1 and R2, and requires an exemption from specific voltage Ride‐
through criteria shall:13 Lower] [Time Horizon: Long‐term Planning]
4.1.
Document information supporting the identified hardware limitation no later
than 12 months following the effective date of PRC‐029‐1. This documentation
shall include:
4.1.1 Identifying information of the IBR (name, facility #, other);
4.1.2 Which aspects of voltage ride‐through requirements that the IBR would
be unable to meet and the capability of the equipment hardware due
to the limitation;
4.1.3 Identify the specific piece(s) of equipment hardware causing the
limitation;
4.1.4 Supporting technical documentation verifying the limitation is due to
hardware that needs to be physically replaced or that the limitation
cannot be removed by software updates or setting changes, and;
4.1.5 Information regarding any plans to remedy the equipment hardware
limitation (such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the
applicable associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and to the Regional
EntityCEA no later than 12 months following the effective date of PRC‐029‐1.
4.2.1
Any response to additional information requested by the applicable
associated Planning Coordinator(s), Transmission Planner(s),
12 Rate of change of frequency (RoOCOoF) is calculated as the average rate of change for multiple calculated system frequencies
for a time period of greater than or equal to 0.1 second. ROoCOoF is not calculated during the fault occurrence and clearance.
13 The exemption requests for a non‐US Registered Entity should be implemented in a manner that is consistent with, or under
the direction of, the applicable governmental authority or its agency in the non‐US jurisdiction.
Draft 3 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Transmission Operator(s), Reliability Coordinator(s), and to the
Regional EntityCEA shall be provided back to the requestor within 90
days of the request.
4.2.14.2.2 Provide a copy of the acceptance of an hardware limitation by the
CEA to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s).14
4.3.
Each Generator Owner and Transmission Owner with a previously submitted
accepted limitationrequest for exemption that replace the
equipmenthardware causing the limitation shall document and communicate
such an hardware equipment change to the associated Planning Coordinator(s),
Transmission Planner(s), Transmission Operator(s), and Reliability
Coordinator(s) within 90 days of the hardware equipment change.
4.3.1
When existing equipment hardware causing the limitation is
replaced, the exemption for that Ride‐through criteria no longer
applies.
M4. Each Generator Owner and Transmission Owner seeking submitting for an exemption
for an IBRfacilities that are is in‐service by the effective date of PRC‐029‐1, shall have
evidence of submission to the Regional EntityCEA consistent with the information
listed in Requirement R4.1. Each Generator Owner and Transmission Owner shall have
evidence of communicated copies of each submission in accordance with Requirement
R4.2 and to the applicable associated entities described in Requirement R4.2.
Acceptable types of evidence for submittals include but are not limited to, meeting
minutes, agreements, copies of procedures or protocols in effect, or email
correspondence. Acceptable types of evidence for an equipmenthardware limitation
may include but is not limited to, documentation that contains study results,
experience from an actual event, or manufacturer’s advice. Each Generator Owner
and Transmission Owner that receives a request for additional information under
Requirement R4.2.1 shall have evidence of providing that information within 90
calendar days. Each Generator Owner that replaces hardware equipment at an IBR
facility that is directly associated with an approved accepted exemption and that
hardware equipment is the cause for the limitation, shall have evidence of
communicating the hardware equipment change to the applicable associated entities
described in Requirement R4.3 within 390 calendar days of the hardware equipment
replacement.
14 Acceptance by the CEA is verification that the information provided includes all information listed in Requirement R4.1.
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full‐time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
Each Generator Owner and Transmission Owner shall retain evidence with
Requirements R1, R2, and R3 in this standard for 36 calendar months or the
date of the last audit, whichever is greater.
Each Generator Owner and Transmission Owner shall retain evidence with
Requirement R4 in this standard for five calendar years or the date of the
last audit, whichever is greater.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Draft 3 of PRC‐029‐1
July 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Generator Owner or
Transmission Owner failed to
demonstrate the design
capability of each applicable
facility IBR to Ride‐through in
accordance with Attachment
1, except for those conditions
identified in Requirement R1.
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility IBR adhered to
Ride‐through requirements in
accordance with Attachment
1, except for those conditions
identified in Requirement R1.
R2.
The Generator Owner or
Transmission Owner failed to
demonstrate the design
capability of each applicable
facility IBR to adhere to
performance requirements
during voltage excursions, as
specified in Requirement R2.
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility IBR adhered to
performance requirements
during voltage excursions, as
specified in Requirement R2.
R3.
The Generator Owner or
Transmission Owner failed to
demonstrate the design
capability of each applicable
facility to Ride‐through in
accordance with Attachment
2.
N/A
N/A
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable
facility adhered to
Ride‐through requirements in
accordance with Attachment
2.
R4.
The Generator Owner or
Transmission Owner with a
previously communicated
The Generator Owner or
Transmission Owner with a
previously communicated
The Generator Owner or
Transmission Owner with a
previously communicated
The Generator Owner or
Transmission Owner failed to
document complete
Draft 3 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
equipment hardware
limitation that repairs or
replaces the documented
limiting hardware equipment
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),
Reliability Coordinator(s), and
Regional EntityCEA more than
390 calendar days but less
than or equal to 6120 calendar
days after the change to the
hardwareequipment.
hardware equipment
limitation that repairs or
replaces the documented
limiting hardware equipment
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Reliability Coordinator(s),
Transmission Operator(s), and
Regional EntityCEA more than
6120 calendar days but less
than or equal to 9150 calendar
days after the change to the
hardwareequipment.
hardware equipment
limitation that repairs or
replaces the documented
limiting hardware equipment
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Reliability Coordinator(s),
Transmission Operator(s), and
Regional EntityCEA more than
9150 calendar days but less
than or equal to 1280 calendar
days after the change to the
hardwareequipment.
information for facilities IBR
identified with known
hardware limitations that
prevent the facility IBR from
meeting voltage Ride‐through
criteria as detailed in
Requirements R1 or R2.
OR
The Generator Owner or
Transmission Owner provided
a copy to the applicable
entities as detailed in
Requirement R4.2 more than
12 months but less than or
equal to 15 months after the
effective date of Requirement
R4.
OR
Draft 3 of PRC‐029‐1
July 2024
OR
The Generator Owner or
Transmission Owner with a
previously communicated
hardware equipment
OR
OR
limitation that repairs or
The Generator Owner failed to The Generator Owner failed to replaces the documented
limiting hardware equipment
respond to the applicable
respond to the applicable
but failed to document and
entities as detailed in
entities as detailed in
Requirement R4.2.1 more than Requirement R4.2.1 more than communicate the change to its
120 days but less than or equal 150 days but less than or equal Planning Coordinator(s),
Transmission Planner(s),
to 150 days after receiving a
to 180 days after receiving a
Transmission
request for additional
request for additional
information by an entity listed information by an entity listed Operator(s),Reliability
Coordinator(s), and Regional
in Requirement R4.2.1.
in Requirement R4.2.1.
Entity CEA more than 1280
calendar days after the change
to the hardwareequipment.
Page 11 of 20
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Violation Severity Levels
R#
Lower VSL
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
90 days but less than or equal
to 120 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
Moderate VSL
High VSL
Severe VSL
OR
The Generator Owner or
Transmission Owner failed to
provide a copy to the
applicable entities as detailed
in R4.2 within 24 months after
the effective date of R4.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Version History
Version
Date
Action
Initial Draft
3/27/24
Draft
Draft 2
6/4/24
Revised following initial comment review
Draft 3
7/22/24
Revised following additional comment review
Draft 3 of PRC‐029‐1
July 2024
Change
Tracking
Page 13 of 20
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-Through Requirements for AC-Connected Wind FacilityIBR 15
Voltage (per unit)16
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A17
N/A
≤ 1.20 and ≥ 1.10
Mandatory Operation Region
1.0
≤ 1.10 and > 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90 and ≥ 0.70
Mandatory Operation Region
3.00
< 0.70 and ≥ 0.50
Mandatory Operation Region
2.50
< 0.50 and ≥ 0.25
Mandatory Operation Region
1.20
< 0.25 and ≥ 0.10
Mandatory Operation Region
0.16
< 0.10
Permissive Operation Region
0.16
Table 222: Voltage Ride-Through Requirements for All Other Inverter-based
Resource FacilitiesIBR
Voltage
(per unit)18
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A19
N/A
≤ 1.20 and > 1.10
Mandatory Operation Region
1.0
≤ 1.10 and > 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90 and ≥ 0.70
Mandatory Operation Region
6.00
< 0.70 and ≥ 0.50
Mandatory Operation Region
3.00
< 0.50 and ≥ 0.25
Mandatory Operation Region
1.20
< 0.25 and ≥ 0.10
Mandatory Operation Region
0.32
< 0.10
Permissive Operation Region
0.32
15 Type 3 and type 4 wind resources directly connected to the AC Transmission System.
16 Refer to bullet #45 below.
17 These conditions are referred to as the “may Ride‐through zone”.
18 Refer to bullet #45 below.
19 These conditions are referred to as the “may Ride‐through zone”.
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
1. Table 1 applies to type 3 and type 4 wind facilities IBR or hybrid IBR that include
wind, unless connected via a dedicated VSC‐HVDC transmission facility.
2. Table 2 applies to all other inverter‐based resourceIBR facility types not covered in
Table 1; including, but not limited to, the following facilities:
a. Inverter‐based resourcesIBR, regardless of their energy resource,
interconnecting via a dedicated VSC‐HVDC transmission facility.
b. Other inverter‐based resourceIBR plants or hybrid plants IBR consisting of
photovoltaic (PV) and BESS.
3. The applicable voltage for Voltage Source Converter High Voltage Direct Current
(VSC‐ HVDC) system with a dedicated connection to an inverter‐based resourceIBR is
on the AC side of the transformer(s) that is (are) used to connect the VSC‐ HVDC
system to the interconnected transmission system.
4. Table 1 applies to hybrid facilities consisting of wind (type 3 or type 4) and various
other IBR technologies. Otherwise, Table 2 applies to hybrid facilities with no wind
(type 3 or type 4).
5.4. The voltage base for per unit calculation is the nominal phase‐to‐ground or
phase‐to‐phase transmission system voltage unless otherwise defined by the
Planning Coordinator, or Transmission Planner, or Transmission Owner.
6.5. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase‐ to ‐neutral or phase ‐to ‐phase fundamental root mean square (RMS) voltage
at the high ‐side of the main power transformer.
7.6. Tables 1 and 2 are only applicable when the frequency is within the “must
Ride‐through zone” as specified in Table 3 Figure 1 of Attachment 2.
8.7. At any given voltage value, each facility IBR shall Ride‐through unless the time
duration at that voltage has exceeded the specified minimum Ride‐through time
duration. If the voltage is continuously varying over time, it is necessary to add the
duration within each band of Tables 1 and 2 over any 10 second time period.
9.8. The specified duration of the mandatory operation regions and the permissive
operation regions in Tables 1 and 2 is cumulative over one or more disturbances
within any 10 second time period.
10.9. The facility IBR may trip for more than four deviations of the applicable voltage
at the high‐side of the main power transformer outside of the continuous operation
region within any 10 second time period.
11.10. Instantaneous trip settings based on instantaneously calculated voltage
measurements with less than filtering lengths of one cycle (16.6 msec) are not
permissible.
12.11. The “must Ride‐through zone” is the combined area of the mandatory operating
regions, the continuous operating regions, and the permissive operating region. All
Draft 3 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
area outside of these operating regions is referred to as the “may Ride‐through
zone”.
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
No‐Trip Zone No – Trip Zone
Figure 1: Voltage Ride-Through Requirements for AC-Connected Wind Facilities
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Figure 2: Voltage Ride‐Through Requirements for All Other IBR
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Attachment 2: Frequency Ride-Through Criteria
Table 3: Frequency Ride-Through Capability Requirements
System Frequency (Hz)
Minimum Ride-Through
Time (sec)
>≥ 64.0
May trip
< 64 and ≥ 61.8
6
< 61.8 and ≥ 61.5
299
< 61.5 and > 61.2
660
≤ 61.2 and >< 58.8
Continuous
≤ 58.8 and < 58.8
660
≤< 58.5 and ≥ 57
299
≤< 57.0 and ≥ 56
6
< 56.0
May trip
1. Frequency measurements are taken at the high‐side of the main power transformer.
2. Frequency is measured over a period of time (typically 3‐6 cycles) to calculate system
frequency at the high‐side of the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency value, each facility shall Ride‐through unless the time duration at
that frequency has exceeded the specified minimum ride‐through time duration.
5. The specified durations of Table 3 are cumulative over one or more disturbances within
a 15‐minute time period.
Draft 3 of PRC‐029‐1
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Page 19 of 20
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources
Figure 31: PRC‐029 Frequency Ride‐Through Requirements
Draft 3 of PRC‐029‐1
July 2024
Page 20 of 20
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Reliability Standards PRC-024-4 and PRC-029-1
Applicable Standard(s)
•
PRC-024-4 – Frequency and Voltage Protection Settings for Synchronous Generators, Type 1
and Type 2 Wind Resources, and Synchronous Condensers
•
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based
Generating Resources
Requested Retirement(s)
•
PRC-024-3 Frequency and Voltage Protection Settings for Generating Resources
Prerequisite Standard(s)
•
None
Proposed Definition(s)
•
None
Applicable Entities
•
See subject Reliability Standards.
Background
The purpose of Project 2020-02 is to modify Reliability Standard PRC-024-3 or replace it with a
performance-based Ride-through standard that ensures generators remain connected to the
Bulk Power System (BPS) during system disturbances. Specifically, the project focuses on using
disturbance monitoring data to substantiate inverter-based resource (IBR) ride-through performance
during grid disturbances. The project also ensures associated generators that fail to Ride-through
system events are addressed with a corrective action plan (if possible) and reported to necessary
entities for situational awareness.
The purpose for this project is based on the culmination of multiple analyses conducted by the ERO
Enterprise regarding widespread IBR tripping events. Furthermore, the NERC Inverter-Based Resource
Performance Subcommittee 1 has developed comprehensive recommendations for improved
See documents at the NERC IRPS website: https://www.nerc.com/comm/RSTC/Pages/IRPS.aspx and the previous Inverter-Based
Resource Performance Working Group website https://www.nerc.com/comm/RSTC/Pages/IRPWG.aspx
1
RELIABILITY | RESILIENCE | SECURITY
performance of IBRs, including the recommendation to develop comprehensive ride-through
requirements.
In October 2023, FERC issued Order No. 901 2 which directs the development of new or modified
Reliability Standards that include new requirements for disturbance monitoring, data sharing, postevent performance validation, and correction of IBR performance. In January 2024, NERC submitted a
filing to FERC outlining a comprehensive work plan to address the directives within Order No. 901. 3
Within the work plan, NERC identified three active Standards Development projects that would need to
be filed for regulatory approval with FERC by November 4, 2024. These projects include 2020-02
Modifications to PRC-024 (Generator Ride-through) 4, 2021-04 Modifications to PRC-002-2 5, and 202302 Analysis and Mitigation of BES Inverter-based Resource Performance Issues 6.
Project 2020-02
Proposed Reliability Standard PRC-029-1 is a new Reliability Standard that includes Ride-through
requirements and performance requirements for IBRs. The scope of this project was adjusted to align
with associated regulatory directives from FERC Order No. 901 and the scope of the other projects
related to “Milestone 2” of the NERC work plan. The components of this project’s Standard
Authorization Request (SAR) that related to the inclusions of new data recording requirements are
covered in Project 2021-04 and the proposed new PRC-028-1 Reliability Standard. Components of this
project’s SAR that relate to analytics and corrective actions plans are covered in Project 2023-02 and the
proposed new PRC-030-1 Reliability Standard.
PRC-029-1 includes requirements for Generator Owner IBR to continue to inject current and perform
voltage support during a BPS disturbance. The standard also specifically requires Generator Owner IBR
to prohibit momentary cessation in the no-trip zone during disturbances.
PRC-024-4 includes modifications to revise applicable facility types to remove IBR, retain type 1 and
type 2 wind, and to include synchronous condensers.
See FERC Order 901, Docket No. RM22-12-000; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=202310193157&optimized=false; October 19, 2023
3 See INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF
RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%2
0901%20Work%20Plan_packaged%20-%20public%20label.pdf; January 17, 2024
4 See NERC Standards Development Project page for Project 2002-02; https://www.nerc.com/pa/Stand/Pages/Project_202002_Transmission-connected_Resources.aspx
5 See NERC Standards Development Project page for Project 2021-04; https://www.nerc.com/pa/Stand/Pages/Project-2021-04Modifications-to-PRC-002-2.aspx
6 See NERC Standards Development Project page for Project 2023-02; https://www.nerc.com/pa/Stand/Pages/Project-2023-02Performance-of-IBRs.aspx
2
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
2
General Considerations
This implementation plan recognizes the urgent need for Reliability Standards to address IBR ride
through performance, as demonstrated by multiple event reports of the last decade, while providing a
reasonable period of time for entities to develop the necessary procedures and change their protection
and control settings to meet the new requirements. The ERO Enterprise acknowledges that there are
IBRs currently in operation and unable to meet voltage Ride-through requirements due to their inability
to modify their coordinated protection and control settings. Consistent with FERC Order No. 901, a
limited and documented exemption process for those IBR is appropriate and included within this
Implementation Plan. Other NERC Standards Development projects will be pursued to address ongoing
identification and mitigation of any potential reliability impacts to the BPS for such exemptions.
This implementation plan also recognizes that certain requirements (Requirements R1, R2, and R3) call
for entities to “ensure the design and operation” of their IBR units meets certain criteria. Design
elements may be implemented more expeditiously than operation requirements; the latter of which
will require entities to show compliance through use of actual disturbance monitoring data. Therefore,
this implementation plan provides staggered timeframes by which entities shall first ensure the design
of their IBR units meets the criteria (12 months following regulatory approval). Subsequent compliance
with the “operation” elements of these requirements shall become due as entities install disturbance
monitoring equipment on each applicable IBR in accordance with the implementation plan for proposed
Reliability Standard PRC-028-1 Disturbance Monitoring and Reporting Requirements for Inverter-based
Resources.
The ERO Enterprise acknowledges that Generator Owners and Generator Operators owning or
operating Bulk Power System connected IBRs that do not meet NERC’s current definition of Bulk Electric
System (“BES”) will be registered no later than May 2026 in accordance with the IBR Registration
proceeding in FERC Docket No. RR24-2. To ensure an orderly registration and compliance process for
these entities, as well as fairness and consistency in the standard’s application among similar asset
types, this implementation plan provides additional time for both new and existing registered entities to
come into compliance with Reliability Standard PRC-029-1’s requirements for their applicable IBRs not
meeting the BES definition. In so doing, this implementation plan advances an orderly process for new
registrants while allowing existing entities to focus their immediate efforts on their assets posing the
highest risk to the reliable operation of the Bulk Power System.
Effective Date and Phased-in Compliance Dates
The effective dates for the proposed Reliability Standards are provided below. Where the standard
drafting team identified the need for a longer implementation period for compliance with a particular
section of a proposed Reliability Standard (i.e., an entire Requirement or a portion thereof), the
additional time for compliance with that section is specified below. The phased-in compliance dates for
those particular sections represent the date that entities must begin to comply with that particular
section of the Reliability Standard, even where the Reliability Standard goes into effect at an earlier
date.
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
3
PRC-024-4
Where approval by an applicable governmental authority is required, Reliability Standard PRC-024-4
shall become effective on the first day of the first calendar quarter that is twelve months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC024-4 shall become effective on the first day of the first calendar quarter that is twelve months after
the date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1
Where approval by an applicable governmental authority is required, Reliability Standard PRC-029-1
shall become effective on the first day of the first calendar quarter that is twelve months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC029-1 shall become effective on the first day of the first calendar quarter that is twelve months after the
date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1 Phased-in Compliance Dates
Requirements R1, R2, and R3
Capability-Based Elements
Bulk Electric System IBRs
Entities shall comply with the portion of Requirements R1, R2, and R3 relating to the design of their
BES IBRs to meet the requirements by the effective date of the standard.
Applicable Non-BES IBRs 7
Entities shall not be required to comply with Requirements R1, R2, and R3 relating to the design of
their applicable non-BES IBRs until the later of: (1) January 1, 2027; or (2) the effective date of the
standard.
Performance-Based Elements (all applicable IBRs)
Entities shall not be required to comply with the portion of Requirements R1, R2, and R3 relating to
the operation of IBRs to meet the requirements until the entity has established the required
The standard defines such as IBRs as “Non-BES Inverter-Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.”
7
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
4
disturbance monitoring equipment capabilities for those IBRs in accordance with the
implementation plan for Reliability Standard PRC-028-1.
Requirement R4
Bulk Electric System IBRs
Entities shall comply with Requirement R4 for their BES IBRs by the effective date of the standard.
Applicable Non-BES IBRs
Entities shall not be required to comply with Requirement R4 or their non-BES IBRs until the later of:
(1) January 1, 2027; or (2) the effective date of the standard.
Retirement Date
PRC-024-3
Reliability Standard PRC-024-3 shall be retired immediately prior to the effective date of Reliability
Standards PRC-024-4 and PRC-029-1 in the particular jurisdiction in which the revised standard is
becoming effective.
Equipment Limitations and Process for Requirement R4
Consistent with FERC Order No. 901, a limited and documented exemption for some legacy IBR with
certain documented equipment limitations are acceptable. Per the Order, these IBRs are
“…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.” 8
To ensure compliance with Requirement R4 and alignment with FERC Order No. 901, only those IBR that
are in operation as of the effective date of PRC-029-1 may be considered for potential exemption.
Further, only those IBR that are unable to meet voltage ride-through requirements due to their inability
to modify their coordinated protection and control settings may be considered for potential exemption.
8
Order No. 901 at p. 193.
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
5
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Reliability Standards PRC-024-4 and PRC-029-1
Applicable Standard(s)
PRC‐024‐4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1
and Type 2 Wind Resources, and Synchronous Condensers
PRC‐029‐1 Frequency and Voltage Ride‐ Tthrough Requirements for Inverter‐Based
Generating Resources
Requested Retirement(s)
PRC‐024‐3 Frequency and Voltage Protection Settings for Generating Resources
Prerequisite Standard(s)
PRC‐028‐1 Disturbance Monitoring and Reporting Requirements for Inverter‐Based
ResourcesNone
Proposed Definition(s)
None
Applicable Entities
See subject Reliability Standards.
Background
The purpose of Project 2020‐02 is to modify Reliability Standard PRC‐024‐3 or replace it with a
performance‐based Rride‐through standard that ensures generators remain connected to the
Bulk‐Power System (BPS) during system disturbances. Specifically, the project focuses on using
disturbance monitoring data to substantiate inverter‐based resource (IBR) ride‐through performance
during grid disturbances. The project also ensures associated generators that fail to rEide‐through
system events are addressed with a corrective action plan (if possible) and reported to necessary
entities for situational awareness.
The purpose for this project is based on the culmination of multiple analyses conducted by the ERO
Enterprise regarding widespread inverter‐based resourceIBR tripping events. Furthermore, the NERC
Inverter‐Based Resource Performance Subcommittee1 has developed comprehensive recommendations
1 See documents at the NERC IRPS website: https://www.nerc.com/comm/RSTC/Pages/IRPS.aspx and the previous Inverter‐Based
Resource Performance Working Group website https://www.nerc.com/comm/RSTC/Pages/IRPWG.aspx
RELIABILITY | RESILIENCE | SECURITY
for improved performance of inverter‐based resources, including the recommendation to develop
comprehensive ride‐through requirements.
In October 2023, FERC issued Order No. 9012 which directs the development of new or modified
Reliability Standards that include new requirements for disturbance monitoring, data sharing, post‐
event performance validation, and correction of IBR performance. In January 2024, NERC submitted a
filing to FERC outlining a comprehensive work plan to address the directives within Order No. 901.3
Within the work plan, NERC identified three active Standards Development projects that would need to
be filed for regulatory approval with FERC by November 4, 2024. These projects include 2020‐02
Modifications to PRC‐024 (Generator Ride‐through)4, 2021‐04 Modifications to PRC‐002‐25, and 2023‐
02 Analysis and Mitigation of BES Inverter‐Based Resource Performance Issues6.
Project 2020‐02
Proposed Reliability Standard PRC‐029‐1 is a new Reliability Standard that includes rRide‐through
requirements and performance requirements for IBRs. The scope of this project was adjusted to align
with associated regulatory directives from FERC Order No. 901 and the scope of the other projects
related to “Milestone 2” of the NERC work plan. The components of this project’s Standard
Authorization Request (SAR) that related to the inclusions of new data recording requirements are
covered in Project 2021‐04 and the proposed new PRC‐028‐1 Reliability Standard. Components of this
project’s SAR that relate to analytics and corrective actions plans are covered in Project 2023‐02 and the
proposed new PRC‐030‐1 Reliability Standard.
PRC‐029‐1 includes requirements for Generator Owner and Transmission Owner IBR to continue to
inject current and perform frequency voltage support during a BPS disturbance. The standard also
specifically requires Generator Owner and Transmission Owner IBR to prohibit momentary cessation in
the no‐trip zone during disturbances.
PRC‐024‐4 includes modifications to revise applicable facility types to remove IBR, retain type 1 and
type 2 wind, and to include synchronous condensers.
2 See FERC Order 901, Docket No. RM22‐12‐000; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019‐
3157&optimized=false; October 19, 2023
3 See INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF
RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%2
0901%20Work%20Plan_packaged%20‐%20public%20label.pdf; January 17, 2024
4 See NERC Standards Development Project page for Project 2002‐02; https://www.nerc.com/pa/Stand/Pages/Project_2020‐
02_Transmission‐connected_Resources.aspx
5 See NERC Standards Development Project page for Project 2021‐04; https://www.nerc.com/pa/Stand/Pages/Project‐2021‐04‐
Modifications‐to‐PRC‐002‐2.aspx
6 See NERC Standards Development Project page for Project 2023‐02; https://www.nerc.com/pa/Stand/Pages/Project‐2023‐02‐
Performance‐of‐IBRs.aspx
Implementation Plan | PRC‐024‐4 and PRC‐029‐1
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | July 2024
2
General Considerations
This implementation plan recognizes the urgent need for Reliability Standards to address IBR ride
through performance, as demonstrated by multiple event reports of the last decade, while providing a
reasonable period of time for entities to develop the necessary procedures and change their protection
and control settings to meet the new requirements. The ERO Enterprise acknowledges that there are
IBRs currently in operation and unable to meet voltage rRide‐through requirements due to their
inability to modify their coordinated protection and control settings. Consistent with FERC Order No.
901, a limited and documented exemption process for those IBR is appropriate and included within this
Implementation Plan. Other NERC Standards Development projects will be pursued to address ongoing
identification and mitigation of any potential reliability impacts to the BPS for such exemptions.
This implementation plan also recognizes that certain requirements (Requirements R1, R2, and R3) call
for entities to “ensure the design and operation” of their IBR units meets certain criteria. Design
elements may be implemented more expeditiously than operation requirements; the latter of which
will require entities to show compliance through use of actual disturbance monitoring data. Therefore,
this implementation plan provides staggered timeframes by which entities shall first ensure the design
of their IBR units meets the criteria (12 months following regulatory approval). Subsequent compliance
with the “operation” elements of these requirements shall become due as entities install disturbance
monitoring equipment on each applicable IBR in accordance with the implementation plan for proposed
Reliability Standard PRC‐028‐1 Disturbance Monitoring and Reporting Requirements for Inverter‐based
Resources.
The ERO Enterprise acknowledges that Generator Owners and Generator Operators owning or
operating Bulk Power System connected IBRs that do not meet NERC’s current definition of Bulk Electric
System (“BES”) will be registered no later than May 2026 in accordance with the IBR Registration
proceeding in FERC Docket No. RR24‐2. To ensure an orderly registration and compliance process for
these entities, as well as fairness and consistency in the standard’s application among similar asset
types, this implementation plan provides additional time for both new and existing registered entities to
come into compliance with Reliability Standard PRC‐029‐1’s requirements for their applicable IBRs not
meeting the BES definition. In so doing, this implementation plan advances an orderly process for new
registrants while allowing existing entities to focus their immediate efforts on their assets posing the
highest risk to the reliable operation of the Bulk Power System.
Effective Date and Phased-in Compliance Dates
The effective dates for the proposed Reliability Standards are provided below. Where the standard
drafting team identified the need for a longer implementation period for compliance with a particular
section of a proposed Reliability Standard (i.e., an entire Requirement or a portion thereof), the
additional time for compliance with that section is specified below. The phased‐in compliance dates for
those particular sections represent the date that entities must begin to comply with that particular
section of the Reliability Standard, even where the Reliability Standard goes into effect at an earlier
date.
Implementation Plan | PRC‐024‐4 and PRC‐029‐1
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | July 2024
3
PRC-024-4
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐024‐4
shall become effective on the first day of the first calendar quarter that is 6twelve months after the
effective date of the applicable governmental authority’s order approving the PRC‐028‐1 standard, or as
otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC‐
024‐4 shall become effective on the first day of the first calendar quarter that is twelve6 months after
the date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐029‐1
shall become effective on the first day of the first calendar quarter that is twelve six months after the
effective date of the applicable governmental authority’s order approving the PRC‐028‐1 standard, or as
otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC‐
029‐1 shall become effective on the first day of the first calendar quarter that is twelve six months after
the date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1 Phased-in Compliance Dates
Requirements R1, R2, and R3
Capability‐Based Elements
Bulk Electric System IBRs
Entities shall comply with the portion of Requirements R1, R2, and R3 relating to the design of their
BES IBRs to meet the requirements by the effective date of the standard.
Applicable Non‐BES IBRs7
Entities shall not be required to comply with Requirements R1, R2, and R3 relating to the design of
their applicable non‐BES IBRs until the later of: (1) January 1, 2027; or (2) the effective date of the
standard.
Performance‐Based Elements (all applicable IBRs)
Entities shall not be required to comply with the portion of Requirements R1, R2, and R3 relating to
the operation of IBRs to meet the requirements until the entity has established the required
7 The standard defines such as IBRs as “Non‐BES Inverter‐Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.”
Implementation Plan | PRC‐024‐4 and PRC‐029‐1
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | July 2024
4
disturbance monitoring equipment capabilities for those IBRs in accordance with the
implementation plan for Reliability Standard PRC‐028‐1.
Requirement R4
Bulk Electric System IBRs
Entities shall comply with Requirement R4 for their BES IBRs by the effective date of the standard.
Applicable Non‐BES IBRs
Entities shall not be required to comply with Requirement R4 or their non‐BES IBRs until the later of:
(1) January 1, 2027; or (2) the effective date of the standard.
Implementation Plan | PRC‐024‐4 and PRC‐029‐1
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | July 2024
5
Retirement Date
PRC-024-3
Reliability Standard PRC‐024‐3 shall be retired immediately prior to the effective date of Reliability
Standards PRC‐024‐04 and PRC‐029‐1 in the particular jurisdiction in which the revised standard is
becoming effective.
Equipment Limitations and Process for Requirement R4
Consistent with FERC Order No. 901, a limited and documented exemption for some legacy IBR with
certain documented equipment limitations are acceptable. Per the Order, these IBRs are
“…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.”8
To ensure compliance with Requirement R4 and alignment with FERC Order No. 901, only those IBR that
are in operation as of the effective date of PRC‐029‐1 may be considered for potential exemption.
Further, only those IBR that are unable to meet voltage ride‐through requirements due to their inability
to modify their coordinated protection and control settings may be considered for potential exemption.
8 Order No. 901 at p. 193.
Implementation Plan | PRC‐024‐4 and PRC‐029‐1
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | July 2024
6
Unofficial Comment Form
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on Project 2020-02 Modifications to PRC-024 (Generator Ride-through) by 8
p.m. Eastern, Monday, August 12, 2024.
Additional information is available on the project page. If you have questions, contact Manager of
Standards Development, Jamie Calderon (email), or at 404-960-0568.
Background Information
The goal of Project 2020-02 is to mitigate the recent and ongoing disturbance ride through performance
issues identified across multiple Interconnections and numbers of disturbances analyzed by NERC and the
Regions. These issues have been associated with Inverter-Based Resources (IBR) with many causes of their
tripping or cessation unrelated to voltage and frequency protection settings requirements in the currently
effective version of PRC-024, PRC-024-3. Proposed Reliability Standard PRC-024-4 includes revisions to
limits its applicability to synchronous generators and synchronous condensers only and remains as a
protection-based standard. A new standard, PRC-029-1, is proposed as a true disturbance ride-through
Reliability Standard with applicability to inverter-based resources.
In October 2023, FERC issued Order No. 901, which directed NERC to develop new or modified existing
Reliability Standards that include new requirements for disturbance monitoring, data sharing, post-event
performance validation, and correction of IBR performance. Project 2020-02 was one of three projects
identified by NERC that must be completed and filed with FERC by November 4, 2024 to address Order
No. 901 directives. At the December 2023 SC meeting, the SC approved waivers for Project 2020-02,
allowing formal comment periods to be reduced from 45 days to 25 calendar days, and final ballot periods
to be reduced from 10 days to as few as 5 calendar days.
The initial draft of the PRC-024-4 and PRC-029-1 drafts were posted for comment March 27- April 22,
2024. Comments were reviewed and incorporated. An additional draft was posted for comment June 28 –
July 8, 2024. Substantive changes were made to the PRC-029-1 draft based on comments received. Formal
comment responses are available in the consideration of comments received document posted along with
these additional drafts. The additional draft for PRC-024-4 passed with an 82.7% successful ballot and is
presented in this posting for Final Ballot.
Questions
1. Do you agree with the proposed definition of Ride-through? If not, please state what revision
would be acceptable and why.
Yes
No
Comments:
RELIABILITY | RESILIENCE | SECURITY
2. Do you agree with the changes made in this draft of PRC-029-1.
Yes
No
Comments:
3. Provide any additional comments for the Drafting Team to consider, if desired.
Comments:
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Unofficial Comment Form | July 2024
2
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1 – Frequency and Voltage Ride-through Requirements for
Inverter-based Generating Resources
General Rationale
The drafting team has created a new Reliability Standard (PRC-029-1) to address inverter-based resource
(IBR) disturbance Ride-through performance criteria. This proposal is a consequence of both the different
natures of synchronous and inverter-based generation resources and several recent events exhibiting
significant IBR Ride-through deficiencies. The proposed PRC-029-1 coincides with certain Ride-through
requirements of IEEE 2800-2022 but is structured to follow language from FERC Order No. 901, which
states that “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.” 1
The lack of standardization of IBR technology (equipment/controller behavior) has created reliability
challenges associated with the interconnection of IBR facilities to the power grid. The nature of the fast
switching of power electronics of IBR generation and the electronic interface to the transmission system is
such that disturbance Ride-through behavior is largely determined by manufacturer-specific equipment
and controls system designs. These controls may be programmed but also have more restrictive limits on
current, both in magnitude and duration. IBR responses to grid disturbances are highly controlled and
managed by using fast switching of power electronics devices dependent upon manufacturer specific
control system design that can be programmed in many ways and with various and concurrent
Ride-through performance objectives. Rather than attempting to restrict the myriad of control
approaches, protections, and settings, it is more straightforward to require Ride-through during defined
frequency and voltage excursions.
In contrast to synchronous generation, the need for IBR Ride-through requirements has been heightened
by recent events during which IBRs have not met PRC-024-3 frequency and voltage Ride-through
expectations, often due to controls and protection only indirectly associated with the system voltage and
frequency excursions. In addition to Ride-through, there is the question of what IBRs should be doing as
they Ride-through. IBR responses to system disturbances can be beneficial or detrimental to both their
own Ride-through and system reliability, often depending on adjustable control settings. Thus, it is
essential to set expectations on performance during Ride-through as well as Ride-through capability.
A further reason for proposing a separate IBR standard is that IBRs do not provide inertia or short circuit
contributions, unlike synchronous machines. The drafting team thinks that IBRs should compensate for
their lack of inertia and short circuit contributions with wider tolerances for frequency and voltage
P 195, FERC Order No. 901; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019-3157&optimized=false; October 17,
2023
1
RELIABILITY | RESILIENCE | SECURITY
excursions. This is the reason for the differences in the frequency and voltage tables and graphs between
the PRC-024-4 and PRC-029-1 standards.
The proposed PRC-029-1 must be understood generally as an event-based standard though it is also
required to provide evidence of the ability to Ride-through disturbance events by means of dynamic
models and simulation results. Compliance with PRC-029-1 is determined chiefly though not exclusively
from IBR Ride-through performance during transmission system events in the field. An IBR becomes
noncompliant with PRC-029-1 when an event in the field occurs that shows that one or more
requirements were not satisfied. This intent is clarified by Operations Assessment as the Time Horizon
designation of requirements R1-R3.
FERC Order No. 901 Directives
PRC-029-1 is proposed in consideration of directives from FERC Order No. 901 that were assigned to the
Project 2020-02 drafting team. The following directives were assigned to this drafting team for inclusion in
this standards project (paragraph numbers of the FERC Order are included for reference):
•
Paragraph 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.”
•
Paragraph 190: “The new or modified Reliability Standards must require registered IBRs to
continue to inject current and perform frequency support during a Bulk-Power System
disturbance.”
•
Paragraph 190: “Any new or modified Reliability Standard must also require registered IBR
generator owners and operators to prohibit momentary cessation in the must Ride-through zone
during disturbances.”
•
Paragraph 190: “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.”
•
Paragraph 193: “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.”
•
Paragraph 193: “Further, we direct NERC to ensure that any such exemption would be applicable
for only existing equipment that is unable to meet voltage Ride-through 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.).”
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
2
•
Paragraph 193: “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).”
•
Paragraph 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, we direct NERC to
develop new or modified Reliability Standards to mitigate the reliability impacts to the Bulk-Power
System of such an exemption.”
•
Paragraph 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 pre-disturbance output level
in a quick and stable manner after a Bulk-Power System.”
•
Paragraph 209: “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 predisturbance levels during a disturbance, consistent with the IBR Interconnection Requirements
Guideline and Canyon 2 Fire Event Report recommendations.”
•
Paragraph 209: “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.”
•
Paragraph 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.”
•
Paragraph 226: “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 rule prior to
that date.” (pertains multiple projects)
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for assuring acceptable Ride-through performance of IBR is either the
Generator Owner.
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
3
Facilities (4.2)
Applicability Facilities include only IBR that also meet NERC registration criteria. Language used within
PRC-029-1 applicability only refers to IBR as a whole plant/facility. Consistent with FERC Order No. 901,
IBR performance is based on the overall IBR plant and disturbance monitoring equipment requirements
established under the proposed PRC-028-1. Requirements within PRC-029-1 do not apply to individual
inverter units or measurements taken at individual inverter unit terminals.
Rationale for Requirement R1
The objective of Requirement R1 is to ensure that all applicable IBRs will Ride-through grid voltage
disturbances consistent with the must Ride-through zone and operation regions specified in Attachment
1. IBRs must be able to demonstrate Ride-through performance, that they remain electrically connected,
i.e., shall not trip, and continue to exchange current, i.e., shall not enter momentary cessation.
The drafting team determined that the definition of “must Ride-through zones” and “operation regions”
should be consistent with those terms as used within IEEE 2800-2022. Additionally, the team determined
that the voltage thresholds of each operation region should be based on measurements taken on the
high-side of the main power transformer in PRC-029-1, also consistent with IEEE 2800-2022.
Battery Energy Storage Systems (BESS) units also must comply with Requirement R1 in all operating
modes including charging, discharging, and idle (energized but not charging or discharging). A BESS in idle
mode must be capable of responding to system voltage and frequency excursions as it does in charging or
discharging modes.
Exceptions to Attachment 1 performance criteria are allowable when 1) an IBR needs to trip to clear a
fault, 2) voltage at the high-side of the main power transformer goes outside an accepted and a
documented hardware equipment limitation established in accordance with Requirement R4, 3)
instantaneous positive sequence voltage phase angle jumps more than 25 electrical degrees at the highside of the main power transformer initiated by a non-fault switching events occur on the transmission
system, or 4) volts per Hz (V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for
longer than 45 seconds or exceed 1.18 per unit for longer than 2 seconds.
When a grid disturbance occurs, such as a close-in fault or a relatively large switching event, the grid
voltage may experience a rapid phase angle shift. In such cases, the phase displacement Δθ can be large
enough to pose challenges for the phase lock loop (PLL) to track the terminal voltage, cause control
instability within the inverter, such as the inner current control loop or the DC link control loop, and even
lead to tripping of the inverter due to the malfunction of the controls.
Since phase angle jumps are common occurrences on the BPS, this standard requires the IBR to be
designed and operated to Ride-through a minimum phase angle jump of 25 electrical degrees. This is a
typical value and aligns with the requirement in IEEE 2800-2022.
Some IBR equipment has PLL loss of synchronism protection, referring to a protective function that
operates when the angle displacement Δθ exceeds a threshold for a predetermined period of time (on the
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
4
order of a couple of milliseconds). Historically, this protection has been used by some inverter
manufacturers, especially for inverters in distribution systems. For the IBR connected to the BPS, this
protection function should be disabled. If it is enabled, the phase angle jump protection setting should be
configured such that the IBR shall only trip to prevent equipment damage.
Rationale for Requirement R2
In addition to having minimum voltage Ride-through capability specified in Requirement R1, all applicable
IBRs are also required to adhere to certain voltage Ride-through performance criteria during system
disturbances. Acceptable performance criteria depend on the operation region that an IBR is presently in
or when in transition from one operation region to another operation region. Requirement R2 includes
specific performance criteria and is needed to assure consistent IBR performance within and each
operation region in Attachment 1 and when in transition between regions.
R ationale for R equirem ent R 2.1
This subpart of Requirement R2 ensures that when the voltage at the high-side of the main power
transformer (MPT) recovers to the continuous operation region from either the mandatory operation
region or the permissive operation region, an IBR delivers the pre-disturbance level of Real Power or
available Real Power, whichever is less. Available Real Power allows for changes of facility Real Power
output attributed to factors such as weather patterns, change of wind, and change in irradiance, but not
changes attributed to IBR tripping in whole or part. This requires an IBR to exit the “High Voltage Ride
Through (HVRT)” or “Low Voltage Ridge Through (LVRT)” modes properly such that it does not cause
reduction in the Real Power when the high-side of MPT voltage recovers to within the continuous
operation region.
When the voltage at the high-side of the MPT is greater than 0.90 per-unit and less than 0.95 per-unit,
IBRs are expected to exit the LVRT mode and come back to “normal operating mode”. If an IBR has a
default total current limit of 1.0 per-unit, the apparent power production of an IBR will be limited below
1.0 per-unit (e.g., the per-unit value of IBR terminal voltage). In such case, the IBR needs to configure a
preference setting, either to maintain pre-disturbance Real Power or maximize the Reactive Power in
order to further help with voltage recovery, or according to requirements specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
R ationale for R equirem ent R 2.2
This subpart of Requirement R2 ensures that when the voltage at the high-side of the MPT is within the
mandatory operation region, IBRs inject or absorb reactive current proportional to the level of terminal
voltage deviations they measure. IBRs shall follow Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator specified certain magnitude of Reactive Power response to voltage
changes, if available.
By default, reactive current prioritization shall be configured unless Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator requires Real Power priority.
R ationale for R equirem ent R 2.3
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
5
This subpart of Requirement R2 ensures that when the voltage at the high-side of the MPT is within the
permissive operation region, IBRs continue to Ride-through, though they are briefly allowed to enter the
current block mode if necessary to avoid tripping off from the grid. The drafting team takes into
consideration the physical operational capability of the power electronics devices under such low voltage
conditions. However, the IBR facility shall restart current exchange in less than or equal to five cycles of
positive sequence voltage returning to the continuous operation region or mandatory operation region. If
the interconnecting entity has performance requirements that are more stringent than the standard, the
Generator Owner should follow the requirements set by the interconnecting entity.
R ationale for R equirem ent R 2.4
This subpart of Requirement R2 ensures when a fault is cleared on the transmission system, the voltage
regulators of connected IBRs must adjust the reactive current injection to restore the transmission system
voltage to the pre-disturbance voltage as defined by the automatic voltage regulator (AVR) setpoint. The
drafting team acknowledges that tuning of the AVR requires a balance between multiple competing
physical factors, e.g., rise time, overshoot, and transient stability. However, it is anticipated that IBR
controls will be tuned to allow for a stable post-disturbance voltage recovery without causing excessive
overshoot or undershoot of the setpoint. When such overshoots do occur, they must not exceed the
magnitude and duration of the applicable table given in Attachment 1. Furthermore, this standard
anticipates that control system tuning to prevent such over/under voltages will focus on the speed at
which the controller responds to setpoint changes rather than on the magnitude of the reactive current
response. For example, reductions in k-factor to prevent over/under voltages should only be considered
as a last resort.
R ationale for R equirem ent R 2.5
This subpart of Requirement R2 ensures that the IBR returns to effective pre-disturbance operation unless
otherwise specified or needed by the Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator.
Rationale for Requirement R3
The objective of Requirement R3 is to ensure that IBRs Ride -through frequency excursion events with
magnitude and time durations as defined in Attachment 2.
Grid frequency reflects the balance of system generation and load. A system event that causes a
generation/load imbalance will cause system frequency to deviate from nominal. The system may
experience an over-frequency event (in the case of more generation than load) or an under-frequency
event (in the case of less generation than load). Inertia resists the deviation from nominal frequency,
giving the operators additional time to rebalance generation and load. System inertia depends on the
amount of rotating mass connected to the system (such as the synchronous generators or motors). The
larger the system inertia, the slower the system frequency will deviate from the nominal value and the
lower the grid Rate Of Change Of Frequency (ROCOF), giving more time to try to rebalance generation and
load. Also, higher system inertia may minimize the risk of Cascading generation loss caused by the
operation of generator frequency protection.
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
6
A reduction in system inertia is an inevitable consequence of a power system transiting toward more IBR
and less synchronous generators. As discussed in the previous paragraph, less system inertia means the
frequency will deviate from the nominal value more quickly during a generation/load imbalance event
and will expose the system to a higher ROCOF. A wider frequency Ride-through capability for IBR may be
required to avoid the risk of widespread tripping. To reduce the risk of widespread IBR tripping during
frequency disturbances, and more generally to ensure the reliability of future grids with high IBR
penetration, the drafting team proposes a 6-second frequency Ride-through capability requirement for
frequencies in the ranges of 61.8Hz to 64Hz or 57.0Hz to 56.0Hz range. The proposed 6-second time
frame of the frequency Ride-through capability requirement is beyond the IEEE 2800 standard frequency
Ride-through requirement and beyond frequency Ride-through requirements for synchronous machines
under PRC-024.
IBRs lack the inertia and short circuit contributions of synchronous machines. To compensate for the lack
of inertia and short circuit contributions, they should have wider tolerances for frequency and voltage
excursions to meet the needs of future power systems with a higher percentage of IBR. Synchronous
resources are more sensitive to frequency deviations than IBR resources. All IBR resources (except for
type 3 wind turbines) interface to the grid through fast switching of power electronics devices. These
power electronic devices are much less sensitive to the transmission system frequency excursion than
non-hydraulic turbine synchronous resources (steam turbines and combustion turbines). In the case of
the non-hydraulic turbine synchronous resources, the turbine is usually considered to be more restrictive
than the generator in limiting IBR frequency Ride-through because of possible mechanical resonances in
the many stages of turbine blades. Off-nominal frequencies may bring blade vibrational frequencies closer
to a mechanical resonate frequency and cause damage due to the vibration stresses. However, inverterinterfaced-IBR does not share this vibrational failure mode. Therefore, IBR should be capable of riding
through the increased proposed 6-second frequency Ride-through requirement without risk of equipment
damage or need for frequency protection to operate.
Requirement R3 does not prescribe specific frequency protection settings for IBR equipment. IBR
frequency protection settings should only be set to protect the IBR from damage caused by operation at
off-nominal frequency. An IBR owner must ensure that the IBR frequency protection does not prevent an
IBR from meeting the R3 Ride-through requirement.
This standard requires that IBRs remain electrically connected and continue to exchange current during a
frequency excursion event in which the frequency remains within the must Ride-through zone according
to Attachment 3 and while the absolute ROCOF magnitude is less than or equal to 5 Hz/second. Some IBR
controllers and their ability to remain electrically connected and continue to exchange current with the
grid are sensitive to ROCOF during a frequency excursion event. If needed to maintain the stability of the
IBR or prevent equipment damage, the R3 requirement allows the IBR to trip for an absolute ROCOF
exceeding 5Hz/sec within the must Ride-through zone of Attachment 2. Failure to Ride-through due to
ROCOF exceeding 5Hz/sec shall only be allowed during a generator/load imbalance event that causes the
frequency to deviate from nominal.
Technical Rationale for Reliability Standard PRC-029-1
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7
To minimize the misoperation tripping of the IBR on the ROCOF setting, the rate of change of frequency
(ROCOF) must be calculated as the average rate of change over multiple calculated system frequencies for
some time greater than or equal to 0.1 seconds. The ROCOF calculation is not applicable during the fault
occurrence and clearance (i.e., protection should not trip due to any perceived ROCOF during the entire
disturbance and recovery period) and should not operate at the onset of a fault, during a fault, or at fault
clearance, i.e., it should be disabled during faults. The IBR shall Ride-through any system disturbance
while the voltage at the high-side of the main power transformer remains within the must Ride-through
zones as specified in Attachment 1. The ROCOF measurement should begin after fault clearance and is
only applicable for generation/load imbalance disturbances such as a system separation, an island
condition, or the loss of a large load or generator.
Rationale for Requirement R4
The objective of Requirement R4 is to ensure legacy IBR (IBR existing as of the enforcement date of PRC029-1) are able to obtain an exemption to the voltage Ride-through requirements if hardware
replacements or other costly upgrades would be necessary to comply with Requirements R1 or
Requirement R2. This provision allows such exemptions as long as such limitations are documented and
communicated to the Planning Coordinator, Transmission Planner, Reliability Coordinator, and
Transmission Operator of the respective footprints in which the IBR project is located. The Planning
Coordinator, Transmission Planner, Reliability Coordinator, and Transmission Operator will then need to
take the voltage Ride-through limitations into account in planning and operations.
Limitations must not be construed as complete exemptions from the applicable Attachment 1 table but
must be specific as to which voltage band(s) and associated duration(s) cannot be satisfied or specific as
to the number of cumulative voltage deviations within a ten-second time period that the equipment can
Ride-through if less than four. Limitation descriptions should identify the specific equipment and explain
the characteristic(s) of that equipment that prevent Ride-through. If any equipment limitation is removed
or otherwise corrected, it is likewise necessary to communicate to the Planning Coordinator, Transmission
Planner, Reliability Coordinator, and Transmission Operator of this.
FERC Order No. 901 states that this provision would be limited to exempting “certain registered IBRs from
voltage Ride-through performance requirements.” This is the reason that no similar provisions are
included for exemptions for frequency or ROCOF Ride-through requirements per R3.
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 2024
8
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1 – Frequency and Voltage Ride-Through Requirements for
Inverter-Based Generating Resources
General Rationale
The drafting team has created a new Reliability Standard (PRC‐029‐1) to address inverter‐based resource
(IBR) disturbance rRide‐through performance criteria. This proposal is a consequence of both the different
natures of synchronous and inverter‐based generation resources and several recent events exhibiting
significant IBR Rride‐through deficiencies. The proposed PRC‐029‐1 coincides with certain rRide‐through
requirements of IEEE 2800‐2022 but is structured to follow language from FERC Order No. 901, which
states that “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.”1
The lack of standardization of IBR technology (equipment/controller behavior) has created reliability
challenges associated with the interconnection of IBR facilities to the power grid. The nature of the fast
switching of power electronics of IBR generation and the electronic interface to the transmission system is
such that disturbance rRide‐through behavior is largely determined by manufacturer‐specific equipment
and controls system designs. These controls may be programmed but also have more restrictive limits on
current, both in magnitude and duration. IBR responses to grid disturbances are highly controlled and
managed by using fast switching of power electronics devices dependent upon manufacturer specific
control system design that can be programmed in many ways and with various and concurrent Rride‐
through performance objectives. Rather than attempting to restrict the myriad of control approaches,
protections, and settings, it is more straightforward to require rRide‐through during defined frequency
and voltage excursions.
In contrast to synchronous generation, the need for IBR Rride‐through requirements has been heightened
by recent events during which IBRs have not met PRC‐024‐3 frequency and voltage rRide‐through
expectations, often due to controls and protection only indirectly associated with the system voltage and
frequency excursions. In addition to Rride‐through, there is the question of what IBRs should be doing as
they Rride‐through. IBR responses to system disturbances can be beneficial or detrimental to both their
own Rride‐through and system reliability, often depending on adjustable control settings. Thus, it is
essential to set expectations on performance during Rride‐through as well as rRide‐through capability.
A further reason for proposing a separate IBR standard is that IBRs do not provide inertia or short circuit
contributions, unlike synchronous machines. The drafting team thinks that IBR should compensate for
their lack of inertia and short circuit contributions with wider tolerances for frequency and voltage
1 P 195, FERC Order No. 901; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019‐3157&optimized=false; October 17,
2023
RELIABILITY | RESILIENCE | SECURITY
excursions. This is the reason for the differences in the frequency and voltage tables and graphs between
the two PRC‐024‐4 and PRC‐029‐1 standards.
The proposed PRC‐029‐1 must be understood generally as an event‐based standard though it is also
required to provide evidence of the ability to rRide‐through disturbance events by means of dynamic
models and simulation results. Compliance with PRC‐029‐1 is determined chiefly though not exclusively
from IBR Rride‐through performance during transmission system events in the field. An IBR becomes
noncompliant with PRC‐029‐1 when an event in the field occurs that shows that one or more
requirements were not satisfied. This intent is clarified by Operations Assessment as the Time Horizon
designation of requirements R1‐R5.
FERC Order No. 901 Directives
PRC‐029‐1 is proposed in consideration of directives from FERC Order No. 901 that were assigned to the
Project 2020‐02 drafting team. The following directives were assigned to this drafting team for inclusion in
this Standards Project (paragraph numbers of the FERC Order are included for reference):
Paragraph 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.”
Paragraph 190: “The new or modified Reliability Standards must require registered IBRs to
continue to inject current and perform frequency support during a Bulk‐Power System
disturbance.”
Paragraph 190: “Any new or modified Reliability Standard must also require registered IBR
generator owners and operators to prohibit momentary cessation in the must ride‐through zone
during disturbances.”
Paragraph 190: “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.”
Paragraph 193: “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.”
Paragraph 193: “Further, we direct NERC to ensure that any such exemption would be applicable
for only existing equipment that is unable to meet voltage ride‐through 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.).”
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2
Paragraph 193: “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).”
Paragraph 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, we direct NERC to
develop new or modified Reliability Standards to mitigate the reliability impacts to the Bulk‐Power
System of such an exemption.”
Paragraph 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 pre‐disturbance output level
in a quick and stable manner after a Bulk‐Power System.”
Paragraph 209: “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.”
Paragraph 209: “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.”
Paragraph 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.”
Paragraph 226: “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 rule prior to
that date.” (pertains multiple projects)
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for assuring acceptable rRide‐through performance of IBR is either the
Generator Owner (GO) or, in the case of High‐voltage Direct Current (VSC‐HVDC) transmission facilities
that are dedicated connections for IBR inverter‐based resources to the BPS, the Transmission Owner (TO).
Technical Rationale for Reliability Standard PRC‐029‐1
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3
Facilities (4.2)
Applicability Facilities includes only those IBR that also meet NERC registration criteria. Language used
within PRC‐029‐1 applicability only refers to IBR as a whole plant/facility. Consistent with FERC Order
No. 901, IBR performance is based on the overall IBR plant and disturbance monitoring equipment
requirements established under the proposed PRC‐028‐1. Requirements within PRC‐029‐1 do not apply to
individual inverter units or measurements taken at individual inverter unit terminals.
Rationale for Requirement R1
The objective of Requirement R1 is to ensure that all applicable IBRs will Rride through grid voltage
disturbances consistent with the must Rride‐through zone and operation regions specified in Attachment
1. IBRs must be able to demonstrate rride‐through performance, that they remain electrically connected,
i.e., shall not trip, and continue to exchange current, i.e., shall not enter momentary cessation.
The drafting team determined that the definition of “must Rride‐through zones” and “operation regions”
should be consistent with those terms as used within IEEE 2800‐2022. Additionally, the team determined
that the voltage thresholds of each operation region should be based on measurements taken on the
high‐side of the main power transformer in PRC‐029‐1, also consistent with IEEE 2800‐2022.
Battery Energy Storage Systems (BESS) units also must comply with Requirement R1 in all operating
modes including charging, discharging, and idle (energized but not charging or discharging). A BESS in idle
mode must be capable of responding to system voltage and frequency excursions as it does in charging or
discharging modes.
Exceptions to Attachment 1 performance criteria are allowable when 1) an IBR needs to trip to clear a
fault within its zone of protection, and 2) voltage at the high‐side of the main power transformer goes
outside an accepted2) and a documented equipment limitation established in accordance withprevents
an IBR from riding through the disturbance as permitted under Requirement R4, 3) instantaneous positive
sequence voltage phase angle jumps more than 25 electrical degrees at the high‐side of the main power
transformer initiated by a non‐fault switching events occur on the transmission system, or 4) volts per Hz
(V/Hz) at the high‐side of the main power transformer exceed 1.1 per unit for longer than 45 seconds or
exceed 1.18 per unit for longer than 2 seconds.
When a grid disturbance occurs, such as a close‐in fault or a relatively large switching event, the grid
voltage may experience a rapid phase angle shift. In such cases, the phase displacement Δθ can be large
enough to pose challenges for the phase lock loop (PLL) to track the terminal voltage, cause control
instability within the inverter, such as the inner current control loop or the DC link control loop, and even
lead to tripping of the inverter due to the malfunction of the controls.
Since phase angle jumps are common occurrences on the BPS, this standard requires the IBR to be
designed and operated to ride‐through a minimum phase angle jump of 25 electrical degrees. This is a
typical value and aligns with the requirement in IEEE 2800 ‐2022.
Technical Rationale for Reliability Standard PRC‐029‐1
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4
Some IBR equipment has PLL loss of synchronism protection, referring to a protective function that
operates when the angle displacement Δθ exceeds a threshold for a predetermined period of time (on the
order of a couple of milliseconds). Historically, this protection has been used by some inverter
manufacturers, especially for inverters in distribution systems. For the IBR connected to the BPS, this
protection function should be disabled. If it is enabled, the phase angle jump protection setting should be
configured such that the IBR shall only trip to prevent equipment damage.
Rationale for Requirement R2
In addition to having minimum voltage rRide‐through capability specified in Requirement R1, all
applicable IBRs are also required to adhere to certain voltage rRide‐through performance criteria during
system disturbances. Acceptable performance criteria depend on the operation region that an IBR is
presently in or when in transition from one operation region to another operation region. Requirement
R2 includes specific performance criteria and is needed to assure consistent IBR performance within and
each operation region in Attachment 1 and when in transition between regions.
Rationale for Requirement R2.1
This subpart of Requirement R2 ensures, when the voltage at the high‐side of the main power
transformer (MPT) recovers to the Ccontinuous Ooperation Rregion from either the Mmandatory
Ooperation rRegion or the pPermissive Ooperation Rregion, an IBR is expected to deliver the pre‐
disturbance level of active Real pPower or available active Real pPower, whichever is less. Available Real
Power allows for changes of facility Real Power output attributed to factors such as weather patterns,
change of wind, and change in irradiance, but not changes attributed to IBR tripping in whole or part. This
requires an IBR to exit the “High Voltage Ride Through (HVRT)” or “Low Voltage Ridge Through (LVRT)”
modes properly such that it does not cause reduction in the active Real p{ower when the system already
recovers the voltage within the Ccontinuous Ooperation Rregion.
When the voltage at the high‐side of the MPT is greater than 0.9 per‐unit and less than 0.95 per‐unit, IBRs
are expected to exit the LVRT mode and come back to “normal operating mode”. If an IBR has a default
total current limit of 1.0 per‐unit, the apparent power production of an IBR will be limited to be below 1.0
per‐unit (e.g., the per‐unit value of IBR terminal voltage). In such case, IBR needs to configure a
preference setting, either to maintain pre‐disturbance active Real Ppower or maximize the rReactive
pPower in order to further help with voltage recovery, or according to requirements specified by the
Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
Rationale for Requirement R2.2
This subpart of Requirement R2 ensures when the voltage at the high‐side of the MPT is within the
Mmandatory oOperation Rregion, IBRs are expected to enter the HVRT and LVRT mode such that it will
inject or absorb reactive current proportional to the level of terminal voltage deviations it measures. IBR
shall follow Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator
specified certain magnitude of Rreactive Ppower response to voltage changes, if available.
By default, reactive current prioritization shall be configured unless Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator requires active Real pPower priority.
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Rationale for Requirement R2.3
This subpart of Requirement R2 ensures that when the voltage at the high‐side of the MPT is within the
permissive operation region, IBRs continue to Ride‐through, through they are briefly allowed to enter the
current block mode if necessary to avoid tripping off from the grid. The drafting team takes into
consideration the physical operational capability of the power electronics devices under such low voltage
conditions. However, the IBR facility shall restart current exchange in less than or equal to five cycles of
positive sequence voltage retraining to a continuous operation region or mandatory operation region. If
the interconnecting entity has performance requirements that are more stringent than the standard, the
Generator Owner should follow the requirements set by the interconnecting entity.
Rationale for Requirement R2.4
This subpart of Requirement R2 ensures when a fault is cleared on the transmission system, the voltage
regulators of connected IBRs must adjust the reactive current injection to restore the transmission system
voltage to the pre‐disturbance voltage as defined by the automatic voltage regulator (AVR) setpoint. The
drafting team acknowledges that tuning of the AVR requires a balance between multiple competing
physical factors, e.g., rise time, overshoot, and transient stability. However, it is anticipated that IBR
controls will be tuned to allow for a stable post‐disturbance voltage recovery without causing excessive
overshoot or undershoot of the setpoint. When such overshoots do occur, they must not exceed the
magnitude and duration of the applicable table given in Attachment 1. Furthermore, this standard
anticipates that control system tuning to prevent such over/under voltages will focus on the speed at
which the controller responds to setpoint changes rather than on the magnitude of the reactive current
response. For example, reductions in k‐factor to prevent over/under voltages should only be considered
as a last resort.
Rationale for Requirement R2.5
This subpart of Requirement R2 ensures that IBR returns to effective pre‐disturbance operation unless
otherwise specified or needed by the Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator.
Must Ride-through
Rationale for Requirement R3
The objective of Requirement R3 is to ensure that IBRs remain electrically connected, synchronized, and
exchanging current, that is, continuing to operate during a frequency excursion event.
Grid frequency reflects the balance of system generation and load. A system event that causes a
generation/load imbalance will cause system frequency to deviate from nominal. The system may
experience an over‐frequency event (in the case of more generation than load) or an under‐frequency
event (in the case of less generation than load). Inertia resists the deviation from nominal frequency,
giving the operators additional time to rebalance generation and load. System inertia depends on the
amount of rotating mass connected to the system (such as the synchronous generators or motors). The
larger the system inertia, the slower the system frequency will deviate from the nominal value and the
lower the grid Rate Of Change Of Frequency (ROCOF), giving more time to try to rebalance generation and
Technical Rationale for Reliability Standard PRC‐029‐1
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | June 2024
6
load. Also, higher system inertia may minimize the risk of Cascading generation loss caused by the
operation of generator frequency protection.
A reduction in system inertia is an inevitable consequence of a power system transiting toward more IBR
and less synchronous generators. As discussed in the previous paragraph, less system inertia means the
frequency will deviate from the nominal value more quickly during a generation/load imbalance event
and will expose the system to a higher ROCOF. A wider frequency ride‐through capability for IBR may be
required to avoid the risk of widespread tripping. To reduce the risk of widespread IBR tripping during
frequency disturbances, and more generally to ensure the reliability of future grids with high IBR
penetration, the drafting team proposes a 6‐second frequency Rride‐through capability requirement for
frequencies in the ranges of 61.8Hz to 64Hz or 57.0Hz to 56.0Hz range. The proposed 6‐second time
frame of the frequency Rride‐through capability requirement is beyond the IEEE 2800 standard frequency
ride‐through requirement and beyond frequency rRide‐through requirements for synchronous machines
under PRC‐024.
IBRs lack the inertia and short circuit contributions of synchronous machines. To compensate for the lack
of inertia and short circuit contributions, they should have wider tolerances for frequency and voltage
excursions to meet the needs of future power systems with a higher percentage of IBR. Synchronous
resources are more sensitive to frequency deviations than IBR resources. All IBR resources (except for
type 3 wind turbines) interface to the grid through fast switching of power electronics devices. These
power electronic devices are much less sensitive to the transmission system frequency excursion than
non‐hydraulic turbine synchronous resources (steam turbines and combustion turbines). In the case of
the non‐hydraulic turbine synchronous resources, the turbine is usually considered to be more restrictive
than the generator in limiting IBR frequency ride‐through because of possible mechanical resonances in
the many stages of turbine blades. Off‐nominal frequencies may bring blade vibrational frequencies closer
to a mechanical resonate frequency and cause damage due to the vibration stresses. However, inverter‐
interfaced‐IBR does not share this vibrational failure mode. Therefore, IBR should be capable of riding
through the increased proposed 6‐second frequency ride‐through requirement without risk of equipment
damage or need for frequency protection to operate.
Requirement R3 does not prescribe specific frequency protection settings for IBR equipment. IBR
frequency protection settings should only be set to protect the IBR from damage caused by operation at
off‐nominal frequency. An IBR owner must ensure that the IBR frequency protection does not prevent an
IBR from meeting the R3 ride‐through requirement.
This standard requires that IBRs remain electrically connected and continue to exchange current during a
frequency excursion event in which the frequency remains within the must Rride‐through zone according
to Attachment 3 and while the absolute ROCOF magnitude is less than or equal to 5 Hz/second. Some IBR
controllers and their ability to remain electrically connected and continue to exchange current with the
grid are sensitive to ROCOF during a frequency excursion event. If needed to maintain the stability of the
IBR or prevent equipment damage, the R3 requirement allows the IBR to trip for an absolute ROCOF
exceeding 5Hz/sec within the must Rride‐through zone as shown in Attachment 2. Failure to Rride‐
Technical Rationale for Reliability Standard PRC‐029‐1
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | June 2024
7
through due to ROCOF exceeding 5Hz/sec shall only be allowed during a generator/load imbalance event
that causes the frequency to deviate from nominal.
To minimize the misoperation tripping of the IBR on the ROCOF setting, the rate of change of frequency
(ROCOF) must be calculated as the average rate of change over multiple calculated system frequencies for
some time greater than or equal to 0.1 seconds. The ROCOF calculation is not applicable during the fault
occurrence and clearance (i.e., protection should not operate trip due to any perceived ROCOFat the
onset of a fault, during athe entire disturbance and recovery period) and should not operate at the onset
of a fault, during a fault, or at fault clearance, i.e., it should be disabled for faults. The IBR shall Rride‐
through any system disturbance while the voltage at the high ‐side of the main power transformer
remains within the must ride‐through zones as specified in Attachment 1.The ROCOF measure should
begin after fault clearance and is only applicable for generation/load imbalance disturbances such as a
system separation, an island condition, or the loss of a large load or generator Furthermore, to reduce the
risk of IBR tripping on ROCOF protection, ROCOF shall be calculated as the average rate of change for
multiple calculated system frequencies for some time greater than or equal to 0.1 seconds.
Rationale for Requirement R4
The objective of Requirement R4 is to ensure legacy IBR (IBR existing as of the enforcement date of PRC‐
029‐1) are able to obtain an exemption to the voltage rRide‐through requirements if hardware
replacements or other costly upgrades would be necessary to comply with Requirements R1 or
Requirement R2. This provision allows such exemptions as long as such limitations are documented and
communicated to the Planning Coordinator, Transmission Planner, and Reliability Coordinator, and
Transmission Operator of the respective footprints in which the IBR project is located. The Planning
Coordinator, Transmission Planner, and Reliability Coordinator, and Transmission Operator will then need
to take the voltage rRide‐through limitations into account in planning and operations.
Limitations must not be construed as complete exemptions from the applicable Attachment 1 table but
must be specific as to which voltage band(s) and associated duration(s) cannot be satisfied or specific as
to the number of cumulative voltage deviations within a ten‐second time period that the equipment can
ride‐through if less than four. Limitation descriptions should identify the specific equipment and explain
the characteristic(s) of that equipment that prevent ride‐through. If any equipment limitation is removed
or otherwise corrected, it is likewise necessary to communicate to the Planning Coordinator, Transmission
Planner, and Reliability Coordinator, and Transmission Operator of this.
FERC Order No. 901 states that this provision would be limited to exempting “certain registered IBRs from
voltage ride‐through performance requirements.” This is the reason that no similar provisions are
included for exemptions for frequency or rate‐of‐change‐of‐frequency (ROCOF) ride‐through
requirements per R3.
Technical Rationale for Reliability Standard PRC‐029‐1
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | June 2024
8
Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-029-1
This document provides the drafting team’s (DT’s) justification for assignment of violation risk factors (VRFs) and violation severity levels
(VSLs) for each requirement in PRC-029-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in the
Electric Reliability Organizations (ERO) Sanction Guidelines. The DT applied the following NERC criteria and FERC Guidelines when developing
the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Power System (BPS) instability, separation, or a cascading sequence
of failures, or could place the BPS at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning time
frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to BPS instability, separation, or a cascading sequence of failures, or could place the BPS at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the BPS, or the ability to effectively monitor and
control the BPS. However, violation of a medium risk requirement is unlikely to lead to BPS instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or restore
the BPS. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by
the preparations, to lead to BPS instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the BPS, or the ability to effectively monitor and control the BPS; or, a requirement that is administrative in nature and a
requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by
the preparations, be expected to adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or
restore the BPS.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the BPS. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the BPS:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
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2
Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
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3
NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the
requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for PRC-029-1, Requirement R1
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R1
Lower
The Generator Owner failed to
demonstrate the design capability
of each applicable IBR to
Ride-through in accordance with
Attachment 1, except for those
conditions identified in
Requirement R1.
Moderate
N/A
High
N/A
Severe
The Generator Owner failed to
demonstrate each applicable IBR
adhered to Ride-through
requirements in accordance with
Attachment 1, except for those
conditions identified in
Requirement R1.
VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
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VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
Definitions of VRFs
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R2
Lower
The Generator Owner failed to
demonstrate the design capability
of each applicable IBR to adhere to
performance requirements during
voltage excursions, as specified in
Requirement R2.
Moderate
N/A
High
N/A
Severe
The Generator Owner failed to
demonstrate each applicable IBR
adhered to performance
requirements during voltage
excursions, as specified in
Requirement R2.
VSL Justifications for PRC-029-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
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VSL Justifications for PRC-029-1, Requirement R2
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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VRF Justifications for PRC-029-1, Requirement R3
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is appropriate that if violated, it would be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R3
Lower
The Generator Owner IBR to
demonstrate the design capability
of each applicable IBR to
Ride-through in accordance with
Moderate
N/A
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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High
N/A
Severe
The Generator Owner IBR to
demonstrate each applicable IBR
adhered to Ride-through
requirements in accordance with
10
Attachment 2.
Attachment 2.
VSL Justifications for PRC-029-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R4
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R4
Lower
Moderate
High
Severe
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),
Reliability Coordinator(s), and CEA
more than 90 calendar days but
less than or equal to 120 calendar
days after the change to the
hardware.
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
120 calendar days but less than or
equal to 150 calendar days after
the change to the hardware.
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
150 calendar days but less than or
equal to 180 calendar days after
the change to the hardware.
The Generator Owner failed to
document complete information
for IBR identified with known
hardware limitations that prevent
the IBR from meeting voltage Ridethrough criteria as detailed in
Requirements R1 or R2.
OR
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 120 days but less than
or equal to 150 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 150 days but less than
or equal to 180 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
OR
The Generator Owner provided a
copy to the applicable entities as
detailed in Requirement R4.2 more
than 12 months but less than or
equal to 15 months after the
effective date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 90 days but less than or
equal to 120 days after receiving a
request for additional information
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
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OR
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),Reliability
Coordinator(s), and CEA more than
180 calendar days after the change
to the hardware.
OR
The Generator Owner failed to
provide a copy to the applicable
entities as detailed in Requirement
R4.2 within 24 months after the
effective date of Requirement R4.
OR
13
VSLs for PRC-029-1, Requirement R4
Lower
Moderate
High
by an entity listed in Requirement
R4.2.1.
Severe
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 180 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
VSL Justifications for PRC-029-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R4
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1
This document provides the drafting team’s (DT’s) justification for assignment of violation risk factors (VRFs) and violation severity levels
(VSLs) for each requirement in PRC‐029‐1. Each requirement is assigned a VRF and a VSL. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in the
Electric Reliability Organizations (ERO) Sanction Guidelines. The DT applied the following NERC criteria and FERC Guidelines when developing
the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Power System instability, separation, or a cascading sequence of
failures, or could place the Bulk‐Power System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Power System instability, separation, or a cascading sequence of failures, or could place the Bulk‐Power System at
an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk‐Power System, or the ability to effectively
monitor and control the Bulk‐Power System. However, violation of a medium risk requirement is unlikely to lead to Bulk‐ Power System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Power
System, or the ability to effectively monitor, control, or restore the Bulk Power System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Power System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk‐Power System, or the ability to effectively monitor and control the Bulk‐Power System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk‐Power
System, or the ability to effectively monitor, control, or restore the Bulk‐Power System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk‐Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the
requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non‐compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for PRC-029-1, Requirement R1
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride‐through system
disturbances. Failure to ride‐through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
Similar requirements in PRC‐024‐3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R1
Lower
The Generator Owner or
Transmission Owner failed to
demonstrate the design capability
of each applicable facility IBR to
Ride‐through in accordance with
Attachment 1, except for those
conditions identified in
Requirement R1.
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable facility
IBR adhered to Ride‐through
requirements in accordance with
Attachment 1, except for those
conditions identified in
Requirement R1.
VSL Justifications for PRC-029-1, Requirement R1
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
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VSL Justifications for PRC-029-1, Requirement R1
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride‐through system
disturbances. Failure to ride‐through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
Similar requirements in PRC‐024‐3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R2
Lower
The Generator Owner or
Transmission Owner failed to
demonstrate the design capability
of each applicable facility IBR to
adhere to performance
requirements during voltage
excursions, as specified in
Requirement R2.
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable facility
IBR adhered to performance
requirements during voltage
excursions, as specified in
Requirement R2.
VSL Justifications for PRC-029-1, Requirement R2
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
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VSL Justifications for PRC-029-1, Requirement R2
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R3
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R3
Lower
The Generator Owner or
Transmission Owner failed to
demonstrate the design capability
of each applicable facility IBR to
Ride‐through in accordance with
Attachment 2.
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to
demonstrate each applicable facility
IBR adhered to Ride‐through
requirements in accordance with
Attachment 2.
VSL Justifications for PRC-029-1, Requirement R3
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
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VSL Justifications for PRC-029-1, Requirement R3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R4
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the Bulk‐Power System.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R4
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner with a
previously communicated
equipment hardware limitation
that repairs or replaces the
documented limiting hardware
equipment but failed to document
and communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),
Reliability Coordinator(s), and
Regional EntityCEA more than 390
calendar days but less than or
equal to 6120 calendar days after
the change to the
hardwareequipment.
The Generator Owner or
Transmission Owner with a
previously communicated
hardware equipment limitation
that repairs or replaces the
documented limiting hardware
equipment but failed to document
and communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),
Reliability Coordinator(s), and
Regional EntityCEA more than 6120
calendar days but less than or
equal to 9150 calendar days after
the change to the
hardwareequipment.
The Generator Owner or
Transmission Owner with a
previously communicated
hardware equipment limitation
that repairs or replaces the
documented limiting hardware
equipment but failed to document
and communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s), and
Reliability Coordinator(s), and
Regional EntityCEA more than 9150
calendar days but less than or
equal to 1280 calendar days after
the change to the
hardwareequipment.
The Generator Owner or
Transmission Owner failed to
document complete information for
facilities IBR identified with known
hardware limitations that prevent
the facility IBR from meeting voltage
Ride‐through criteria as detailed in
Requirements R1 or R2.
OR
The Generator Owner or
Transmission Owner provided a
copy to the applicable entities as
detailed in Requirement R4.2 more
than 12 months but less than or
equal to 15 months after the
effective date of Requirement R4.
OR
The Generator Owner or
Transmission Owner with a
previously communicated hardware
equipment limitation that repairs or
replaces the documented limiting
OR
OR
hardware equipment but failed to
document and communicate the
The Generator Owner failed to
The Generator Owner failed to
change to its Planning
respond to the applicable entities
respond to the applicable entities
Coordinator(s), Transmission
as detailed in Requirement R4.2.1
as detailed in Requirement R4.2.1
Planner(s), Transmission
more than 120 days but less than
more than 150 days but less than
or equal to 150 days after receiving or equal to 180 days after receiving Operator(s), Reliability
Coordinator(s), and Regional
a request for additional
a request for additional
EntityCEA more than 1280 calendar
information by an entity listed in
information by an entity listed in
days after the change to the
Requirement R4.2.1.
Requirement R4.2.1.
hardwareequipment.
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OR
The Generator Owner or
Transmission Owner failed to
provide a copy to the applicable
entities as detailed in R4.2 within 24
months after the effective date of
R4.
OR
The Generator Owner failed to
respond to the applicable entities as
detailed in Requirement R4.2.1
more than 180 days after receiving a
request for additional information
by an entity listed in Requirement
R4.2.1.
VSL Justifications for PRC-029-1, Requirement R4
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
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VSL Justifications for PRC-029-1, Requirement R4
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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Standards Development Consideration of Directives from
FERC Order 901
June 2024
Background
The Federal Energy Regulatory Commission (FERC) issued Order No. 901 on October 19, 2023, which includes directives on new or modified NERC Reliability
Standard projects. Order No. 901 addresses a wide spectrum of reliability risks to the grid from the application of inverter-based resources (IBR); including
both utility scale and behind the-meter or distributed energy resources. Within the Order, are four milestones that include sets of directives to NERC. The
first milestone was achieved on January 17, 2024 as NERC filed its initial work plan to address all aspects of Order No. 901 throughout the next three years. 1
The filed work plan includes extensive detail on Standards Development approach and next steps to accomplish the suite of directives addressing IBR. The
work plan was intended to be an initial roadmap to guide development for each of the Reliability Standards Projects identified as a 901-related project.
This document includes specifics for how each directive assigned to Project 2020-02 Modifications to PRC-024 (Generator Ride-through) drafting team have
been addressed.
Resources
FERC Order No. 901 – Final Rule Reliability Standards to Address Inverter-Based Resources
NERC Mapping Document for FERC Order 901 Directives to Standards Development Projects, Draft SARs, and Pending SARs
1
INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901; 01/17/2024;
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%20901%20Work%20Plan_packaged%20%20public%20label.pdf
RELIABILITY | RESILIENCE | SECURITY
Index
Paragraph
Milestone
of Order
49
190
2
50
190
2
Directive Subpart Summary
“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 support
during a Bulk-Power System
disturbance.”
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
The new standard PRC-029-1 will require registered generator
owners of IBRs to both design and operate their IBR plants to ride
through voltage and frequency excursions within “must ridethrough zones” according to how these zones are defined in the
standard. The must ride-through zones are defined in terms of
voltage and frequency magnitude and time duration. Tripping of
IBR plants is permitted only outside of the defined must ridethrough zones. The voltage and frequency must ride-through
zones are based on IEEE 2800-2022 no-trip zones and are
established in view of experience with voltage and frequency
excursions in planning and operating criteria disturbances, underfrequency load shedding stages, reasonable and practical limits of
IBR voltage and frequency tolerances, PRC-024-3 voltage and
frequency relay setting graphs, and include adequate margins
against worst-case conditions that could be brought about during
system disturbances.
In association with the new PRC-029 standard, a definition of the
term ride-through is proposed for addition to the NERC Glossary of
Terms that essentially states that IBR facilities must remain
connected and continue to fulfill their established control and
regulation functions (which generally involve exchange of current)
in order to qualify as riding through system disturbances. Support
of frequency is predicated on, and to a large degree achieved by
the riding through of system disturbances.
Frequency regulation (or governing) is presently not a continentwide necessity and not a requirement on individual generating
2
Index
Paragraph
Milestone
of Order
51
190
2
52
190
2
53
193
2
Directive Subpart Summary
“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, postdisturbance ramp rates, phase
lock loop synchronization, and
other known causes of IBR
tripping or momentary
cessation.”
“Therefore, we direct NERC
through its standard
development process to
determine whether the new
or modified Reliability
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
plants/facilities in NERC standards. RTO/ISO requirements may
apply.
Momentary cessation, understood as inverter temporary current
blocking while still remaining connected, is restricted to only two
system conditions: 1) non-fault line switching caused voltage
phase angle jumps in excess of 25 degrees that could result in
tripping unless the inverter goes into current blocking, and 2)
while voltage at the plant-system interface is less than 0.10 per
unit during which time it may be difficult or impractical to
maintain current exchange.
IBR frequency and voltage ride through requirements are
established in the new PRC-029 standard as noted above. A
default post-disturbance ramp rate of 1.0 second is specified
unless a faster or slower rate is specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator to accommodate specific system postdisturbance recovery needs. Any Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator
specified ramp rate becomes the standard requirement. Tripping
due to phase lock loop loss of synchronism is specifically not
permitted within voltage and frequency must ride through zones.
Exemption from the voltage must ride-through zone requirement
of PRC-029-1 is permitted for IBR plants/facilities that are in
service at the enforcement date of the standard. The IBR
Generator Owner must document the need for an exemption and
the documentation must explain what hardware prevents the IBR
3
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
Standards should provide for a
limited and documented
exemption for certain
registered IBRs from voltage
ride through performance
requirements.”
54
193
2
“Further, we direct NERC to
ensure that any such
exemption would be
applicable for only existing
equipment that is unable to
meet voltage ride-through
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
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
from meeting the requirement and must be specific as to what
aspect of the voltage must ride-through zone cannot be met. The
Compliance Enforcement Authority checks that all aspects of the
documentation specified in the standard have been provided by
the GO and the GO is required to supply further information on
the need for and the nature of the exemption if requested by the
Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator. The implementation plan
provides a 12-month time window for exemption requests to be
submitted following the enforcement date. Following the 12month window, further exemption requests will either not be
accepted or could be considered an admission of non-compliance.
The exemption provision of PRC-029-1 is available only for IBR
plants/facilities that are in service at the enforcement date as
noted above. The exemption provision also stipulates that once
the plant/facility hardware causing the inability to comply with the
voltage must ride-through requirement is replaced, the exemption
is withdrawn (“no longer applies”).
4
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
through, phase lock loop,
ramp rates, etc.).”
55
193
2
“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).”
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
The exemption provision of PRC-029-1 requires an IBR Generator
Owner to supply its exemption request documentation to its
Transmission Planner, Planning Coordinator, Reliability
Coordinator, and Transmission Operator within the 12-month
window following the enforcement date as noted above.
5
Index
Paragraph
Milestone
of Order
56
199
2
57
208
2
Directive Subpart Summary
“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, we
direct NERC to develop new or
modified Reliability Standards
to mitigate the reliability
impacts to the Bulk-Power
System of such an
exemption.”
“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
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
Mitigation of the reliability impacts of voltage must ride-through
exemptions are existing NERC standard responsibilities of
Transmission Planners, Planning Coordinators, Reliability
Coordinators, and Transmission Operators under TPL, IRO, TOP,
and other standards. These entities may need to restrict the
operation of exempted IBRs where and when their tripping may
result in detrimental reliability impacts.
As indicated above, a default post-disturbance ramp rate of 1.0
second is specified unless a faster or slower rate is specified by the
Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator to accommodate specific
system post-disturbance recovery needs. Any Transmission
Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator specified ramp rate becomes the standard
requirement.
6
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
programmed to artificially
interfere with the resource
returning to a pre-disturbance
output level in a quick and
stable manner after a BulkPower System.”
59
209
2
60
209
2
“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-
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Description of How This Directive has Been Addressed
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Phase lock loop loss of synchronism is not allowed as a cause of
tripping while voltage remains within the must ride-through zone
unless there are phase jumps more than 25 degrees caused by
non-fault switching events. A footnote under R1 also specifically
states that phase lock loop loss of synchronism as not a
permissible condition for tripping while voltage remains within the
must ride-through zone.
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
As indicated above, tripping due to phase lock loop loss of
synchronism is specifically not permitted within voltage and
frequency must ride-through zones. The requirement to return to
pre-disturbance power also includes a provision for return to
“available active power" to allow for “changes of facility
active power output attributed to factors such as weather
patterns, change of wind, and change in irradiance,” but
“changes of facility active power attributed to IBR tripping in
7
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
Power System at predisturbance levels during a
disturbance, consistent with
the IBR Interconnection
Requirements Guideline and
Canyon 2 Fire Event Report
recommendations.”
61
209
2
63A
226
2
“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.”
“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
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Description of How This Directive has Been Addressed
whole or part” are not permitted. Injecting current at predisturbance levels during a disturbance is not always
practical or desirable. PRC-029-1 R2 specifies IBR required
active and reactive power performance during voltage
disturbances.
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
IBRs are non-synchronous but can exhibit forms of instability other
than loss of synchronism. System stability is a shared responsibility
of Transmission Planners, Planning Coordinators, Reliability
Coordinators, and Transmission Operators. IBR generation levels
may need to be restricted by these entities to maintain system
stability including IBR stability.
Each of the
identified
Reliability
Standards Projects
in Milestone 2 will
include
implementation
plans that assure
The PRC-029-1 implementation is a staggered implementation
beginning twelve months following governmental approval with
enforcement of all provisions within the twelve months following
approval except as necessary to coordinate with the PRC-028-1
implementation plan that extends to 2030.
8
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
sequentially stagger the
effective and enforceable
dates to ensure an orderly
industry transition for
complying with the IBR
directives in this final rule
prior to that date.”
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
all new or
modified
Reliability
Standards are
effective and
enforceable
before 2030.
Description of How This Directive has Been Addressed
9
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough) | PRC-024-4 and PRC-029-1
Formal Comment Period Open through August 12, 2024
Now Available
A formal comment period for PRC-029-1 - Frequency and Voltage Ride-through Requirements for
Inverter-based Resources, is open through 8 p.m. Eastern, Monday, August 12, 2024.
This will be the last opportunity for NERC to ballot these projects through traditional mechanisms. The
Board may take requisite action during the August 2024 Board of Trustees meeting to ensure
directives are met.
The Standards Committee approved waivers to the Standard Processes Manual at their December 2023
meeting. These waivers were sought by NERC Standards staff for reduced formal comment and ballot
periods. This will assist the drafting teams in expediting the standards development process due to firm
timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket No. RM22-12-000
on October 19, 2023.
To assist industry in this upcoming comment and ballot period, NERC has released a Milestone 2
Summary that provides high-level overview of the current state of the associated projects and their
interrelationships. The standard drafting team’s considerations of the responses received from the
previous comment period are reflected in this draft of the standard.
Note: PRC-024-4 passed the recent additional ballot (conducted June 28 – July 8, 2024). The drafting
team will be moving this standard to a final ballot when the PRC-029-1 ballots open (August 2-12, 2024)
as only non-substantive revision(s) were made.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
RELIABILITY | RESILIENCE | SECURITY
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
Additional ballots for the standard and implementation plan, as well as the non-binding poll of the
associated Violation Risk Factors and Violation Severity Levels will be conducted August 2-12, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Manager of Standards Development, Jamie Calderon (via email)
or at 404-960-0568 Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
(Generator Ride-through) observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Formal Comment Period Open
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 22, 2024
2
Comment Report
Project Name:
2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-029-1
Comment Period Start Date:
7/22/2024
Comment Period End Date:
8/12/2024
Associated Ballots:
2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan AB 3 OT
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 AB 3 ST
There were 70 sets of responses, including comments from approximately 159 different people from approximately 112 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
Questions
1. Do you agree with the proposed definition of Ride-through? If not, please state what revision would be acceptable and why.
2. Do you agree with the changes made in this draft of PRC-029-1?
3. Provide any additional comments for the Drafting Team to consider, if desired.
Organization
Name
MRO
Name
Segment(s)
Anna Martinson 1,2,3,4,5,6
Region
MRO
Group Name
MRO Group
Group Member
Name
Shonda McCain
Group
Member
Organization
Group
Member
Segment(s)
Omaha Public 1,3,5,6
Power District
(OPPD)
Group Member
Region
MRO
Michael Brytowski Great River
Energy
1,3,5,6
MRO
Jamison Cawley
Nebraska
Public Power
District
1,3,5
MRO
Jay Sethi
Manitoba
Hydro (MH)
1,3,5,6
MRO
Husam Al-Hadidi
Manitoba
1,3,5,6
Hydro (System
Preformance)
MRO
Kimberly Bentley
Western Area 1,6
Power
Adminstration
MRO
Jaimin Patal
Saskatchewan 1
Power
Coporation
(SPC)
MRO
George Brown
Pattern
Operators LP
5
MRO
Larry Heckert
Alliant Energy 4
(ALTE)
MRO
Terry Harbour
MidAmerican
Energy
Company
(MEC)
1,3
MRO
Dane Rogers
Oklahoma
Gas and
Electric
(OG&E)
1,3,5,6
MRO
Seth Shoemaker
Muscatine
Power &
Water
1,3,5,6
MRO
Michael Ayotte
ITC Holdings
1
MRO
Andrew Coffelt
Board of
1,3,5,6
Public UtilitiesKansas (BPU)
MRO
Peter Brown
Invenergy
MRO
Angela Wheat
Southwestern 1
Power
Administration
5,6
MRO
MRO
Anna Martinson 1,2,3,4,5,6
MRO
Southwest
Power Pool,
Inc. (RTO)
Charles Yeung 2
MRO,NPCC,R SRC 2024
F,SERC,SPP
RE,Texas
RE,WECC
WEC Energy
Group, Inc.
ACES Power
Marketing
FirstEnergy FirstEnergy
Corporation
Christine Kane
Jodirah Green
Mark Garza
3
1,3,4,5,6
4
MRO Group
WEC Energy
Group
MRO,NPCC,R ACES
F,SERC,Texas Collaborators
RE,WECC
FE Voter
Bobbi Welch
Midcontinent
ISO, Inc.
2
MRO
Charles Yeung
SPP
2
MRO
Ali Miremadi
CAISO
1
WECC
Bobbi Welch
Midcontinent
ISO, Inc.
2
MRO
Greg Campoli
NYISO
1
NPCC
Elizabeth Davis
PJM
2
RF
Matt Goldberg
ISO New
England
2
NPCC
Christine Kane
WEC Energy
Group
3
RF
Matthew Beilfuss
WEC Energy
Group, Inc.
4
RF
Clarice Zellmer
WEC Energy
Group, Inc.
5
RF
David Boeshaar
WEC Energy
Group, Inc.
6
RF
Bob Soloman
Hoosier
Energy
Electric
Cooperative
1
RF
Kris Carper
Arizona
1
Electric Power
Cooperative,
Inc.
WECC
Jason Procuniar
Buckeye
Power, Inc.
4
RF
Jolly Hayden
East Texas
Electric
Cooperative,
Inc.
NA - Not
Applicable
Texas RE
Scott Brame
North Carolina 3,4,5
Electric
Membership
Corporation
SERC
Nick Fogleman
Prairie Power, 1,3
Inc.
SERC
Julie Severino
FirstEnergy FirstEnergy
Corporation
1
RF
Aaron
Ghodooshim
FirstEnergy FirstEnergy
Corporation
3
RF
FirstEnergy FirstEnergy
Corporation
Southern
Company Southern
Company
Services, Inc.
Black Hills
Corporation
Northeast
Power
Coordinating
Council
Mark Garza
4
Pamela Hunter 1,3,5,6
FE Voter
SERC
Rachel Schuldt 6
Ruida Shu
1,2,3,4,5,6,7,8, NPCC
9,10
Southern
Company
Black Hills
Corporation All Segments
NPCC RSC
Robert Loy
FirstEnergy FirstEnergy
Solutions
5
RF
Mark Garza
FirstEnergyFirstEnergy
1,3,4,5,6
RF
Stacey Sheehan
FirstEnergy FirstEnergy
Corporation
6
RF
Matt Carden
Southern
Company Southern
Company
Services, Inc.
1
SERC
Joel Dembowski
Southern
Company Alabama
Power
Company
3
SERC
Ron Carlsen
Southern
Company Southern
Company
Generation
6
SERC
Leslie Burke
Southern
Company Southern
Company
Generation
5
SERC
Micah Runner
Black Hills
Corporation
1
WECC
Josh Combs
Black Hills
Corporation
3
WECC
Rachel Schuldt
Black Hills
Corporation
6
WECC
Carly Miller
Black Hills
Corporation
5
WECC
Sheila Suurmeier
Black Hills
Corporation
5
WECC
Gerry Dunbar
Northeast
Power
Coordinating
Council
10
NPCC
Deidre Altobell
Con Edison
1
NPCC
Michele Tondalo
United
Illuminating
Co.
1
NPCC
Stephanie UllahMazzuca
Orange and
Rockland
1
NPCC
Northeast
Power
Coordinating
Council
Ruida Shu
1,2,3,4,5,6,7,8, NPCC
9,10
NPCC RSC
Michael Ridolfino
Central
1
Hudson Gas &
Electric Corp.
NPCC
Randy Buswell
Vermont
1
Electric Power
Company
NPCC
James Grant
NYISO
2
NPCC
Dermot Smyth
Con Ed Consolidated
Edison Co. of
New York
1
NPCC
David Burke
Orange and
Rockland
3
NPCC
Peter Yost
Con Ed Consolidated
Edison Co. of
New York
3
NPCC
Salvatore
Spagnolo
New York
Power
Authority
1
NPCC
Sean Bodkin
Dominion Dominion
Resources,
Inc.
6
NPCC
David Kwan
Ontario Power 4
Generation
NPCC
Silvia Mitchell
NextEra
1
Energy Florida Power
and Light Co.
NPCC
Sean Cavote
PSEG
4
NPCC
Jason Chandler
Con Edison
5
NPCC
Tracy MacNicoll
Utility Services 5
NPCC
Shivaz Chopra
New York
Power
Authority
6
NPCC
Vijay Puran
New York
6
State
Department of
Public Service
NPCC
David Kiguel
Independent
7
NPCC
Joel Charlebois
AESI
7
NPCC
Joshua London
Eversource
Energy
1
NPCC
Jeffrey Streifling
NB Power
Corporation
1,4,10
NPCC
Northeast
Power
Coordinating
Council
Dominion Dominion
Resources,
Inc.
Ruida Shu
Sean Bodkin
Western
Electricity
Coordinating
Council
Steven
Rueckert
Tim Kelley
Tim Kelley
1,2,3,4,5,6,7,8, NPCC
9,10
6
NPCC RSC
Dominion
10
WECC
WECC
SMUD and
BANC
Joel Charlebois
AESI
7
NPCC
John Hastings
National Grid
1
NPCC
Erin Wilson
NB Power
1
NPCC
James Grant
NYISO
2
NPCC
Michael
Couchesne
ISO-NE
2
NPCC
Kurtis Chong
IESO
2
NPCC
Michele Pagano
Con Edison
4
NPCC
Bendong Sun
Bruce Power
4
NPCC
Carvers Powers
Utility Services 5
NPCC
Wes Yeomans
NYSRC
7
NPCC
Victoria Crider
Dominion
Energy
3
NA - Not
Applicable
Sean Bodkin
Dominion
Energy
6
NA - Not
Applicable
Steven Belle
Dominion
Energy
1
NA - Not
Applicable
Barbara Marion
Dominion
Energy
5
NA - Not
Applicable
Steve Rueckert
WECC
10
WECC
Curtis Crews
WECC
10
WECC
Nicole Looney
Sacramento
Municipal
Utility District
3
WECC
Charles Norton
Sacramento
Municipal
Utility District
6
WECC
Wei Shao
Sacramento
Municipal
Utility District
1
WECC
Foung Mua
Sacramento
Municipal
Utility District
4
WECC
Nicole Goi
Sacramento
Municipal
Utility District
5
WECC
Kevin Smith
Balancing
Authority of
Northern
California
1
WECC
1. Do you agree with the proposed definition of Ride-through? If not, please state what revision would be acceptable and why.
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
No
Document Name
Comment
Black Hills Corporation supports the comments provided by the NAGF which state: a. Recommend removing the word “entire” and the phase “in its
entirety” from the proposed definition; b. adding the following revised language”…and continuing to operate through System Disturbances as defined in
the applicable Reliaiblity Standards.”
Likes
0
Dislikes
0
Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
No
Document Name
Comment
Duke Energy agrees with and supports the following NAGF comment:
The NAGF does not agree with the proposed definition of Ride-through and provides the following recommendations for consideration:
a.
Recommend removing the word “entire” and the phrase “in its entirety” from the proposed definition.
b.
Recommend adding the following revised language “…and continuing to operate through System Disturbances as defined in the applicable
Reliability Standards.”
Likes
0
Dislikes
0
Response
Robert Follini - Avista - Avista Corporation - 3
Answer
Document Name
Comment
See EEi comments
No
Likes
0
Dislikes
0
Response
Brian Van Gheem - Radian Generation - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
1.
We believe the addition of “in its entirety” is ambiguous and misplaced within the proposed definition. We propose the phrase should be moved to
the end to imply the entire time duration of a Disturbance, from the start of the Disturbance to its return to pre-disturbance conditions.
2.
We believe the addition of the term “System” should be removed from the definition. According to the NERC Glossary of Terms, the term is
defined as “a combination of generation, transmission, and distribution components.” This proposed Reliability Standard only applies to
Generator Owners, an entity that would not possess transmission and distribution asset components.
3.
We believe the reference to the term “Disturbance” within the definition is too vague by itself. The proposed title of this Reliability Standard is
“Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources.” The proposed purpose of this Reliability Standard is “to
ensure that [Inverter‐Based Resources] IBRs Ride-through to support the Bulk Power System (BPS) during and after defined frequency and
voltage excursions.” Both imply any definition used in reference to this Reliability Standard should be narrowed to unplanned Frequency and
Voltage events that produce abnormal system conditions or deviations to the electric system, as derived from term’s definition listed within the
NERC Glossary of Terms. Therefore, we propose ending the “Ride‐through” definition with the phrase “through the duration of a frequency or
voltage Disturbance in its entirety, from its start to the return to pre-disturbance conditions.”
Likes
0
Dislikes
0
Response
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF does not agree with the proposed definition of Ride-through and provides the following recommendations for consideration:
a. Recommend removing the word “entire” and the phrase “in its entirety” from the proposed definition.
b. Recommend adding the following revised language “…and continuing to operate through System Disturbances as defined in the applicable
Reliability Standards.”
Likes
0
Dislikes
Response
0
Alison MacKellar - Constellation - 5
Answer
No
Document Name
Comment
Constellation aligns with NAGF comments. Legacy inverters will not be able to ride through voltage and frequency events. It’s important to include
exemption for legacy inverters.
Alison Mackellar on behalf of Constellation Segments 5 and 6
Likes
0
Dislikes
0
Response
Megan Melham - Decatur Energy Center LLC - 5
Answer
No
Document Name
Comment
Capital Power supports the NAGF's comments:
The NAGF does not agree with the proposed definition of Ride-through and provides the following recommendations for consideration:
a. Recommend removing the word “entire” and the phrase “in its entirety” from the proposed definition.
b. Recommend adding the following revised language “…and continuing to operate through System Disturbances as defined in the applicable Reliability
Standards.”
Likes
0
Dislikes
0
Response
Richard Vendetti - NextEra Energy - 5
Answer
No
Document Name
Comment
NextEra believes that the definition of ride-through is too broad and does not directly tie back to voltage or frequency requirements. The word “entire”
leaves too much room for interpretation of single IBR unit driving an unnecessary investigation.
Likes
0
Dislikes
0
Response
Kimberly Turco - Constellation - 6
Answer
No
Document Name
Comment
Constellation aligns with NAGF comments. Legacy inverters will not be able to ride through voltage and frequency events. It’s important to include
exemption for legacy inverters.
Kimberly Turco on behalf of Constellation Energy Segments 5 and 6.
Likes
0
Dislikes
0
Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
No
Document Name
Comment
Minnesota Power (hereafter MP) agrees with EEI that the “ride-through” definition was clearer as proposed in IEEE 2800-2022.
Likes
0
Dislikes
0
Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
No
LG&E/KU agrees with EEI; there is no reason to deviate from the definition included in IEEE Std 2800-2022 and IEEE Std 1547-2018: “Ability to
withstand voltage or frequency disturbances inside defined limits and to continue operating as specified.” This definition makes it more clear that there
are “limits” to Ride-through. The definition proposed by the DT implies that any tripping is failed Ride-through, even if the trip occurs for a condition
where it is acceptable. Include the IEEE definition verbatim, there is no need for modification.
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Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
No
Document Name
Comment
"Please see EEI Comments"
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0
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0
Response
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Comment
WEC Energy Group supports the comments of the NAGF for Question 1.
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0
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Carver Powers - Utility Services, Inc. - 4
Answer
Document Name
Comment
No
Request clarification on the meaning of “in its entirety” and its intended purpose. Its inclusion adds confusion as the beginning of the definition already
states “the entire plant/facility”. Does “in its entirety” apply to the entire facility, or the entire disturbance event?
Recommend “Ride-through: The entire plant/facility remaining connected to the Bulk Power System and continuing to operate through System
Disturbances.”
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0
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
No
Document Name
Comment
NIPSCO believes that the definition of ride-through is too broad and does not directly tie back to voltage or frequency requirements. The word “entire”
leaves too much room for interpretation of single IBR unit driving an unnecessary investigation.
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0
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0
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Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
B.
Ride-through definition
·
Consider adopting definition from IEEE 2800, which is from IEEE 1547, and well understood by the industry.
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Colin Chilcoat - Invenergy LLC - 6
Answer
Document Name
No
Comment
Invenergy recommends removing “entire” and “in its entirety” from the proposed definition. As written, the definition attempts to prescribe an
unreasonable interpretation of what ride-through should be from a system reliability perspective.
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Rhonda Jones - Invenergy LLC - 5
Answer
No
Document Name
Comment
Invenergy recommends removing “entire” and “in its entirety” from the proposed definition. As written, the definition attempts to prescribe an
unreasonable interpretation of what ride-through should be from a system reliability perspective.
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0
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George E Brown - Pattern Operators LP - 5
Answer
No
Document Name
Comment
Pattern Energy does not believe it is necessary to add a glossary term for Ride-Through. Ride-through is an operational requirement that is defined by a
set of magintudes and should remain defined within the requirements of the NERC Relaibility Standards, as traditionaly done.
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0
Response
Srinivas Kappagantula - Arevon Energy - 5
Answer
Document Name
Comment
No
Please refer to NAGF comments.
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0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2
Answer
No
Document Name
Comment
MISO supports the comments of the ISO/RTO Council (IRC) Standards Review Committee (SRC).
In addition, we believe it is important to get the wording of the Ride-through definition accurate and clear. If the language is not clear (as to what is
allowed/disallowed), it will likely lead to future disagreements.
One possible solution is to add the words “as specified” to the Ride-through definition to more explicitly tie the definition to the requirements under the
proposed PRC-029 standard as shown below.
Ride‐through: The entire plant/facility remaining connected to the Bulk Power System, and continuing in its entirety to operate as specified through
the time‐frame of System Disturbances.
This is only one possible approach to better capture the intent of the standard as described in the below excerpt from the PRC-029-1 Technical
Rationale, Rational for Requirement R3 (page 6) which references the need to remain synchronized, an important aspect to specify:
“The objective of Requirement R3 is to ensure that IBRs remain electrically connected, synchronized, and exchanging current, that is, continuing to
operate during a frequency excursion event.”
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0
Response
Jennifer Neville - Western Area Power Administration - 1,6
Answer
No
Document Name
Comment
Support MRO NSRF comments
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0
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Response
0
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Document Name
Comment
ERCOT joins the comments submitted by the ISO/RTO Council (IRC) Standards Review Committee (SRC) and adopts them as its own. In addition,
ERCOT notes that revising the definition of the term “Ride-through” to recognize that the continued operation associated with ride-through needs to be
maintained not just through the Disturbance but all the way through recovery to a new operating point would result in a clearer definition that better
aligns with PRC-030, which provides that IBR unit losses (partial trips) are not allowed.
ERCOT supports the alternative definition of Ride-through that the SRC proposed, and ERCOT would also support revising that definition to read as
follows: “Ride-through: The entire plant/facility (including its dispersed power producing inverters) remaining connected to the electric system and
continuing in its entirety to operate in a manner that supports grid reliability through a System Disturbance, including the period of recovery back to a
normal operating condition.”
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0
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0
Response
Kyle Thomas - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
The definition of ride-through should be updated as follows: “The entire plant/facility remaining connected to the Bulk Power System and contininuing in
its entirety to operate as specified through System Disturbances inside defined limits.
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0
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0
Response
Brian Lindsey - Entergy - 1
Answer
Document Name
Comment
No Comment
Yes
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0
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0
Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Yes
Document Name
Comment
FirstEnergy has no objections to the proposed definition of Ride-through definition.
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0
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0
Response
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Yes
Document Name
Comment
None
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0
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0
Response
Patricia Lynch - NRG - NRG Energy, Inc. - 5
Answer
Yes
Document Name
Comment
NRG Energy Inc is in support of the comments made by EPSA.
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0
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Response
0
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Yes
Document Name
Comment
See EEI Comments
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0
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0
Response
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
EEI does not oppose the proposed definition of Ride-through.
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0
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0
Response
Nick Leathers - Ameren - Ameren Services - 3 - SERC
Answer
Yes
Document Name
Comment
Ameren does not have any additional comments for consideration by the drafting team.
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0
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0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Yes
Southern Company suggests using a different word or phrase for …“entire” plant/facility… to indicate that the expectation is that no equipment should
drop out of service during the disturbance and remain connected throughout the disturbance. The use of the word “entire” could mean all plant
equipment, including that which is already out of service for other reasons.
Suggested wording:
“The plant/facility shall remain connected and in service, maintaining the pre-distubance equipment configuration in operation, throughout the entirety of
the system disturbance and recovery.”
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0
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0
Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Yes
Document Name
Comment
While WECC voted Affirmative, WECC suggests the DT emphasize the nature of the definition may not allow a single turbine or solar array to be lost in
a System Disturbance (equates to failed “Ride-through” with loss).
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0
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0
Response
Ayslynn Mcavoy - Arkansas Electric Cooperative Corporation - 3
Answer
Yes
Document Name
Comment
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0
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0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Yes
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0
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0
Response
Thomas Foltz - AEP - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Bruce Walkup - Arkansas Electric Cooperative Corporation - 6
Answer
Yes
Document Name
Comment
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0
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0
Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
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0
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0
Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
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0
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0
Response
David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
Yes
Document Name
Comment
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0
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0
Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
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0
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Response
0
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Yes
Document Name
Comment
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0
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0
Response
Casey Jones - Berkshire Hathaway - NV Energy - 5 - WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Yes
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0
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0
Response
Adam Burlock - Adam Burlock On Behalf of: Ashley Scheelar, TransAlta Corporation, 5; - Adam Burlock
Answer
Yes
Document Name
Comment
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0
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0
Response
Ruchi Shah - AES - AES Corporation - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Yes
Document Name
Comment
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0
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0
Response
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Yes
Document Name
Comment
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0
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0
Response
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer
Yes
Document Name
Comment
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0
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0
Response
Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
Yes
Document Name
Comment
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0
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0
Response
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer
Yes
Document Name
Comment
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0
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Response
0
Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Mike Magruder - Avista - Avista Corporation - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Yes
Document Name
Comment
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0
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0
Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Yes
Document Name
Comment
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0
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0
Response
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Martin Sidor - NRG - NRG Energy, Inc. - 6
Answer
Document Name
Comment
NRG agrees with and refers the SDT to the EPSA comments.
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0
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0
Response
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC,Texas RE,NPCC,SERC,RF, Group Name SRC 2024
Answer
Document Name
Comment
In the proposed definition of “Ride-through”, the ISO/RTO Council (IRC) Standards Review Committee (SRC) believes that the requirement that a facility
continue “to operate” is inadequate; the definition needs to require the facility to maintain performance that is beneficial (or at the very least, not
detrimental) to overall grid reliability.
It is preferable if the ride-through definition referred to the electric system instead of the BPS to be consistent with the IBR definition.
Finally, the concept of ride-through needs to recognize that the continued operation associated with ride-through needs to be maintained not just
through the Disturbance but all the way through recovery to a new operating point. It is not clear that the existing Disturbance definition includes the
recovery period.
To address these concerns, the ride-through definition could be revised to read as follows:
“Ride-through: The entire plant/facility remaining connected to the electric system and continuing in its entirety to operate in a manner that supports grid
reliability through a System Disturbance, including the period of recovery back to a normal operating condition.”
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Marty Hostler - Northern California Power Agency - 3,4,5,6
Answer
Document Name
Comment
NCPA is not registered to vote on this item and thus is not opposing it or FERC Order 901.
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0
2. Do you agree with the changes made in this draft of PRC-029-1?
Jennifer Neville - Western Area Power Administration - 1,6
Answer
No
Document Name
Comment
Support MRO NSRF comments
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0
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0
Response
Marty Hostler - Northern California Power Agency - 3,4,5,6
Answer
No
Document Name
Comment
We don't know if this proposal is going to improve reliability or the extent of reliability improvement, if any. The SDT has not shown us tangible relability
improvement indices that support the modifications made. Considering this standard has been changed several times over the last few years we are
skeptical that changes made will improve reliability. However, we do not oppose the proposal.
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0
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0
Response
Srinivas Kappagantula - Arevon Energy - 5
Answer
No
Document Name
Comment
Please see SEIA and NAGF comments on these standards. Lack of exemptions for frequency ride through requirements especially for older legacy IBR
facilities is critically important as some of these plants may not be able to comply with this standard.
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0
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
No
Document Name
Comment
AEPC signed on to ACES comments:
It is the opinion of ACES that the definition of what constitutes an IBR should be consistent across the industry. The Project 2020-02 SDT has been
working diligently towards this goal and we do not believe that an individual standard should deviate from their approach. Thus we recommend removing
the phrase “The Elements associated with” from section 4.2 and modifying this section as follows:
4.2. Facilities:
4.2.1. Bulk Electric System (BES) IBRs; and
4.2.2. Non-BES IBRs that either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system
designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
R1. ACES believes that phrase “and is initiated by a non-fault switching event on the transmission system” should be struck from the 3rd bullet point of
Requirement R1. It is our opinion that the GO will likely be unable to differentiate between an event initiated by a fault or an event initiated by a “nonfault switching event” on the Transmission system. In short, Transmission switching events are outside the purview of the GO.
R3/R4. ACES has grave concerns with the lack of any exceptions to Requirement R3 for existing IBRs. It is our opinion that Requirements R3 and R4
should be modified to include an exception for an IBR that is in-service by the effective date of PRC-029-1 and has a known hardware limitation that
prevents the IBR from meeting Frequency Ride-through criteria.
R4. Lastly, it is ACES opinion that the acronym “CEA” should be spelled out in the first use within PRC-029-1 so as to eliminate any confusion as to
what this term means. “CEA” is not a defined term and while it used in the NERC Rules of Procedure, it is not commonly used within the Reliability
Standards.
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0
Response
George E Brown - Pattern Operators LP - 5
Answer
No
Document Name
Comment
Pattern Energy supports Edison Electric Institute’s and Grid Strategies LLC’s comments.
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0
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0
Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
No
Document Name
Comment
PGAE recommends R3 and R4 to be revised to allow for existing IBR facility limitations for Frequenecy Ride Through, similar to the approach in R1 and
R2.
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0
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0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Document Name
Comment
No
It is the opinion of ACES that the definition of what constitutes an IBR should be consistent across the industry. The Project 2020-06 SDT has been
working diligently towards this goal and we do not believe that an individual standard should deviate from their approach. Thus we recommend removing
the phrase “The Elements associated with” from section 4.2 and modifying this section as follows:
4.2.
Facilities:
4.2.1.
Bulk Electric System (BES) IBRs; and
4.2.2. Non-BES IBRs that either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a
system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
R1.
ACES believes that phrase “and is initiated by a non-fault switching event on the transmission system” should be struck from the 3rd bullet point
of Requirement R1. It is our opinion that the GO will likely be unable to differentiate between an event initiated by a fault or an event initiated by a “nonfault switching event” on the Transmission system. In short, Transmission switching events are outside the purview of the GO.
R3/R4. ACES has grave concerns with the lack of any exceptions to Requirement R3 for existing IBRs. It is our opinion that Requirements R3 and R4
should be modified to include an exception for an IBR that is in-service by the effective date of PRC-029-1 and has a known hardware limitation that
prevents the IBR from meeting Frequency Ride-through criteria.
R4.
Lastly, it is ACES opinion that the acronym “CEA” should be spelled out in the first use within PRC-029-1 so as to eliminate any confusion as to
what this term means. “CEA” is not a defined term and while it used in the NERC Rules of Procedure, it is not commonly used within the Reliability
Standards.
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0
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0
Response
Rhonda Jones - Invenergy LLC - 5
Answer
Document Name
Comment
No
Invenergy has the following comments regarding this draft of PRC-029-1:
R1: Bullet 3 presents significant challenges, and it is unclear how an entity would demonstrate compliance with the design aspect of PRC-029-1.
Generator Owners will likely not be able to properly model the non-fault switching event condition and would thus be unable to independently assure
design adherence to that requirement.
Remove “in whole or part” from Footnote 7 and Footnote 10. As drafted, the footnotes are inconsistent with IEEE-2800.
Attachment 1 bullet 10 must be removed or significantly amended. Some protection decisions must be made in a matter of micro-seconds, and as
drafted, bullet 10 would adversely impact reliability by subjecting equipment to potentially damaging surges of current or voltage that near instantaneous
protection settings are designed to mitigate.
Invenergy disagrees with the SDT’s interpretation of FERC Order 901, and we would like to reiterate that there is no clear evidentiary record to support
the exclusion of limited exceptions from the frequency ride-through requirements. What’s most concerning however is the SDT’s recent assertion that it
“does not have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901.” We continue to await the requested technical justification studies and would like to direct the SDT to the several public
comments filed by OEMs in ERCOT’s NOGRR 245 proceeding, that illustrate equipment challenges to meet reasonable data driven ride-through
capability limits that fall below the current draft of PRC-029-1.
•
GE
245NOGRR-58 GE Vernova Comments 110723.doc (live.com)
245NOGRR-63 GE Vernova Comments 011924.docx (live.com)
•
Vestas
245NOGRR-57 Vestas Comments 110123.doc (live.com)
•
Siemens Gamesa
245NOGRR-56 Siemens Gamesa Renewable Energy Comments 103023.docx (live.com)
Additionally, the SDT and NERC are encouraged to leverage the industry provided information regarding equipment limitations submitted according to
provisions in the currently effectively Reliability Standard PRC-024-3.
As written, Draft 3 of PRC-029-1 ignores the technical realities surrounding many gigawatts of inverter-based resources installed on the BES today and
provides no path to compliance for entities with well documented and understood hardware limitations. Invenergy would like to remind NERC that
FERC has on many occasions, including within Order 901, granted NERC the leeway to exercise its technical expertise, experience, and discretion to
develop appropriate requirements.
A reasonable path to compliance for facilities with equipment that is unable to meet the proposed voltage or frequency ride-through requirements would
be to retain and carry over R3 from PRC-024-4. This would ensure equitable treatment of all generation types, provide sensible accommodations for
equipment limitations, and push facilities to maximize their capabilities to the extent possible. In fact, FERC alluded to that in paragraph 193 of Order
901, stating, “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.”
Absent limited exemptions from the ride-through requirements or a clear path to compliance for entities with hardware limitations, the frequency bands
must be amended. To date, the SDT has provided no evidence that the proposed frequency bands, well beyond those of IEEE-2800-2002, would
benefit BES reliability.
Likes
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0
Response
Colin Chilcoat - Invenergy LLC - 6
Answer
Document Name
Comment
No
Invenergy has the following comments regarding this draft of PRC-029-1:
R1: Bullet 3 presents significant challenges, and it is unclear how an entity would demonstrate compliance with the design aspect of PRC-029-1.
Generator Owners will likely not be able to properly model the non-fault switching event condition and would thus be unable to independently assure
design adherence to that requirement.
Remove “in whole or part” from Footnote 7 and Footnote 10. As drafted, the footnotes are inconsistent with IEEE-2800.
Attachment 1 bullet 10 must be removed or significantly amended. Some protection decisions must be made in a matter of micro-seconds, and as
drafted, bullet 10 would adversely impact reliability by subjecting equipment to potentially damaging surges of current or voltage that near instantaneous
protection settings are designed to mitigate.
Invenergy disagrees with the SDT’s interpretation of FERC Order 901, and we would like to reiterate that there is no clear evidentiary record to support
the exclusion of limited exceptions from the frequency ride-through requirements. What’s most concerning however is the SDT’s recent assertion that it
“does not have sufficient data at this time to determine whether additional frequency-based exemptions are appropriate and consistent with the overall
reliability goals of Order No. 901.” We continue to await the requested technical justification studies and would like to direct the SDT to the several public
comments filed by OEMs in ERCOT’s NOGRR 245 proceeding, that illustrate equipment challenges to meet reasonable data driven ride-through
capability limits that fall below the current draft of PRC-029-1.
GE
245NOGRR-58 GE Vernova Comments 110723.doc (live.com)
245NOGRR-63 GE Vernova Comments 011924.docx (live.com)
Vestas
245NOGRR-57 Vestas Comments 110123.doc (live.com)
Siemens Gamesa
245NOGRR-56 Siemens Gamesa Renewable Energy Comments 103023.docx (live.com)
Additionally, the SDT and NERC are encouraged to leverage the industry provided information regarding equipment limitations submitted according to
provisions in the currently effectively Reliability Standard PRC-024-3.
As written, Draft 3 of PRC-029-1 ignores the technical realities surrounding many gigawatts of inverter-based resources installed on the BES today and
provides no path to compliance for entities with well documented and understood hardware limitations. Invenergy would like to remind NERC that
FERC has on many occasions, including within Order 901, granted NERC the leeway to exercise its technical expertise, experience, and discretion to
develop appropriate requirements.
A reasonable path to compliance for facilities with equipment that is unable to meet the proposed voltage or frequency ride-through requirements would
be to retain and carry over R3 from PRC-024-4. This would ensure equitable treatment of all generation types, provide sensible accommodations for
equipment limitations, and push facilities to maximize their capabilities to the extent possible. In fact, FERC alluded to that in paragraph 193 of Order
901, stating, “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.”
Absent limited exemptions from the ride-through requirements or a clear path to compliance for entities with hardware limitations, the frequency bands
must be amended. To date, the SDT has provided no evidence that the proposed frequency bands, well beyond those of IEEE-2800-2002, would
benefit BES reliability.
Likes
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0
0
Response
Mike Magruder - Avista - Avista Corporation - 1
Answer
No
Document Name
Comment
We concur with EEI's comments.
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0
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0
Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
No
Document Name
Comment
NIPSCO recommends removing the phrase “demonstrate the design of each facility” from the proposed standard and returning to the original eventbased requirements. The phrase may prove difficult to fully comply with, as a Functional Entity would have to know the design of the collector system
and parameters and run the models correctly to demonstrate this. Much of this needed information would need to be provided by the manufacturer,
which may require non-disclosure agreements.
Please clarify or remove “other mechanisms” from requirement R2.
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0
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0
Response
Carver Powers - Utility Services, Inc. - 4
Answer
Document Name
Comment
No
Requirement 2.1.1 through 2.1.3 are all required, recommend ensuring consistency in formatting and include an “and” at the end of 2.1.2.
Request clarification of the intent of 2.1.3. The proposed language is not written clearly, and the intent is not apparent. Recommend at a minimum
addressing this sub-requirement in the technical rationale. An additional recommendation is to provide clarification on how requirement 2.1.3 relates to
the tables in Attachment 1.
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Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Comment
R3. Wording “…and the absolute rate of change of frequency (RoCoF)12 magnitude is less than or equal to 5 Hz/second.” should be removed from R3.
The rate of change of frequency nas never been an issue in past IBR disturbances. In addition, PRC-024 does not mentions and includes rate of change
of frequency requirements. There is no technical rationale for this.
R3. Requirement should include exceptions due to hardware limitation, the same exception that was given for voltage requirements. WEC Energy Group
owns a wind farm with frequency limitation that may not meet PRC-029 requirements. Please explain what should we do? Do not overlook limited
capabilities of older Type 3 wind IBRs. WEC Energy Group recognized similar concerns commented by industry, please address it.
WEC Energy Group suggests SDT to create and add graphs for support Tables 1 and 2 and the respective notes. Graphs should highlight “must
Ride‐through zone” and “may Ride‐through zone” terms that are listed in note 11.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer
No
Document Name
Comment
"Please see EEI Comments"
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0
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer
No
Document Name
2020-02 LG&E KU Comments.docx
Comment
Please see the attached comments.
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Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
EEI does not support the approval of PRC-029-1 because it intends to require existing resources to meet the frequency performance standards
mandated in Requirement R3 and provides no mechanism for IBR resource owners to declare a technical exemption consistent with voltage ridethrough requirements contained in Requirements R1 and R2. It is EEI’s understanding that this was done because the drafting team (DT) understood
that the FERC Order did not allow any exemption for frequency ride-through requirements. However, in Paragraph 193 of FERC Order No. 901, the
Commission expressly directed NERC to determine through its standards development process whether the Reliability Standards mandated therein
should include a limited exemption for certain IBRs from voltage ride-through performance requirements. Importantly, the Commission, in Order No. 901
did not concomitantly prohibit the inclusion of a similar exemption from frequency ride-through performance requirements, either expressly or implicitly.
Rather, it left that decision firmly in the hands of subject matter experts, as was made evident when it encouraged “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.” Reliability Standards to Address Inverter-Based Resources, Order No. 901, 185 FERC ¶ 61,042, at P 193 (2022) (emphasis added).
EEI further notes that we are unaware of any frequency ride-through events, beyond equipment control setting errors, that have been documented and
cited in any of the NERC Event reports to justify a need to disallow reasonable equipment exemptions for IBRs that cannot meet the proposed
frequency ride-through requirements. Nevertheless, PRC-029-1 contains requirements for frequency ride-through that are likely infeasible to implement
through either hardware or software means, in many cases for existing resources. (Noting that while software upgrades might be a viable option for
some newer IBRs, software solutions for older resources would not be a viable remedy because many of the older resources would not have the
computing capability necessary to support such upgrades.)
To address our concerns, we recommend the following:
1.
2.
Change PRC-029-1 to include reasonable and justified exemptions for legacy IBR facilities. (See edits to R4 below)
Align the Frequency ride-through curve in PRC-029-1 with IEEE 2800-2022. (Align Table 3 of attachment 2 to IEEE 2800-2022)
PRC-029-1 (Requirement R4 – Changes in Boldface)
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of PRC-029-1, has known hardware limitations that prevent the IBR
from meeting voltage and frequency Ride-through criteria as detailed in Requirements R1, R2, and R3 and requires an exemption from specific Ridethrough criteria shall:10 Lower] [Time Horizon: Long-term Planning]
4.1.
Document information supporting the identified hardware limitation no later than 12 months following the effective date of PRC-029-1. This
documentation shall include:
4.1.1
Identifying information of the IBR (name and facility #);
4.1.2
Which aspects of voltage or frequency Ride-through requirements that the IBR would be unable to meet and the capability of the hardware
due to the limitation;
4.1.3
Identify the specific piece(s) of hardware causing the limitation;
4.1.4
Supporting technical documentation verifying the limitation is due to hardware that needs to be physically replaced or that the limitation cannot
be removed by software updates or setting changes, and;
4.1.5
Information regarding any plans to remedy the hardware limitation (such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA no later than 12 months following the effective date of PRC-029-1.
4.2.1
Any response to additional information requested by the associated Planning Coordinator(s), Transmission Planner(s), Transmission
Operator(s), Reliability Coordinator(s), and the CEA shall be provided back to the requestor within 90 days of the request.
4.2.2
Provide a copy of the acceptance of a hardware limitation by the CEA to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s).11
4.3.
Each Generator Owner with a previously accepted limitation that replace the hardware causing the limitation shall document and
communicate such a hardware change to the associated Planning Coordinator(s), Transmission Planner(s), Transmission Operator(s), and Reliability
Coordinator(s) within 90 days of the hardware change.
4.3.1
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When existing hardware causing the limitation is replaced, the exemption for that Ride-through criteria no longer applies.
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI Comments
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Kimberly Turco - Constellation - 6
Answer
Document Name
No
Comment
Constellation aligns with NAGF comments.
Kimberly Turco on behalf of Constellation Energy Segments 5 and 6.
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Richard Vendetti - NextEra Energy - 5
Answer
No
Document Name
Comment
Facilities:
4.2.1. The Elements associated with (1) Bulk Electric System (BES) IBRs inverter‐based resources and (2) Non‐BES IBRs that either have or
contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such
capacity to a common point of connection at a voltage greater than or equal to 60 kV
NextEra aligns with EEI’s recommendation to remove “elements associated with” from Section 4.2.1
R1 and R2
NextEra believes that further clarity on reporting could be added to R1 and R2 consistent with the technical rationale.
R3
With a large portion of wind fleet across multiple OEMS, NextEra recommends there be an exception process for R3, or that it should not be applied
retroactively. This is a particular concern for entrants for the Non-BES Assets.
R4
NextEra aligns with the below comments provided from EEI:
EEI does not agree with imposing new unverified requirements on existing resources as proposed in PRC-029-1 because it is unclear how many
existing resources can meet the frequency performance standards mandated in Requirement 3. We are additionally concerned because resource
owners have not been given adequate time to fully assess the impact of imposing these new requirements on their existing resources, which align with
IEEE 2800-2022 (See 7.3.2.1 Figure 12 & Table 15 (Frequency ride-through, page 80; and see 7.3.2.3.5 Rate of change of frequency (ROCOF), page
82), and did not exist as a Standard until February 2022, after most of these resources were built or placed in service. For this reason, we cannot
support the approval of PRC-029-1 without the following changes to Requirement 4 ensure that existing resources that were not design and do not have
the capability to meet these requirements are allowed to declare an exemption for frequency ride-through similar to what is provided for resources that
cannot meet the voltage ride-through requirements. See the proposed changes to R4 in boldface below:
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of PRC-029-1, has known hardware limitations that prevent the
IBR from meeting voltage and frequency Ride-through criteria as detailed in Requirements R1, and R2, and R3 and requires an exemption from
specific voltage Ride-through criteria shall:10 Lower] [Time Horizon: Long-term Planning]
4.1.
Document information supporting the identified hardware limitation no later than 12 months following the effective date of PRC-029-1. This
documentation shall include:
4.1.1
Identifying information of the IBR (name and facility #);
4.1.2
Which aspects of voltage or frequency Ride-through requirements that the IBR would be unable to meet and the capability of the hardware
due to the limitation;
{C}4.1.3
Identify the specific piece(s) of hardware causing the limitation;
4.1.4
Supporting technical documentation verifying the limitation is due to hardware that needs to be physically replaced or that the limitation cannot
be removed by software updates or setting changes, and;
4.1.5
Information regarding any plans to remedy the hardware limitation (such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA no later than 12 months following the effective date of PRC-029-1.
4.2.1
Any response to additional information requested by the associated Planning Coordinator(s), Transmission Planner(s), Transmission
Operator(s), Reliability Coordinator(s), and the CEA shall be provided back to the requestor within 90 days of the request.
4.2.2
Provide a copy of the acceptance of an a hardware limitation by the CEA to the associated Planning Coordinator(s), Transmission Planner
(s), Transmission Operator(s), and Reliability Coordinator(s).11
4.3.
Each Generator Owner with a previously accepted limitation that replace the hardware causing the limitation shall document and
communicate such a hardware change to the associated Planning Coordinator(s), Transmission Planner(s), Transmission Operator(s), and Reliability
Coordinator(s) within 90 days of the hardware change.
4.3.1
When existing hardware causing the limitation is replaced, the exemption for that Ride-through criteria no longer applies.
Footnote 7
“Available Real Power” is not NERC defined term located in the NERC Glossary of Terms. By adding to the footnote, this creates confusion.
NextEra recommends defining and adding to NERC Glossary.
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Megan Melham - Decatur Energy Center LLC - 5
Answer
Document Name
Comment
No
Capital Power supports the NAGF's comments:
The NAGF strongly recommends that PRC-029 be revised to allow for frequency ride through (“FRT”) exemptions to address such limitations for legacy
IBR facilities. Not including FRT exemptions will result in a standard that will make certain IBR legacy facilities automatically non-compliant when the
standards become effective.
Requirement R3 – the NAGF is concerned that legacy IBR facilities are not capable of meeting the 5 Hz/second maximum ROCOF or the 25-degree
phase angle jump requirements. Therefore, FRT exemptions are necessary and need to be included in Requirement R3. In support of this concern, the
NAGF points to the ERCOT NOGRR245 TAC Presentation, December 4, 2023 – page 4 which indicates that 40% of OEMs cannot comply with the
previously proposed specific 5 Hz/second maximum ROCOF requirement and 41% of OEMs cannot comply with the previously proposed specific 25degree phase angle jump requirement.
December 4 2024 NOGRR245 TAC Stephen Solis - Principal System Operations Improvement
Requirement R4.2.2 – the NAGF is unclear as to what the Compliance Enforcement Authority (CEA) acceptance for an IBR hardware limitation
exemption will consist of. Will the CEA provide an email response confirming acceptance to the Generator Owner submitting the exemption? How are
such exemptions to be submitted and to whom within the CEA organization?
In addition to the NAGF comments above, after discussions with a wind turbine OEM, some legacy equipment will not be able to handle the 64 Hz
overfrequency ride-through requirement stipulated in PRC-029. Requiring IBRs to ride through an overfrequency in the range of 61.8 Hz to 64 Hz is
beyond the IEEE 2800 standard, as stated by the SDT within the technical rationale. We recommend aligning the frequency ride-through requirement to
be more in line with the IEEE 2800 standard and reducing the final "no-trip" overfrequency requirement to 61.8Hz in addition to changing the wording of
Requirement R4 to allow for FRT exemptions. More discussions with IBR OEMs must be held to confirm equipment capabilities.
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Alison MacKellar - Constellation - 5
Answer
No
Document Name
Comment
Constellation aligns with NAGF comments.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
No
Comment
The NAGF strongly recommends that PRC-029 be revised to allow for frequency ride through (“FRT”) exemptions to address such limitations for legacy
IBR facilities. Not including FRT exemptions will result in a standard that will make certain IBR legacy facilities automatically non-compliant when the
standards become effective.
Requirement R3 – the NAGF is concerned that legacy IBR facilities are not capable of meeting the 5 Hz/second maximum ROCOF or the 25-degree
phase angle jump requirements. Therefore, FRT exemptions are necessary and need to be included in Requirement R3. In support of this concern, the
NAGF points to the ERCOT NOGRR245 TAC Presentation, December 4, 2023 – page 4 which indicates that 40% of OEMs cannot comply with the
previously proposed specific 5 Hz/second maximum ROCOF requirement and 41% of OEMs cannot comply with the previously proposed specific 25degree phase angle jump requirement.
December 4 2024 NOGRR245 TAC Stephen Solis - Principal System Operations Improvement
The NAGF recommends aligning exception language with IEEE-2800. The proposed PRC-029 ride through requirements do not include the technology
limitations discussed in IEEE-2800.
Requirement R4.2.2 – the NAGF is unclear as to what the Compliance Enforcement Authority (CEA) acceptance for an IBR hardware limitation
exemption will consist of. Will the CEA provide an email response confirming acceptance to the Generator Owner submitting the exemption? How are
such exemptions to be submitted and to whom within the CEA organization?
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Ruchi Shah - AES - AES Corporation - 5
Answer
No
Document Name
Comment
•
AES CE believes additional changes are needed as explained below.
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Adam Burlock - Adam Burlock On Behalf of: Ashley Scheelar, TransAlta Corporation, 5; - Adam Burlock
Answer
No
Document Name
Comment
TransAlta supports multiple other organizations who recommend the addition of frequency ride-through to the allowable hardware limitations in R4.
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
No
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) on question 2
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Michael Goggin - Grid Strategies LLC - 5
Answer
No
Document Name
Comment
In the current draft of PRC-029, R4 should be modified to allow existing resources with equipment limitations to obtain an exemption from the frequency
ride-through requirements in R3, instead of only allowing an exemption from the voltage ride-through requirements in R1 and R2. This is necessary
because most existing IBR generators cannot meet the stringent frequency ride-through requirements proposed in R3 without deploying significant
hardware modifications or replacement, which goes against the intent of FERC Order 901.
Without change, a large share of the 270 GW of operating IBR plants,[1] representing an investment of hundreds of billions of dollars, will be forced into
early retirement. Abruptly forcing such a large volume of existing generators offline would not only impose massive costs, but also cause generation
shortfalls in many regions. Such drastic action could be understandable if the frequency ride-through requirement were addressing a real reliability
concern. However, NERC and the drafting team have repeatedly been unable to provide any technical justification for imposing the frequency ridethrough requirement existing IBR plants. None of the reports NERC has published in response to IBR ride-through events have identified frequency ridethrough as a significant concern. There is no reason to impose such a massive cost and reliability impact for a solution in search of a problem.
Information provided by the two largest IBR owners in the U.S. confirms that most existing IBRs cannot meet the frequency ride-through requirements.
One of these developers indicated that more than 30% of its fleet could not comply with the draft standard. The other indicated that half of its operating
IBR fleet has no viable path to compliance, and a large share of the remainder will require cost-prohibitive retrofits, so if the standard went into effect as
drafted a large share of its operating fleet will have to be retired or fully repowered. Other developers that operate the remainder of the 270 GW IBR fleet
would likely see comparable impacts. Retiring, or at best taking out of service for an extended period of time for repowering, such a large volume of
facilities during a time of rapid growth in peak load and energy needs would cause far greater reliability concerns than whatever concern the frequency
ride-through requirement is attempting to address.
Information provided by these developers indicates that a large share of wind, solar, and battery resources cannot meet the frequency ride-through
standard without significant hardware replacement. The frequency ride-through requirements are particularly problematic for some existing wind
generators. In the Technical Rationale document accompanying the second PRC-029 draft, the drafting team notes that some wind generators are more
sensitive to frequency deviations, writing that “All IBR resources (except for type 3 wind turbines) interface to the grid through fast switching of power
electronics devices. These power electronic devices are much less sensitive to the transmission system frequency excursion than non‐hydraulic turbine
synchronous resources.”[2] However, the drafting team then incorrectly concludes that “Therefore, IBR should be capable of riding through the
increased proposed 6‐second frequency ride‐through requirement without risk of equipment damage or need for frequency protection to operate.” The
Technical Rationale document does not offer any justification for its assumption that Type III wind turbines can meet the frequency ride-through
requirements, despite noting that those turbines more directly interface with the grid and thus are more affected by frequency deviations than other
IBRs.
In fact, many existing Type III wind turbines cannot meet the frequency ride-through requirements proposed in this draft of PRC-029. Those resources
were designed to meet the reliability Standards and interconnection requirements that were in effect when they were placed in service, and were not
designed to ride through frequency excursions of the magnitude and duration proposed in the draft Standard. Imposing a retroactive requirement on
these generators is particularly problematic as it is not typically feasible to retrofit existing wind turbines to increase their ability to withstand mechanical
stresses due to frequency changes. In such cases, making existing equipment better able to withstand frequency changes would require full
replacement or extensive modification of hardware, which would come at a significant, and sometimes prohibitive, cost. At minimum, bringing wind
plants that cannot meet the current standard into compliance would require replacing the turbine converter and controller. Further, frequency changes
can impose mechanical stresses on highly sensitive elements in the wind turbine’s rotating equipment, including the generator, gearbox, the main shaft,
and bearings associated with all of that equipment, and requiring such resources to ride through frequency changes they were not designed to operate
through can damage that equipment. Subjecting Type III wind turbines to this damage may lead to increased outages or premature failure of these
generators, potentially increasing reliability risks. As noted above, if the standard went into effect as drafted a large share of the operating IBR fleet will
have to be retired or fully repowered. Retiring these facilities during a time of rapid growth in peak load and energy needs would cause far greater
reliability concerns than whatever concern the frequency ride-through requirement is attempting to address.
The Solution: Frequency ride-through exemptions for existing IBRs
The easiest solution is to modify R4 to allow existing resources with equipment limitations to obtain an exemption from the frequency ride-through
requirements in R3, which would make PRC-029 consistent with a long precedent of FERC interconnection requirements and NERC Standards only
applying prospectively, including PRC-024. Retroactive requirements impose a much greater financial burden on the generator than prospective
Standards, and set a bad precedent by unfairly penalizing generators that met all requirements that were in effect at the time they were installed. Retrofit
or replacement costs are typically much greater than if the capability were installed at the plant to begin with. In some cases parts needed for retrofits
may not be available, particularly for models that have been discontinued or manufacturers that are no longer in business, potentially requiring the
replacement of the entire power conversion system. Moreover, existing IBR generators typically sell their output at a fixed price under a long-term power
purchase agreement, and unexpected retrofit or replacement costs cannot typically be recovered once a power purchase agreement has been signed.
These unexpected and unrecoverable costs are far more concerning to lenders and other generation project financiers as they were not accounted for
during the project’s financing. As a result, retroactive requirements set a bad precedent by introducing regulatory uncertainty that makes future
generation investment more uncertain and riskier, and likely more costly by forcing financiers to charge higher risk premiums. Changing the rules in the
middle of the game and penalizing resources that were designed to the standards in effect at the time they were built also establishes a bad precedent,
in addition to imposing costs that are not just and reasonable and undue discrimination relative to resources covered by PRC-024.
Fortunately, these problems can be fixed by simply inserting “R3” into the list of permissible exemptions in R4, which would allow existing resources with
equipment limitations to obtain an exemption from the frequency ride-through requirements in R3.
In the Technical Rationale document, the drafting team points to FERC’s directive in Order No. 901 to justify not allowing existing resources to obtain an
exemption from the frequency ride-through requirements in R3: “FERC Order No. 901 states that this provision would be limited to exempting ‘certain
registered IBRs from voltage ride‐through performance requirements.’ This is the reason that no similar provisions are included for exemptions for
frequency or rate‐of‐change‐of‐frequency (ROCOF) ride‐through requirements per R3.”[3]
However, a contextual reading of Order No. 901 indicates FERC was focused on targeting equipment limitation exemptions at existing generators that
would have to physically replace or modify hardware to comply with the Standard, and not focused on limiting such exemptions to voltage ride-through
requirements. Paragraph 193 in its entirety, and particularly the first sentence, explain that FERC’s intent was exempting existing resources that would
have to physically replace or modify hardware: “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.” As a result, FERC continued by directing that “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.”[4]
Allowing existing plants to apply for an equipment limitation exemption for the frequency ride-through requirements in R3 is necessary to ensure some
existing generators do not have to physically replace or modify hardware, as explained above. As a result, such an exemption is consistent with FERC’s
directive and intent in Order No. 901. As documented in the following footnote, there is ample precedent for NERC and standards drafting teams to
exercise their technical expertise to craft Standards to align content and requirements with technical realities.[5]
Additional context in Order 901 further demonstrates that FERC intended for NERC to include an exemption for existing IBRs that cannot meet
frequency ride-through requirements. At paragraph 190 in Order No. 901, FERC directed NERC to develop Standards that ensure resources “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.” For many existing IBRs that cannot meet the proposed frequency ridethrough requirements, tripping is necessary to protect the IBR equipment, similar to when synchronous generation resources use tripping as protection
from internal faults. As a result, an exemption from R3 for existing resources is consistent with FERC’s intent. Order No. 901 also directed NERC to
consider the “PRC-024-3, Requirement R3 as an example for establishing registered IBR technology exemptions,” and that exemption applies equally to
voltage ride-through and frequency ride-through settings, further suggesting that FERC will allow certain IBRs an exemption from the frequency ridethrough requirements.[6] Finally, Order No. 901 notes that in the notice of proposed rulemaking that led to the order, FERC “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.”[7] FERC then adopted that very proposal,{C}[8] further demonstrating that FERC sought to direct NERC to only require
frequency and voltage ride-through where technologically feasible.
When asked about this issue, FERC staff has indicated that as a general matter, when a Commission Order is silent on a topic it is neither requiring
something nor requiring the absence of that thing. NERC is taking a contrary position by arguing that due to FERC’s silence they are not allowed to give
an exemption for frequency ride-through.
NERC has been unable to present any technical reason why FERC would not allow a frequency ride-through exemption for existing IBRs, as none
exists. Frequency ride-through has not been identified as a significant concern in any of the reports NERC has commissioned regarding IBR ridethrough during disturbance events. Moreover, there is no technical justification for requiring existing IBRs to meet the extremely wide frequency ridethrough bands proposed in PRC-029. PRC-029 requires IBRs to remain online for 6 seconds at 56-64 Hz, 5 minutes at 57-61.8, 11 minutes at 58.561.5, and indefinitely at 58.8-61.2 Hz. Under-Frequency Load Shedding (UFLS) that restores frequency following an extreme disturbance typically
begins at 59.4 or 59.5 Hz. There is no credible reliability reason for requiring IBRs to remain online for 5 minutes for excursions that are 5 times more
severe than the threshold at which UFLS restores frequency, and indefinitely for a frequency excursion twice as severe as that threshold. Such a
requirement for IBRs is particularly pointless because PRC-024 would have allowed synchronous resources’ relays to trip those generators far before
that point for far less severe excursions.
This highlights another likely reason FERC Order No. 901 did not explicitly direct NERC to include frequency ride-through exemptions: FERC did not
anticipate that NERC would adopt such a strict frequency ride-through requirement that some existing IBR plants cannot meet it. The drafting team even
notes at page 7 in the Technical Rationale document that “The proposed 6‐second time frame of the frequency ride‐through capability requirement is
beyond the IEEE 2800 standard frequency ride‐through requirement and beyond frequency ride‐through requirements for synchronous machines
under proposed PRC‐024‐4.” There is nothing in Order No. 901 that suggests that FERC was opposed to existing equipment exemptions for a
frequency ride-through standard that was drafted after FERC issued Order No. 901 and is more stringent than FERC anticipated. A much more
reasonable interpretation is that the logic FERC provided in paragraph 193 of Order No. 901 also applies to a frequency ride-through requirement that
some existing resources cannot meet without physical modification or replacement of equipment. In fact, paragraph 193 makes clear that FERC’s
language focuses on an exemption from voltage ride-through requirements because “a subset of existing registered IBRs… may be unable to implement
the voltage ride though performance requirements directed herein.”
At the end of paragraph 193, FERC also explained that an exemption for existing resources would not harm reliability because “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.” FERC’s reasoning in paragraph 193 also applies to an exemption from frequency
ride-through requirements, but particularly the conclusion that exempting existing plants does not cause reliability concerns and therefore should be
allowed. The NERC drafting team’s technical justification document explicitly explains that the frequency ride-through requirement is “to ensure the
reliability of future grids with high IBR penetration,”{C}[9] based on concerns about declining inertia due to IBRs replacing synchronous resources.
NERC and others have demonstrated that inertia and frequency response will remain more than adequate for the foreseeable future even following
disturbances that are several times larger than current credible contingencies, and that higher IBR penetrations can actually significantly improve
frequency stabilization following disturbances.[10]
As a result, there is no reliability concern from an exemption for the small number of existing resources that cannot meet the requirements without
physical modification or replacement of equipment. Moreover, as FERC notes, these plants will replace that equipment anyway over time as legacy
inverters fail or are replaced with more modern equipment for other reasons, and the draft standard requires replacement equipment to comply with the
Standard. Utility-scale inverters installed at solar and battery installations typically come with warranties of 10 years or less,{C}[11] and those inverters
are typically replaced at least once during the plant’s lifetime. Many existing wind plants are also being repowered with newer turbines, often to allow the
project to receive another 10 years of production tax credits after the initial 10 years of credits have been received. As a result, by the time the drafting
team’s concerns about inertia in a high IBR penetration future might materialize, the vast majority of IBRs that cannot meet the frequency ride-through
requirements will have been replaced with new equipment that is not exempt.
Moreover, the drafting team’s assumption that frequency deviations will be larger on a future low inertia power system is flawed. IBRs can provide fast
frequency response, which stabilizes frequency in the initial seconds following a grid disturbance, before synchronous generators begin to provide their
slower primary frequency response.[12] Thus fast frequency response provides a similar service to inertia in helping to arrest the change in frequency
before primary frequency response is fully deployed, reducing the need for inertia.[13] Fast frequency response is easily provided by batteries due to
their available energy, but can also be provided by curtailed wind or solar resources. Power systems with high IBR penetrations will tend to have some
wind or solar curtailment in a significant share of hours. If allowed to do so, solar an battery resources with spare DC capacity behind the inverter can
also temporarily exceed their interconnection agreement’s AC injection limit to provide fast frequency response.
The replacement of inflexible synchronous resources with more flexible IBRs could also significantly improve primary frequency response, as NERC’s
modeling has demonstrated.{C}[14] NERC has also documented that only about 30% of synchronous generators provide primary frequency response,
and only about 10% provide sustained primary frequency response.[15] Even with less inertia, the fast and accurate frequency response provided by
IBRs will keep frequency more tightly controlled than the slow to nonexistent primary frequency response from synchronous generators. The
replacement of large synchronous generators with smaller IBRs should also reduce the magnitude of frequency deviations following the loss of
generators. If frequency response does begin to emerge as a concern, the more effective solution would be to enforce requirements on synchronous
generators that are supposed to provide it but do not. If necessary, operators would alter real-time dispatch, as ERCOT and some island power systems
occasionally do today, to ensure that inertia and fast frequency response are adequate to ensure under-frequency load shedding or generator tripping
thresholds are not reached. Finally, grid-forming inverters are increasingly being deployed with battery storage and other IBR installations, further
increasing the contributions of IBRs to stabilizing frequency.
At page 8 in the Technical Rationale document, the drafting team argues that “To compensate for the lack of inertia and short circuit contributions,
[IBRs] should have wider tolerances for frequency and voltage excursions to meet the needs of future power systems with a higher percentage of IBR.”
The drafting team also argues that IBRs should have to ride-through much larger frequency deviations than synchronous resources because
“Synchronous resources are more sensitive to frequency deviations than IBR resources.” This logic is flawed for many reasons. Grid operators need all
resources to ride through disturbances, and the contribution of a resource to inertia or short circuit needs is irrelevant to that need. Any concerns about
resources’ inertia and short circuit contributions are outside the drafting team’s scope and authority, and should be addressed by other means (such as
by increasing the deployment of grid-forming IBRs in the localized areas that have short circuit or stability concerns). It is also perverse for the drafting
team to penalize IBRs for being less sensitive to frequency deviations than synchronous generators. As noted below, there are already grounds for
FERC to reject this proposed standard due to undue discrimination against IBRs relative to the far more lenient requirements on synchronous
generators under PRC-024, including an equipment limitation exemption for synchronous generators from the frequency relay setting requirement in
PRC-024,[16] and this only adds to those concerns.
In short, the drafting team’s unfounded concerns about a future power system do not justify withholding an exemption to frequency ride-through
requirements for existing IBRs that will have been largely replaced by the time any concerns might materialize.
Finally, R4 equipment limitation exemptions should be allowed for resources with signed interconnection agreements as of the effective date of the
Standard, instead of resources that are in-service as of that date. Resource equipment decisions are typically locked down at the time the
interconnection agreement is signed, and a change in requirements after that point can require a costly change in equipment or settings that may also
trigger a material modification and resulting interconnection restudies. The implementation plan for PRC-029 indicates that the effective date for the
Standard will be the first day of the first quarter six months after FERC approval. Many resources take significantly longer than that to move from a
signed interconnection agreement to being placed in service, so it makes more sense to allow R4 equipment limitation exemptions for resources that
have a signed interconnection agreement as of the effective date of the Standard.
The current draft of the PRC-029 Standard is unworkable and will impose massive costs on some existing generators with no benefit for reliability. As
explained above, the drafting team incorrectly ventures that “IBR should be capable of riding through the increased proposed 6‐second frequency
ride‐through requirement without risk of equipment damage or need for frequency protection to operate,” even after noting that some wind turbines use
very different technology. NERC’s rigorous standard development process exists to ensure that errors like this do not make it into final Standards, and
the exceedingly low level of support for the initial draft and the major revisions in the current draft indicate that further revisions will likely be necessary. It
takes time to fine tune highly technical requirements and vet them across the industry to avoid unnecessary and exorbitant costs for existing resources
that cannot meet the standard.
If PRC-29 continues to fall short of the level of support required for approval in this round of balloting, and NERC proceeds under Rules of Procedure
Rule 321.2.1 by having the Standards Committee convene a technical conference and use the input from the technical conference to revise the
standard for a final re-balloting period, incorporating an exemption from the frequency ride-through requirement for existing IBR generators would help to
secure sufficient support for the standard to pass during re-balloting. Irreparable and immediate harm will occur if PRC-029 is allowed to move forward
in its current form, harm that cannot be undone even if NERC immediately opens a standards revisions effort after the adoption of PRC-029 to fix these
concerns. The current implementation plan requires BES IBRs to “ensure the design of their IBR units meets the criteria” within 12 months following
regulatory approval of the standard, while for non-BES IBRs the compliance deadline will be the later of January 1, 2027, or 12 months following
regulatory approval of the standard.[17] A year or two provides IBR owners with no time to wait if hundreds of GW of existing IBRs are required to
secure retrofit or replacement equipment, find skilled technicians and tools to install that equipment, and complete that work during scheduled plant
outages, especially since the entire industry will be pulling from the same pool of equipment and skilled labor. As a result, if PRC-029 is approved in its
current form, IBR owners will immediately begin incurring massive non-refundable costs for equipment orders and labor contracts, as they cannot wait in
the hope that a subsequent revision effort will fix this error. Moreover, the typical timeline from Standard Authorization Request through standard
balloting and FERC approval is much more than a year, so industry would have no reason to expect such an effort could be completed before PRC-029
took effect.
Alternative solutions
If NERC refuses to accept that Order 901 allows it to exempt existing IBRs from the frequency ride-through requirement, alternative solutions can
mitigate the harm the proposed standard would cause. One alternative solution would be modifying the standard to allow IBRs, or at least existing IBRs,
to meet far less stringent frequency ride-through curves than those proposed in PRC-029. The less stringent frequency ride-through curve or curves
could be taken from PRC-024. As noted above, the PRC-024 curves are closer to but still significantly wider than UFLS thresholds, and thus are better
tailored to meeting actual reliability needs. An additional advantage is that the PRC-024 curves have been in place for many years and thus many
existing IBRs were designed with relays that would not trip them for disturbances of that magnitude. In contrast, the curves proposed in PRC-029 are far
more stringent than past design practice and could not have been anticipated by IBRs when they were built. Industry could work to identify a reasonable
and attainable frequency ride-through curve or curves at the technical conference that will likely be convened due to Rule 321.2.1, which could then be
incorporated into the revised standard that subsequently goes out for a final re-balloting period.
This approach will not mitigate all of the harm caused by PRC-029, as PRC-024 still allows exemptions for equipment limitations,[18] while NERC is
taking the position that PRC-029 cannot. Moreover, adopting something approximating the PRC-024 curves in PRC-029 would still result in disparate
treatment for IBRs because PRC-024 is only a relay-setting standard and PRC-029 is a ride-through performance requirement. The most elegant
solution, and the one least likely to result in a costly mistake that requires expensive retrofits and plant retirement for no reliability benefit, and risk FERC
rejection of the standard, is to simply include an exemption for existing resources.
Undue discrimination
Providing an exemption in PRC-029 R4 for existing IBRs that cannot meet the frequency ride-through requirement in R3 will provide less disparity with
the treatment of synchronous resources under PRC-024, and is therefore an essential step if NERC wants to reduce the risk of FERC rejecting the
proposed standard due to undue discrimination against IBRs. As noted above, PRC-024 allows exemptions for equipment limitations,[19] so exempting
existing IBRs from PRC-029’s frequency ride-through requirements would reduce the undue discrimination towards IBRs.
It should also be noted that PRC-029 is far more stringent because it is a ride-through performance requirement, while the existing and proposed
versions of PRC-024 are simply relay-setting standards. PRC-024 only requires protective relays to be set so they do not trip the generator within
specified bounds, but it allows a resource to trip offline for other reasons. PRC-024-4 explicitly allows a plant to trip if protection systems trip auxiliary
plant equipment, per section 4.2.3. In contrast, PRC-029 is a performance standard that requires IBRs to remain electrically connected and to continue
to exchange current within the specified voltage and frequency bounds. Said another way, an IBR and a synchronous resource could both trip during the
same disturbance, and the IBR would be in violation of PRC-029 but the synchronous generator would not be in violation of PRC-024-4, as long as the
synchronous generator did not trip due to the settings of its protection system.
To ensure grid reliability and resilience, all resources including IBRs and synchronous resources should ride through grid disturbances. The failure of
synchronous generators to ride through grid disturbances threatens grid reliability as much or more than the failure of IBRs, as synchronous resources
are often producing at a higher level of output, are more typically relied on as capacity resources, and often take longer to come back online and ramp
up to full output if they trip due to a disturbance.
FERC Order No. 901 directed NERC to treat IBRs similarly to how NERC Standards treat synchronous generators, writing that the IBR Standard should
“permit IBR tripping only to protect the IBR equipment in scenarios similar to when synchronous generation resources use tripping as protection from
internal faults.”{C}[20] Allowing synchronous generators to trip but requiring IBRs to ride through the same or similar disturbance could be challenged at
FERC as undue discrimination. Providing synchronous generators with an exemption from PRC-024’s frequency relay setting requirements but not
offering IBRs an exemption from the far more stringent frequency ride-through requirements in PRC-029 only compounds the undue discrimination, and
makes an even stronger case for FERC to reject PRC-029 as proposed.
Not requiring ride-through performance from synchronous generators is also at odds with the intent for this project that NERC stated in its February
2023 comments on the FERC proposed rulemaking that led to Order No. 901: “A comprehensive, performance-based ride-through standard is needed
to assure future grid reliability. To that end, NERC re-scoped an existing project, 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 generating resources.”[21]
FERC’s Order No. 901 also noted NERC’s statement that this project would require ride-through performance from all generating resources,[22] so a
failure to require ride-through performance from synchronous generators is contrary to both NERC’s and FERC’s intent.
Providing an exemption in PRC-029 R4 for existing IBRs that cannot meet the frequency ride-through requirement in R3 will provide less disparity with
the treatment of synchronous resources under PRC-024, and is therefore an essential step if NERC wants to reduce the risk of FERC rejecting the
proposed standard due to undue discrimination against IBRs.
{C}[1]{C} https://www.utilitydive.com/news/clean-energy-capacity-wind-solar-2024-acp-report/715501/
{C}[2]{C} Technical Rationale, PRC-029-1 – Frequency and Voltage Ride-Through Requirements for Inverter-Based Generating Resources, at 8,
https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-0291_Technical_Rationale_Redline_to_Last_Posted_06182024.pdf (“Technical Rationale”).
{C}[3]{C} Id., at 10
{C}[4]{C} Reliability Standards to Address Inverter-Based Resources, Order No. 901, 185 FERC ¶ 61,042, P 193 (2023).
{C}[5]{C} For example, Section 215(d)(2) of the FPA requires FERC to give “due weight” to the technical expertise of the ERO when evaluating the
content of a proposed Reliability Standard or modification to a Standard.
Order No. 733-A, P 11: “In this order, we emphasize and affirm that we do not intend to prohibit NERC from exercising its technical expertise to develop
a solution to an identified reliability concern that is equally effective and efficient as the one proposed in Order No. 733.”
Order No. 748, P 43: “In consideration of these ongoing efforts, we will not direct specific modifications to these Reliability Standards and, rather,
accept NERC’s commitment to exercise its technical expertise to study these issues and develop appropriate revisions to applicable Standards as may
be necessary.”
Order No. 896, P 36: “NERC may also consider other approaches that achieve the objectives outlined in this final rule. Further, as recommended by
PJM, we believe there is value in engaging with national labs, RTOs, NOAA, and other agencies and organizations in developing benchmark events.
Considering NERC’s key role, technical expertise, and experience assessing the reliability impacts of various events and conditions, we encourage
NERC to engage with national labs, RTOs, NOAA, and other agencies and organizations as needed.”
Order No. 901, P 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.”
{C}[6]{C} Order 901, P 193
{C}[7]{C} Id. at P 178.
{C}[8]{C} Id. at P 190.
{C}[9]{C} Technical Rationale at 7.
{C}[10]{C} East Interconnection Frequency Response Assessment with Inverter Based Resources, at 7
https://www.energy.gov/sites/prod/files/2018/07/f53/2.1.4%20Frequency%20Response%20Panel%20-%20Velummylum%2C%20NERC.pdf.
{C}[11]{C} Best Practices for Operation and Maintenance of Photovoltaic and Energy Storage Systems, at 55,
https://www.nrel.gov/docs/fy19osti/73822.pdf.
{C}[12]{C}Fast Frequency Response Concepts and Bulk Power System Reliability Needs, https://www.nerc.com/comm/PC/InverterBased%20Resource
%20Performance%20Task%20Force%20IRPT/Fast_Frequency_Response_Concepts_and_BPS_Reliability_Needs_White_Paper.pdf.
{C}[13]{C} Inertia and the Power Grid: A Guide Without the Spin, https://www.nrel.gov/docs/fy20osti/73856.pdf.
{C}[14]{C} East Interconnection Frequency Response Assessment with Inverter Based Resources, at 7
https://www.energy.gov/sites/prod/files/2018/07/f53/2.1.4%20Frequency%20Response%20Panel%20-%20Velummylum%2C%20NERC.pdf.
{C}[15]{C} https://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/FRI_Report_10-30-12_Master_w-appendices.pdf
{C}[16]{C} https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-024-4_Draft_2_Clean_06182024.pdf, R3, at
pages 5-6
{C}[17]{C} https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-024-4_PRC-029-1_Implementation
%20Plan_Redline_to_Last_Posted_07222024.pdf
{C}[18]{C} https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-024-4_Draft_2_Clean_06182024.pdf, R3, at
pages 5-6
{C}[19]{C} https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-024-4_Draft_2_Clean_06182024.pdf, R3, at
pages 5-6
{C}[20]{C} Order No. 901, at P190
[21]{C}https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Comments_IBR%20Standards%20NOPR.pdf, at 21-22.
[22]{C} Order No. 901, at P185
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Brian Van Gheem - Radian Generation - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
1.
Requirements R1, R2 and R3 use the phrase “ensure design and operation” to imply a Generator Owner is required to guarantee an IBR will be
operated in Real-time as designed. We observe the Standard Drafting Team’s (SDT) previous response to the meaning of this phrase is clarified
through the “additional specificity and examples for objectively evaluating compliance” within each requirement’s measure. We believe this is
outside the scope of the NERC Protection and Control Reliability Standards, as only a Generator Operator can make such guarantees. The
scope of the Protection and Control Reliability Standards are to ensure facility equipment is properly configured and with settings that achieved
2.
3.
4.
5.
6.
7.
8.
9.
sufficient and observable reliability during facility operating simulations. Several of these Reliability Standards have periodicities that ensure the
initial design philosophy is still being achieved through repeatable simulations, even years after a facility’s commissioning date. The purpose of
NERC Reliability Standard PRC-005-6 is to ensure a facility’s Protection Systems, particularly relays, are maintained within their intended design
settings. We believe the phrase proposed by the SDT should be clarified to imply designed to operate under simulated conditions and
disturbances. For Requirement R1, we propose this clarification for consideration, “Each Generator Owner shall ensure each IBR is designed,
both initially and following the IBR’s commissioning, to meet or exceed the Ride‐through requirements in accordance with the Continuous
Operation Region specified in Attachment 1.”
We believe the possibility of an IBR limitation should not be limited to hardware. In the past, such limitations may have been imposed on
Generator Owners because some equipment manufacturers were unable to achieve functional requirements through firmware modifications.
Moreover, some equipment manufacturers terminated their business operations entirely. We believe the SDT should broaden each reference
within the Reliability Standard and omit any descriptive adjectives associated with a limitation.
Part 2.1.3 states during a voltage excursion, each Generator Owner shall ensure the design of its IBR is set to prioritize Real Power or Reactive
Power, unless overridden by another registered entity, when the voltage at the high side of the main power transformer is less than 0.95 per unit,
yet still within the continuous operation region as specified in Attachment 1, and the IBR cannot deliver both Real Power and Reactive Power. We
believe the SDT could simplify this language, as the Generator Owner will not have enough information of the Bulk Power System to make an
informed decision on the appropriate priority during anticipated system conditions and configurations in the future. We believe the SDT should
instead clarify the default priority for Generator Owners is Reactive Power, like Part 2.2.
Under Requirement R3, each Generator Owner is required to ensure its IBRs meet or exceed the Ride-through requirements during a frequency
excursion event whereby the absolute rate of change of frequency (RoCoF) magnitude is less than or equal to 5 Hz/second. This requirement
assumes the configurable function is enabled. We recommend the SDT clarify the absolute rate of change of frequency (RoCoF) magnitude
requirement is set only when such a function is enabled.
To summarize Requirement R4, any limitations identifying an IBR is unable to meet the voltage Ride‐through criteria detailed in Requirements
R1 and R2 must be documented. Under the individual parts of this requirement, there is no option available for a Generator Owner to have a
limitation indefinitely applied. We also believe Parts 4.1.4 and 4.1.5 require supporting technical documentation and plans to correct a limitation
as possible language that should be incorporated in the requirement’s measure.
We believe the SDT should modify the language of each measure for Requirements R1, R2, and R3. The phrase “but are not limited to” should
be removed within each measure. The possible evidence identified should not imply that each example is needed. We also recommend replacing
the “and” within the items of a series with an “or.”
As defined within Section 2.5 of Appendix 3A (Standard Processes Manual) of the NERC Rules of Procedure, a Measure “provides identification
of the evidence or types of evidence that may demonstrate compliance with the associated requirement.” We believe the reference to “shall”
within each measure of a requirement of this proposed Reliability Standard is misaligned with the NERC Rules of Procedure. For instance, as
proposed, each Generator Owner is required to retain evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic
Disturbance Recorder, and Fault Recorder) data to demonstrate the operation of each IBR did adhere to Ride‐through requirements. Such data
may not be available because of equipment failures that are then handled through compliance with other Reliability Standards. Entities also need
to implement their own internal processes to extract this data before a limited storage capacity overrides this historical information. We believe
the Standard Drafting Team should instead focus on identifying evidence that may demonstrate compliance, such as an ongoing design
philosophy that each IBR will meet the Ride‐through requirements in accordance with the Continuous Operation Regions specified within the
Reliability Standard’s attachments.
We believe a significant burden has been placed on Generator Owners with the expectation listed within Measure M2 that the Generator Owner
will retain, for each voltage excursion, actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault
Recorder) data to demonstrate that the operation of each IBR did adhere to this Reliability Standard’s performance requirements. It should be
noted that other proposed Reliability Standards are placing limitations on which voltage excursions are applicable for analysis. A similar burden is
listed within Measure M3 with each frequency excursion. We recommend the SDT remove this burden entirely. Instead, we propose offering a
Generator Owner an opportunity to provide their IBR’s equipment settings for the period prior to the facility’s commissioning and actual
disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data at the Generator Owner’s
discretion. If the Generator Owner needs to demonstrate their facility’s performance following a Disturbance, the actual disturbance monitoring
data will be requested under Reliability Standard PRC-030-1. Moreover, such a request should originate from an external reliability entity and not
require the Generator Owner to collect actual disturbance monitoring data following each voltage or frequency excursion.
We believe the mathematical symbol associated the 1.10 per unit voltage range listed in Attachment 1, Table 2, should be greater than and equal
to” instead of just “greater than.”
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Robert Follini - Avista - Avista Corporation - 3
Answer
No
Document Name
Comment
See EEi comments
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Patricia Lynch - NRG - NRG Energy, Inc. - 5
Answer
No
Document Name
Comment
NRG Energy Inc is in support of the comments made by EPSA.
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
No
(A) Duke Energy agrees with and supports EEI R4 comments for the three reasons cited by EEI because it is unclear how many existing resources can
meet the frequency performance standards mandated in Requirement 3 and resource owners have not been given adequate time to fully assess the
impact of imposing these new requirements on their existing resources,
(B) Duke Energy disagrees with the language in Measures 1-3 and recommends alternative language as stated below:
Measures 1-3 generally states:
“Each Generator Owner shall retain evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and
Fault Recorder) data to demonstrate the operation of each facility IBR did adhere to Ride‐through requirements,” as specified in Requirement 1/2/3.
This statement requires heavy administrative burden and data storage since it would require capturing data daily and downloading the data to a storage
location separate from the DDR,FR, & SER; since this equipment has low memory thresholds, memory could be exceeded. Accordingly, the TO/TOP
would be required to notify the GO of a grid frequency event and data could be overwritten prior to TO/TOP notification.
Recommendation:
Each Generator Owner shall retain evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and
Fault Recorder) data, “upon notification for TO/TOP” to demonstrate the operation of each facility IBR did adhere to Ride‐through requirements “or
notification of data overwrite to TO/TOP.”
(C) Measure 1, 2 and 3 language is not consistent (suggested corrections added below):
- The word data was eliminated from M1: …Fault Recorder) “data” to demonstrate…
- The word ride-through was eliminated from M2: …IBR will adhere to “Ride-through” requirements, as specified in Requirement…
- Did the SDT intentionally substitute “performance” for “Ride-through requirements” in M2 – see second sentence excerpt below?
…each IBR did adhere to “Ride-through requirements”, as specified in Requirement…
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Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer
No
Document Name
Comment
TEPC agrees with EEI's comments regarding PRC-029-1, requirement 4. EEI does not agree with imposing new unverified requirements on existing
resources as proposed in PRC-029-1 because it is unclear how many existing resources can meet the frequency performance standards mandated in
Requirement 3. We are additionally concerned because resource owners have not been given adequate time to fully assess the impact of imposing
these new requirements on their existing resources, which align with IEEE 2800-2022 (See 7.3.2.1 Figure 12 & Table 15 (Frequency ride-through, page
80; and see 7.3.2.3.5 Rate of change of frequency (ROCOF), page 82), and did not exist as a Standard until February 2022, after most of these
resources were built or placed in service. For this reason, we cannot support the approval of PRC-029-1 without the following changes to Requirement
4 ensure that existing resources that were not design and do not have the capability to meet these requirements are allowed to declare an exemption for
frequency ride-through similar to what is provided for resources that cannot meet the voltage ride-through requirements.
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Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Document Name
Comment
No
AZPS Supports the following comments that were submitted by EEI on behalf of its members:
EEI does not agree with imposing new unverified requirements on existing resources as proposed in PRC-029-1 because it is unclear how many
existing resources can meet the frequency performance standards mandated in Requirement 3. We are additionally concerned because resource
owners have not been given adequate time to fully assess the impact of imposing these new requirements on their existing resources, which align with
IEEE 2800-2022 (See 7.3.2.1 Figure 12 & Table 15 (Frequency ride-through, page 80; and see 7.3.2.3.5 Rate of change of frequency (ROCOF), page
82), and did not exist as a Standard until February 2022, after most of these resources were built or placed in service. For this reason, we cannot
support the approval of PRC-029-1 without the following changes to Requirement 4 ensure that existing resources that were not design and do not have
the capability to meet these requirements are allowed to declare an exemption for frequency ride-through similar to what is provided for resources that
cannot meet the voltage ride-through requirements. See the proposed changes to R4 below:
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of PRC-029-1, has known hardware limitations that prevent the IBR
from meeting voltage and frequency Ride-through criteria as detailed in Requirements R1, R2, and R3 and requires an exemption from specific Ridethrough criteria shall:
4.1.
Document information supporting the identified hardware limitation no later than 12 months following the effective date of PRC-029-1. This
documentation shall include:
4.1.1
Identifying information of the IBR (name and facility #);
4.1.2
Which aspects of voltage or frequency Ride-through requirements that the IBR would be unable to meet and the capability of the hardware due
to the limitation;
4.1.3
Identify the specific piece(s) of hardware causing the limitation;
4.1.4
Supporting technical documentation verifying the limitation is due to hardware that needs to be physically replaced or that the limitation cannot
be removed by software updates or setting changes, and;
4.1.5
Information regarding any plans to remedy the hardware limitation (such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA no later than 12 months following the effective date of PRC-029-1.
4.2.1
Any response to additional information requested by the associated Planning Coordinator(s), Transmission Planner(s), Transmission Operator
(s), Reliability Coordinator(s), and the CEA shall be provided back to the requestor within 90 days of the request.
4.2.2
Provide a copy of the acceptance of a hardware limitation by the CEA to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s).11
4.3.
Each Generator Owner with a previously accepted limitation that replace the hardware causing the limitation shall document and communicate
such a hardware change to the associated Planning Coordinator(s), Transmission Planner(s), Transmission Operator(s), and Reliability Coordinator(s)
within 90 days of the hardware change.
4.3.1
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When existing hardware causing the limitation is replaced, the exemption for that Ride-through criteria no longer applies.
0
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
No
Document Name
Comment
Dominion Energy supports EEI comments. Current technology does not appear to support being able to fulfill these requirements on a go forward basis.
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
No
Document Name
Comment
Please see additional comments in Question #3.
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Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
No
Document Name
Comment
Black Hills Corporation supports the comments provided by the NAGF which state: ”…recommends that PRC-029 be revised to allow for frequency ride
through (“FRT”) exemptions to address such limitations for legacy IBR facilities. Not including FRT exemptions will result in a standard that will make
certan IBR legacy facilities automatically non-compliant when the standards becomes effective.
Requirement R3 – the NAGF is concerned that legacy IBR facilities are not capable of meeting the 5 Hz/second maximum ROCOF or the 25-degree
phase angle jump requirements. Therefore, FRT exemptions are necessary and need to be included in Requirement R3.
Requirement R4.2.2 – the NAGF is unclear as to what the Compliance Enforcement Authority (CEA) acceptance for a IBR hardware limitation
exemption will consist of. Will the CEA provide an email response confiming acceptance to the Generator Owner submitting the exemption? How are
such exemptions to be submitted and to whom within the CEA organization?
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David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
No
Document Name
Comment
Vistra supports comments made by AEP (Fultz)
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
1.
2.
3.
4.
Requirement 2.1.3/2.2/2.5 - What does “other mechanisms” mean? Too vague.
Requirement 4.1.1 - change “facility #” to “facility unique identification number.”
Requirement 4.2 - “CEA” is not defined in first instance of the acronym in the document.
Multiple Requirements list several points of contact for notification (“associated” PC, TP, TO, RC, CEA). This seems like a very long list of
contacts that would likely lead to unnecessary PNCIs. Can this list be reduced?
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
No
FirstEnergy does not agree with the current draft(3) of PRC-029-1.
FirstEnergy continues to request the DT consider changing PRC-029-1 Requirement R2, part 2.5, from ‘Real Power’ to ‘Apparent Power’. To satisfy
R2.5 as written, IBR sites would need to operate in static VAR control rather than automatic voltage control (adjusting VARs to control voltage). This
would maintain a static power factor on the sites that would fail to provide effective voltage support due to manual intervention required to adjust VAR
setpoint, not allowing for immediate response to voltage changes. This weakened response to voltage changes could result in less stable grid voltage,
increasing potential for voltage trips, which does not align with the intent of the Standard. Changing this to ‘Apparent Power’ would make compliance
more achievable while improving voltage support from IBR generators, enhancing IBR stability and reliability.
FirstEnergy also does not agree with the concept of ‘Available Real Power’ as used in R2.1.1 & R2.5 and defined in in footnotes 4 & 7 of Standard draft
3. Terminology/concepts critical for determining or maintaining compliance should be clearly defined in the NERC Glossary of Terms, not nested in a
Standard footnote. For this term, specifically as it pertains to solar installations, the methods for measuring and approximating the ‘Available’ irradiance
should be defined in detail as a Standard Attachment or preferably a Reliability Guideline. This guidance is required to create design specifications and
ensure Owners/Operators consistently and uniformly quantify this resource for a given time and physical location. However, even with well-defined
methods provided, it seems the ability of an Owner/Operator to definitively prove an exception in the case of solar would be challenging and difficult to
audit; examples of evidence needed to properly justify an exception should be provided as guidance as well.
FirstEnergy also believes there could be a conflict between VAR-002 and PRC-029 for those IBR Resources meeting the applicability criteria of both
Standards. VAR-002 requires generators to operate in automatic voltage control mode, adjusting reactive power output to control voltage. Adherence to
PRC-029 R2.5 seems to directly conflict. This would require having alternative instructions from the TP/PC/RC/TOP, essentially granting an exception to
one of the two Standards, to avoid a situation of non-compliance. Further clarification from the DT is warranted addressing the overlap/conflict between
the two Standards and how an applicable IBR generator is to comply to both.
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Bruce Walkup - Arkansas Electric Cooperative Corporation - 6
Answer
No
Document Name
Comment
1. “Removing Transmission Owners (TOs) from the applicability section places all accountability during voltage and frequency excursions on the IBR’s
Generator Owner (GO) regardless of the initial incident that starts the voltage or frequency excursion and regardless of who owns any impacted
connecting equipment. This creates an inconsistency in compliance between PRC-024-4 and PRC-029-1.”
2. “The new wording in Section 2.1.3 is unclear.”
3. “Sections 2.1 and 2.2 are worded in a way that seems conflicting.”
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Thomas Foltz - AEP - 5
Answer
No
Document Name
Comment
R1, R2 and R3 state, “Each Generator Owner shall ensure the design and operation is such…” Operation of the equipment is the GOP’s responsibility,
not the GO’s. If the SDT’s intention was regarding the design of the system, AEP recommends revising the language to instead state, “Each Generator
Owner shall ensure the *operational design* is such…”.
AEP recommends removing the phrase “demonstrate the design of each facility” from the proposed standard and returning to the original event-based
requirements. The phrase may prove difficult to fully comply with, as a Functional Entity would have to know the design of the collector system and
parameters and run the models correctly to demonstrate this. Much of this needed information would need to be provided by the manufacturer, which
may require non-disclosure agreements.
There needs to be an exemption for system-related causes of ride-through failure. IBRs should be exempt from ride-through requirements in R1 through
R3 if tripping or failure to ride through is attributable to any of the following:
1. Sub-synchronous control interaction or ferro-resonance involving series compensation confirmed by the TOP, RC, TP, or PC
2. Unstable behavior of other nearby IBRs or dynamic devices such as FACTS or HVDC confirmed by the TOP, RC, TP, or PC
3. System short circuit levels during contingencies below the level of IBR stable operation confirmed by the TOP, RC, TP, or PC
4. System-level transient or oscillatory instabilities confirmed by the TOP, RC, TP, or PC
AEP is concerned by the inclusion of the phrase “other mechanisms” in this standard, and recommend it be removed from Requirements 2.1.3, 2.2, and
2.5 as we believe it could be misinterpreted or misunderstood.
AEP believes the text “any response to additional information requested” in R 4.2.1 is confusing and should be clarified. AEP suggests it instead state
“Additional information requested by the associated…”. In addition, Compliance Enforcement Authority should be spelled out in its entirety in its first use
in the standard.
R4.2.2 states an obligation to “Provide a copy of the acceptance of a hardware limitation by the CEA to the associated Planning Coordinator(s),
Transmission Planner(s), Transmission Operator(s), and Reliability Coordinator(s).” AEP recommends that insight be provided in the Technical
Rationale as to how the SDT envisions this acceptance process, and the timing thereof, would work.
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Brian Lindsey - Entergy - 1
Answer
Document Name
Comment
No
M1: This seems more like a requirement than a measure for meeting the requirement.
R2, M2, M3 and R4: Duplicative of Mod-026 and MOD-027. Also, seems to be dependent on PRC-028 passing and sites having DDRs installed.
R2 is not clear. It seems to overlap significantly with VAR-002.
R2.5 While the IBRs can respond quicker than 1 second and should be able to retore active power to the pre-disturbance level within that time-frame it
may be difficult to have enough historian capability to ensure proper evidence.
R3 No provisions for exemptions for frequency limitations.
R4.1 thru 4.2: Are we seeking approval from this large list of entities for an exemption or are we documenting the limitation that prevents from meeting
requirement 1? If we have to get approval there is no requirement in this standard that require any of these entities to provide that approval.
Recommend limiting who must be notified to just the TP or TP and RC. There needs to be a single point of contact instead multiple entities.
The CEA should not play a role in the acceptance or denial of limitations. Standards Drafting Teams have no authority to create requirements that the
CEA must adhere to therefore, there are no penalties to the CEA if they do not provide an acceptance.
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Ayslynn Mcavoy - Arkansas Electric Cooperative Corporation - 3
Answer
No
Document Name
Comment
SMEs responded with the following comments:
1.
2.
3.
“Removing Transmission Owners (TOs) from the applicability section places all accountability during voltage and frequency excursions on the
IBR’s Generator Owner (GO) regardless of the initial incident that starts the voltage or frequency excursion and regardless of who owns any
impacted connecting equipment. This creates an inconsistency in compliance between PRC-024-4 and PRC-029-1.”
“The new wording in Section 2.1.3 is unclear.”
“Sections 2.1 and 2.2 are worded in a way that seems conflicting."
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Yes
Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own.
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Yes
Document Name
Comment
The DT should cpnsider emphasizing the nature of the definition may not allow a single turbine or solar array to be lost in a System Disturbance
(equates to failed “Ride-through” with loss).
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC,Texas RE,NPCC,SERC,RF, Group Name SRC 2024
Answer
Yes
Document Name
Comment
The SRC supports the addition of Part 4.2.2.:
4.2.2 Provide a copy of the acceptance of an hardware limitation by the CEA to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s).
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Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
The work and efforts of this standard drafting team are much appreciated. Thank you for considering EPRI comments on the previous drafts as
submitted previously. The new Draft 3 appears to be improved regarding internal consistency and alignment with requirements specified in voluntary
industry standards, for example, IEEE 2800-2022. However, further improvements and alignment could be considered as follows:
A.
General comments:
•
•
•
Aligned with the directives to NERC in FERC order 901, the draft PRC-029 standard and the Implementation Plan for Project 2020-02 propose
that the requirements apply to all applicable IBRs upon the standard’s revised effective date or the newly added phased-in compliance dates.
Applicable IBRs include existing (Legacy) IBRs that are already in operation prior to the specified dates. Requirement R4 provides a path for each
Generator Owner to request a limited and documented exemption of a legacy IBR from the voltage ride-through criteria specified in R1 and R2.
According to the Implementation Plan of Project 2020-02, “[o]ther NERC Standards Development projects will be pursued to address ongoing
identification and mitigation of any potential reliability impacts to the BPS for such exemptions.” A similar exemption from Requirement R3 that
specifies applicable IBR frequency ride-through criteria is not possible according to the draft standard.
◦ The proposed approach may require documentation of hardware limitations or reconfiguration for a significant number of legacy IBRs
across North America. Neither the draft Technical Rationale nor the FERC record under RM22-12 present or cite sufficient technical
evidence that supports this broad application of the proposed standard to existing IBRs in all applicable NERC regions.
◦ International experience has shown that documentation of hardware limitations to support exemption from, or the retroactive application of
similarly stringent ride-through capability requirements on legacy IBRs are associated with significant uncertainties, potential technical and
procedural challenges, and costs. Justification of similarly ambitious regulations enforced in other countries required the production of
evidence like post-mortem disturbance analysis or case studies that quantified the potential impact of non-compliant existing IBRs on the
bulk power system stability and reliability.[1],[2]
◦ Consequently, stakeholder concerns contribute to low approval rates for the draft PRC-029, possibly causing delays in moving the draft
standard through the NERC process toward timely and effective enforcement for at least all new IBRs. Considering the approx. 2,600 GW
of new IBRs in the interconnection queues across North America[3], these delays bear potentially significant risk for the BPS.
◦ Furthermore, the proposed revised effective date and newly added phased-in compliance date of the capability-based elements of
Requirements R1, R2, and R3 as specified in the draft PRC-029 are different from the transition periods found in international practice of
similarly ambitious rule changes for new and IBRs (see the comments on Implementation Plan below for further details).
The term Inverter‐based Resource (IBR) to which the draft standard is intended to apply refers to proposed definitions being developed under
the Project 2020‐06 Verifications of Models and Data for Generators. Although the new draft includes redlines that strike the explicit mentioning
of VSC-HVDC transmission facilities that are dedicated connections for IBR to the BPS, the definition proposed by Project 2020-06 is sufficiently
broad that it could cover such facilities. For further clarity on the scope and application of the proposed PRC-029 standard, it could be helpful to
add a clarifying sentence or to copy parts of Footnote 2 that clarifies the location of the “main power transformer” in case of IBR connecting via a
dedicated VSC-HVDC transmission facility into the terms section on page 2 of the standard.
For the purpose of clarity, harmonization, and compliance of IBR across North America, proposed requirements could even further align with
requirements that are testable and verifiable as specified in voluntary industry standards developed through an open process such as ANSI,
CIGRE, IEC, or IEEE. The drafting team is encouraged to review these standards and where applicable further align, for example:
◦ Requirement R1 and R2 relate to IEEE Std 2800™-2022, Clause 7.2.2 (Voltage disturbance ride-through requirements), with consideration
of Clause 7.3.2.4 (Voltage phase angle changes ride-through) as a stated exception in R1.
◦ Requirement R3 relates to IEEE Std 2800™-2022, Clause 7.3.2 (Frequency disturbance ride-through requirements), with consideration of
Clause 7.3.2.3.5 (Rate of change of frequency (ROCOF) ride-through) as a stated exception in R3.
◦ Measures M1–M3 relate to IEEE P2800.2 Draft 1.0a, Clause 5 (Type tests), Clause 6 (Validation procedures for IBR unit models and
•
•
•
•
supplemental IBR device models), and Clause 7 (Design evaluations), Clause 8 (As-built installation evaluations), Clause 9
(Commissioning tests), Clause 10 (Post commission model validation), and Clause 11 (Post-commissioning monitoring).
◦ Measure M4, additionally, relates to IEEE P2800.2 Draft 1.0a, Clause 12 (Periodic tests), and Clause 13 (Periodic verification).
The draft standard does not specify grid conditions for which the specified ride-through requirements apply. During its lifetime, a plant may
experience many different operational conditions, along with changes to the grid, and may fail to ride-through an event if the plant was operating
in a grid condition vastly different from that which it was designed for. The standard could include an exception for such situations based on
leading industry practices, or a requirement for the TP, PC, etc. to specify such an exception.
IEEE 2800-2022 allows for an exception for “self-protection” when negative-sequence voltage is greater than specified duration and threshold
within continuous operation region. There is no such exception in draft PRC-029. Such an exception may be necessary for type III wind turbine
generator (WTG) based plants.
Standard does not allow any flexibility for failure of ride-through resulting from misoperation of protection system. The misoperation of protection
system may occur for many reasons over the life of a plant. For example, for a fault on a transmission system, if differential protection for the
main step-up transformer misoperates due to environmental issues such as damage due to water from a leaking roof or animal intrusion, then
plant would be considered out of compliance. If a synchronous machine based generating plant trips because of similar issue, it would not be out
of compliance with PRC-024.
Requirements R1–R4 call out both “design and operation”. If the plant is designed to ride-through, then is it necessary to specifically call out and
include IBR “operation” into the scope of PRC-029?
◦ The inclusion of “operation” in PRC-029 would put a Generator Owner out of compliance with the standard whenever one of their IBR
plants fails to ride-through real world disturbances, including incidents where failure of ride-through within the specified abnormal voltage
and frequency conditions was beyond the GO’s control.
◦ An alternative approach could be to narrow the scope of PRC-029 to require a Generator Owner to adequately design each IBR to have
the capability to ride-through the specified abnormal conditions. The GO could then be further required by PRC-028 and PRC-030 to
monitor IBR performance during operations and for real world events. If an IBR was found to have failed ride-through during operations,
then PRC-030 could require the GO to identify the underlying issues and to take corrective action.
B.
Ride-through definition
·
Consider adopting definition from IEEE 2800, which is from IEEE 1547, and well understood by the industry.
C.
Requirement R1:
•
•
D.
Requirement calls out “design and operation”. If the plant is designed to ride-through then is it necessary to specifically call out “operation”?
◦ The Reliability Standard PRC-006, Requirement R3, requires PC to develop UFLS program. Several assumptions are made here. If an
event occurs, then R11 requires assessment of an event and if deficiency in UFLS program is identified then PC is required to consider
deficiencies in R12. If UFLS program was deficient then PC is not out of compliance with R3 (or any other requirements in the standard).
This is a good-faith approach: Design UFLS program and if actual event shows deficiency in UFLS Program then fix it. No compliance
issues, as far as UFLS program was designed per Requirement R3.
◦ Same approach could be taken in PRC-029, where R1 could require that plant is designed to ride-through specified voltage disturbance.
The PRC-028 and PRC-030 then requires monitoring of plant performance and take corrective actions when necessary.
◦ The same approach could be extended to requirements R2 and R3.
If IBR operation remains within the scope of PRC-029, then consider revising the beginning of the sentence as following for better readability:
Each Generator Owner shall design and operate each IBR to meet or exceed Ride-through requirements…
◦ The same changes could be extended to requirements R2 and R3.
Requirement R2
•
Refer to comments on R1 that could be extended to requirement R2.
E.
Requirement R2, Part 2.1
•
•
•
F.
Why is it necessary to specify a performance requirement when voltage is in the continuous operation region? The standard remains silent on
performance expectation for frequency ride-through requirements. For performance requirement for voltage ride-through mandatory operation
region is also very brief. The intent of this standard is to focus on ride-through during voltage and frequency disturbances. If there is a desire to
address performance then one option could be to simply state that performance shall be as specified by TP, PC, etc. That is in Part 2.1.3
anyway.
Part 2.1.2: remove “and according to its controller settings”. It is not incorrect but “according to its controller settings” inherently apply to all
performance requirements.
Part 2.1.3: this requirement in IEEE 2800 was necessary and was tied to reactive power capability requirement as shown in Figure 8 of IEEE
2800. Given PRC-029 does not include reactive power capability requirements, perhaps PRC-029 could remain silent.
Requirement R2, Part 2.2
•
•
•
G.
Part 2.2 applies at the high-side of the main power transformer. The IBR is required to exchange current, up to the maximum capability. How is
the “maximum capability” of an IBR determined? There could be some explanation, perhaps with examples, in the technical rationale document.
The phrase “provide voltage support on affected phases during both symmetrical and unsymmetrical voltage disturbances” is confusing.
◦ It is understood that intent is to require to inject “unbalanced current” or “negative-sequence” current during asymmetrical faults. However,
as written, injection of balanced reactive current into an unbalanced fault meets the requirement to provide voltage support on affected
phases, in addition to unaffected phase. The standard does not prohibit voltage support on unaffected phases. The voltage support on
unaffected phase is usually problematic. But the requirement, as written, does not prohibit this.
◦ During a L-G fault, current in a faulted phase is dependent on transformer winding configuration. Does this requirement, unintentionally,
specify specific transformer configuration?
During mandatory operation, voltage is abnormal and could be almost zero for close-in faults. As such, “current” over “power” is more
appropriate. Power in faulted and unfaulted phases could be different as well. Replace real and reactive power with active (real) and reactive
current respectively.
Requirement R2, Part 2.3.1
•
H.
Per language in attachment 1, permissive operation is allowed when line-to-ground or line-to-line voltage is below 10%. But per Part 2.3.1, IBR is
required to restart current exchange when positive-sequence voltage enters continuous or mandatory operation region. This is conflicting. For
example, for a line-to-ground fault on high-side terminals of main power transformer, the positive-sequence voltage would be more than 10%, i.e.,
in the mandatory operation region.
Requirement R2, Part 2.4
•
I.
The intent of this requirement is understood. However, if there are multiple plants in the area, then one plant misbehaving may cause overvoltage
on high-side terminals of the main power transformer of other plants in the area. Also, the post-fault dynamics greatly depend on system
operating condition (peak, shoulder, off-peak, etc.) along with transmission outages, status of capacitor banks, etc. The Generator Owner usually
does not have system data to evaluate post-fault system dynamics and to determine if plant’s behavior is or not a contributing factor to
overvoltage.
Requirement R3
•
•
Refer to comments on R1 that could be extended to requirement R3.
The proposed frequency ride-through requirement is more stringent than the applicable requirement in IEEE Std 2800-2022. The justification
provided in the technical rationale is based on engineering judgement with no provided substantiating studies. Furthermore, the PRC-006
•
•
J.
requires the design of UFLS program to keep frequency withing certain bounds. Requiring IBRs to ride-through a slightly more frequency
deviation compared to frequency deviation band allowed in PRC-006 seems reasonable. However, the proposed frequency ride-through
requirement is much more stringent. Consider aligning with IEEE Std 2800 frequency ride-through requirement as a minimum requirement and let
regions specify more stringent requirements where justified.
The standard does not allow exception for frequency ride-through requirements. While the physical strain on legacy IBR plants to ride-through
frequency disturbances may be less significant compared to the strain during voltage ride-through, the capabilities of legacy IBR hardware
(including wind-turbine generators, inverters, transformers, and auxiliary equipment like fans and pumps for cooling, if present) are, at best,
uncertain. For plants in commercial operation before the effective date of this standard, installed equipment may not have been tested to the
specified frequency ride-through capability and that could make determining if a legacy IBR plant would be able to ride-through proposed
frequency ride-through requirements challenging.
◦ The SDT points to directive in FERC order 901 and states that order 901 does not allow exception for frequency ride-through. However,
order 901 does not require frequency ride-through requirements as stringent as the ones proposed.
◦ It is also not clear to us from the record in RM22-12 whether FERC intentionally limited the exemption from ride-through to only voltage
ride-through, and on what technical grounds the exemption did not also include frequency ride-through.[4],[5],[6]
Footnote 9 could be simplified as following: The ROCOF is an average rate of change of frequency over an averaging window of at least 0.1
second.
Requirement R4
•
We re-iterate the following observations related to the Effective Date and Phased-in Compliance Dates stated in the Implementation Plan of the
project, as previously offered in our EPRI comments on the initial draft of PRC-029:
o Aligned with the directives to NERC in FERC order 901, the draft proposes that all requirements specified in PRC-029 apply to all applicable IBRs
upon the standard’s effective date, including Legacy IBRs that were already in operation prior to that date. This approach may require reconfiguration or
documentation of hardware limitations for a significant number of existing IBRs across North America. In some cases, for example where the original
equipment manufacturer (OEM) of hardware used in Legacy IBRs has gone out of business, or the OEM has ceased to support a legacy hardware
product line, documentation of hardware limitations and development of models accurately representing Legacy IBR performance may be challenging.
Additional exemptions to address these challenges could be included in R4 of the draft standard or the implementation plan.
o One example for an alternative approach to the one proposed in the draft PRC-029 could be that TOs and reliability coordinators were to discern on
a regional or case-by-case basis about the application of PRC-029 to Legacy IBRs, preferably based on technical evidence like case studies assessing
and quantifying the potential BPS reliability impacts from Legacy IBR in their regions.[7] If documentation of Legacy IBR hardware limitations was not
available, worst-case assumptions could be made in these case studies. If such studies indicated a viable reliability risk, R4 could be applied to selected
or all Legacy IBRs. This could produce documentation of hardware limitations to refine study assumptions to produce more realistic case study results. If
refined results still indicated a viable reliability risk, R1-R3 could be applied to Legacy IBRs selectively.
•
•
•
K.
We refer to our questioning of FERC’s intentionality with not including an exemption for frequency ride-through capability per our comments on
Requirement R3 above.
For further comments on the Effective Date and Phased-in Compliance Dates refer to below comments on the Implementation Plan.
Parts 4.1 and 4.2 refers to exemption for a plant but part 4.3 refers to hardware in plant. If few of many wind-turbine generators in a plant are
replaced, then plant still has limitation because most of the wind-turbine generators still have limited capability. Perhaps some clarification could
be added that if “all hardware with documented capability limitation” is replaced, only then an exemption for a legacy IBR would not apply any
longer.
Violation Risk Factors
•
•
The language for the assignment of a VRF to Requirement R4 in the draft standard is truncated. Consider revising to: [Violation Risk Factor:
Lower]
Each Generator Owner is required per Requirement R4 to identify, document, and communicate about legacy IBRs that have hardware
limitations related to the voltage ride-through criteria specified in R1 and R2. Why is a VRF of “Lower” assigned to R4 and not a VRF of
“Medium”? Could the uncertainty related to the capability and performance of legacy IBRs associated with a violation of R4 (a requirement that is
administrative in nature and a requirement in a planning time frame) by a Generator Owner not, under the abnormal conditions, be expected to
directly and adversely affect the electrical state or capability of the Bulk‐Power System, or the ability to effectively control the Bulk Power
System?
L.
Violation Severity Levels
•
R1, R2, and R3: The lower VSL for each of these requirements is for failure to demonstrate the design capability to ride-through. There are two
reasons for which this could arise:
(1) Plant is capable to ride-through but is not demonstrated in design evaluation or interconnection studies.
(2) Plant is not capable to ride-through and that is demonstrated in design evaluation or interconnection studies.
•
•
Reason (1) is not a problem for grid reliability, it is just that studies are not adequate to demonstrate ride-through capability, and hence lower VSL
is justified. But reason (2) is not any different from a case in severe VSL where an entity fails to demonstrate that IBR adhered to ride-through
requirements (based on actual system disturbance event data).
The VSLs could be rephrased to read:
◦ Lower VSL: The Generator Owner failed to produce adequate evidence demonstrating for each applicable IBR that it was designed to
Ride-through in accordance with …
◦ Severe VSL: The Generator Owner either produced evidence demonstrating for any of their applicable IBR that it was not adequately
designed to adhere to Ride-through, or the Generator Owner failed to produce evidence of actual disturbance monitoring data for a specific
event that demonstrate each applicable IBR adhered to Ride-through requirements in accordance with …
M. Attachment 1
•
•
•
•
•
Tables 1 and 2 are inconsistent. Table 1 states “>= 1.10” whereas Table 2 states “>1.10”.
Clarify that cumulative window, for voltage band where ride-through duration is 1800-second, is 3600-second. Also, consider clarifying that 1800second ride-through duration is only applicable to nominal voltages other than 500 kV.
Numbered item #3: states that applicable voltage is “… on the AC side of the transformer(s) that is (are) used to connect…..”. Both sides of
transformer are AC, one is on DC-AC converter side and another on AC grid side. As written, voltage on either side of transformer is applicable.
Please clarify that applicable voltage is on AC “grid” side of the transformer.
Numbered item #5: Consider revising as following - The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of phase-to[strike: neutral] [add: ground] or phase-to-phase fundamental [add: frequency] root mean square (RMS) voltage at the high-side of the main
power transformer.
Numbered item #7: The interpretation of ride-through curves/points needs further clarification. Would a wind-based IBR plant be required to ridethrough an event where at t=0 voltage drops from nominal to zero, then @t=0.16 s voltage rises to 25%, @t=1.2 s voltage rises to 50%, @t=2.5 s
voltage rises to 70%, @t=3 s voltage rises to 90%? The item (8) is also tied to item (12), where a combined “area” is stated. Does must ridethrough zone represent an “area” (represented by deviation in voltage multiplied by time duration)? Consider adding a few examples in the
technical rationale.
◦ Note that IEEE 2800-2022, informative Annex D, Section D.1 (Interpretation of voltage ride-through capability requirements specifies)
states that the interpretation used in the standard is a “voltage versus time curve.” However, the same Annex includes a Figure D.4 that
intends to show “a realistic and complex trajectory of a voltage during a disturbance” for which the informative annex then further states
that an IBR plant “is required to ride through,” effectively interpreting the IEEE 2800-2022 ride-through curves as a “voltage versus time
envelope.” Thus, there seems to be some ambiguity in IEEE 2800-2022 as to how to interpret its ride-through curves, a finding that could
be considered and resolved in a potential future revision or amendment of IEEE 2800.
◦ If the voltage ride-through requirements proposed in Attachment 1 were to be specified or interpreted as a “voltage versus time envelope,”,
and considering that an unknown number of IEEE SA balloters that voted affirmatively on IEEE 2800-2022 may have interpreted the IEEE
2800-2022 requirements as the less stringent “voltage versus time curves” explained in Annex D of the standard, the proposed PRC-029
could be perceived as more stringent than IEEE 2800-2022.
◦ Adding a few examples in the technical rationale could help clarify the correct interpretation of the voltage ride-through curves specified in
Attachment 1.
•
N.
Numbered item 10: Please clarify if this statement applies to protection applied to high side of main power transformer only OR everywhere in the
plant.
Attachment 2:
•
•
•
O.
Table 3: To be consistent with other frequency thresholds, could “> 61.2” be “>= 61.2” instead. If so, range for continuous operation then be “<
61.2 and > 58.8”.
Consider adding a statement that frequency ride-through requirements apply only when voltage is in the must ride-through zone.
Numbered item 3: What is meant by control settings? Is the intent to state protection settings instead?
Implementation Plan
•
The proposed revised effective date and newly added phased-in compliance date of the capability-based elements of Requirements R1, R2, and
R3 as specified in PRC-029-1 for primarily new IBRs of,
◦ “the first day of the first calendar quarter that is twelve months [emphasis added by EPRI] after” either “the effective date of the applicable
governmental authority’s order approving” or “the date the standard is adopted by the NERC Board of Trustees” for (primarily new) Bulk
Electric System IBRs, and
◦ “until the later of: (1) January 1, 2027; or (2) the effective date of the standard” for (primarily new) Applicable Non-BES IBRs
are different from transition periods found in international practice of similarly significant rule changes for new IBRs. Examples for reference include, but
are not limited to:
•
◦
◦
(European) Commission Regulation (EU) 2016/631 of 14 April 2016 establishing a network code on requirements for grid connection of
generators, Article 72 (Entry into force) states, “the requirements of this Regulation shall apply from three years [emphasis added by EPRI]
after publication.” [8]
German Government, “Verordnung zu Systemdienstleistungen durch Windenergieanlagen (Systemdienstleistungsverordnung –
SDLWindV) (Ordinance for Ancillary Services of Wind Power Plants (Ancillary Services Ordinance - SDLWindV),”[9]
Mandatory requirement for new wind power plants to meet specified requirements by March 31, 2011, i.e., 19 months after ordinance entered into
force.
•
◦
ERCOT, “Issue NOGRR245. Inverter-Based Resource (IBR) Ride-Through Requirements. Report of Board Meeting on June 18,
2024,”[10] and ERCOT, “Nodal Operating Guide Revision Request (NOGRR) 245, Inverter-Based Resource (IBR) Ride-Through
Requirements. ERCOT Update,” August 8, 2024.”[11]
All new IBRs with a Standard Generation Interconnection Agreement (SGIA) after August 1, 2024, i.e., immediately once the NOGRR enters into
force (subject to change until ERCOT board approval and until there is a non-appealable Public Utility Commission of Texas (PUCT) final order is in
place)
Extension of exemption from requirements new IBRs with a Standard Generation Interconnection Agreement (SGIA) after August 1, 2024, does
not exceed December 31, 2028, i.e., 4 years and 4 months (subject to change until ERCOT board approval and until there is a non-appealable Public
Utility Commission of Texas (PUCT) final order is in place)
•
The proposed revised effective date and newly added phased-in compliance date of the Requirement R4 as specified in PRC-029-1 for primarily
legacy IBRs of,
◦ “the first day of the first calendar quarter that is twelve months [emphasis added by EPRI] after” either “the effective date of the applicable
governmental authority’s order approving” or “the date the standard is adopted by the NERC Board of Trustees” for (primarily legacy) Bulk
Electric System IBRs, and
◦
“until the later of: (1) January 1, 2027; or (2) the effective date of the standard” for (primarily legacy) Applicable Non-BES IBRs
are either not applicable, or—for re-configurations that do not require replacement of hardware—comparable, or—for retrofits that do require
replacement of hardware—they are different from transition periods found in national and international practice of similarly significant retro-active
enforcements for legacy IBRs. Examples for reference include, but are not limited to:
•
◦
(European) Commission Regulation (EU) 2016/631 of 14 April 2016 establishing a network code on requirements for grid connection of
generators, Article 4 (Application to existing power-generating modules) states, [12]
-
“Existing power-generating modules are not subject to the requirements of this Regulation, except where: … .”
-
“For the purposes of this Regulation, a power-generating module shall be considered existing if:
·
(a) it is already connected to the network on the date of entry into force of this Regulation; or
·
(b) the power-generating facility owner has concluded a final and binding contract for the purchase of the main generating plant by two years
[emphasis added by EPRI] after the entry into force of the Regulation.
•
◦
-
German Government, “Verordnung zu Systemdienstleistungen durch Windenergieanlagen (Systemdienstleistungsverordnung –
SDLWindV) (Ordinance for Ancillary Services of Wind Power Plants (Ancillary Services Ordinance – SDLWindV)),”[13]
Financial incentive for voluntary retrofits of legacy wind power plants between July 11, 2009, and January 1, 2011, i.e., 1.5-years.
•
◦
German Government, “Verordnung zur Gewährleistung der technischen Sicherheit und Systemstabilität des
Elektrizitätsversorgungsnetzes (Systemstabilitätsverordnung - SysStabV) (System Stability Regulation – SysStabV)),“[14]
Mandatory requirement for reconfiguration of legacy IBRs and distributed energy resources (DERs) larger than 100 kW by August 31, 2013, i.e.,
13 months after ordinance entered into force.
•
◦
ERCOT, “Issue NOGRR245. Inverter-Based Resource (IBR) Ride-Through Requirements. Report of Board Meeting on June 18,
2024,”[15] and ERCOT, “Nodal Operating Guide Revision Request (NOGRR) 245, Inverter-Based Resource (IBR) Ride-Through
Requirements. ERCOT Update,” August 8, 2024.”[16]
Mandatory requirement for legacy IBRs with an SGIA executed prior to August 1, 2024 to maximize the performance of their protection systems,
controls, and other plant equipment (within equipment limitations) to achieve, as close as reasonably possible, the capability and performance set forth
in IEEE 2800-2022 no later than December 31, 2025, i.e., 17 months after NOGRR enters into force.
Extension of exemption from requirements for legacy IBRs with a Standard Generation Interconnection Agreement (SGIA) prior to August 1, 2024,
does not exceed December 31, 2027, i.e., 3 years and 4 months (subject to change until ERCOT board approval and until there is a non-appealable
Public Utility Commission of Texas (PUCT) final order is in place)
•
P.
The first use of the word “or” in the sentence under the section Effective Date and Phased-in Compliance Dates, PRC-029-1 Phased-in
Compliance Dates, Requirement 4, Applicable Non-BES IBRs on page 5 of the Implementation Plan could be replaced for clarity with the word
“for” to then read: Entities shall not be required to comply with Requirement R4 for their non-BES IBRs until the later of: (1) January 1, 2027; or
(2) the effective date of the standard.
Technical Rationale
•
IEEE Std 2800™-2022, a voluntary industry standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting
with Associated Transmission Electric Power Systems is mentioned in the Technical Rationale document for PRC-029-1 but not cited properly. In
all instances where the document refers to that IEEE standard, referencing could be improved by following our guidance offered below. Where
appropriate, reference to and proper citation of IEEE P2800.2, an active IEEE Standards Association project for developing of a Recommended
Practice for Test and Verification Procedures for Inverter-based Resources (IBRs) Interconnecting with Bulk Power Systems, may serve as an
additional reference.
◦ Suggested referencing of IEEE Std 2800™-2022:
For the initial citation within any document, we suggest citing the standard as follows: IEEE Std 2800™, IEEE Standard for Interconnection and
Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
-
Subsequent mentions of the standard could refer to it as: IEEE 2800
•
◦
Similar guidelines could be applied to IEEE Std 2800.2™:
We recommend citing the standard in full on first reference as: IEEE P2800.2, Draft Recommended Practice for Test and Verification Procedures
for Inverter-based Resources (IBRs) Interconnecting with Bulk Power Systems
-
Followed by subsequent mentions as: IEEE P2800.2
•
•
Q.
Considering the explicit statements in the "PRC-029-1_Technical_Rationale" document about the intended alignment with IEEE Std 2800™-2022
requirements in formulating the technical content of PRC-029-1 by the drafting team, references to specific clauses of IEEE Std 2800™-2022
could provide more clarity to industry stakeholders about which parts of the IEEE standard the PRC-029-1 aims to incorporate. It may also be
helpful to identify areas where they are not aligned. Refer to the examples in our general comments above.
IEEE 2800-2022 may not be the only industry standard with scope that overlaps with the proposed PRC-029 standard. ANSI and CIGRE
currently may not have related standards. While IEC does have standards and technical specifications with related scope, these documents tend
to be less specific in their technical requirements compared to IEEE standards like IEEE 2800-2022.[17]
Justifications
•
•
The table for “VRF Justifications for PRC-029-1, Requirement R3” on page 11 of the Justifications lists a Proposed VRF of “Lower”; but the draft
PRC-029 standard assigns R3 a “[Violation Risk Factor: High]”. Consider resolving inconsistency across the two documents.
Refer further to the comment on the VRF assignment for Requirement R4 above.
[1] Grid Codes for Interconnection of Inverter-Based Distributed Energy Resources by Country: Recent Trends and Developments. EPRI. Palo Alto, CA:
November 2014. 3002003283. [Online] https://www.epri.com/research/products/000000003002003283 (last accessed, January 24, 2023)
[2] Dispersed Generation Impact on CE Region Security: Dynamic Study. 2014 Report Update. European Network of Transmission System Operators
for Electricity (ENTSO-E), ENTSO-E SPD Report, Brussels, Belgium: December 2014. [Online] https://eepublicdownloads.entsoe.eu/cleandocuments/Publications/SOC/Continental_Europe/141113_Dispersed_Generation_Impact_on_Continental_Europe_Region_Security.pdf (last
accessed, January 24, 2023)
[3] LBNL (2024) [Online] https://emp.lbl.gov/generation-storage-and-hybrid-capacity
[4] E-1-RM22-12-000.pdf [Online] https://www.ferc.gov/media/e-1-rm22-12-000 (last accessed, August 6, 2024)
[5] 20230206-5094_ACP-SEIA IBR NOPR comments (Final).pdf [Online] https://elibrary.ferc.gov/eLibrary/filedownload?fileid=49DB8845-A3E3-CEEAA6D8-86289C500000 (last accessed, August 6, 2024)
[6] E-2-RM22-12-000.pdf [Online] https://www.ferc.gov/media/e-2-rm22-12-000 (last accessed, August 6, 2024)
[7] EPRI is currently working on case studies relevant to these topics and is also aware of others doing similar work.
[8] ENTSO-E: Requirements for Generators. [Online] https://www.entsoe.eu/network_codes/rfg/ (last accessed, August 6, 2024)
[9] Federal Law Gazette I (no. 39) (2009): 1734–46. [Online] https://www.clearingstelle-eeg-kwkg.de/gesetz/695 (last accessed, August 6, 2024)
[10] ERCOT, “Issue NOGRR245. [Online] https://www.ercot.com/mktrules/issues/NOGRR245 (last accessed, August 9, 2024)
[11] ERCOT, “Nodal Operating Guide Revision Request (NOGRR) 245, Inverter-Based Resource (IBR) Ride-Through Requirements. ERCOT Update,”
August 8, 2024 [Online] https://www.ercot.com/calendar/08082024-NOGRR245-_-Review-of (last accessed, August 9, 2024)
[12] Ref. Footnote 10
[13] Federal Law Gazette I (no. 39) (2009): 1734–46. [Online] https://www.clearingstelle-eeg-kwkg.de/gesetz/695 (last accessed, August 6, 2024)
[14] Federal Law Gazette I (no. 40) (2012): 1635. [Online] https://www.gesetze-im-internet.de/sysstabv/BJNR163510012.html (last accessed, August 6,
2024)
[15] Ref. Footnote 16
[16] Ref. Footnote 17
[17] Example IEC standards and technical specifications with related scope may include IEC 61400-27, IEC 62934:2021, IEC TS 63102:2021, and IEC
TR 63401-4:2022.
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Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Yes
Document Name
Comment
PNM agrees with the comments of EEI.
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Nick Leathers - Ameren - Ameren Services - 3 - SERC
Answer
Yes
Document Name
Comment
Ameren recommends that the drafting team clarify the phrase "current block mode." Additionally, there is some concern that the technical requirements
are so rigid that it might become challenging for utilities to implement a cost effective solution for the entity and customers. Additionally, Ameren
supports the responses from both EEI and NAGF for this question.
R1, bullet point #2:
R1 suggests that we have to set protection so that we do not trip until capabilities are exceeded, which is not how Ameren sets protection. Ameren sets
protection systems to operate before capabilities of equipment are exceeded. In addition, engineers should be setting relays per capabilities of
equipment to prevent damage and to maximize their capability. We do not suggest using a generic capability when equipment may have higher
capabilities. We suggest replacing the second bullet with the following and removing the last bullet.
"The applicable in-service protection system devices are set to operate to isolate or de-energize equipment in order to limit or prevent damage when the
voltage or Volts per Hz (V/Hz) at the high-side of the main power transformer exceed accepted equipment capabilities in accordance with requirement
R4; or"
Then add a footnote:
"If the Volts per Hz (V/Hz) withstand capability of the main power transformer is not available for an existing facility, then the applicable in-service
protection system may be set to isolate or de-energize equipment if the volts per Hz at the high-side of the main power transformer exceed 1.1 per unit
for longer than 45 seconds or exceed 1.18 per-unit for longer than 2 seconds"
R4, 4.1.2:
In Ameren's experience, manufacturers are unwilling to share hardware capabilities on the inverter and claim it is proprietary or some other reason. We
suggest a re-write of 4.1.2 to add an exclusion such as the following:
"...If the Functional Entity has requested the capability of the hardware limitation, but the manufacturer will not provide the capability, the Functional
Entity must provide evidence that they have made the effort to request this information from the manufacturer and provide this in lieu of the capability."
Ameren requests the SDT to provide 2 years to verify compliance with R1, R2, R3 and R4 of the standard since the requirements are extensive.
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Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
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0
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer
Yes
Document Name
Comment
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0
Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Yes
Document Name
Comment
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0
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Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
Yes
Document Name
Comment
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Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer
Document Name
Comment
Yes
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Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Yes
Document Name
Comment
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0
Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Yes
Document Name
Comment
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0
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Casey Jones - Berkshire Hathaway - NV Energy - 5 - WECC
Answer
Yes
Document Name
Comment
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0
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Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Yes
Document Name
Comment
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Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
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0
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0
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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
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Bobbi Welch - Midcontinent ISO, Inc. - 2
Answer
Document Name
Comment
MISO supports the addition of Part 4.2.2.:
4.2.2 Provide a copy of the acceptance of an hardware limitation by the CEA to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s).
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Southern Company appreciates the work of the SDT but would like to offer the follwing changes for consideration:
•
•
•
•
•
•
There is a risk that changes to the IBR definition under Project 2020-06 may alter the definition for that contained in PRC-029, thus complicating
standard implementation.
Without providing technical justification, a FRT curve is more stringent than IEEE2800. In addition, industry has not been provided with any
technical studies justifying the need for the proposed 6-second FRT bands. Southern Company recommends that the SDT align the FRT
requirements with IEEE 2800. Individual Regions should be allowed to adopt more stringent FRT standards based on their respective system
needs and resource capabilities.
There is no technical justification for No FRT exemptions. (other than the “Regulatory Rationale” provided from FERC 901 Order). Section 215(d)
(2) of the FPA requires FERC to give “due weight” to the technical expertise of the ERO when evaluating the content of a proposed Reliability
Standard or modification to a Standard.
The ROCOF requirement may be infeasible for certain legacy IBRs that are unable to disable ROCOF protection and distinguish between fault
and non-fault conditions.
Table 1 and 2 footnote 6 states that the voltage ride through charts are only valid when frequency is within the “must Ride-through zone” as
specified in Figure 1 of Attachment 2. The SDT should add a similar footnote to Attachment 2 Table 3 FRT table stating that the frequency ride
through charts are only valid when voltage is within the “must Ride-through zone”. Illustrated in the Voltage Ride-through figures.
In the Implementation Plan, Southern Company recommends extending the capability due date from 12 months of effective date of standard to
18 – 24 months due to expected complexity of solution development and deployment.
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Martin Sidor - NRG - NRG Energy, Inc. - 6
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Document Name
Comment
NRG agrees with and refers the SDT to the EPSA comments.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has the following clarifying comments on PRC-029-1:
•
Texas RE recommends correcting Requirement R2 subpart 2.3.1:
2.3.1 If a an IBR enters current blocking mode, it shall restart current exchange in less than or equal to five cycles of positive sequence voltage returning
to a continuous operation region or mandatory operation region
•
•
In Requirement Part 4.1.1, Texas RE recommends changing “facility #” to “facility unique identifier” or “facility unique number”.
Texas RE recommends Compliance Enforcement Authority (CEA) should be spelled out in Requirement R4 subpart 4.2 since it is the first time
seeing that term in the requirement language.
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0
3. Provide any additional comments for the Drafting Team to consider, if desired.
Bruce Walkup - Arkansas Electric Cooperative Corporation - 6
Answer
Document Name
Comment
None.
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
None
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
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Document Name
Comment
N/A
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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name
Comment
Section 4: Applicability:
4.2 is not aligned with the PRC-028. The DT should consider the alignment of the applicability section between all IBR standards.
1)
It is not clear what “The Elements associated with..” means in 4.2.1. Does it mean power system elements?
R2:
The new wording in Section 2.1.3 is unclear.
MH recommends it be changed to “Prioritize Real Power or Reactive Power delivery when the voltage is less than 0.95 per unit, the voltage is within the
continuous operating region, and the IBR cannot deliver both Real Power and Reactive Power due to a current limit or Reactive Power limit unless
otherwise specified through other mechanisms by an associated Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission
Operator.”
R3:
MH is still concerned with the lack of provisions for exemptions for frequency limitation (RoCoF) that may put some of the legacy IBR in a non-compliant
state and may require a costly upgrade to meet R3 requirements.
MH recommends the following:
Extending the implementation date for R3 for legacy IBR to 18 months
or/and
Lowering the RoCoF for legacy IBR from 5 Hz /second to 3Hz/ second
R4:
The CEA is not a defined NERC term in the Glossary of Terms Used in NERC standard list, MH recommends spelled out Compliance Enforcement
Authority (CEA) in Requirement R4 subpart 4.2 since it is the first time seeing that term in the requirement language.
Attachment #1:
MH agrees with removing the previous figures 1 and 2 from attachment # 1 but we recommend adding at least three voltage waveform examples into
TR to illustrate how the Table 1 and 2 should be used to determine the compliance with voltage ride through
TR:
More information should be added to some frequency waveform examples in TR to illustrate how to calculate the RoCoF
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
Tri-State agrees with the additional comments provided by the MRO NSRF.
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Dominion Energy supports EEI comments.
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Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of its members:
EEI offers the following additional comments on the proposed 3rd draft of PRC-029-1:
·
EEI does not support the inclusion of the phrase “The Elements associated with” as contained in the Facilities Section (4.2.1). The inclusion of this
phrase expands the scope in ways that are unclear creating unnecessary compliance confusion.
·
Bullet 1 under Requirement R1 is unnecessary and should be deleted, noting that facilities are never obligated to stay connected to a fault.
·
EEI asks that the DT provide additional clarity to Requirement R4, subpart 4.2.2 noting that there is insufficient clarity regarding what is needed to
support a hardware limitation and what the deadline is for the submission of a limitation.
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
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Document Name
Comment
Duke Energy agrees with and supports submitted EEI Additional Comments.
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Robert Follini - Avista - Avista Corporation - 3
Answer
Document Name
Comment
none
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Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Document Name
Comment
The language in Section 4, Applicability does not match the language used in the latest proposed version of PRC-028-1. Although the language in
PRC-029-1 is cleaner and preferred, it is not quite clear what is meant by the inclusion of the words “The Elements associated with” in Section 4.2.1.
These words are unnecessary.
SMUD would prefer that the drafting team delete these words and change Section 4, Applicablity to the language below. The language used in Section
4, Applicability for the currently proposed PRC-028-1, PRC-029-1 and PRC-030-1 should match. This change is non-substantive and could be made in
the final ballot.
The existing language in PRC-029-1 (and PRC-030-1) is as follows:
4.1 Functional Entities:
4.1.1. Generator Owner
4.2 Facilities:
4.2.1. The Elements associated with (1) Bulk Electric System (BES) IBRs; and (2) Non-BES IBRs that either have or contribute to an aggregate
nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point
of connection at a voltage greater than or equal to 60 kV.
The existing language in PRC-028-1 is as follows:
4.1. Functional Entities:
4.1.1. Generator Owner that owns equipment as identified in section 4.2
4.2. Facilities:
4.2.1 BES Inverter-Based Resources
4.2.2 Non-BES Inverter-Based Resources that either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA,
connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV
SMUD’s preferred language in PRC-029-1 Section 4, Applicability is as follows:
4.1 Functional Entities:
4.1.1. Generator Owner
4.2. Facilities:
4.2.1 BES Inverter-Based Resources
4.2.2 Non-BES Inverter-Based Resources that either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA,
connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.
SMUD also agrees with the comments submitted by the MRO NSRF on Requirements R2, R3, R4, and Attachment 1.
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Casey Jones - Berkshire Hathaway - NV Energy - 5 - WECC
Answer
Document Name
Comment
NV Energy agrees with the NSRF comments especially on the lack of exceptions for legacy IBR systems (R3)
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Brian Van Gheem - Radian Generation - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
1.
2.
3.
We believe NERC should coordinate the Implementation Plans for the three standard development projects associated with Milestone 2 of its
work plan to address the directives within FERC Order No. 901. This would give most Generator Owners one set of compliance implementation
dates to track. The phased-in compliance dates should align with those proposed under NERC Standard Development Project 2021-04,
Reliability Standards PRC-002-5 and PRC-028-1, as those dates have been well vented across industry. As that project has proposed for some
Generator Owners, this can be as much as within three (3) calendar years of the standard’s effective date for 50% of those Generator Owners’
BES Inverter‐Based Resources. Then the rest of their BES Inverter‐Based Resources must be compliant by January 1, 2030. The SDT Project
2021-04 SDT made similar simplifications for other Generator Owners with future IBRs yet to commission and for Category 2 Generator Owners.
We point out a misspelling of the work “ride-through” within the first paragraph of the Background Section of the Implementation Plan.
Thank you for the opportunity to comment.
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 3
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Ruchi Shah - AES - AES Corporation - 5
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Document Name
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•
•
•
•
AES CE is concerned by the language in several Measures reading “Each Generator Owner and Transmission Owner have evidence of actual
disturbance monitoring…”. There will be many plants that do not experience an applicable disturbance before this Standard becomes effective
and therefore cannot demonstrate adherence to ride-through requirements as prescribed. We are also concerned about expectations for this
Measure as time goes on, are we expected to document and record every applicable disturbance and the asset’s performance? Setting up
monitoring/tracking/retention for this portion of the Measures is a huge additional burden that will be ongoing unless clarification is provided.
OEMs have not been forthcoming with operating limit data/equipment trip capabilities, and will not comment on or approve alternative proposed
settings without a significant amount of studies and simulations from the GO first. Due to the lack of information from OEMs, we are concerned
that the exemption process in R4 will be impossible to meet within the 12 month timeframe for larger GOs.
Quality EMT models including all equipment information needed are not available for legacy equipment (inverters, PPCs). Many legacy inverters
do not have an EMT model, and those that do have models are not adequately validated against equipment performance. Creation of models is
either not supported or can be developed at very high cost. Models created after the inverters were initially released are of inadequate quality
because the equipment is no longer able to be in a lab environment.
To consider this, AESCE suggests that the SDT include exceptions for legacy equipment where the performance may not be predictable
specifically due to a lack of modeling or inverter information.
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Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1
Answer
Document Name
Comment
TAL understands that the committee was following previous precedent of the 20MVA or greater facilities; however, we believe this standard will create
undue hardship on utilities who will be required to meet this standard. 20MVA seems like a low threshold for the size of IBRs. TAL believes the impact
of IBRs as small as 20 MVA seems minimal to the integrity of the BES.
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
Comment
The NAGF has no additional comments.
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Alison MacKellar - Constellation - 5
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Document Name
Comment
Constellation has no additional comments.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
Comment
Section 4: Applicability:
4.2 is not aligned with the PRC-028. The DT should consider the alignment of the applicability section between all IBR standards.
1) It is not clear to me what “The Elements associated with...” means in 4.2.1. Does it mean power system elements?
R2 The new wording in Section 2.1.3 is unclear.
MRO NSRF recommends it be changed to “Prioritize Real Power or Reactive Power delivery when the voltage is less than 0.95 per unit, the voltage is
within the continuous operating region, and the IBR cannot deliver both Real Power and Reactive Power due to a current limit or Reactive Power limit
unless otherwise specified through other mechanisms by an associated Transmission Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator.”
R3 The MRO NSRF is still concerned with the lack of provisions for exemptions for frequency limitation (RoCof) that may put some of the legacy IBR in
a non-compliant state and may require a costly upgrade to meet R3 requirements.
MRO NSRF Recommends the adoption of a frequency ride requirement for legacy equipment be delayed until Generator Owners can properly evaluate
the capability of legacy equipment.
R4 The CEA is not a defined NERC term in the Glossary of Terms Used in NERC standard list, MRO NSRF recommends spelling out Compliance
Enforcement Authority (CEA) in Requirement R4 subpart 4.2 since it is the first time seeing that term in the requirement language.
Attachment #1
MRO NSRF agrees with removing the previous figures 1 and 2 from attachment # 1 but we recommend adding at least three voltage waveform
examples into TR to illustrate how the Table 1 and 2 should be used to determine the compliance with voltage ride through
TR More information should be added to some frequency waveform examples in TR to illustrate how to calculate the RoCoF.
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Junji Yamaguchi - Hydro-Quebec (HQ) - 1,5
Answer
Document Name
2020-02_Unoffical_Comment_Form_07222024(HQ).docx
Comment
see attached file
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Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Document Name
Comment
R3 refers to “must Ride-through zone” but Attachment 2 does not identify what this zone is.
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Kimberly Turco - Constellation - 6
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Document Name
Comment
Constellation has no additional comments.
Kimberly Turco on behalf of Constellation Energy Segments 5 and 6.
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Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
Document Name
Comment
Madison Gas and Electric supports the comments of the MRO NSRF.
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
MP agrees with MRO’s NERC Standards Review Forum’s (NSRF) additional comments.
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Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer
Document Name
Comment
RF appreciates the improvements made in this version.
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Romel Aquino - Edison International - Southern California Edison Company - 3
Answer
Document Name
EEI Near Final Draft Comments _ Project 2020-02 PRC-029 Draft 3 _ Rev 0f __ 8_09_2024.docx
Comment
See comments submitted by the Edison Eclectic Institute in the attached file.
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI Comments
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Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI offers the following additional comments on the proposed 3rd draft of PRC-029-1:
•
•
•
EEI does not support the inclusion of the phrase “The Elements associated with” as contained in the Facilities Section (4.2.1). The inclusion of
this phrase expands the scope in ways that are unclear creating unnecessary compliance confusion.
Bullet 1 under Requirement R1 is unnecessary and should be deleted, noting that facilities are never obligated to stay connected to a fault.
EEI asks that the DT provide additional clarity to Requirement R4, subpart 4.2.2 noting that there is insufficient clarity regarding what is needed to
support a hardware limitation and what the deadline is for the submission of a limitation.
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Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
LG&E/KU greatly appreciates the SDT’s work and is providing feedback with the intent of providing helpful input that will assist in creating a clearer and
more consistent standard to meet the FERC directives. We acknowledge the large number of comments provided and thank the drafting team for their
work on this standard. A summary of our most substantive feedback is below:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
Change R1 to apply to voltage and frequency Ride-through (and renumber R1 -> R3, R2 -> R1, and R3 -> R2).
Remove footnote 3 or, at minimum, clarify that current blocking is allowed only if not prohibited by the associated functional entities.
Ensure M1 addresses all of the exemptions in R1.
Replace “Reactive Power limit” with “apparent power limit” in R2 Part 2.1.3, and restore the “according to the requirements …” language.
R2 Part 2.3 should clarify that current blocking is acceptable only if not prohibited by the associated functional entities.
All mentions of continuous, mandatory, and/or permissive operating regions should include a reference to Attachment 1 (e.g., “specified in
Attachment 1”) since these terms are no longer defined terms.
Move R4 Part 4.2.2 up a level (i.e., 4.2.2 -> 4.3, 4.3 -> 4.4) and include a timeline for the GO to notify the associated functional entities after it has
received an acceptance or rejection of its hardware limitation.
Modify items 1 and 2 in Attachment 1 to better address hybrid plants.
Remove the second sentence of item 7 in Attachment 1.
Add an item in Attachment 1 defining “deviation”.
Add an item in Attachment 1 permitting IBRs to trip for consecutive voltage deviations subject to the requirements of the associated functional
entities.
Add an item in Attachment 2, “Table 3 is only applicable when the voltage is within the “must Ride-through zone” as specified in Attachment 1.”
Modify Table 3 to match IEEE 2800 requirements.
Remove Figure 1.
In locations where alternative performance requirements are discussed, either add Transmission Owner to the list of entities or replace the list
(TP, PC, RC, or TOP) with “the associated functional entities”. It is the TO that is responsible for establishing and evaluating interconnection
requirements for interconnecting generation Facilities (FAC-001/002).
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Nick Leathers - Ameren - Ameren Services - 3 - SERC
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Document Name
Comment
Ameren does not have any additional comments for consideration by the drafting team.
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Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
Document Name
Comment
Each requirement contains statement “…shall ensure the design and operation is such that …”. The statement has no quantitative meaning nor direct
requirements. Let’s take R2.2. or R2.3. for example:
Assuming SDT members own and operate IBRs, please explain WHAT YOU WILL DO to comply with R2.2. and R2.3.
WEC Energy Group requests that the Implementation Guidance document be created and published to help industry better understand this convoluted
and unclear standard and how to implement it. Following is an example of a standard being unclear:
R2. “Each Generator Owner shall ensure the design and operation is such that the voltage performance for each IBR adheres to the following during a
voltage excursion, unless a documented hardware limitation exists in accordance with Requirement R4.”
What is defined as “voltage excursion”? Is it the voltage outside the region identified in Attachment 1, or is it something else?
Further, R2.1. goes on to state: “While the voltage at the high-side of the main power transformer remains within the continuous operation region as
specified in Attachment 1, each IBR shall..”.
If the voltage remains within the “continuous operating region”, how is that a “voltage excursion”.
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Carver Powers - Utility Services, Inc. - 4
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Document Name
Comment
In our entity’s review of this project, we are voting in the affirmative. We understand and appreciate that this project addresses important considerations
for reliability and security responsiveness. However, we also recognize that this project in its current form presents compliance and performance risks
that remain unresolved. While affirmatively supporting this project to address the immediate regulatory assignments tied to FERC Order 901, NERC and
the ERO must continue a constructive dialog with industry beyond this vote to truly optimize the impacts of this project on reliability, sustainability, and
affordability. We encourage NERC to permit extending the SDT team and project to offer prospective enhancements or revisions to satisfy these
compliance and performance risks.
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Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
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Document Name
Comment
PNM agrees with the comments made by EEI.
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Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
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Document Name
2020-02_EPRI Comments on Draft 3 of NERC PRC-029 (IBR ride-through) Reliability Standard.pdf
Comment
I.
Introduction
1.
The Electric Power Research Institute (EPRI)[1] respectfully submits these comments (This Response) in response to North American
Electric Reliability Corporation (NERC)’s request for formal comment on Project 2020-02 Modifications to PRC-024 (Generator Ride-through), issued on
July 22, 2024.
2.
EPRI closely collaborates with its members inclusive of electric power utilities, Independent System Operators (ISOs), and Regional
Transmission Organizations (RTOs), as well as numerous other stakeholders, domestically and internationally. In its role, EPRI conducts independent
research and development relating to the generation, delivery, and use of electricity for public benefit by working to help make electricity more reliable,
affordable and environmentally safe. EPRI’s comments on this topic are technical in nature based upon EPRI’s research, development, and
demonstration experience over the last 50 years in planning, analyzing, and developing technologies for electric power.
3.
EPRI research and technology transfer deliverables are generally accessible on its website to the public, either for free or for purchase, and
occasionally subject to licensing, export control, and other requirements.[2] The publicly available and free-of-charge milestone reports from a U.S.
Department of Energy (DOE)- and EPRI member-funded research project, Adaptive Protection and Validated Models to Enable Deployment of High
Penetrations of Solar PV (“PV-MOD”), [3] and other research deliverables substantiate many of the comments made in This Response.
4.
While not a standards development organization (SDO), EPRI conducts research and demonstration projects in relevant areas as well as
facilitates knowledge transfer and collaboration that SDOs may, at times, use to inform technical and regulatory standards development, such as in
Institute of Electrical and Electronics Engineers (IEEE), International Electrotechnical Commission (IEC), International Council on Large Electric
Systems (CIGRE), and NERC.[4]
5.
EPRI’s comments in This Response address reliability and NERC’s draft PRC-029 Reliability Standards for IBRs ride-through requirements
developed under project 2020-02. All comments are aimed at providing independent technical information to respond to the draft published by NERC
based on EPRI’s research and development results and associated staff expertise and do not necessarily reflect the opinions of those supporting and
working with EPRI to conduct collaborative research and development. Where appropriate, EPRI’s comments do not only address the specific questions
of the NOPR but also related scope that may help to inform a final order. Some of EPRI’s comments presented in This Response have also been
submitted in response to the previous Federal Energy Regulatory Commission’s (FERC) Notice of Proposed Rulemaking (NOPR) to direct North
American Electric Reliability Corporation (NERC) to develop Reliability Standards for inverter-based resources (IBRs) that cover data sharing, model
validation, planning and operational studies, and performance requirements (RM22-12), issued on November 17, 2022.
6.
EPRI also submitted comments on the initial draft of PRC-029 which was issued on March 27, 2024, and on Draft 2 which was issued June
18, 2024. This 3rd set of EPRI comments supports the same direction as the previously submitted comments and offers a technical analysis based on
the latest “Draft 3”.[5]
II.
Conclusion
7.
EPRI appreciates the opportunity to provide NERC with its technical recommendations and comments on these important topics related to
Reliability Standards for IBRs. EPRI looks forward to working with its members, NERC, and other stakeholders on providing further independent
technical information on these important questions.
III.
Contact Information
Jens C. Boemer, Technical Executive
Manish Patel, Technical Executive
Anish Gaikwad, Deputy Director
Aidan Tuohy, Director, R&D
EPRI
3420 Hillview Ave
Palo Alto, CA 94304
Email: JBoemer@epri.com, ManPatel@epri.com, AGaikwad@epri.com, ATuohy@epri.com
Robert Chapman, Senior Vice President, Corporate Affairs
EPRI
3420 Hillview Ave
Palo Alto, CA 94304
Email: RChapman@epri.com
[1] EPRI is a nonprofit corporation organized under the laws of the District of Columbia Nonprofit Corporation Act and recognized as a tax-exempt
organization under Section 501(c)(3) of the U.S. Internal Revenue Code of 1996, as amended, and acts in furtherance of its public benefit mission. EPRI
was established in 1972 and has principal offices and laboratories located in Palo Alto, Calif.; Charlotte, N.C.; Knoxville, Tenn.; and Lenox, Mass. EPRI
conducts research and development relating to the generation, delivery, and use of electricity for the benefit of the public. An independent, nonprofit
organization, EPRI brings together its scientists and engineers as well as experts from academia and industry to help address challenges in electricity,
including reliability, efficiency, health, safety, and the environment. EPRI also provides technology, policy and economic analyses to inform long-range
research and development planning, as well as supports research in emerging technologies.
[2] https://www.epri.com (last accessed, August 6, 2024)
[3] PV-MOD Project Website. EPRI. Palo Alto, CA: 2024. [Online] https://www.epri.com/pvmod (last accessed, August 6, 2024)
[4] For transparency, we would like to disclose that EPRI collaborates with other organizations such as IEEE, IEC, CIGRE, and NERC; however, EPRI is
not a regulatory- or standard-setting organization. EPRI research is often considered in the development of recommendations, guidelines, and best
practices that are not determinative.
[5] https://www.nerc.com/pa/Stand/Pages/Project_2020-02_Transmission-connected_Resources.aspx
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Constantin Chitescu - Ontario Power Generation Inc. - 5
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Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment
NPCC RSC supports the project.
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Mike Magruder - Avista - Avista Corporation - 1
Answer
Document Name
Comment
We concur with EEI's comments.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Southern Company received the following feedback from one of our OEM providers relating to the Frequency Ride-Through requirements in PRC-029:
“...confirms that neither its legacy nor new turbines can meet the proposed frequency ride-through requirements. Wind turbines contain hundreds of
electromechanical devices that must be redesigned and tested before any new stringent frequency ride-through zones can be confirmed."
"...is currently designing and evaluating our turbines' capabilities according to IEEE 2800 standards. Consequently, any new requirements deviating
from IEEE 2800 will be unfeasible in the near term.”
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Colin Chilcoat - Invenergy LLC - 6
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Comment
Invenergy thanks the drafting team for the opportunity to provide the above comments.
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Rhonda Jones - Invenergy LLC - 5
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Document Name
Comment
Invenergy thanks the drafting team for the opportunity to provide the above comments.
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Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Document Name
Comment
Thank you for the opportunity to comment.
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George E Brown - Pattern Operators LP - 5
Answer
Document Name
Comment
Pattern Energy supports Edison Electric Institute’s and Grid Strategies LLC’s comments.
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Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Document Name
Comment
Thank you for the opportunity to comment.
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC,Texas RE,NPCC,SERC,RF, Group Name SRC 2024
Answer
Document Name
Comment
In the previous posting, the SRC provided this comment which was not addressed in the current version for comment and ballot:
Attachment 1 lists a minimum ride-through time of 1800 seconds for the continuous operation voltage region between 1.05 pu and 1.1 pu (<= 1.1 and
>1.05) in Tables 1 and 2. The SRC requests that, consistent with IEEE 2800, an exception for 500 kV systems be allowed such that the minimum ridethrough time for 1.05 pu < voltage <= 1.1 pu for 500 kV systems is “Continuous,” because the 1.05 pu < voltage <= 1.1 pu voltage range is within the
normal operation range for some systems, such as PJM’s system.
The SRC again requests the exception for 500KV systems be incorporated. The SDT has not explainedwhy this difference from the IEEE 2800 is
appropriate for 500 KV reliability.
We recommend the M1 references to Sequence Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder be adjusted to lower case terms,
as these are not defined in the Glossary of Terms. PRC 28 utilizes acronyms for these that may be appropriate for this standard. Similarly a change
was made in R4 to replace Regional Entity with CEA, which is an undefined term and acronym in the Glossary. Suggest spelling this out and
considering defining or pointing to the Rules of Procedure.
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Srinivas Kappagantula - Arevon Energy - 5
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Document Name
Comment
None.
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Bobbi Welch - Midcontinent ISO, Inc. - 2
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Document Name
Comment
MISO understands the increased need for Ride-through capabilities as system inertia decreases. We also see challenges for equipment to demonstrate
compatibility with the frequency requirements (Attachment 2) which go beyond industry standards (IEEE 2800) and MISO’s current Tariff requirements.
MISO’s plan for conformity currently relies on IEEE P2800.2 and we are planning to use that as the basis for testing to ensure IBRs meet MISO Tariff
requirements. We ask that consideration be given to aligning PRC-029 with other existing industry standards.
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Marty Hostler - Northern California Power Agency - 3,4,5,6
Answer
Document Name
Comment
Regarding the Implementation Plan. Six months after FERC approval is unreasonable to have equipment and procedures in place and changes made.
Especially considering several entities will need to order and install new monitoring equipment from most likely the same companies. This
implementation plan should be the same as PRC-28.
NCPA understands Ferc Order 901. The SDT has not provided any cost or expected reliability indices improvement estimates. Consequently, it is
impossible for entities to determine if this proposal is cost effective to address recommendations of FERC order 901 or if, or to what extent, this proposal
will improve reliability.
Reliability standards should not be added or changed until the SDT provides said information so that Registered Entities can make educated
determinations related to the cost and benefits of reliability standard modifications or new proposals.
The SDT has not provide a cost or tangible reliability benefit estimate. Thus we are unable to analyze the cost and reliability benefits this proposal
would provide without any data. And, ironically GO/GOP IBR Entities are being asked to spend money to procure and install a bunch of devices to
record data and/or to perform new activities that may, or may not, improve reliability. And if they do improve reliability, we don't have any idea if the
reliability benefits are worth the cost. Electricity customers' rates would need to be raised and there is no justification or hard evidence related to the
improved reliability increase magnitude; i.e. no cost/benefit justification to provide electricity customers as to why their rates are increasing.
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
WECC believes that PRC-029 does a good job being consistent on use of IBR (and PRC-028 and PRC-030 DTs should take note on consistency.)
Note that the redlined version of the posted Standard did not capitalize “reactive power” in M2 but the clean version did. Another example is Footnote
11 in the redline version used “active power” but clean version was changed to “Real Power”. DT could receive responses based on either document
and needs to ensure consistency in the clean version or note the differences.
WECC suggests that Requirement 4 could be removed and listed as actions to be done within the Implementation Plan. From an auditing perspective,
noncompliance is based on administrative issues (failure to provide in 12 months) and is only applicable to units already “in-service” as of the effective
date. “In-service” is meant to be exactly what? (WECC has an applicable temr in the NERC Glossary, but that is only appliable in the Western
Interconnection. Different entites may have a differend definition of "in-service." Suggest a defintion be developed.) First synch date the IBR is “inservice”. Reliability issues can happen with units not at the COD date and this issue should not be ignored or exacerbated by assuming, if that is the
case, that “in-service” equated to COD. There will be discussions as to what the effective date is (for R4 specifically) due to the Implementation Plan
dependence provided by the DT. This again calls for a timeline to be provided for each Standard being considered especially for these IBR-related
Standards as the IPs are not clearly defined. Still not clear why CEAs need notification of hardware limitations within a Standard. A onetime Alert for R4
may be appropriate followed up by a Periodic Data Submittal when hardware issues are alleviated (currently no response to CEA is required which begs
the question why inform them in the first place?). Severe VSL needs to remove CEA as a result of not being in the section for responses required.
VSLs for R3 need to be adjusted to use “IBR” versus “facility”. VSLs for R4 indicated a basis of effective date of R4 versus effective date of Standard as
the language of the Standard states. This needs corrected as those dates may be different. Another clear reason to provide a timeline diagram of
Implementation Plan dates.
Attachment 2 Bullet 1 for Voltage- Is the “that include wind” limited to type 3 and type 4 for the hybrid aspect?
Attachment 2 Bullet 4 for frequency—Need to replace “facility” with IBR.
PRC-029 Implementation Plan Requirement 4 “Non-BES IBRs”- Need to change “or” to “for” in the sentence describing R4’s timeline for
implementation. Bottom of page 5 capitalize “ride-through”.
All BES IBRs, including those that have repeatedly failed from a performance perspective, default to the PRC-028 timeline which employs an extended
timeframe for phased-in implementation.
PRC-029 Implementation Plan- Separating the Requirements compliance obligation timeframe out by design and operation is not realistic and gives the
false appearance of being partially applicable prior to Jan 1, 2030. The language of the Requirements, as written, will be contested by entities as the
language requires both the “design and operation” for BES IBRs and non-BES IBRs. Effectively a review of the design will be an administrative effort
for an item that could be designed today but there is no quality or accuracy language for the design aspects. The proof that design was completed in an
effective manner to mitigate the risk can only be determined if an event occurs. R4 has additional implementation time built into the Requirement
language which provides a false appearance of being applicable on the effective date of the Standard.
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Jennifer Neville - Western Area Power Administration - 1,6
Answer
Document Name
Comment
Section 4: Applicability:
{C}4.2 {C}is not aligned with the PRC-028. The DT should consider the alignment of the applicability section between all IBR standards.
{C}1)
R2
It is not clear to me what “The Elements associated with...” means in 4.2.1. Does it mean power system elements?
The new wording in Section 2.1.3 is unclear.
MRO NSRF recommends it be changed to “Prioritize Real Power or Reactive Power delivery when the voltage is less than 0.95 per unit, the voltage is
within the continuous operating region, and the IBR cannot deliver both Real Power and Reactive Power due to a current limit or Reactive Power limit
unless otherwise specified through other mechanisms by an associated Transmission Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator.”
R3
The MRO NSRF is still concerned with the lack of provisions for exemptions for frequency limitation (RoCof) that may put some of the legacy
IBR in a non-compliant state and may require a costly upgrade to meet R3 requirements.
MRO NSRF Recommends the adoption of a frequency ride requirement for legacy equipment be delayed until Generator Owners can properly evaluate
the capability of legacy equipment.
R4
The CEA is not a defined NERC term in the Glossary of Terms Used in NERC standard list, MRO NSRF recommends spelling out Compliance
Enforcement Authority (CEA) in Requirement R4 subpart 4.2 since it is the first time seeing that term in the requirement language.
Attachment #1
MRO NSRF agrees with removing the previous figures 1 and 2 from attachment # 1 but we recommend adding at least three voltage waveform
examples into TR to illustrate how the Table 1 and 2 should be used to determine the compliance with voltage ride through
TR
More information should be added to some frequency waveform examples in TR to illustrate how to calculate the RoCoF.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own. In addition, ERCOT encourages NERC to consider defining the
averaging window for Rate of Change of Frequency, as leaving the averaging window open ended will result in measurement inconsistencies in
protection systems and post-event analysis.
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Kyle Thomas - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Elevate continues to strongly encourage NERC to reconsider adoption of IEEE 2800-2022. The unwillingness to adopt IEEE 2800-2022 by NERC
is leading to entirely duplicative efforts that are not serving any additional value as compared to the work conducted in the IEEE 2800-2022
developments. It does not appear that a holistic approach and strategy is being taken to meet the FERC Order No. 901 directives, which is leading to
very low ballot scores, significant rework, and misalignment with industry recommended practices.
The draft NERC PRC-029 is duplicative with IEEE 2800-2022 Clause 7 yet only covers a small fraction of the IBR-specific capability/performance
requirements and necessary equipment limitation details that are outlined in that clause. Therefore, there is no clear reliability benefit versus the cost of
implementation PRC-029 as compared with IEEE 2800-2022 and the recommendations set forth in the NERC disturbance reports and guidelines. There
are three core items that should be addressed in the draft NERC PRC-029 standard:
•
•
•
Requirement R4 of the standard be updated to include frequency ride-through criteria exemptions for IBRs in-service by the effective date of the
standard that have known hardware limitations.
The draft PRC-029 standard should align the FRT curve with the IEEE 2800 standard’s FRT curve
If necessary, the "maximization" concept could be introduced to maximize the capabilities of legacy IBRs to the available
software/firmware/setting limits.
Elevate strongly recommends a single NERC standard that adopts IEEE 2800-2022 in a uniform and consistent manner. NERC can also issue a
reliability guideline or implementation guidance that supports industry implementation of the standard. Rather than recreate parts of IEEE 2800-2022
inconsistently over multiple different standards, Elevate recommends a singular standard for BPS-connected IBR capability and performance
requirements related to IEEE 2800-2022. Additional NERC standards can be developed where needed in situations where they are not covered directly
with IEEE 2800-2022 (e.g., NERC PRC-030).
Concerns with Draft PRC-029
If the draft PRC-029 standard is to be pursued as currently structured, Elevate would like to highlight the following concerns:
·
Inconsistencies with PRC-029 and IEEE 2800-2022: There are numerous inconsistencies in the draft standard language and attachment 1 and
2 when compared to IEEE 2800-2022. These should be considered and reviewed for clarity and completeness in the standard.
•
•
•
•
•
•
•
•
•
IEEE 2800 recognizes FRT requirement limitations, but the standard does not
IEEE 2800 recognizes limitations with VSC-HVDC equipment in meeting consecutive votlage deviation ride-through capabilite, the PRC-029
standard does not.
IEEE 2800 allows for an exception for “self-protection” when negative-sequence voltage is greater than specified duration and threshold, which
may be required for Type III WTG based plants. PRC-029 does not have this exception.
IEEE 2800 recognizes 500kV system voltages are actually operated in the range of 525kV and therefore has equipment rated to 550kV. These
500kV operating conditions and corresponding updated voltage ride-through curves should be considered in the standard.
In IEEE 2800 the frequency ride-through criteria defines 10-minute time periods for the cumulative specifications of FRT, whereas the standard
defines them in a 15 minute time period (Table 3 of Attachment 2). This should be clarified and identified.
IEEE 2800 has an exception on IBR post-disturbance current limitations for voltage disturbances that reduce RPA voltage to less than 50% of
nominal, but the standard does not have this exception.
A ride-through duration of 1800 seconds is specified in both IEEE 2800 and draft PRC-029 for V > 1.05 and ≤ 1.10. PRC-029 is silent on the
cumulative time period for this requirement, whereas IEEE 2800-2022 specifies that this is cumulative over a 3600 second time period.
Attachment 2: frequency ride-through criteria should be updated to fully match with IEEE 2800. Creating a different FRT ride-through curve
without adequate technical justification will continue to challenge the industry.
The standard should be updated to explicitly state that the voltage ride-through curves are to be interpreted as voltage vs time duration as is
stated in IEEE 2800. This is to ensure that there is no incorrect interpretation that these curves are “envelope” curves. This could be done by
adding a new note to explicitly call out the voltage vs time duration interpretation of the curves.
Likes
0
Dislikes
Response
0
Bill Zuretti - Electric Power Supply Association - 5
Answer
Document Name
Comment
Likes
0
Dislikes
Response
0
EPSA FINAL Comments on IBR Standards .pdf
Consideration of Comments
Project Name:
2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-029-1
Comment Period Start Date: 7/22/2024
Comment Period End Date: 8/12/2024
Associated Ballot(s):
2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan AB 3 OT
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 AB 3 ST
There were 70 sets of responses, including comments from approximately 159 different people from approximately 112
companies representing 10 of the Industry Segments as shown in the table on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, let us know immediately. Our goal is to give every comment serious consideration in
this process. If you feel there has been an error or omission, contact Manager of Standards Information, Nasheema Santos (via email) or
at (404) 290-6796.
RELIABILITY | RESILIENCE | SECURITY
Questions
1. Do you agree with the proposed definition of Ride-through? If not, please state what revision would be acceptable and why.
2. Do you agree with the changes made in this draft of PRC-029-1?
3. Provide any additional comments for the Drafting Team to consider, if desired.
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
2
Organization
Name
MRO
Name
Segment(s)
Anna
1,2,3,4,5,6
Martinson
Region
MRO
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
Group Name
Group
Member
Name
MRO Group Shonda
McCain
Group Member
Organization
Group
Group
Member Member
Segment(s) Region
Omaha Public
Power District
(OPPD)
1,3,5,6
MRO
Michael
Brytowski
Great River
Energy
1,3,5,6
MRO
Jamison
Cawley
Nebraska Public
Power District
1,3,5
MRO
Jay Sethi
Manitoba Hydro
(MH)
1,3,5,6
MRO
Husam AlHadidi
Manitoba Hydro
(System
Preformance)
1,3,5,6
MRO
Kimberly
Bentley
Western Area
Power
Adminstration
1,6
MRO
Jaimin Patal Saskatchewan
1
Power
Coporation (SPC)
MRO
George
Brown
Pattern Operators 5
LP
MRO
Larry
Heckert
Alliant Energy
(ALTE)
MRO
4
3
Terry
Harbour
MidAmerican
1,3
Energy Company
(MEC)
Dane Rogers Oklahoma Gas
and Electric
(OG&E)
Southwest Charles
Power Pool, Yeung
Inc. (RTO)
2
MRO,NPCC,RF,SERC,SPP
RE,Texas RE,WECC
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
SRC 2024
MRO
1,3,5,6
MRO
Seth
Muscatine Power 1,3,5,6
Shoemaker & Water
MRO
Michael
Ayotte
ITC Holdings
1
MRO
Andrew
Coffelt
Board of Public
Utilities- Kansas
(BPU)
1,3,5,6
MRO
Peter Brown Invenergy
5,6
MRO
Angela
Wheat
1
MRO
Bobbi Welch Midcontinent ISO, 2
Inc.
MRO
Charles
Yeung
SPP
2
MRO
Ali
Miremadi
CAISO
1
WECC
Southwestern
Power
Administration
Bobbi Welch Midcontinent ISO, 2
Inc.
MRO
Greg
Campoli
NPCC
NYISO
1
4
WEC Energy Christine 3
Group, Inc. Kane
ACES Power Jodirah
Marketing Green
1,3,4,5,6
Elizabeth
Davis
PJM
Matt
Goldberg
ISO New England 2
NPCC
WEC Energy Christine
Group
Kane
WEC Energy
Group
3
RF
Matthew
Beilfuss
WEC Energy
Group, Inc.
4
RF
Clarice
Zellmer
WEC Energy
Group, Inc.
5
RF
David
Boeshaar
WEC Energy
Group, Inc.
6
RF
Hoosier Energy
Electric
Cooperative
1
RF
MRO,NPCC,RF,SERC,Texas ACES
Bob
RE,WECC
Collaborators Soloman
2
RF
Kris Carper
Arizona Electric 1
Power
Cooperative, Inc.
WECC
Jason
Procuniar
Buckeye Power,
Inc.
RF
4
Jolly Hayden East Texas
NA - Not
Texas RE
Electric
Applicable
Cooperative, Inc.
Scott Brame North Carolina
Electric
Membership
Corporation
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
3,4,5
SERC
5
FirstEnergy - Mark
FirstEnergy Garza
Corporation
Southern
Pamela
Company - Hunter
Southern
Company
Services, Inc.
4
1,3,5,6
FE Voter
SERC
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
Southern
Company
Nick
Fogleman
Prairie Power,
Inc.
1,3
SERC
Julie
Severino
FirstEnergy FirstEnergy
Corporation
1
RF
Aaron
FirstEnergy Ghodooshim FirstEnergy
Corporation
3
RF
Robert Loy
5
RF
Mark Garza FirstEnergyFirstEnergy
1,3,4,5,6
RF
Stacey
Sheehan
FirstEnergy FirstEnergy
Corporation
6
RF
Matt Carden Southern
Company Southern
Company
Services, Inc.
1
SERC
Joel
Southern
Dembowski Company Alabama Power
Company
3
SERC
Ron Carlsen Southern
Company Southern
6
SERC
FirstEnergy FirstEnergy
Solutions
6
Company
Generation
Leslie Burke Southern
Company Southern
Company
Generation
Black Hills
Rachel
Corporation Schuldt
6
5
SERC
1
WECC
3
WECC
Black Hills
Corporation
6
WECC
Carly Miller Black Hills
Corporation
5
WECC
Sheila
Suurmeier
Black Hills
Corporation
5
WECC
Gerry
Dunbar
Northeast Power 10
Coordinating
Council
NPCC
Deidre
Altobell
Con Edison
1
NPCC
Michele
Tondalo
United
Illuminating Co.
1
NPCC
Stephanie
UllahMazzuca
Orange and
Rockland
1
NPCC
Black Hills
Micah
Black Hills
Corporation - Runner
Corporation
All Segments Josh Combs Black Hills
Corporation
Rachel
Schuldt
Northeast
Ruida Shu 1,2,3,4,5,6,7,8,9,10 NPCC
Power
Coordinating
Council
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
NPCC RSC
7
Michael
Ridolfino
Central Hudson
Gas & Electric
Corp.
1
NPCC
Randy
Buswell
Vermont Electric 1
Power Company
NPCC
James Grant NYISO
Dermot
Smyth
2
NPCC
Con Ed 1
Consolidated
Edison Co. of New
York
NPCC
David Burke Orange and
Rockland
3
NPCC
Peter Yost
Con Ed 3
Consolidated
Edison Co. of New
York
NPCC
Salvatore
Spagnolo
New York Power 1
Authority
NPCC
Sean Bodkin Dominion Dominion
Resources, Inc.
6
NPCC
David Kwan Ontario Power
Generation
4
NPCC
NextEra Energy - 1
Florida Power
and Light Co.
NPCC
Silvia
Mitchell
Sean Cavote PSEG
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
4
NPCC
8
Jason
Chandler
Con Edison
5
NPCC
Tracy
MacNicoll
Utility Services
5
NPCC
Shivaz
Chopra
New York Power 6
Authority
NPCC
Vijay Puran New York State
Department of
Public Service
6
NPCC
David Kiguel Independent
7
NPCC
Joel
Charlebois
AESI
7
NPCC
Joshua
London
Eversource
Energy
1
NPCC
Jeffrey
Streifling
NB Power
Corporation
1,4,10
NPCC
Joel
Charlebois
AESI
7
NPCC
John
Hastings
National Grid
1
NPCC
Erin Wilson NB Power
1
NPCC
James Grant NYISO
2
NPCC
Michael
Couchesne
2
NPCC
2
NPCC
ISO-NE
Kurtis Chong IESO
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
9
Dominion Dominion
Resources,
Inc.
Sean
Bodkin
6
Dominion
Western
Steven
10
Electricity
Rueckert
Coordinating
Council
Tim Kelley
Tim Kelley
WECC
WECC
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
SMUD and
BANC
Michele
Pagano
Con Edison
4
NPCC
Bendong
Sun
Bruce Power
4
NPCC
Carvers
Powers
Utility Services
5
NPCC
Wes
Yeomans
NYSRC
7
NPCC
Victoria
Crider
Dominion Energy 3
NA - Not
Applicable
Sean Bodkin Dominion Energy 6
NA - Not
Applicable
Steven Belle Dominion Energy 1
NA - Not
Applicable
Barbara
Marion
Dominion Energy 5
NA - Not
Applicable
Steve
Rueckert
WECC
10
WECC
Curtis Crews WECC
10
WECC
Nicole
Looney
Sacramento
3
Municipal Utility
District
WECC
Charles
Norton
Sacramento
6
Municipal Utility
District
WECC
10
Wei Shao
Sacramento
1
Municipal Utility
District
WECC
Foung Mua Sacramento
4
Municipal Utility
District
WECC
Nicole Goi
WECC
Sacramento
5
Municipal Utility
District
Kevin Smith Balancing
Authority of
Northern
California
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
1
WECC
11
1. Do you agree with the proposed definition of Ride-through? If not, please state what revision would be acceptable and why.
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
No
Document Name
Comment
Black Hills Corporation supports the comments provided by the NAGF which state: a. Recommend removing the word “entire” and the phase
“in its entirety” from the proposed definition; b. adding the following revised language”…and continuing to operate through System
Disturbances as defined in the applicable Reliaiblity Standards.”
Likes
0
Dislikes
0
Response
Thank you for your comment.
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. The definition now reads as: “The plant/facility remains connected and continues to operate
through voltage or frequency system disturbances.”
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
No
Document Name
Comment
Duke Energy agrees with and supports the following NAGF comment:
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
12
The NAGF does not agree with the proposed definition of Ride-through and provides the following recommendations for consideration:
a.
Recommend removing the word “entire” and the phrase “in its entirety” from the proposed definition.
b.
Recommend adding the following revised language “…and continuing to operate through System Disturbances as defined in the
applicable Reliability Standards.”
Likes
0
Dislikes
0
Response
Thank you for your comment.
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a Grid Disturbance. The definition now reads as: The plant/facility remains connected and continues to operate
through voltage or frequency system disturbances.
Robert Follini - Avista - Avista Corporation - 3
Answer
No
Document Name
Comment
See EEi comments
Likes
0
Dislikes
0
Response
Thank you, please see the response to EEI.
Brian Van Gheem - Radian Generation - NA - Not Applicable - NA - Not Applicable
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
13
Answer
No
Document Name
Comment
1.
We believe the addition of “in its entirety” is ambiguous and misplaced within the proposed definition. We propose the phrase should
be moved to the end to imply the entire time duration of a Disturbance, from the start of the Disturbance to its return to predisturbance conditions.
2.
We believe the addition of the term “System” should be removed from the definition. According to the NERC Glossary of Terms, the
term is defined as “a combination of generation, transmission, and distribution components.” This proposed Reliability Standard only
applies to Generator Owners, an entity that would not possess transmission and distribution asset components.
3.
We believe the reference to the term “Disturbance” within the definition is too vague by itself. The proposed title of this Reliability
Standard is “Frequency and Voltage Ride‐through Requirements for Inverter‐Based Resources.” The proposed purpose of this
Reliability Standard is “to ensure that [Inverter‐Based Resources] IBRs Ride-through to support the Bulk Power System (BPS) during
and after defined frequency and voltage excursions.” Both imply any definition used in reference to this Reliability Standard should be
narrowed to unplanned Frequency and Voltage events that produce abnormal system conditions or deviations to the electric system,
as derived from term’s definition listed within the NERC Glossary of Terms. Therefore, we propose ending the “Ride‐through”
definition with the phrase “through the duration of a frequency or voltage Disturbance in its entirety, from its start to the return to
pre-disturbance conditions.”
Likes
0
Dislikes
0
Response
Thank you for your comment.
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
14
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF does not agree with the proposed definition of Ride-through and provides the following recommendations for consideration:
a.
Recommend removing the word “entire” and the phrase “in its entirety” from the proposed definition.
b. Recommend adding the following revised language “…and continuing to operate through System Disturbances as defined in the
applicable Reliability Standards.”
Likes
0
Dislikes
0
Response
Thank you for your comment.
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Alison MacKellar - Constellation - 5
Answer
No
Document Name
Comment
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
15
Constellation aligns with NAGF comments. Legacy inverters will not be able to ride through voltage and frequency events. It’s important to
include exemption for legacy inverters.
Alison Mackellar on behalf of Constellation Segments 5 and 6
Likes
0
Dislikes
0
Response
Thank you for your comment.
Megan Melham - Decatur Energy Center LLC - 5
Answer
No
Document Name
Comment
Capital Power supports the NAGF's comments:
The NAGF does not agree with the proposed definition of Ride-through and provides the following recommendations for consideration:
a. Recommend removing the word “entire” and the phrase “in its entirety” from the proposed definition.
b. Recommend adding the following revised language “…and continuing to operate through System Disturbances as defined in the applicable
Reliability Standards.”
Likes
0
Dislikes
0
Response
Thank you for your comment.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
16
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Richard Vendetti - NextEra Energy - 5
Answer
No
Document Name
Comment
NextEra believes that the definition of ride-through is too broad and does not directly tie back to voltage or frequency requirements. The
word “entire” leaves too much room for interpretation of single IBR unit driving an unnecessary investigation.
Likes
0
Dislikes
0
Response
Thank you for your comment.
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Kimberly Turco - Constellation - 6
Answer
No
Document Name
Comment
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
17
Constellation aligns with NAGF comments. Legacy inverters will not be able to ride through voltage and frequency events. It’s important to
include exemption for legacy inverters.
Kimberly Turco on behalf of Constellation Energy Segments 5 and 6.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
No
Document Name
Comment
Minnesota Power (hereafter MP) agrees with EEI that the “ride-through” definition was clearer as proposed in IEEE 2800-2022.
Likes
0
Dislikes
0
Response
Thank you, please see the response to EEI.
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
18
Answer
No
Document Name
Comment
LG&E/KU agrees with EEI; there is no reason to deviate from the definition included in IEEE Std 2800-2022 and IEEE Std 1547-2018: “Ability to
withstand voltage or frequency disturbances inside defined limits and to continue operating as specified.” This definition makes it more clear
that there are “limits” to Ride-through. The definition proposed by the DT implies that any tripping is failed Ride-through, even if the trip
occurs for a condition where it is acceptable. Include the IEEE definition verbatim, there is no need for modification.
Likes
0
Dislikes
0
Response
Thank you, please see the response to EEI.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
No
Document Name
Comment
"Please see EEI Comments"
Likes
0
Dislikes
0
Response
Thank you, please see the response to EEI.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
19
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Comment
WEC Energy Group supports the comments of the NAGF for Question 1.
Likes
0
Dislikes
0
Response
Thank you, please see the response to EEI.
Carver Powers - Utility Services, Inc. - 4
Answer
No
Document Name
Comment
Request clarification on the meaning of “in its entirety” and its intended purpose. Its inclusion adds confusion as the beginning of the
definition already states “the entire plant/facility”. Does “in its entirety” apply to the entire facility, or the entire disturbance event?
Recommend “Ride-through: The entire plant/facility remaining connected to the Bulk Power System and continuing to operate through
System Disturbances.”
Likes
Dislikes
0
0
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
20
Response
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
No
Document Name
Comment
NIPSCO believes that the definition of ride-through is too broad and does not directly tie back to voltage or frequency requirements. The
word “entire” leaves too much room for interpretation of single IBR unit driving an unnecessary investigation.
Likes
0
Dislikes
0
Response
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
21
Answer
No
Document Name
Comment
B. Ride-through definition
·
Consider adopting definition from IEEE 2800, which is from IEEE 1547, and well understood by the industry.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Colin Chilcoat - Invenergy LLC - 6
Answer
No
Document Name
Comment
Invenergy recommends removing “entire” and “in its entirety” from the proposed definition. As written, the definition attempts to prescribe
an unreasonable interpretation of what ride-through should be from a system reliability perspective.
Likes
0
Dislikes
0
Response
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
22
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Rhonda Jones - Invenergy LLC - 5
Answer
No
Document Name
Comment
Invenergy recommends removing “entire” and “in its entirety” from the proposed definition. As written, the definition attempts to prescribe
an unreasonable interpretation of what ride-through should be from a system reliability perspective.
Likes
0
Dislikes
0
Response
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
George E Brown - Pattern Operators LP - 5
Answer
No
Document Name
Comment
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
23
Pattern Energy does not believe it is necessary to add a glossary term for Ride-Through. Ride-through is an operational requirement that is
defined by a set of magintudes and should remain defined within the requirements of the NERC Relaibility Standards, as traditionaly done.
Likes
0
Dislikes
0
Response
Thank you for your comment. The term is also used to bridge the PRC-029 standard with “Ride-through criteria” used in PRC-030.
Srinivas Kappagantula - Arevon Energy - 5
Answer
No
Document Name
Comment
Please refer to NAGF comments.
Likes
0
Dislikes
0
Response
Thank you, please see the response to NAGF.
Bobbi Welch - Midcontinent ISO, Inc. - 2
Answer
No
Document Name
Comment
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
24
MISO supports the comments of the ISO/RTO Council (IRC) Standards Review Committee (SRC).
In addition, we believe it is important to get the wording of the Ride-through definition accurate and clear. If the language is not clear (as to
what is allowed/disallowed), it will likely lead to future disagreements.
One possible solution is to add the words “as specified” to the Ride-through definition to more explicitly tie the definition to the
requirements under the proposed PRC-029 standard as shown below.
Ride‐through: The entire plant/facility remaining connected to the Bulk Power System, and continuing in its entirety to operate as specified
through the time‐frame of System Disturbances.
This is only one possible approach to better capture the intent of the standard as described in the below excerpt from the PRC-029-1
Technical Rationale, Rational for Requirement R3 (page 6) which references the need to remain synchronized, an important aspect to
specify:
“The objective of Requirement R3 is to ensure that IBRs remain electrically connected, synchronized, and exchanging current, that is,
continuing to operate during a frequency excursion event.”
Likes
0
Dislikes
0
Response
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
A definition may be used by other standards. “As specified” would be unclear as to who or how these specifications are made. “Remaining
synchronized” was previously rejected as it does not accurately define the operations of all IBR, as defined by Project 2020-06, during and
immediately following all fault types.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
25
Jennifer Neville - Western Area Power Administration - 1,6
Answer
No
Document Name
Comment
Support MRO NSRF comments
Likes
0
Dislikes
0
Response
Thank you, please see the response to MRO NSRF.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Document Name
Comment
ERCOT joins the comments submitted by the ISO/RTO Council (IRC) Standards Review Committee (SRC) and adopts them as its own. In
addition, ERCOT notes that revising the definition of the term “Ride-through” to recognize that the continued operation associated with ridethrough needs to be maintained not just through the Disturbance but all the way through recovery to a new operating point would result in a
clearer definition that better aligns with PRC-030, which provides that IBR unit losses (partial trips) are not allowed.
ERCOT supports the alternative definition of Ride-through that the SRC proposed, and ERCOT would also support revising that definition to
read as follows: “Ride-through: The entire plant/facility (including its dispersed power producing inverters) remaining connected to the
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
26
electric system and continuing in its entirety to operate in a manner that supports grid reliability through a System Disturbance, including the
period of recovery back to a normal operating condition.”
Likes
0
Dislikes
0
Response
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Partial trips are specific performance parameters that are evaluated within PRC-030.
Kyle Thomas - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
The definition of ride-through should be updated as follows: “The entire plant/facility remaining connected to the Bulk Power System and
contininuing in its entirety to operate as specified through System Disturbances inside defined limits.
Likes
0
Dislikes
0
Response
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
27
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
“A definition may be used by other standards. “As specified” would be unclear as to who or how these specifications are made.
Brian Lindsey - Entergy - 1
Answer
Yes
Document Name
Comment
No Comment
Likes
0
Dislikes
0
Response
Thank you.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Yes
Document Name
Comment
FirstEnergy has no objections to the proposed definition of Ride-through definition.
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
28
Thank you.
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Yes
Document Name
Comment
None
Likes
0
Dislikes
0
Response
Thank you.
Patricia Lynch - NRG - NRG Energy, Inc. - 5
Answer
Yes
Document Name
Comment
NRG Energy Inc is in support of the comments made by EPSA.
Likes
0
Dislikes
0
Response
Thank you.
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Yes
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
29
Document Name
Comment
See EEI Comments
Likes
0
Dislikes
0
Response
Thank you.
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
EEI does not oppose the proposed definition of Ride-through.
Likes
0
Dislikes
0
Response
Thank you.
Nick Leathers - Ameren - Ameren Services - 3 - SERC
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
30
Ameren does not have any additional comments for consideration by the drafting team.
Likes
0
Dislikes
0
Response
Thank you.
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Southern Company suggests using a different word or phrase for …“entire” plant/facility… to indicate that the expectation is that no
equipment should drop out of service during the disturbance and remain connected throughout the disturbance. The use of the word
“entire” could mean all plant equipment, including that which is already out of service for other reasons.
Suggested wording:
“The plant/facility shall remain connected and in service, maintaining the pre-distubance equipment configuration in operation, throughout
the entirety of the system disturbance and recovery.”
Likes
0
Dislikes
0
Response
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Consideration of Comments
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31
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Yes
Document Name
Comment
While WECC voted Affirmative, WECC suggests the DT emphasize the nature of the definition may not allow a single turbine or solar array to
be lost in a System Disturbance (equates to failed “Ride-through” with loss).
Likes
0
Dislikes
0
Response
Thank you. Partial trips are specific performance parameters that are evaluated within PRC-030.
Ayslynn Mcavoy - Arkansas Electric Cooperative Corporation - 3
Answer
Yes
Document Name
Comment
Thank you.
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Yes
Document Name
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
32
Comment
Likes
0
Dislikes
0
Response
Thank you.
Thomas Foltz - AEP - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Bruce Walkup - Arkansas Electric Cooperative Corporation - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
33
Thank you.
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
34
Likes
0
Dislikes
0
Response
Thank you.
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
35
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District,
3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Tim Kelley, Group Name SMUD and BANC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Casey Jones - Berkshire Hathaway - NV Energy - 5 - WECC
Answer
Yes
Document Name
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
36
Comment
Likes
0
Dislikes
0
Response
Thank you.
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1,
6; Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Adam Burlock - Adam Burlock On Behalf of: Ashley Scheelar, TransAlta Corporation, 5; - Adam Burlock
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
37
Response
Thank you.
Ruchi Shah - AES - AES Corporation - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Yes
Document Name
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
38
Comment
Likes
0
Dislikes
0
Response
Thank you.
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
39
Response
Thank you.
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Yes
Document Name
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
40
Comment
Likes
0
Dislikes
0
Response
Thank you.
Mike Magruder - Avista - Avista Corporation - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
41
Thank you.
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thank you.
Martin Sidor - NRG - NRG Energy, Inc. - 6
Answer
Document Name
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
42
Comment
NRG agrees with and refers the SDT to the EPSA comments.
Likes
0
Dislikes
0
Response
Thank you.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC,Texas RE,NPCC,SERC,RF, Group Name SRC 2024
Answer
Document Name
Comment
In the proposed definition of “Ride-through”, the ISO/RTO Council (IRC) Standards Review Committee (SRC) believes that the requirement
that a facility continue “to operate” is inadequate; the definition needs to require the facility to maintain performance that is beneficial (or at
the very least, not detrimental) to overall grid reliability.
It is preferable if the ride-through definition referred to the electric system instead of the BPS to be consistent with the IBR definition.
Finally, the concept of ride-through needs to recognize that the continued operation associated with ride-through needs to be maintained not
just through the Disturbance but all the way through recovery to a new operating point. It is not clear that the existing Disturbance definition
includes the recovery period.
To address these concerns, the ride-through definition could be revised to read as follows:
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
43
“Ride-through: The entire plant/facility remaining connected to the electric system and continuing in its entirety to operate in a manner that
supports grid reliability through a System Disturbance, including the period of recovery back to a normal operating condition.”
Likes
0
Dislikes
0
Response
Thank you.
The definition cannot specify exact performance. From the Standard Processes Manual: Definitions shall not contain statements of
performance Requirements.
The Standards Committee, with advisement from NERC, the 2020-02 Drafting Team, and leveraging the results of the September 4-5
Technical Conference on Ride-through have incorporated industry suggestions concerning the definition for “Ride-through”. The resulting
definition removes language that has been identified as either ambiguous or appears to specify performance requirements for how an IBR
should recover following a grid disturbance. Similarly, “system” and “disturbance” are now lowercase terms. The definition now reads as:
“The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.”
Marty Hostler - Northern California Power Agency - 3,4,5,6
Answer
Document Name
Comment
NCPA is not registered to vote on this item and thus is not opposing it or FERC Order 901.
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
44
Thank you.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
45
2. Do you agree with the changes made in this draft of PRC-029-1?
Jennifer Neville - Western Area Power Administration - 1,6
Answer
No
Document Name
Comment
Support MRO NSRF comments
Likes
0
Dislikes
0
Response
Thank you, please see the response to MRO NSRF.
Marty Hostler - Northern California Power Agency - 3,4,5,6
Answer
No
Document Name
Comment
We don't know if this proposal is going to improve reliability or the extent of reliability improvement, if any. The SDT has not shown us
tangible relability improvement indices that support the modifications made. Considering this standard has been changed several times
over the last few years we are skeptical that changes made will improve reliability. However, we do not oppose the proposal.
Likes
Dislikes
0
0
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
46
Response
Thank you for your comment.
PRC-029-1 is consistent with directives ordered by FERC and the SAR scope assigned to the drafting team.
Srinivas Kappagantula - Arevon Energy - 5
Answer
No
Document Name
Comment
Please see SEIA and NAGF comments on these standards. Lack of exemptions for frequency ride through requirements especially for older
legacy IBR facilities is critically important as some of these plants may not be able to comply with this standard.
Likes
0
Dislikes
0
Response
Thank you for your comment. This issue will be addressed in the upcoming draft.
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
No
Document Name
Comment
AEPC signed on to ACES comments:
It is the opinion of ACES that the definition of what constitutes an IBR should be consistent across the industry. The Project 2020-02 SDT
has been working diligently towards this goal and we do not believe that an individual standard should deviate from their approach. Thus
we recommend removing the phrase “The Elements associated with” from section 4.2 and modifying this section as follows:
4.2. Facilities:
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
47
4.2.1. Bulk Electric System (BES) IBRs; and
4.2.2. Non-BES IBRs that either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected
through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to
60 kV.
R1. ACES believes that phrase “and is initiated by a non-fault switching event on the transmission system” should be struck from the 3rd
bullet point of Requirement R1. It is our opinion that the GO will likely be unable to differentiate between an event initiated by a fault or
an event initiated by a “non-fault switching event” on the Transmission system. In short, Transmission switching events are outside the
purview of the GO.
R3/R4. ACES has grave concerns with the lack of any exceptions to Requirement R3 for existing IBRs. It is our opinion that Requirements
R3 and R4 should be modified to include an exception for an IBR that is in-service by the effective date of PRC-029-1 and has a known
hardware limitation that prevents the IBR from meeting Frequency Ride-through criteria.
R4. Lastly, it is ACES opinion that the acronym “CEA” should be spelled out in the first use within PRC-029-1 so as to eliminate any
confusion as to what this term means. “CEA” is not a defined term and while it used in the NERC Rules of Procedure, it is not commonly
used within the Reliability Standards.
Likes
0
Dislikes
0
Response
Thank you for your comment.
“The Elements” has been removed.
R1 bullet three is an optional exemption. GOs are not required to use any exemption from R1.
Frequency exemptions have been addressed in the latest draft.
CEA has been spelled out.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
48
George E Brown - Pattern Operators LP - 5
Answer
No
Document Name
Comment
Pattern Energy supports Edison Electric Institute’s and Grid Strategies LLC’s comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. Please see the response to EEI and Grid Strategies.
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric
Company, 3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
No
Document Name
Comment
PGAE recommends R3 and R4 to be revised to allow for existing IBR facility limitations for Frequenecy Ride Through, similar to the
approach in R1 and R2.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Consideration of Comments
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49
Frequency exemptions have been addressed in the latest draft.
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
No
Document Name
Comment
It is the opinion of ACES that the definition of what constitutes an IBR should be consistent across the industry. The Project 2020-06 SDT
has been working diligently towards this goal and we do not believe that an individual standard should deviate from their approach. Thus
we recommend removing the phrase “The Elements associated with” from section 4.2 and modifying this section as follows:
4.2.
4.2.1.
Facilities:
Bulk Electric System (BES) IBRs; and
4.2.2. Non-BES IBRs that either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected
through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to
60 kV.
R1.
ACES believes that phrase “and is initiated by a non-fault switching event on the transmission system” should be struck from the
3rd bullet point of Requirement R1. It is our opinion that the GO will likely be unable to differentiate between an event initiated by a
fault or an event initiated by a “non-fault switching event” on the Transmission system. In short, Transmission switching events are
outside the purview of the GO.
R3/R4. ACES has grave concerns with the lack of any exceptions to Requirement R3 for existing IBRs. It is our opinion that Requirements
R3 and R4 should be modified to include an exception for an IBR that is in-service by the effective date of PRC-029-1 and has a known
hardware limitation that prevents the IBR from meeting Frequency Ride-through criteria.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
50
R4.
Lastly, it is ACES opinion that the acronym “CEA” should be spelled out in the first use within PRC-029-1 so as to eliminate any
confusion as to what this term means. “CEA” is not a defined term and while it used in the NERC Rules of Procedure, it is not commonly
used within the Reliability Standards.
Likes
0
Dislikes
0
Response
Thank you for your comment.
“The Elements” has been removed.
R1 bullet three is an optional exemption. GOs are not required to use any exemption from R1.
Frequency exemptions have been addressed in the latest draft.
CEA has been spelled out.
Rhonda Jones - Invenergy LLC - 5
Answer
No
Document Name
Comment
Invenergy has the following comments regarding this draft of PRC-029-1:
R1: Bullet 3 presents significant challenges, and it is unclear how an entity would demonstrate compliance with the design aspect of
PRC-029-1. Generator Owners will likely not be able to properly model the non-fault switching event condition and would thus be unable
to independently assure design adherence to that requirement.
Remove “in whole or part” from Footnote 7 and Footnote 10. As drafted, the footnotes are inconsistent with IEEE-2800.
Consideration of Comments
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51
Attachment 1 bullet 10 must be removed or significantly amended. Some protection decisions must be made in a matter of microseconds, and as drafted, bullet 10 would adversely impact reliability by subjecting equipment to potentially damaging surges of current
or voltage that near instantaneous protection settings are designed to mitigate.
Invenergy disagrees with the SDT’s interpretation of FERC Order 901, and we would like to reiterate that there is no clear evidentiary
record to support the exclusion of limited exceptions from the frequency ride-through requirements. What’s most concerning however is
the SDT’s recent assertion that it “does not have sufficient data at this time to determine whether additional frequency-based
exemptions are appropriate and consistent with the overall reliability goals of Order No. 901.” We continue to await the requested
technical justification studies and would like to direct the SDT to the several public comments filed by OEMs in ERCOT’s NOGRR 245
proceeding, that illustrate equipment challenges to meet reasonable data driven ride-through capability limits that fall below the current
draft of PRC-029-1.
•
GE
245NOGRR-58 GE Vernova Comments 110723.doc (live.com)
245NOGRR-63 GE Vernova Comments 011924.docx (live.com)
•
Vestas
245NOGRR-57 Vestas Comments 110123.doc (live.com)
•
Siemens Gamesa
245NOGRR-56 Siemens Gamesa Renewable Energy Comments 103023.docx (live.com)
Additionally, the SDT and NERC are encouraged to leverage the industry provided information regarding equipment limitations submitted
according to provisions in the currently effectively Reliability Standard PRC-024-3.
As written, Draft 3 of PRC-029-1 ignores the technical realities surrounding many gigawatts of inverter-based resources installed on the
BES today and provides no path to compliance for entities with well documented and understood hardware limitations. Invenergy would
like to remind NERC that FERC has on many occasions, including within Order 901, granted NERC the leeway to exercise its technical
expertise, experience, and discretion to develop appropriate requirements.
Consideration of Comments
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52
A reasonable path to compliance for facilities with equipment that is unable to meet the proposed voltage or frequency ride-through
requirements would be to retain and carry over R3 from PRC-024-4. This would ensure equitable treatment of all generation types,
provide sensible accommodations for equipment limitations, and push facilities to maximize their capabilities to the extent possible. In
fact, FERC alluded to that in paragraph 193 of Order 901, stating, “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.”
Absent limited exemptions from the ride-through requirements or a clear path to compliance for entities with hardware limitations, the
frequency bands must be amended. To date, the SDT has provided no evidence that the proposed frequency bands, well beyond those of
IEEE-2800-2002, would benefit BES reliability.
Likes
0
Dislikes
0
Response
Thank you for your comment.
R1 bullet three is an optional exemption. GOs are not required to use any exemption from R1.
The definition of “ride-through” has been modified.
Frequency exemptions have been addressed in the latest draft to address OEM design capability limits regarding frequency thresholds.
CEA has been spelled out.
Colin Chilcoat - Invenergy LLC - 6
Answer
No
Document Name
Comment
Invenergy has the following comments regarding this draft of PRC-029-1:
Consideration of Comments
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53
R1: Bullet 3 presents significant challenges, and it is unclear how an entity would demonstrate compliance with the design aspect of
PRC-029-1. Generator Owners will likely not be able to properly model the non-fault switching event condition and would thus be unable
to independently assure design adherence to that requirement.
Remove “in whole or part” from Footnote 7 and Footnote 10. As drafted, the footnotes are inconsistent with IEEE-2800.
Attachment 1 bullet 10 must be removed or significantly amended. Some protection decisions must be made in a matter of microseconds, and as drafted, bullet 10 would adversely impact reliability by subjecting equipment to potentially damaging surges of current or
voltage that near instantaneous protection settings are designed to mitigate.
Invenergy disagrees with the SDT’s interpretation of FERC Order 901, and we would like to reiterate that there is no clear evidentiary
record to support the exclusion of limited exceptions from the frequency ride-through requirements. What’s most concerning however is
the SDT’s recent assertion that it “does not have sufficient data at this time to determine whether additional frequency-based
exemptions are appropriate and consistent with the overall reliability goals of Order No. 901.” We continue to await the requested
technical justification studies and would like to direct the SDT to the several public comments filed by OEMs in ERCOT’s NOGRR 245
proceeding, that illustrate equipment challenges to meet reasonable data driven ride-through capability limits that fall below the current
draft of PRC-029-1.
GE
245NOGRR-58 GE Vernova Comments 110723.doc (live.com)
245NOGRR-63 GE Vernova Comments 011924.docx (live.com)
Vestas
245NOGRR-57 Vestas Comments 110123.doc (live.com)
Siemens Gamesa
245NOGRR-56 Siemens Gamesa Renewable Energy Comments 103023.docx (live.com)
Consideration of Comments
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54
Additionally, the SDT and NERC are encouraged to leverage the industry provided information regarding equipment limitations submitted
according to provisions in the currently effectively Reliability Standard PRC-024-3.
As written, Draft 3 of PRC-029-1 ignores the technical realities surrounding many gigawatts of inverter-based resources installed on the
BES today and provides no path to compliance for entities with well documented and understood hardware limitations. Invenergy would
like to remind NERC that FERC has on many occasions, including within Order 901, granted NERC the leeway to exercise its technical
expertise, experience, and discretion to develop appropriate requirements.
A reasonable path to compliance for facilities with equipment that is unable to meet the proposed voltage or frequency ride-through
requirements would be to retain and carry over R3 from PRC-024-4. This would ensure equitable treatment of all generation types,
provide sensible accommodations for equipment limitations, and push facilities to maximize their capabilities to the extent possible. In
fact, FERC alluded to that in paragraph 193 of Order 901, stating, “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.”
Absent limited exemptions from the ride-through requirements or a clear path to compliance for entities with hardware limitations, the
frequency bands must be amended. To date, the SDT has provided no evidence that the proposed frequency bands, well beyond those of
IEEE-2800-2002, would benefit BES reliability.
Likes
0
Dislikes
0
Response
Thank you for your comment.
R1 bullet three is an optional exemption. GOs are not required to use any exemption from R1.
The definition of “ride-through” has been modified.
Frequency exemptions have been addressed in the latest draft to address OEM design capability limits regarding frequency thresholds.
CEA has been spelled out.
Mike Magruder - Avista - Avista Corporation - 1
Answer
No
Document Name
Consideration of Comments
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55
Comment
We concur with EEI's comments.
Likes
0
Dislikes
0
Response
Thank you, please refer to response to EEI.
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
No
Document Name
Comment
NIPSCO recommends removing the phrase “demonstrate the design of each facility” from the proposed standard and returning to the
original event-based requirements. The phrase may prove difficult to fully comply with, as a Functional Entity would have to know the
design of the collector system and parameters and run the models correctly to demonstrate this. Much of this needed information would
need to be provided by the manufacturer, which may require non-disclosure agreements.
Please clarify or remove “other mechanisms” from requirement R2.
Likes
0
Dislikes
0
Response
Thank you for your comments.
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56
Comments in previous drafts significantly desired to include design capability within PRC-029-1 to assist in determinations of compliance
outside of experience. Entities will be required to have accurate models based on performance following the implementation of
Milestone 3 directives of FERC Order No. 901.
The usage of “other mechanisms” is to assure clarity that those are inclusive of requirements given outside of PRC-029-1; it is intended to
prevent a GO from being non-compliant if required to operate differently than PRC-029-1.
Carver Powers - Utility Services, Inc. - 4
Answer
No
Document Name
Comment
Requirement 2.1.1 through 2.1.3 are all required, recommend ensuring consistency in formatting and include an “and” at the end of 2.1.2.
Request clarification of the intent of 2.1.3. The proposed language is not written clearly, and the intent is not apparent. Recommend at a
minimum addressing this sub-requirement in the technical rationale. An additional recommendation is to provide clarification on how
requirement 2.1.3 relates to the tables in Attachment 1.
Likes
0
Dislikes
0
Response
Thank you for your comment. This item was not addressed during the technical conference.
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Comment
Consideration of Comments
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57
R3. Wording “…and the absolute rate of change of frequency (RoCoF)12 magnitude is less than or equal to 5 Hz/second.” should be
removed from R3. The rate of change of frequency nas never been an issue in past IBR disturbances. In addition, PRC-024 does not
mentions and includes rate of change of frequency requirements. There is no technical rationale for this.
R3. Requirement should include exceptions due to hardware limitation, the same exception that was given for voltage requirements.
WEC Energy Group owns a wind farm with frequency limitation that may not meet PRC-029 requirements. Please explain what should
we do? Do not overlook limited capabilities of older Type 3 wind IBRs. WEC Energy Group recognized similar concerns commented by
industry, please address it.
WEC Energy Group suggests SDT to create and add graphs for support Tables 1 and 2 and the respective notes. Graphs should highlight
“must Ride‐through zone” and “may Ride‐through zone” terms that are listed in note 11.
Likes
0
Dislikes
0
Response
Thank you for your comment. Frequency criteria and exemptions are addressed in the latest draft.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
No
Document Name
Comment
"Please see EEI Comments"
Likes
0
Dislikes
0
Response
Thank you, please see the response to EEI.
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Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer
No
Document Name
2020-02 LG&E KU Comments.docx
Comment
Please see the attached comments.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
EEI does not support the approval of PRC-029-1 because it intends to require existing resources to meet the frequency performance
standards mandated in Requirement R3 and provides no mechanism for IBR resource owners to declare a technical exemption consistent
with voltage ride-through requirements contained in Requirements R1 and R2. It is EEI’s understanding that this was done because the
drafting team (DT) understood that the FERC Order did not allow any exemption for frequency ride-through requirements. However, in
Paragraph 193 of FERC Order No. 901, the Commission expressly directed NERC to determine through its standards development process
whether the Reliability Standards mandated therein should include a limited exemption for certain IBRs from voltage ride-through
performance requirements. Importantly, the Commission, in Order No. 901 did not concomitantly prohibit the inclusion of a similar
exemption from frequency ride-through performance requirements, either expressly or implicitly. Rather, it left that decision firmly in the
hands of subject matter experts, as was made evident when it encouraged “NERC’s standard drafting team to consider currently effective
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59
Reliability Standard PRC-024-3, Requirement R3 as an example for establishing registered IBR technology exemptions.” Reliability
Standards to Address Inverter-Based Resources, Order No. 901, 185 FERC ¶ 61,042, at P 193 (2022) (emphasis added).
EEI further notes that we are unaware of any frequency ride-through events, beyond equipment control setting errors, that have been
documented and cited in any of the NERC Event reports to justify a need to disallow reasonable equipment exemptions for IBRs that
cannot meet the proposed frequency ride-through requirements. Nevertheless, PRC-029-1 contains requirements for frequency
ride-through that are likely infeasible to implement through either hardware or software means, in many cases for existing resources.
(Noting that while software upgrades might be a viable option for some newer IBRs, software solutions for older resources would not be
a viable remedy because many of the older resources would not have the computing capability necessary to support such upgrades.)
To address our concerns, we recommend the following:
1.
2.
Change PRC-029-1 to include reasonable and justified exemptions for legacy IBR facilities. (See edits to R4 below)
Align the Frequency ride-through curve in PRC-029-1 with IEEE 2800-2022. (Align Table 3 of attachment 2 to IEEE 2800-2022)
PRC-029-1 (Requirement R4 – Changes in Boldface)
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of PRC-029-1, has known hardware limitations that
prevent the IBR from meeting voltage and frequency Ride-through criteria as detailed in Requirements R1, R2, and R3 and requires an
exemption from specific Ride-through criteria shall:10 Lower] [Time Horizon: Long-term Planning]
4.1.
Document information supporting the identified hardware limitation no later than 12 months following the effective date of
PRC-029-1. This documentation shall include:
4.1.1
Identifying information of the IBR (name and facility #);
4.1.2
Which aspects of voltage or frequency Ride-through requirements that the IBR would be unable to meet and the capability of
the hardware due to the limitation;
4.1.3
Identify the specific piece(s) of hardware causing the limitation;
4.1.4
Supporting technical documentation verifying the limitation is due to hardware that needs to be physically replaced or that the
limitation cannot be removed by software updates or setting changes, and;
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60
4.1.5
Information regarding any plans to remedy the hardware limitation (such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), Reliability Coordinator(s), and the CEA no later than 12 months following the effective date of
PRC-029-1.
4.2.1
Any response to additional information requested by the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA shall be provided back to the requestor within 90 days of the request.
4.2.2
Provide a copy of the acceptance of a hardware limitation by the CEA to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s).11
4.3.
Each Generator Owner with a previously accepted limitation that replace the hardware causing the limitation shall document
and communicate such a hardware change to the associated Planning Coordinator(s), Transmission Planner(s), Transmission Operator(s),
and Reliability Coordinator(s) within 90 days of the hardware change.
4.3.1
Likes
When existing hardware causing the limitation is replaced, the exemption for that Ride-through criteria no longer applies.
0
Dislikes
0
Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
61
See EEI Comments
Likes
0
Dislikes
0
Response
Thank you for your comment. Please see the response to EEI.
Kimberly Turco - Constellation - 6
Answer
No
Document Name
Comment
Constellation aligns with NAGF comments.
Kimberly Turco on behalf of Constellation Energy Segments 5 and 6.
Likes
0
Dislikes
0
Response
Thank you, please see the response to NAGF.
Richard Vendetti - NextEra Energy - 5
Answer
No
Document Name
Comment
Consideration of Comments
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62
Facilities:
4.2.1. The Elements associated with (1) Bulk Electric System (BES) IBRs inverter‐based resources and (2) Non‐BES IBRs that either have or
contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV
NextEra aligns with EEI’s recommendation to remove “elements associated with” from Section 4.2.1
R1 and R2
NextEra believes that further clarity on reporting could be added to R1 and R2 consistent with the technical rationale.
R3
With a large portion of wind fleet across multiple OEMS, NextEra recommends there be an exception process for R3, or that it should not
be applied retroactively. This is a particular concern for entrants for the Non-BES Assets.
R4
NextEra aligns with the below comments provided from EEI:
EEI does not agree with imposing new unverified requirements on existing resources as proposed in PRC-029-1 because it is unclear how
many existing resources can meet the frequency performance standards mandated in Requirement 3. We are additionally concerned
because resource owners have not been given adequate time to fully assess the impact of imposing these new requirements on their
existing resources, which align with IEEE 2800-2022 (See 7.3.2.1 Figure 12 & Table 15 (Frequency ride-through, page 80; and see 7.3.2.3.5
Rate of change of frequency (ROCOF), page 82), and did not exist as a Standard until February 2022, after most of these resources were
built or placed in service. For this reason, we cannot support the approval of PRC-029-1 without the following changes to Requirement 4
ensure that existing resources that were not design and do not have the capability to meet these requirements are allowed to declare an
exemption for frequency ride-through similar to what is provided for resources that cannot meet the voltage ride-through requirements.
See the proposed changes to R4 in boldface below:
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63
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of PRC-029-1, has known hardware limitations that
prevent the IBR from meeting voltage and frequency Ride-through criteria as detailed in Requirements R1, and R2, and R3 and requires
an exemption from specific voltage Ride-through criteria shall:10 Lower] [Time Horizon: Long-term Planning]
4.1.
Document information supporting the identified hardware limitation no later than 12 months following the effective date of
PRC-029-1. This documentation shall include:
4.1.1
Identifying information of the IBR (name and facility #);
4.1.2
Which aspects of voltage or frequency Ride-through requirements that the IBR would be unable to meet and the capability of
the hardware due to the limitation;
{C}4.1.3
Identify the specific piece(s) of hardware causing the limitation;
4.1.4
Supporting technical documentation verifying the limitation is due to hardware that needs to be physically replaced or that the
limitation cannot be removed by software updates or setting changes, and;
4.1.5
Information regarding any plans to remedy the hardware limitation (such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), Reliability Coordinator(s), and the CEA no later than 12 months following the effective date of
PRC-029-1.
4.2.1
Any response to additional information requested by the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA shall be provided back to the requestor within 90 days of the request.
4.2.2
Provide a copy of the acceptance of an a hardware limitation by the CEA to the associated Planning Coordinator(s),
Transmission Planner(s), Transmission Operator(s), and Reliability Coordinator(s).11
4.3.
Each Generator Owner with a previously accepted limitation that replace the hardware causing the limitation shall document
and communicate such a hardware change to the associated Planning Coordinator(s), Transmission Planner(s), Transmission Operator(s),
and Reliability Coordinator(s) within 90 days of the hardware change.
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64
4.3.1
When existing hardware causing the limitation is replaced, the exemption for that Ride-through criteria no longer applies.
Footnote 7
“Available Real Power” is not NERC defined term located in the NERC Glossary of Terms. By adding to the footnote, this creates confusion.
NextEra recommends defining and adding to NERC Glossary.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Megan Melham - Decatur Energy Center LLC - 5
Answer
No
Document Name
Comment
Capital Power supports the NAGF's comments:
The NAGF strongly recommends that PRC-029 be revised to allow for frequency ride through (“FRT”) exemptions to address such
limitations for legacy IBR facilities. Not including FRT exemptions will result in a standard that will make certain IBR legacy facilities
automatically non-compliant when the standards become effective.
Requirement R3 – the NAGF is concerned that legacy IBR facilities are not capable of meeting the 5 Hz/second maximum ROCOF or the
25-degree phase angle jump requirements. Therefore, FRT exemptions are necessary and need to be included in Requirement R3. In
support of this concern, the NAGF points to the ERCOT NOGRR245 TAC Presentation, December 4, 2023 – page 4 which indicates that 40%
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
65
of OEMs cannot comply with the previously proposed specific 5 Hz/second maximum ROCOF requirement and 41% of OEMs cannot
comply with the previously proposed specific 25-degree phase angle jump requirement.
December 4 2024 NOGRR245 TAC Stephen Solis - Principal System Operations Improvement
Requirement R4.2.2 – the NAGF is unclear as to what the Compliance Enforcement Authority (CEA) acceptance for an IBR hardware
limitation exemption will consist of. Will the CEA provide an email response confirming acceptance to the Generator Owner submitting the
exemption? How are such exemptions to be submitted and to whom within the CEA organization?
In addition to the NAGF comments above, after discussions with a wind turbine OEM, some legacy equipment will not be able to handle
the 64 Hz overfrequency ride-through requirement stipulated in PRC-029. Requiring IBRs to ride through an overfrequency in the range
of 61.8 Hz to 64 Hz is beyond the IEEE 2800 standard, as stated by the SDT within the technical rationale. We recommend aligning the
frequency ride-through requirement to be more in line with the IEEE 2800 standard and reducing the final "no-trip" overfrequency
requirement to 61.8Hz in addition to changing the wording of Requirement R4 to allow for FRT exemptions. More discussions with IBR
OEMs must be held to confirm equipment capabilities.
Likes
0
Dislikes
0
Response
Thank you, please see the response to NAGF.
Alison MacKellar - Constellation - 5
Answer
No
Document Name
Comment
Constellation aligns with NAGF comments.
Alison Mackellar on behalf of Constellation Segments 5 and 6
Likes
0
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
66
Dislikes
0
Response
Thank you, please see the response to NAGF.
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF strongly recommends that PRC-029 be revised to allow for frequency ride through (“FRT”) exemptions to address such
limitations for legacy IBR facilities. Not including FRT exemptions will result in a standard that will make certain IBR legacy facilities
automatically non-compliant when the standards become effective.
Requirement R3 – the NAGF is concerned that legacy IBR facilities are not capable of meeting the 5 Hz/second maximum ROCOF or the
25-degree phase angle jump requirements. Therefore, FRT exemptions are necessary and need to be included in Requirement R3. In
support of this concern, the NAGF points to the ERCOT NOGRR245 TAC Presentation, December 4, 2023 – page 4 which indicates that 40%
of OEMs cannot comply with the previously proposed specific 5 Hz/second maximum ROCOF requirement and 41% of OEMs cannot
comply with the previously proposed specific 25-degree phase angle jump requirement.
December 4 2024 NOGRR245 TAC Stephen Solis - Principal System Operations Improvement
The NAGF recommends aligning exception language with IEEE-2800. The proposed PRC-029 ride through requirements do not include the
technology limitations discussed in IEEE-2800.
Requirement R4.2.2 – the NAGF is unclear as to what the Compliance Enforcement Authority (CEA) acceptance for an IBR hardware
limitation exemption will consist of. Will the CEA provide an email response confirming acceptance to the Generator Owner submitting the
exemption? How are such exemptions to be submitted and to whom within the CEA organization?
Likes
0
Consideration of Comments
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67
Dislikes
0
Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Ruchi Shah - AES - AES Corporation - 5
Answer
No
Document Name
Comment
•
AES CE believes additional changes are needed as explained below.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Adam Burlock - Adam Burlock On Behalf of: Ashley Scheelar, TransAlta Corporation, 5; - Adam Burlock
Answer
No
Document Name
Comment
TransAlta supports multiple other organizations who recommend the addition of frequency ride-through to the allowable hardware
limitations in R4.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
68
Likes
0
Dislikes
0
Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3,
5, 1, 6; Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
No
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) on question 2
Likes
0
Dislikes
0
Response
Thank you, please see the response to EEI.
Michael Goggin - Grid Strategies LLC - 5
Answer
No
Document Name
Comment
Consideration of Comments
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69
In the current draft of PRC-029, R4 should be modified to allow existing resources with equipment limitations to obtain an exemption
from the frequency ride-through requirements in R3, instead of only allowing an exemption from the voltage ride-through requirements
in R1 and R2. This is necessary because most existing IBR generators cannot meet the stringent frequency ride-through requirements
proposed in R3 without deploying significant hardware modifications or replacement, which goes against the intent of FERC Order 901.
Without change, a large share of the 270 GW of operating IBR plants,[1] representing an investment of hundreds of billions of dollars,
will be forced into early retirement. Abruptly forcing such a large volume of existing generators offline would not only impose massive
costs, but also cause generation shortfalls in many regions. Such drastic action could be understandable if the frequency ride-through
requirement were addressing a real reliability concern. However, NERC and the drafting team have repeatedly been unable to provide any
technical justification for imposing the frequency ride-through requirement existing IBR plants. None of the reports NERC has published in
response to IBR ride-through events have identified frequency ride-through as a significant concern. There is no reason to impose such a
massive cost and reliability impact for a solution in search of a problem.
Information provided by the two largest IBR owners in the U.S. confirms that most existing IBRs cannot meet the frequency ride-through
requirements. One of these developers indicated that more than 30% of its fleet could not comply with the draft standard. The other
indicated that half of its operating IBR fleet has no viable path to compliance, and a large share of the remainder will require costprohibitive retrofits, so if the standard went into effect as drafted a large share of its operating fleet will have to be retired or fully
repowered. Other developers that operate the remainder of the 270 GW IBR fleet would likely see comparable impacts. Retiring, or at
best taking out of service for an extended period of time for repowering, such a large volume of facilities during a time of rapid growth in
peak load and energy needs would cause far greater reliability concerns than whatever concern the frequency ride-through requirement
is attempting to address.
Information provided by these developers indicates that a large share of wind, solar, and battery resources cannot meet the frequency
ride-through standard without significant hardware replacement. The frequency ride-through requirements are particularly problematic
for some existing wind generators. In the Technical Rationale document accompanying the second PRC-029 draft, the drafting team
notes that some wind generators are more sensitive to frequency deviations, writing that “All IBR resources (except for type 3 wind
turbines) interface to the grid through fast switching of power electronics devices. These power electronic devices are much less
sensitive to the transmission system frequency excursion than non‐hydraulic turbine synchronous resources.”[2] However, the drafting
team then incorrectly concludes that “Therefore, IBR should be capable of riding through the increased proposed 6‐second frequency
ride‐through requirement without risk of equipment damage or need for frequency protection to operate.” The Technical Rationale
document does not offer any justification for its assumption that Type III wind turbines can meet the frequency ride-through
Consideration of Comments
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requirements, despite noting that those turbines more directly interface with the grid and thus are more affected by frequency deviations than
other IBRs.
In fact, many existing Type III wind turbines cannot meet the frequency ride-through requirements proposed in this draft of PRC-029.
Those resources were designed to meet the reliability Standards and interconnection requirements that were in effect when they were
placed in service, and were not designed to ride through frequency excursions of the magnitude and duration proposed in the draft
Standard. Imposing a retroactive requirement on these generators is particularly problematic as it is not typically feasible to retrofit
existing wind turbines to increase their ability to withstand mechanical stresses due to frequency changes. In such cases, making existing
equipment better able to withstand frequency changes would require full replacement or extensive modification of hardware, which
would come at a significant, and sometimes prohibitive, cost. At minimum, bringing wind plants that cannot meet the current standard
into compliance would require replacing the turbine converter and controller. Further, frequency changes can impose mechanical
stresses on highly sensitive elements in the wind turbine’s rotating equipment, including the generator, gearbox, the main shaft, and
bearings associated with all of that equipment, and requiring such resources to ride through frequency changes they were not designed
to operate through can damage that equipment. Subjecting Type III wind turbines to this damage may lead to increased outages or
premature failure of these generators, potentially increasing reliability risks. As noted above, if the standard went into effect as drafted a
large share of the operating IBR fleet will have to be retired or fully repowered. Retiring these facilities during a time of rapid growth in
peak load and energy needs would cause far greater reliability concerns than whatever concern the frequency ride-through requirement
is attempting to address.
The Solution: Frequency ride-through exemptions for existing IBRs
The easiest solution is to modify R4 to allow existing resources with equipment limitations to obtain an exemption from the frequency
ride-through requirements in R3, which would make PRC-029 consistent with a long precedent of FERC interconnection requirements and
NERC Standards only applying prospectively, including PRC-024. Retroactive requirements impose a much greater financial burden on the
generator than prospective Standards, and set a bad precedent by unfairly penalizing generators that met all requirements that were in
effect at the time they were installed. Retrofit or replacement costs are typically much greater than if the capability were installed at the
plant to begin with. In some cases parts needed for retrofits may not be available, particularly for models that have been discontinued or
manufacturers that are no longer in business, potentially requiring the replacement of the entire power conversion system. Moreover,
existing IBR generators typically sell their output at a fixed price under a long-term power purchase agreement, and unexpected retrofit
or replacement costs cannot typically be recovered once a power purchase agreement has been signed. These unexpected and
unrecoverable costs are far more concerning to lenders and other generation project financiers as they were not accounted for during the
project’s financing. As a result, retroactive requirements set a bad precedent by introducing regulatory uncertainty that makes future
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generation investment more uncertain and riskier, and likely more costly by forcing financiers to charge higher risk premiums. Changing
the rules in the middle of the game and penalizing resources that were designed to the standards in effect at the time they were built also
establishes a bad precedent, in addition to imposing costs that are not just and reasonable and undue discrimination relative to resources
covered by PRC-024.
Fortunately, these problems can be fixed by simply inserting “R3” into the list of permissible exemptions in R4, which would allow existing
resources with equipment limitations to obtain an exemption from the frequency ride-through requirements in R3.
In the Technical Rationale document, the drafting team points to FERC’s directive in Order No. 901 to justify not allowing existing
resources to obtain an exemption from the frequency ride-through requirements in R3: “FERC Order No. 901 states that this provision
would be limited to exempting ‘certain registered IBRs from voltage ride‐through performance requirements.’ This is the reason that no
similar provisions are included for exemptions for frequency or rate‐of‐change‐of‐frequency (ROCOF) ride‐through requirements per
R3.”[3]
However, a contextual reading of Order No. 901 indicates FERC was focused on targeting equipment limitation exemptions at existing
generators that would have to physically replace or modify hardware to comply with the Standard, and not focused on limiting such
exemptions to voltage ride-through requirements. Paragraph 193 in its entirety, and particularly the first sentence, explain that FERC’s
intent was exempting existing resources that would have to physically replace or modify hardware: “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.” As a result, FERC continued by directing that “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.”[4]
Allowing existing plants to apply for an equipment limitation exemption for the frequency ride-through requirements in R3 is necessary to
ensure some existing generators do not have to physically replace or modify hardware, as explained above. As a result, such an
exemption is consistent with FERC’s directive and intent in Order No. 901. As documented in the following footnote, there is ample
precedent for NERC and standards drafting teams to exercise their technical expertise to craft Standards to align content and
requirements with technical realities.[5]
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Additional context in Order 901 further demonstrates that FERC intended for NERC to include an exemption for existing IBRs that cannot
meet frequency ride-through requirements. At paragraph 190 in Order No. 901, FERC directed NERC to develop Standards that ensure
resources “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.” For many existing IBRs that
cannot meet the proposed frequency ride-through requirements, tripping is necessary to protect the IBR equipment, similar to when
synchronous generation resources use tripping as protection from internal faults. As a result, an exemption from R3 for existing resources is
consistent with FERC’s intent. Order No. 901 also directed NERC to consider the “PRC-024-3, Requirement R3 as an example for
establishing registered IBR technology exemptions,” and that exemption applies equally to voltage ride-through and frequency ridethrough settings, further suggesting that FERC will allow certain IBRs an exemption from the frequency ride-through requirements.[6]
Finally, Order No. 901 notes that in the notice of proposed rulemaking that led to the order, FERC “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.”[7] FERC then adopted that very proposal,{C}[8] further demonstrating that FERC sought to
direct NERC to only require frequency and voltage ride-through where technologically feasible.
When asked about this issue, FERC staff has indicated that as a general matter, when a Commission Order is silent on a topic it is neither
requiring something nor requiring the absence of that thing. NERC is taking a contrary position by arguing that due to FERC’s silence they
are not allowed to give an exemption for frequency ride-through.
NERC has been unable to present any technical reason why FERC would not allow a frequency ride-through exemption for existing IBRs,
as none exists. Frequency ride-through has not been identified as a significant concern in any of the reports NERC has commissioned
regarding IBR ride-through during disturbance events. Moreover, there is no technical justification for requiring existing IBRs to meet the
extremely wide frequency ride-through bands proposed in PRC-029. PRC-029 requires IBRs to remain online for 6 seconds at 56-64 Hz, 5
minutes at 57-61.8, 11 minutes at 58.5-61.5, and indefinitely at 58.8-61.2 Hz. Under-Frequency Load Shedding (UFLS) that restores
frequency following an extreme disturbance typically begins at 59.4 or 59.5 Hz. There is no credible reliability reason for requiring IBRs to
remain online for 5 minutes for excursions that are 5 times more severe than the threshold at which UFLS restores frequency, and
indefinitely for a frequency excursion twice as severe as that threshold. Such a requirement for IBRs is particularly pointless because
PRC-024 would have allowed synchronous resources’ relays to trip those generators far before that point for far less severe excursions.
This highlights another likely reason FERC Order No. 901 did not explicitly direct NERC to include frequency ride-through exemptions:
FERC did not anticipate that NERC would adopt such a strict frequency ride-through requirement that some existing IBR plants cannot
meet it. The drafting team even notes at page 7 in the Technical Rationale document that “The proposed 6‐second time frame of the
frequency ride‐through capability requirement is beyond the IEEE 2800 standard frequency ride‐through requirement and beyond
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frequency ride‐through requirements for synchronous machines under proposed PRC‐024‐4.” There is nothing in Order No. 901 that
suggests that FERC was opposed to existing equipment exemptions for a frequency ride-through standard that was drafted after FERC
issued Order No. 901 and is more stringent than FERC anticipated. A much more reasonable interpretation is that the logic FERC provided
in paragraph 193 of Order No. 901 also applies to a frequency ride-through requirement that some existing resources cannot meet
without physical modification or replacement of equipment. In fact, paragraph 193 makes clear that FERC’s language focuses on an
exemption from voltage ride-through requirements because “a subset of existing registered IBRs… may be unable to implement the
voltage ride though performance requirements directed herein.”
At the end of paragraph 193, FERC also explained that an exemption for existing resources would not harm reliability because “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.” FERC’s reasoning in paragraph
193 also applies to an exemption from frequency ride-through requirements, but particularly the conclusion that exempting existing
plants does not cause reliability concerns and therefore should be allowed. The NERC drafting team’s technical justification document
explicitly explains that the frequency ride-through requirement is “to ensure the reliability of future grids with high IBR penetration,”
{C}[9] based on concerns about declining inertia due to IBRs replacing synchronous resources. NERC and others have demonstrated that
inertia and frequency response will remain more than adequate for the foreseeable future even following disturbances that are several
times larger than current credible contingencies, and that higher IBR penetrations can actually significantly improve frequency
stabilization following disturbances.[10]
As a result, there is no reliability concern from an exemption for the small number of existing resources that cannot meet the
requirements without physical modification or replacement of equipment. Moreover, as FERC notes, these plants will replace that
equipment anyway over time as legacy inverters fail or are replaced with more modern equipment for other reasons, and the draft
standard requires replacement equipment to comply with the Standard. Utility-scale inverters installed at solar and battery installations
typically come with warranties of 10 years or less,{C}[11] and those inverters are typically replaced at least once during the plant’s
lifetime. Many existing wind plants are also being repowered with newer turbines, often to allow the project to receive another 10 years
of production tax credits after the initial 10 years of credits have been received. As a result, by the time the drafting team’s concerns
about inertia in a high IBR penetration future might materialize, the vast majority of IBRs that cannot meet the frequency ride-through
requirements will have been replaced with new equipment that is not exempt.
Moreover, the drafting team’s assumption that frequency deviations will be larger on a future low inertia power system is flawed. IBRs
can provide fast frequency response, which stabilizes frequency in the initial seconds following a grid disturbance, before synchronous
generators begin to provide their slower primary frequency response.[12] Thus fast frequency response provides a similar service to
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inertia in helping to arrest the change in frequency before primary frequency response is fully deployed, reducing the need for inertia.
[13] Fast frequency response is easily provided by batteries due to their available energy, but can also be provided by curtailed wind or
solar resources. Power systems with high IBR penetrations will tend to have some wind or solar curtailment in a significant share of hours.
If allowed to do so, solar an battery resources with spare DC capacity behind the inverter can also temporarily exceed their
interconnection agreement’s AC injection limit to provide fast frequency response.
The replacement of inflexible synchronous resources with more flexible IBRs could also significantly improve primary frequency response,
as NERC’s modeling has demonstrated.{C}[14] NERC has also documented that only about 30% of synchronous generators provide primary
frequency response, and only about 10% provide sustained primary frequency response.[15] Even with less inertia, the fast and accurate
frequency response provided by IBRs will keep frequency more tightly controlled than the slow to nonexistent primary frequency
response from synchronous generators. The replacement of large synchronous generators with smaller IBRs should also reduce the
magnitude of frequency deviations following the loss of generators. If frequency response does begin to emerge as a concern, the more
effective solution would be to enforce requirements on synchronous generators that are supposed to provide it but do not. If necessary,
operators would alter real-time dispatch, as ERCOT and some island power systems occasionally do today, to ensure that inertia and fast
frequency response are adequate to ensure under-frequency load shedding or generator tripping thresholds are not reached. Finally,
grid-forming inverters are increasingly being deployed with battery storage and other IBR installations, further increasing the
contributions of IBRs to stabilizing frequency.
At page 8 in the Technical Rationale document, the drafting team argues that “To compensate for the lack of inertia and short circuit
contributions, [IBRs] should have wider tolerances for frequency and voltage excursions to meet the needs of future power systems with
a higher percentage of IBR.” The drafting team also argues that IBRs should have to ride-through much larger frequency deviations than
synchronous resources because “Synchronous resources are more sensitive to frequency deviations than IBR resources.” This logic is
flawed for many reasons. Grid operators need all resources to ride through disturbances, and the contribution of a resource to inertia or
short circuit needs is irrelevant to that need. Any concerns about resources’ inertia and short circuit contributions are outside the drafting
team’s scope and authority, and should be addressed by other means (such as by increasing the deployment of grid-forming IBRs in the
localized areas that have short circuit or stability concerns). It is also perverse for the drafting team to penalize IBRs for being less
sensitive to frequency deviations than synchronous generators. As noted below, there are already grounds for FERC to reject this
proposed standard due to undue discrimination against IBRs relative to the far more lenient requirements on synchronous generators
under PRC-024, including an equipment limitation exemption for synchronous generators from the frequency relay setting requirement in
PRC-024,[16] and this only adds to those concerns.
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In short, the drafting team’s unfounded concerns about a future power system do not justify withholding an exemption to frequency ridethrough requirements for existing IBRs that will have been largely replaced by the time any concerns might materialize.
Finally, R4 equipment limitation exemptions should be allowed for resources with signed interconnection agreements as of the effective
date of the Standard, instead of resources that are in-service as of that date. Resource equipment decisions are typically locked down at
the time the interconnection agreement is signed, and a change in requirements after that point can require a costly change in
equipment or settings that may also trigger a material modification and resulting interconnection restudies. The implementation plan for
PRC-029 indicates that the effective date for the Standard will be the first day of the first quarter six months after FERC approval. Many
resources take significantly longer than that to move from a signed interconnection agreement to being placed in service, so it makes
more sense to allow R4 equipment limitation exemptions for resources that have a signed interconnection agreement as of the effective
date of the Standard.
The current draft of the PRC-029 Standard is unworkable and will impose massive costs on some existing generators with no benefit for
reliability. As explained above, the drafting team incorrectly ventures that “IBR should be capable of riding through the increased
proposed 6‐second frequency ride‐through requirement without risk of equipment damage or need for frequency protection to operate,”
even after noting that some wind turbines use very different technology. NERC’s rigorous standard development process exists to ensure
that errors like this do not make it into final Standards, and the exceedingly low level of support for the initial draft and the major
revisions in the current draft indicate that further revisions will likely be necessary. It takes time to fine tune highly technical
requirements and vet them across the industry to avoid unnecessary and exorbitant costs for existing resources that cannot meet the
standard.
If PRC-29 continues to fall short of the level of support required for approval in this round of balloting, and NERC proceeds under Rules of
Procedure Rule 321.2.1 by having the Standards Committee convene a technical conference and use the input from the technical
conference to revise the standard for a final re-balloting period, incorporating an exemption from the frequency ride-through
requirement for existing IBR generators would help to secure sufficient support for the standard to pass during re-balloting. Irreparable
and immediate harm will occur if PRC-029 is allowed to move forward in its current form, harm that cannot be undone even if NERC
immediately opens a standards revisions effort after the adoption of PRC-029 to fix these concerns. The current implementation plan
requires BES IBRs to “ensure the design of their IBR units meets the criteria” within 12 months following regulatory approval of the
standard, while for non-BES IBRs the compliance deadline will be the later of January 1, 2027, or 12 months following regulatory approval
of the standard.[17] A year or two provides IBR owners with no time to wait if hundreds of GW of existing IBRs are required to secure
retrofit or replacement equipment, find skilled technicians and tools to install that equipment, and complete that work during scheduled
plant outages, especially since the entire industry will be pulling from the same pool of equipment and skilled labor. As a result, if
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PRC-029 is approved in its current form, IBR owners will immediately begin incurring massive non-refundable costs for equipment orders
and labor contracts, as they cannot wait in the hope that a subsequent revision effort will fix this error. Moreover, the typical timeline
from Standard Authorization Request through standard balloting and FERC approval is much more than a year, so industry would have no
reason to expect such an effort could be completed before PRC-029 took effect.
Alternative solutions
If NERC refuses to accept that Order 901 allows it to exempt existing IBRs from the frequency ride-through requirement, alternative
solutions can mitigate the harm the proposed standard would cause. One alternative solution would be modifying the standard to allow
IBRs, or at least existing IBRs, to meet far less stringent frequency ride-through curves than those proposed in PRC-029. The less stringent
frequency ride-through curve or curves could be taken from PRC-024. As noted above, the PRC-024 curves are closer to but still
significantly wider than UFLS thresholds, and thus are better tailored to meeting actual reliability needs. An additional advantage is that
the PRC-024 curves have been in place for many years and thus many existing IBRs were designed with relays that would not trip them for
disturbances of that magnitude. In contrast, the curves proposed in PRC-029 are far more stringent than past design practice and could
not have been anticipated by IBRs when they were built. Industry could work to identify a reasonable and attainable frequency
ride-through curve or curves at the technical conference that will likely be convened due to Rule 321.2.1, which could then be
incorporated into the revised standard that subsequently goes out for a final re-balloting period.
This approach will not mitigate all of the harm caused by PRC-029, as PRC-024 still allows exemptions for equipment limitations,[18] while
NERC is taking the position that PRC-029 cannot. Moreover, adopting something approximating the PRC-024 curves in PRC-029 would still
result in disparate treatment for IBRs because PRC-024 is only a relay-setting standard and PRC-029 is a ride-through performance
requirement. The most elegant solution, and the one least likely to result in a costly mistake that requires expensive retrofits and plant
retirement for no reliability benefit, and risk FERC rejection of the standard, is to simply include an exemption for existing resources.
Undue discrimination
Providing an exemption in PRC-029 R4 for existing IBRs that cannot meet the frequency ride-through requirement in R3 will provide less
disparity with the treatment of synchronous resources under PRC-024, and is therefore an essential step if NERC wants to reduce the risk
of FERC rejecting the proposed standard due to undue discrimination against IBRs. As noted above, PRC-024 allows exemptions for
equipment limitations,[19] so exempting existing IBRs from PRC-029’s frequency ride-through requirements would reduce the undue
discrimination towards IBRs.
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It should also be noted that PRC-029 is far more stringent because it is a ride-through performance requirement, while the existing and
proposed versions of PRC-024 are simply relay-setting standards. PRC-024 only requires protective relays to be set so they do not trip the
generator within specified bounds, but it allows a resource to trip offline for other reasons. PRC-024-4 explicitly allows a plant to trip if
protection systems trip auxiliary plant equipment, per section 4.2.3. In contrast, PRC-029 is a performance standard that requires IBRs to
remain electrically connected and to continue to exchange current within the specified voltage and frequency bounds. Said another way,
an IBR and a synchronous resource could both trip during the same disturbance, and the IBR would be in violation of PRC-029 but the
synchronous generator would not be in violation of PRC-024-4, as long as the synchronous generator did not trip due to the settings of its
protection system.
To ensure grid reliability and resilience, all resources including IBRs and synchronous resources should ride through grid disturbances. The
failure of synchronous generators to ride through grid disturbances threatens grid reliability as much or more than the failure of IBRs, as
synchronous resources are often producing at a higher level of output, are more typically relied on as capacity resources, and often take
longer to come back online and ramp up to full output if they trip due to a disturbance.
FERC Order No. 901 directed NERC to treat IBRs similarly to how NERC Standards treat synchronous generators, writing that the IBR
Standard should “permit IBR tripping only to protect the IBR equipment in scenarios similar to when synchronous generation resources
use tripping as protection from internal faults.”{C}[20] Allowing synchronous generators to trip but requiring IBRs to ride through the
same or similar disturbance could be challenged at FERC as undue discrimination. Providing synchronous generators with an exemption
from PRC-024’s frequency relay setting requirements but not offering IBRs an exemption from the far more stringent frequency
ride-through requirements in PRC-029 only compounds the undue discrimination, and makes an even stronger case for FERC to reject
PRC-029 as proposed.
Not requiring ride-through performance from synchronous generators is also at odds with the intent for this project that NERC stated in
its February 2023 comments on the FERC proposed rulemaking that led to Order No. 901: “A comprehensive, performance-based
ride-through standard is needed to assure future grid reliability. To that end, NERC re-scoped an existing project, 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 generating resources.”[21] FERC’s Order No. 901 also noted NERC’s statement that this project
would require ride-through performance from all generating resources,[22] so a failure to require ride-through performance from
synchronous generators is contrary to both NERC’s and FERC’s intent.
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Providing an exemption in PRC-029 R4 for existing IBRs that cannot meet the frequency ride-through requirement in R3 will provide less
disparity with the treatment of synchronous resources under PRC-024, and is therefore an essential step if NERC wants to reduce the risk
of FERC rejecting the proposed standard due to undue discrimination against IBRs.
{C}[1]{C} https://www.utilitydive.com/news/clean-energy-capacity-wind-solar-2024-acp-report/715501/
{C}[2]{C} Technical Rationale, PRC-029-1 – Frequency and Voltage Ride-Through Requirements for Inverter-Based Generating Resources,
at 8, https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-0291_Technical_Rationale_Redline_to_Last_Posted_06182024.pdf (“Technical Rationale”).
{C}[3]{C} Id., at 10
{C}[4]{C} Reliability Standards to Address Inverter-Based Resources, Order No. 901, 185 FERC ¶ 61,042, P 193 (2023).
{C}[5]{C} For example, Section 215(d)(2) of the FPA requires FERC to give “due weight” to the technical expertise of the ERO when
evaluating the content of a proposed Reliability Standard or modification to a Standard.
Order No. 733-A, P 11: “In this order, we emphasize and affirm that we do not intend to prohibit NERC from exercising its technical
expertise to develop a solution to an identified reliability concern that is equally effective and efficient as the one proposed in Order
No. 733.”
Order No. 748, P 43: “In consideration of these ongoing efforts, we will not direct specific modifications to these Reliability Standards
and, rather, accept NERC’s commitment to exercise its technical expertise to study these issues and develop appropriate revisions to
applicable Standards as may be necessary.”
Order No. 896, P 36: “NERC may also consider other approaches that achieve the objectives outlined in this final rule. Further, as
recommended by PJM, we believe there is value in engaging with national labs, RTOs, NOAA, and other agencies and organizations in
developing benchmark events. Considering NERC’s key role, technical expertise, and experience assessing the reliability impacts of various
events and conditions, we encourage NERC to engage with national labs, RTOs, NOAA, and other agencies and organizations as needed.”
Order No. 901, P 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
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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.”
{C}[6]{C} Order 901, P 193
{C}[7]{C} Id. at P 178.
{C}[8]{C} Id. at P 190.
{C}[9]{C} Technical Rationale at 7.
{C}[10]{C} East Interconnection Frequency Response Assessment with Inverter Based Resources, at 7
https://www.energy.gov/sites/prod/files/2018/07/f53/2.1.4%20Frequency%20Response%20Panel%20-%20Velummylum%2C%20NERC.pdf.
{C}[11]{C} Best Practices for Operation and Maintenance of Photovoltaic and Energy Storage Systems, at 55,
https://www.nrel.gov/docs/fy19osti/73822.pdf.
{C}[12]{C}Fast Frequency Response Concepts and Bulk Power System Reliability Needs,
https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/Fast_Frequency_Response_
Concepts_and_BPS_Reliability_Needs_White_Paper.pdf.
{C}[13]{C} Inertia and the Power Grid: A Guide Without the Spin, https://www.nrel.gov/docs/fy20osti/73856.pdf.
{C}[14]{C} East Interconnection Frequency Response Assessment with Inverter Based Resources, at 7
https://www.energy.gov/sites/prod/files/2018/07/f53/2.1.4%20Frequency%20Response%20Panel%20-%20Velummylum%2C%20NERC.pdf.
{C}[15]{C} https://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/FRI_Report_10-30-12_Master_wappendices.pdf
{C}[16]{C} https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-0244_Draft_2_Clean_06182024.pdf, R3, at pages 5-6
{C}[17]{C} https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-024-4_PRC-0291_Implementation%20Plan_Redline_to_Last_Posted_07222024.pdf
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{C}[18]{C} https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-0244_Draft_2_Clean_06182024.pdf, R3, at pages 5-6
{C}[19]{C} https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-0244_Draft_2_Clean_06182024.pdf, R3, at pages 5-6
{C}[20]{C} Order No. 901, at P190
[21]{C}https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Comments_IBR%20Standards%20NOPR.pdf, at
21-22.
[22]{C} Order No. 901, at P185
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Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Brian Van Gheem - Radian Generation - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
1.
Requirements R1, R2 and R3 use the phrase “ensure design and operation” to imply a Generator Owner is required to guarantee
an IBR will be operated in Real-time as designed. We observe the Standard Drafting Team’s (SDT) previous response to the
meaning of this phrase is clarified through the “additional specificity and examples for objectively evaluating compliance” within
each requirement’s measure. We believe this is outside the scope of the NERC Protection and Control Reliability Standards, as
only a Generator Operator can make such guarantees. The scope of the Protection and Control Reliability Standards are to ensure
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2.
3.
4.
5.
6.
facility equipment is properly configured and with settings that achieved sufficient and observable reliability during facility
operating simulations. Several of these Reliability Standards have periodicities that ensure the initial design philosophy is still
being achieved through repeatable simulations, even years after a facility’s commissioning date. The purpose of NERC Reliability
Standard PRC-005-6 is to ensure a facility’s Protection Systems, particularly relays, are maintained within their intended design
settings. We believe the phrase proposed by the SDT should be clarified to imply designed to operate under simulated conditions
and disturbances. For Requirement R1, we propose this clarification for consideration, “Each Generator Owner shall ensure each
IBR is designed, both initially and following the IBR’s commissioning, to meet or exceed the Ride‐through requirements in
accordance with the Continuous Operation Region specified in Attachment 1.”
We believe the possibility of an IBR limitation should not be limited to hardware. In the past, such limitations may have been
imposed on Generator Owners because some equipment manufacturers were unable to achieve functional requirements through
firmware modifications. Moreover, some equipment manufacturers terminated their business operations entirely. We believe the
SDT should broaden each reference within the Reliability Standard and omit any descriptive adjectives associated with a limitation.
Part 2.1.3 states during a voltage excursion, each Generator Owner shall ensure the design of its IBR is set to prioritize Real Power
or Reactive Power, unless overridden by another registered entity, when the voltage at the high side of the main power
transformer is less than 0.95 per unit, yet still within the continuous operation region as specified in Attachment 1, and the IBR
cannot deliver both Real Power and Reactive Power. We believe the SDT could simplify this language, as the Generator Owner
will not have enough information of the Bulk Power System to make an informed decision on the appropriate priority during
anticipated system conditions and configurations in the future. We believe the SDT should instead clarify the default priority for
Generator Owners is Reactive Power, like Part 2.2.
Under Requirement R3, each Generator Owner is required to ensure its IBRs meet or exceed the Ride-through requirements
during a frequency excursion event whereby the absolute rate of change of frequency (RoCoF) magnitude is less than or equal to
5 Hz/second. This requirement assumes the configurable function is enabled. We recommend the SDT clarify the absolute rate of
change of frequency (RoCoF) magnitude requirement is set only when such a function is enabled.
To summarize Requirement R4, any limitations identifying an IBR is unable to meet the voltage Ride‐through criteria detailed in
Requirements R1 and R2 must be documented. Under the individual parts of this requirement, there is no option available for a
Generator Owner to have a limitation indefinitely applied. We also believe Parts 4.1.4 and 4.1.5 require supporting technical
documentation and plans to correct a limitation as possible language that should be incorporated in the requirement’s measure.
We believe the SDT should modify the language of each measure for Requirements R1, R2, and R3. The phrase “but are not
limited to” should be removed within each measure. The possible evidence identified should not imply that each example is
needed. We also recommend replacing the “and” within the items of a series with an “or.”
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As defined within Section 2.5 of Appendix 3A (Standard Processes Manual) of the NERC Rules of Procedure, a Measure “provides
identification of the evidence or types of evidence that may demonstrate compliance with the associated requirement.” We
believe the reference to “shall” within each measure of a requirement of this proposed Reliability Standard is misaligned with the
NERC Rules of Procedure. For instance, as proposed, each Generator Owner is required to retain evidence of actual disturbance
monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data to demonstrate the
operation of each IBR did adhere to Ride‐through requirements. Such data may not be available because of equipment failures
that are then handled through compliance with other Reliability Standards. Entities also need to implement their own internal
processes to extract this data before a limited storage capacity overrides this historical information. We believe the Standard
Drafting Team should instead focus on identifying evidence that may demonstrate compliance, such as an ongoing design
philosophy that each IBR will meet the Ride‐through requirements in accordance with the Continuous Operation Regions specified
within the Reliability Standard’s attachments.
8. We believe a significant burden has been placed on Generator Owners with the expectation listed within Measure M2 that the
Generator Owner will retain, for each voltage excursion, actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic
Disturbance Recorder, and Fault Recorder) data to demonstrate that the operation of each IBR did adhere to this Reliability
Standard’s performance requirements. It should be noted that other proposed Reliability Standards are placing limitations on
which voltage excursions are applicable for analysis. A similar burden is listed within Measure M3 with each frequency excursion.
We recommend the SDT remove this burden entirely. Instead, we propose offering a Generator Owner an opportunity to provide
their IBR’s equipment settings for the period prior to the facility’s commissioning and actual disturbance monitoring (i.e. Sequence
of Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder) data at the Generator Owner’s discretion. If the Generator
Owner needs to demonstrate their facility’s performance following a Disturbance, the actual disturbance monitoring data will be
requested under Reliability Standard PRC-030-1. Moreover, such a request should originate from an external reliability entity and
not require the Generator Owner to collect actual disturbance monitoring data following each voltage or frequency excursion.
9. We believe the mathematical symbol associated the 1.10 per unit voltage range listed in Attachment 1, Table 2, should be greater
than and equal to” instead of just “greater than.”
7.
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0
Response
Thank you for your comment.
1, 2, 4, 5, 8. The approach by the drafting team is consistent with FERC Order No. 901 and the assigned SAR to this drafting team.
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3. Performance is to prioritize based on pre-established requirements with TOs. IBR are not required to prioritize both.
6. Measures are to assist in compliance and are not enforceable.
7. See PRC-028 for data requirements. Multiple SER and DR data points are required to be captured per that standard.
9. No change has been made to this chart.
Robert Follini - Avista - Avista Corporation - 3
Answer
No
Document Name
Comment
See EEi comments
Likes
0
Dislikes
0
Response
Thank you. Please see the response to EEI.
Patricia Lynch - NRG - NRG Energy, Inc. - 5
Answer
No
Document Name
Comment
NRG Energy Inc is in support of the comments made by EPSA.
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0
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Response
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Thank you. Please see the response to EPSA.
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
No
Document Name
Comment
(A) Duke Energy agrees with and supports EEI R4 comments for the three reasons cited by EEI because it is unclear how many existing
resources can meet the frequency performance standards mandated in Requirement 3 and resource owners have not been given
adequate time to fully assess the impact of imposing these new requirements on their existing resources,
(B) Duke Energy disagrees with the language in Measures 1-3 and recommends alternative language as stated below:
Measures 1-3 generally states:
“Each Generator Owner shall retain evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance
Recorder, and Fault Recorder) data to demonstrate the operation of each facility IBR did adhere to Ride‐through requirements,” as
specified in Requirement 1/2/3.
This statement requires heavy administrative burden and data storage since it would require capturing data daily and downloading the
data to a storage location separate from the DDR,FR, & SER; since this equipment has low memory thresholds, memory could be
exceeded. Accordingly, the TO/TOP would be required to notify the GO of a grid frequency event and data could be overwritten prior to
TO/TOP notification.
Recommendation:
Each Generator Owner shall retain evidence of actual disturbance monitoring (i.e. Sequence of Event Recorder, Dynamic Disturbance
Recorder, and Fault Recorder) data, “upon notification for TO/TOP” to demonstrate the operation of each facility IBR did adhere to Ride‐
through requirements “or notification of data overwrite to TO/TOP.”
(C) Measure 1, 2 and 3 language is not consistent (suggested corrections added below):
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- The word data was eliminated from M1: …Fault Recorder) “data” to demonstrate…
- The word ride-through was eliminated from M2: …IBR will adhere to “Ride-through” requirements, as specified in Requirement…
- Did the SDT intentionally substitute “performance” for “Ride-through requirements” in M2 – see second sentence excerpt below?
…each IBR did adhere to “Ride-through requirements”, as specified in Requirement…
Likes
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0
Response
Thank you. Please see the responses to PRC-028-1 regarding data requirements and preservation of disturbance monitoring data as well
as PRC-030-1 for analytical triggers. A GO is not required to independently determine when a system disturbance has occurred.
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer
No
Document Name
Comment
TEPC agrees with EEI's comments regarding PRC-029-1, requirement 4. EEI does not agree with imposing new unverified requirements on
existing resources as proposed in PRC-029-1 because it is unclear how many existing resources can meet the frequency performance
standards mandated in Requirement 3. We are additionally concerned because resource owners have not been given adequate time to
fully assess the impact of imposing these new requirements on their existing resources, which align with IEEE 2800-2022 (See 7.3.2.1
Figure 12 & Table 15 (Frequency ride-through, page 80; and see 7.3.2.3.5 Rate of change of frequency (ROCOF), page 82), and did not
exist as a Standard until February 2022, after most of these resources were built or placed in service. For this reason, we cannot support
the approval of PRC-029-1 without the following changes to Requirement 4 ensure that existing resources that were not design and do
not have the capability to meet these requirements are allowed to declare an exemption for frequency ride-through similar to what is
provided for resources that cannot meet the voltage ride-through requirements.
Likes
0
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Dislikes
0
Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
No
Document Name
Comment
AZPS Supports the following comments that were submitted by EEI on behalf of its members:
EEI does not agree with imposing new unverified requirements on existing resources as proposed in PRC-029-1 because it is unclear how
many existing resources can meet the frequency performance standards mandated in Requirement 3. We are additionally concerned
because resource owners have not been given adequate time to fully assess the impact of imposing these new requirements on their
existing resources, which align with IEEE 2800-2022 (See 7.3.2.1 Figure 12 & Table 15 (Frequency ride-through, page 80; and see 7.3.2.3.5
Rate of change of frequency (ROCOF), page 82), and did not exist as a Standard until February 2022, after most of these resources were
built or placed in service. For this reason, we cannot support the approval of PRC-029-1 without the following changes to Requirement 4
ensure that existing resources that were not design and do not have the capability to meet these requirements are allowed to declare an
exemption for frequency ride-through similar to what is provided for resources that cannot meet the voltage ride-through requirements.
See the proposed changes to R4 below:
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of PRC-029-1, has known hardware limitations that
prevent the IBR from meeting voltage and frequency Ride-through criteria as detailed in Requirements R1, R2, and R3 and requires an
exemption from specific Ride-through criteria shall:
4.1.
Document information supporting the identified hardware limitation no later than 12 months following the effective date of
PRC-029-1. This documentation shall include:
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4.1.1
Identifying information of the IBR (name and facility #);
4.1.2
Which aspects of voltage or frequency Ride-through requirements that the IBR would be unable to meet and the capability of
the hardware due to the limitation;
4.1.3
Identify the specific piece(s) of hardware causing the limitation;
4.1.4
Supporting technical documentation verifying the limitation is due to hardware that needs to be physically replaced or that the
limitation cannot be removed by software updates or setting changes, and;
4.1.5
Information regarding any plans to remedy the hardware limitation (such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1 to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), Reliability Coordinator(s), and the CEA no later than 12 months following the effective date of
PRC-029-1.
4.2.1
Any response to additional information requested by the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA shall be provided back to the requestor within 90 days of the request.
4.2.2
Provide a copy of the acceptance of a hardware limitation by the CEA to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s).11
4.3.
Each Generator Owner with a previously accepted limitation that replace the hardware causing the limitation shall document
and communicate such a hardware change to the associated Planning Coordinator(s), Transmission Planner(s), Transmission Operator(s),
and Reliability Coordinator(s) within 90 days of the hardware change.
4.3.1
Likes
When existing hardware causing the limitation is replaced, the exemption for that Ride-through criteria no longer applies.
0
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0
Response
Thank you for your comment.
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Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
No
Document Name
Comment
Dominion Energy supports EEI comments. Current technology does not appear to support being able to fulfill these requirements on a go
forward basis.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
No
Document Name
Comment
Please see additional comments in Question #3.
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Response
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Thank you for your comment.
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
No
Document Name
Comment
Black Hills Corporation supports the comments provided by the NAGF which state: ”…recommends that PRC-029 be revised to allow for
frequency ride through (“FRT”) exemptions to address such limitations for legacy IBR facilities. Not including FRT exemptions will result in
a standard that will make certan IBR legacy facilities automatically non-compliant when the standards becomes effective.
Requirement R3 – the NAGF is concerned that legacy IBR facilities are not capable of meeting the 5 Hz/second maximum ROCOF or the
25-degree phase angle jump requirements. Therefore, FRT exemptions are necessary and need to be included in Requirement R3.
Requirement R4.2.2 – the NAGF is unclear as to what the Compliance Enforcement Authority (CEA) acceptance for a IBR hardware
limitation exemption will consist of. Will the CEA provide an email response confiming acceptance to the Generator Owner submitting the
exemption? How are such exemptions to be submitted and to whom within the CEA organization?
Likes
0
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0
Response
Thank you. Please see the response to NAGF.
David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
No
Document Name
Comment
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Vistra supports comments made by AEP (Fultz)
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0
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0
Response
Thank you. Please see the response to AEP.
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
1.
2.
3.
4.
Requirement 2.1.3/2.2/2.5 - What does “other mechanisms” mean? Too vague.
Requirement 4.1.1 - change “facility #” to “facility unique identification number.”
Requirement 4.2 - “CEA” is not defined in first instance of the acronym in the document.
Multiple Requirements list several points of contact for notification (“associated” PC, TP, TO, RC, CEA). This seems like a very long
list of contacts that would likely lead to unnecessary PNCIs. Can this list be reduced?
Likes
0
Dislikes
0
Response
Thank you for your comment.
The usage of “other mechanisms” is to assure clarity that those are inclusive of requirements given outside of PRC-029-1; it is intended to
prevent a GO from being non-compliant if required to operate differently that PRC-029-1.
The # has been changed as noted.
CEA has been defined in the first usage.
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The list is consistent with entities who will be expected to be notified of limited capability (planners and operators) as well as the CEA for
the limitation acceptance.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
No
Document Name
Comment
FirstEnergy does not agree with the current draft(3) of PRC-029-1.
FirstEnergy continues to request the DT consider changing PRC-029-1 Requirement R2, part 2.5, from ‘Real Power’ to ‘Apparent Power’.
To satisfy R2.5 as written, IBR sites would need to operate in static VAR control rather than automatic voltage control (adjusting VARs to
control voltage). This would maintain a static power factor on the sites that would fail to provide effective voltage support due to manual
intervention required to adjust VAR setpoint, not allowing for immediate response to voltage changes. This weakened response to
voltage changes could result in less stable grid voltage, increasing potential for voltage trips, which does not align with the intent of the
Standard. Changing this to ‘Apparent Power’ would make compliance more achievable while improving voltage support from IBR
generators, enhancing IBR stability and reliability.
FirstEnergy also does not agree with the concept of ‘Available Real Power’ as used in R2.1.1 & R2.5 and defined in in footnotes 4 & 7 of
Standard draft 3. Terminology/concepts critical for determining or maintaining compliance should be clearly defined in the NERC Glossary of
Terms, not nested in a Standard footnote. For this term, specifically as it pertains to solar installations, the methods for measuring and
approximating the ‘Available’ irradiance should be defined in detail as a Standard Attachment or preferably a Reliability Guideline. This
guidance is required to create design specifications and ensure Owners/Operators consistently and uniformly quantify this resource for a
given time and physical location. However, even with well-defined methods provided, it seems the ability of an Owner/Operator to
definitively prove an exception in the case of solar would be challenging and difficult to audit; examples of evidence needed to properly
justify an exception should be provided as guidance as well.
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FirstEnergy also believes there could be a conflict between VAR-002 and PRC-029 for those IBR Resources meeting the applicability
criteria of both Standards. VAR-002 requires generators to operate in automatic voltage control mode, adjusting reactive power output to
control voltage. Adherence to PRC-029 R2.5 seems to directly conflict. This would require having alternative instructions from the
TP/PC/RC/TOP, essentially granting an exception to one of the two Standards, to avoid a situation of non-compliance. Further clarification
from the DT is warranted addressing the overlap/conflict between the two Standards and how an applicable IBR generator is to comply to
both.
Likes
0
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0
Response
Thank you for your comment.
Drafting teams are encouraged to use existing defined terms such as Real Power and Reactive Power when possible.
R2.5 only applies when returning to the continuous operating region and has recovered from the mandatory (or permissive) operating
region.
The usage of footnotes to clarify a specific requirement are appropriate in PRC-029-1. Guidance is outside the scope of a Reliability
Standard and an entity must be able consider their own facts and circumstances when seeking to comply.
The usage of “other mechanisms” is to assure clarity that those are inclusive of requirements given outside of PRC-029-1; it is intended to
prevent a GO from being non-compliant if required to operate differently that PRC-029-1.
Bruce Walkup - Arkansas Electric Cooperative Corporation - 6
Answer
No
Document Name
Comment
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1. “Removing Transmission Owners (TOs) from the applicability section places all accountability during voltage and frequency excursions
on the IBR’s Generator Owner (GO) regardless of the initial incident that starts the voltage or frequency excursion and regardless of who
owns any impacted connecting equipment. This creates an inconsistency in compliance between PRC-024-4 and PRC-029-1.”
2. “The new wording in Section 2.1.3 is unclear.”
3. “Sections 2.1 and 2.2 are worded in a way that seems conflicting.”
Likes
0
Dislikes
0
Response
Thank you for your comment.
Transmission Owners have been removed from all milestone 3 and are not required to assure the ride-through capability of a GOs IBR.
PRC-029-1 allows exceptions when needing to disconnect to clear a fault. Section 2 was reviewed and appears clear.
Thomas Foltz - AEP - 5
Answer
No
Document Name
Comment
R1, R2 and R3 state, “Each Generator Owner shall ensure the design and operation is such…” Operation of the equipment is the GOP’s
responsibility, not the GO’s. If the SDT’s intention was regarding the design of the system, AEP recommends revising the language to
instead state, “Each Generator Owner shall ensure the *operational design* is such…”.
AEP recommends removing the phrase “demonstrate the design of each facility” from the proposed standard and returning to the original
event-based requirements. The phrase may prove difficult to fully comply with, as a Functional Entity would have to know the design of
the collector system and parameters and run the models correctly to demonstrate this. Much of this needed information would need to
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be provided by the manufacturer, which may require non-disclosure agreements.
There needs to be an exemption for system-related causes of ride-through failure. IBRs should be exempt from ride-through requirements in
R1 through R3 if tripping or failure to ride through is attributable to any of the following:
1. Sub-synchronous control interaction or ferro-resonance involving series compensation confirmed by the TOP, RC, TP, or PC
2. Unstable behavior of other nearby IBRs or dynamic devices such as FACTS or HVDC confirmed by the TOP, RC, TP, or PC
3. System short circuit levels during contingencies below the level of IBR stable operation confirmed by the TOP, RC, TP, or PC
4. System-level transient or oscillatory instabilities confirmed by the TOP, RC, TP, or PC
AEP is concerned by the inclusion of the phrase “other mechanisms” in this standard, and recommend it be removed from Requirements
2.1.3, 2.2, and 2.5 as we believe it could be misinterpreted or misunderstood.
AEP believes the text “any response to additional information requested” in R 4.2.1 is confusing and should be clarified. AEP suggests it
instead state “Additional information requested by the associated…”. In addition, Compliance Enforcement Authority should be spelled
out in its entirety in its first use in the standard.
R4.2.2 states an obligation to “Provide a copy of the acceptance of a hardware limitation by the CEA to the associated Planning
Coordinator(s), Transmission Planner(s), Transmission Operator(s), and Reliability Coordinator(s).” AEP recommends that insight be
provided in the Technical Rationale as to how the SDT envisions this acceptance process, and the timing thereof, would work.
Likes
0
Dislikes
0
Response
Thank you for your comment. The approach to PRC-029-1 is consistent with FERC Order No. 901 and the SAR assigned to the drafting
team.
CEA has been spelled out in the first usage and R4 was modified for clarity.
The process for acceptance by the CEA will be determined through the CMEP process and is not within the scope of a Reliability Standard.
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Brian Lindsey - Entergy - 1
Answer
No
Document Name
Comment
M1: This seems more like a requirement than a measure for meeting the requirement.
R2, M2, M3 and R4: Duplicative of Mod-026 and MOD-027. Also, seems to be dependent on PRC-028 passing and sites having DDRs
installed.
R2 is not clear. It seems to overlap significantly with VAR-002.
R2.5 While the IBRs can respond quicker than 1 second and should be able to retore active power to the pre-disturbance level within that
time-frame it may be difficult to have enough historian capability to ensure proper evidence.
R3 No provisions for exemptions for frequency limitations.
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R4.1 thru 4.2: Are we seeking approval from this large list of entities for an exemption or are we documenting the limitation that prevents
from meeting requirement 1? If we have to get approval there is no requirement in this standard that require any of these entities to
provide that approval.
Recommend limiting who must be notified to just the TP or TP and RC. There needs to be a single point of contact instead multiple
entities.
The CEA should not play a role in the acceptance or denial of limitations. Standards Drafting Teams have no authority to create
requirements that the CEA must adhere to therefore, there are no penalties to the CEA if they do not provide an acceptance.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Measures are not enforceable and are not requirements.
R2: The usage of “other mechanisms” is to assure clarity that those are inclusive of requirements given outside of PRC-029-1; it is
intended to prevent a GO from being non-compliant if required to operate differently that PRC-029-1.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
The inclusion of additional planners and operators is consistent with the expectations within FERC Order No. 901.
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The CEA is the appropriate entity to determine if the entity has met the requirements of R4. An entity who has submitted data per R4 to
the CEA and is awaiting acceptance by the CEA, is still compliant with R4.
Ayslynn Mcavoy - Arkansas Electric Cooperative Corporation - 3
Answer
No
Document Name
Comment
SMEs responded with the following comments:
“Removing Transmission Owners (TOs) from the applicability section places all accountability during voltage and frequency
excursions on the IBR’s Generator Owner (GO) regardless of the initial incident that starts the voltage or frequency excursion and
regardless of who owns any impacted connecting equipment. This creates an inconsistency in compliance between PRC-024-4 and PRC029-1.”
2. “The new wording in Section 2.1.3 is unclear.”
3. “Sections 2.1 and 2.2 are worded in a way that seems conflicting."
1.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Transmission Owners have been removed from all milestone 3 and are not required to assure the ride-through capability of a GOs IBR.
PRC-029-1 allows exceptions when needing to disconnect to clear a fault. Section 2 was reviewed and appears clear.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Yes
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Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own.
Likes
0
Dislikes
0
Response
Thank you. Please see the response to IRC SRC.
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Yes
Document Name
Comment
The DT should cpnsider emphasizing the nature of the definition may not allow a single turbine or solar array to be lost in a System
Disturbance (equates to failed “Ride-through” with loss).
Likes
0
Dislikes
0
Response
Thank you for your comment.
Partial IBR trips are analyzed within PRC-030-1 and PRC-029-1 R2.5.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC,Texas RE,NPCC,SERC,RF, Group Name SRC 2024
Answer
Yes
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Document Name
Comment
The SRC supports the addition of Part 4.2.2.:
4.2.2 Provide a copy of the acceptance of an hardware limitation by the CEA to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s).
Likes
0
Dislikes
0
Response
Thank you for your comment.
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
The work and efforts of this standard drafting team are much appreciated. Thank you for considering EPRI comments on the previous
drafts as submitted previously. The new Draft 3 appears to be improved regarding internal consistency and alignment with requirements
specified in voluntary industry standards, for example, IEEE 2800-2022. However, further improvements and alignment could be
considered as follows:
A. General comments:
•
Aligned with the directives to NERC in FERC order 901, the draft PRC-029 standard and the Implementation Plan for Project
2020-02 propose that the requirements apply to all applicable IBRs upon the standard’s revised effective date or the newly added
phased-in compliance dates. Applicable IBRs include existing (Legacy) IBRs that are already in operation prior to the specified
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•
dates. Requirement R4 provides a path for each Generator Owner to request a limited and documented exemption of a legacy
IBR from the voltage ride-through criteria specified in R1 and R2. According to the Implementation Plan of Project 2020-02,
“[o]ther NERC Standards Development projects will be pursued to address ongoing identification and mitigation of any potential
reliability impacts to the BPS for such exemptions.” A similar exemption from Requirement R3 that specifies applicable IBR
frequency ride-through criteria is not possible according to the draft standard.
o The proposed approach may require documentation of hardware limitations or reconfiguration for a significant number of
legacy IBRs across North America. Neither the draft Technical Rationale nor the FERC record under RM22-12 present or
cite sufficient technical evidence that supports this broad application of the proposed standard to existing IBRs in all
applicable NERC regions.
o International experience has shown that documentation of hardware limitations to support exemption from, or the
retroactive application of similarly stringent ride-through capability requirements on legacy IBRs are associated with
significant uncertainties, potential technical and procedural challenges, and costs. Justification of similarly ambitious
regulations enforced in other countries required the production of evidence like post-mortem disturbance analysis or case
studies that quantified the potential impact of non-compliant existing IBRs on the bulk power system stability and
reliability.[1],[2]
o Consequently, stakeholder concerns contribute to low approval rates for the draft PRC-029, possibly causing delays in
moving the draft standard through the NERC process toward timely and effective enforcement for at least all new IBRs.
Considering the approx. 2,600 GW of new IBRs in the interconnection queues across North America[3], these delays bear
potentially significant risk for the BPS.
o Furthermore, the proposed revised effective date and newly added phased-in compliance date of the capability-based
elements of Requirements R1, R2, and R3 as specified in the draft PRC-029 are different from the transition periods found
in international practice of similarly ambitious rule changes for new and IBRs (see the comments on Implementation Plan
below for further details).
The term Inverter‐based Resource (IBR) to which the draft standard is intended to apply refers to proposed definitions being
developed under the Project 2020‐06 Verifications of Models and Data for Generators. Although the new draft includes redlines
that strike the explicit mentioning of VSC-HVDC transmission facilities that are dedicated connections for IBR to the BPS, the
definition proposed by Project 2020-06 is sufficiently broad that it could cover such facilities. For further clarity on the scope and
application of the proposed PRC-029 standard, it could be helpful to add a clarifying sentence or to copy parts of Footnote 2 that
clarifies the location of the “main power transformer” in case of IBR connecting via a dedicated VSC-HVDC transmission facility
into the terms section on page 2 of the standard.
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•
•
•
•
•
For the purpose of clarity, harmonization, and compliance of IBR across North America, proposed requirements could even further
align with requirements that are testable and verifiable as specified in voluntary industry standards developed through an open
process such as ANSI, CIGRE, IEC, or IEEE. The drafting team is encouraged to review these standards and where applicable further
align, for example:
o Requirement R1 and R2 relate to IEEE Std 2800™-2022, Clause 7.2.2 (Voltage disturbance ride-through requirements), with
consideration of Clause 7.3.2.4 (Voltage phase angle changes ride-through) as a stated exception in R1.
o Requirement R3 relates to IEEE Std 2800™-2022, Clause 7.3.2 (Frequency disturbance ride-through requirements), with
consideration of Clause 7.3.2.3.5 (Rate of change of frequency (ROCOF) ride-through) as a stated exception in R3.
o Measures M1–M3 relate to IEEE P2800.2 Draft 1.0a, Clause 5 (Type tests), Clause 6 (Validation procedures for IBR unit
models and supplemental IBR device models), and Clause 7 (Design evaluations), Clause 8 (As-built installation evaluations),
Clause 9 (Commissioning tests), Clause 10 (Post commission model validation), and Clause 11 (Post-commissioning
monitoring).
o Measure M4, additionally, relates to IEEE P2800.2 Draft 1.0a, Clause 12 (Periodic tests), and Clause 13 (Periodic verification).
The draft standard does not specify grid conditions for which the specified ride-through requirements apply. During its lifetime, a
plant may experience many different operational conditions, along with changes to the grid, and may fail to ride-through an
event if the plant was operating in a grid condition vastly different from that which it was designed for. The standard could
include an exception for such situations based on leading industry practices, or a requirement for the TP, PC, etc. to specify such
an exception.
IEEE 2800-2022 allows for an exception for “self-protection” when negative-sequence voltage is greater than specified duration
and threshold within continuous operation region. There is no such exception in draft PRC-029. Such an exception may be
necessary for type III wind turbine generator (WTG) based plants.
Standard does not allow any flexibility for failure of ride-through resulting from misoperation of protection system. The
misoperation of protection system may occur for many reasons over the life of a plant. For example, for a fault on a transmission
system, if differential protection for the main step-up transformer misoperates due to environmental issues such as damage due
to water from a leaking roof or animal intrusion, then plant would be considered out of compliance. If a synchronous machine
based generating plant trips because of similar issue, it would not be out of compliance with PRC-024.
Requirements R1–R4 call out both “design and operation”. If the plant is designed to ride-through, then is it necessary to
specifically call out and include IBR “operation” into the scope of PRC-029?
o The inclusion of “operation” in PRC-029 would put a Generator Owner out of compliance with the standard whenever one
of their IBR plants fails to ride-through real world disturbances, including incidents where failure of ride-through within the
specified abnormal voltage and frequency conditions was beyond the GO’s control.
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o
An alternative approach could be to narrow the scope of PRC-029 to require a Generator Owner to adequately design
each IBR to have the capability to ride-through the specified abnormal conditions. The GO could then be further required
by PRC-028 and PRC-030 to monitor IBR performance during operations and for real world events. If an IBR was found to
have failed ride-through during operations, then PRC-030 could require the GO to identify the underlying issues and to take
corrective action.
B.
Ride-through definition
·
Consider adopting definition from IEEE 2800, which is from IEEE 1547, and well understood by the industry.
C. Requirement R1:
•
•
Requirement calls out “design and operation”. If the plant is designed to ride-through then is it necessary to specifically call out
“operation”?
o The Reliability Standard PRC-006, Requirement R3, requires PC to develop UFLS program. Several assumptions are made
here. If an event occurs, then R11 requires assessment of an event and if deficiency in UFLS program is identified then PC
is required to consider deficiencies in R12. If UFLS program was deficient then PC is not out of compliance with R3 (or any
other requirements in the standard). This is a good-faith approach: Design UFLS program and if actual event shows
deficiency in UFLS Program then fix it. No compliance issues, as far as UFLS program was designed per Requirement R3.
o Same approach could be taken in PRC-029, where R1 could require that plant is designed to ride-through specified voltage
disturbance. The PRC-028 and PRC-030 then requires monitoring of plant performance and take corrective actions when
necessary.
o The same approach could be extended to requirements R2 and R3.
If IBR operation remains within the scope of PRC-029, then consider revising the beginning of the sentence as following for better
readability: Each Generator Owner shall design and operate each IBR to meet or exceed Ride-through requirements…
o The same changes could be extended to requirements R2 and R3.
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D. Requirement R2
•
E.
Refer to comments on R1 that could be extended to requirement R2.
Requirement R2, Part 2.1
•
•
•
F.
Why is it necessary to specify a performance requirement when voltage is in the continuous operation region? The standard
remains silent on performance expectation for frequency ride-through requirements. For performance requirement for voltage
ride-through mandatory operation region is also very brief. The intent of this standard is to focus on ride-through during voltage
and frequency disturbances. If there is a desire to address performance then one option could be to simply state that performance
shall be as specified by TP, PC, etc. That is in Part 2.1.3 anyway.
Part 2.1.2: remove “and according to its controller settings”. It is not incorrect but “according to its controller settings” inherently
apply to all performance requirements.
Part 2.1.3: this requirement in IEEE 2800 was necessary and was tied to reactive power capability requirement as shown in
Figure 8 of IEEE 2800. Given PRC-029 does not include reactive power capability requirements, perhaps PRC-029 could remain
silent.
Requirement R2, Part 2.2
•
•
Part 2.2 applies at the high-side of the main power transformer. The IBR is required to exchange current, up to the maximum
capability. How is the “maximum capability” of an IBR determined? There could be some explanation, perhaps with examples, in
the technical rationale document.
The phrase “provide voltage support on affected phases during both symmetrical and unsymmetrical voltage disturbances” is
confusing.
o It is understood that intent is to require to inject “unbalanced current” or “negative-sequence” current during
asymmetrical faults. However, as written, injection of balanced reactive current into an unbalanced fault meets the
requirement to provide voltage support on affected phases, in addition to unaffected phase. The standard does not
prohibit voltage support on unaffected phases. The voltage support on unaffected phase is usually problematic. But the
requirement, as written, does not prohibit this.
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During a L-G fault, current in a faulted phase is dependent on transformer winding configuration. Does this requirement,
unintentionally, specify specific transformer configuration?
During mandatory operation, voltage is abnormal and could be almost zero for close-in faults. As such, “current” over “power” is
more appropriate. Power in faulted and unfaulted phases could be different as well. Replace real and reactive power with active
(real) and reactive current respectively.
o
•
G. Requirement R2, Part 2.3.1
•
Per language in attachment 1, permissive operation is allowed when line-to-ground or line-to-line voltage is below 10%. But per
Part 2.3.1, IBR is required to restart current exchange when positive-sequence voltage enters continuous or mandatory operation
region. This is conflicting. For example, for a line-to-ground fault on high-side terminals of main power transformer, the positivesequence voltage would be more than 10%, i.e., in the mandatory operation region.
H. Requirement R2, Part 2.4
•
I.
The intent of this requirement is understood. However, if there are multiple plants in the area, then one plant misbehaving may
cause overvoltage on high-side terminals of the main power transformer of other plants in the area. Also, the post-fault dynamics
greatly depend on system operating condition (peak, shoulder, off-peak, etc.) along with transmission outages, status of capacitor
banks, etc. The Generator Owner usually does not have system data to evaluate post-fault system dynamics and to determine if
plant’s behavior is or not a contributing factor to overvoltage.
Requirement R3
•
•
Refer to comments on R1 that could be extended to requirement R3.
The proposed frequency ride-through requirement is more stringent than the applicable requirement in IEEE Std 2800-2022. The
justification provided in the technical rationale is based on engineering judgement with no provided substantiating studies.
Furthermore, the PRC-006 requires the design of UFLS program to keep frequency withing certain bounds. Requiring IBRs to ride-
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•
•
J.
through a slightly more frequency deviation compared to frequency deviation band allowed in PRC-006 seems reasonable.
However, the proposed frequency ride-through requirement is much more stringent. Consider aligning with IEEE Std 2800
frequency ride-through requirement as a minimum requirement and let regions specify more stringent requirements where
justified.
The standard does not allow exception for frequency ride-through requirements. While the physical strain on legacy IBR plants to
ride-through frequency disturbances may be less significant compared to the strain during voltage ride-through, the capabilities
of legacy IBR hardware (including wind-turbine generators, inverters, transformers, and auxiliary equipment like fans and pumps
for cooling, if present) are, at best, uncertain. For plants in commercial operation before the effective date of this standard,
installed equipment may not have been tested to the specified frequency ride-through capability and that could make
determining if a legacy IBR plant would be able to ride-through proposed frequency ride-through requirements challenging.
o The SDT points to directive in FERC order 901 and states that order 901 does not allow exception for frequency
ride-through. However, order 901 does not require frequency ride-through requirements as stringent as the ones
proposed.
o It is also not clear to us from the record in RM22-12 whether FERC intentionally limited the exemption from ride-through
to only voltage ride-through, and on what technical grounds the exemption did not also include frequency ridethrough.[4],[5],[6]
Footnote 9 could be simplified as following: The ROCOF is an average rate of change of frequency over an averaging window of at
least 0.1 second.
Requirement R4
•
We re-iterate the following observations related to the Effective Date and Phased-in Compliance Dates stated in the
Implementation Plan of the project, as previously offered in our EPRI comments on the initial draft of PRC-029:
o Aligned with the directives to NERC in FERC order 901, the draft proposes that all requirements specified in PRC-029 apply to all
applicable IBRs upon the standard’s effective date, including Legacy IBRs that were already in operation prior to that date. This approach
may require reconfiguration or documentation of hardware limitations for a significant number of existing IBRs across North America. In
some cases, for example where the original equipment manufacturer (OEM) of hardware used in Legacy IBRs has gone out of business, or
the OEM has ceased to support a legacy hardware product line, documentation of hardware limitations and development of models
accurately representing Legacy IBR performance may be challenging. Additional exemptions to address these challenges could be
included in R4 of the draft standard or the implementation plan.
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o One example for an alternative approach to the one proposed in the draft PRC-029 could be that TOs and reliability coordinators were
to discern on a regional or case-by-case basis about the application of PRC-029 to Legacy IBRs, preferably based on technical evidence
like case studies assessing and quantifying the potential BPS reliability impacts from Legacy IBR in their regions.[7] If documentation of
Legacy IBR hardware limitations was not available, worst-case assumptions could be made in these case studies. If such studies indicated
a viable reliability risk, R4 could be applied to selected or all Legacy IBRs. This could produce documentation of hardware limitations to
refine study assumptions to produce more realistic case study results. If refined results still indicated a viable reliability risk, R1-R3 could
be applied to Legacy IBRs selectively.
•
•
•
We refer to our questioning of FERC’s intentionality with not including an exemption for frequency ride-through capability per our
comments on Requirement R3 above.
For further comments on the Effective Date and Phased-in Compliance Dates refer to below comments on the Implementation
Plan.
Parts 4.1 and 4.2 refers to exemption for a plant but part 4.3 refers to hardware in plant. If few of many wind-turbine generators
in a plant are replaced, then plant still has limitation because most of the wind-turbine generators still have limited capability.
Perhaps some clarification could be added that if “all hardware with documented capability limitation” is replaced, only then an
exemption for a legacy IBR would not apply any longer.
K. Violation Risk Factors
•
•
The language for the assignment of a VRF to Requirement R4 in the draft standard is truncated. Consider revising to: [Violation
Risk Factor: Lower]
Each Generator Owner is required per Requirement R4 to identify, document, and communicate about legacy IBRs that have
hardware limitations related to the voltage ride-through criteria specified in R1 and R2. Why is a VRF of “Lower” assigned to R4
and not a VRF of “Medium”? Could the uncertainty related to the capability and performance of legacy IBRs associated with a
violation of R4 (a requirement that is administrative in nature and a requirement in a planning time frame) by a Generator Owner
not, under the abnormal conditions, be expected to directly and adversely affect the electrical state or capability of the
Bulk‐Power System, or the ability to effectively control the Bulk Power System?
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L.
Violation Severity Levels
•
R1, R2, and R3: The lower VSL for each of these requirements is for failure to demonstrate the design capability to ride-through.
There are two reasons for which this could arise:
(1) Plant is capable to ride-through but is not demonstrated in design evaluation or interconnection studies.
(2) Plant is not capable to ride-through and that is demonstrated in design evaluation or interconnection studies.
•
•
Reason (1) is not a problem for grid reliability, it is just that studies are not adequate to demonstrate ride-through capability, and
hence lower VSL is justified. But reason (2) is not any different from a case in severe VSL where an entity fails to demonstrate that
IBR adhered to ride-through requirements (based on actual system disturbance event data).
The VSLs could be rephrased to read:
o Lower VSL: The Generator Owner failed to produce adequate evidence demonstrating for each applicable IBR that it was
designed to Ride-through in accordance with …
o Severe VSL: The Generator Owner either produced evidence demonstrating for any of their applicable IBR that it was not
adequately designed to adhere to Ride-through, or the Generator Owner failed to produce evidence of actual disturbance
monitoring data for a specific event that demonstrate each applicable IBR adhered to Ride-through requirements in
accordance with …
M. Attachment 1
•
•
•
•
Tables 1 and 2 are inconsistent. Table 1 states “>= 1.10” whereas Table 2 states “>1.10”.
Clarify that cumulative window, for voltage band where ride-through duration is 1800-second, is 3600-second. Also, consider
clarifying that 1800-second ride-through duration is only applicable to nominal voltages other than 500 kV.
Numbered item #3: states that applicable voltage is “… on the AC side of the transformer(s) that is (are) used to connect…..”. Both
sides of transformer are AC, one is on DC-AC converter side and another on AC grid side. As written, voltage on either side of
transformer is applicable. Please clarify that applicable voltage is on AC “grid” side of the transformer.
Numbered item #5: Consider revising as following - The applicable voltage for Tables 1 and 2 is identified as the voltage max/min
of phase-to-[strike: neutral] [add: ground] or phase-to-phase fundamental [add: frequency] root mean square (RMS) voltage at the
high-side of the main power transformer.
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•
•
Numbered item #7: The interpretation of ride-through curves/points needs further clarification. Would a wind-based IBR plant be
required to ride-through an event where at t=0 voltage drops from nominal to zero, then @t=0.16 s voltage rises to 25%, @t=1.2
s voltage rises to 50%, @t=2.5 s voltage rises to 70%, @t=3 s voltage rises to 90%? The item (8) is also tied to item (12), where a
combined “area” is stated. Does must ride-through zone represent an “area” (represented by deviation in voltage multiplied by
time duration)? Consider adding a few examples in the technical rationale.
o Note that IEEE 2800-2022, informative Annex D, Section D.1 (Interpretation of voltage ride-through capability requirements
specifies) states that the interpretation used in the standard is a “voltage versus time curve.” However, the same Annex
includes a Figure D.4 that intends to show “a realistic and complex trajectory of a voltage during a disturbance” for which
the informative annex then further states that an IBR plant “is required to ride through,” effectively interpreting the
IEEE 2800-2022 ride-through curves as a “voltage versus time envelope.” Thus, there seems to be some ambiguity in
IEEE 2800-2022 as to how to interpret its ride-through curves, a finding that could be considered and resolved in a
potential future revision or amendment of IEEE 2800.
o If the voltage ride-through requirements proposed in Attachment 1 were to be specified or interpreted as a “voltage versus
time envelope,”, and considering that an unknown number of IEEE SA balloters that voted affirmatively on IEEE 2800-2022
may have interpreted the IEEE 2800-2022 requirements as the less stringent “voltage versus time curves” explained in
Annex D of the standard, the proposed PRC-029 could be perceived as more stringent than IEEE 2800-2022.
o Adding a few examples in the technical rationale could help clarify the correct interpretation of the voltage ride-through
curves specified in Attachment 1.
Numbered item 10: Please clarify if this statement applies to protection applied to high side of main power transformer only OR
everywhere in the plant.
N. Attachment 2:
•
•
•
Table 3: To be consistent with other frequency thresholds, could “> 61.2” be “>= 61.2” instead. If so, range for continuous
operation then be “< 61.2 and > 58.8”.
Consider adding a statement that frequency ride-through requirements apply only when voltage is in the must ride-through zone.
Numbered item 3: What is meant by control settings? Is the intent to state protection settings instead?
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O. Implementation Plan
•
The proposed revised effective date and newly added phased-in compliance date of the capability-based elements of
Requirements R1, R2, and R3 as specified in PRC-029-1 for primarily new IBRs of,
o “the first day of the first calendar quarter that is twelve months [emphasis added by EPRI] after” either “the effective date
of the applicable governmental authority’s order approving” or “the date the standard is adopted by the NERC Board of
Trustees” for (primarily new) Bulk Electric System IBRs, and
o “until the later of: (1) January 1, 2027; or (2) the effective date of the standard” for (primarily new) Applicable Non-BES
IBRs
are different from transition periods found in international practice of similarly significant rule changes for new IBRs. Examples for
reference include, but are not limited to:
•
o
o
(European) Commission Regulation (EU) 2016/631 of 14 April 2016 establishing a network code on requirements for grid
connection of generators, Article 72 (Entry into force) states, “the requirements of this Regulation shall apply from three
years [emphasis added by EPRI] after publication.” [8]
German Government, “Verordnung zu Systemdienstleistungen durch Windenergieanlagen
(Systemdienstleistungsverordnung – SDLWindV) (Ordinance for Ancillary Services of Wind Power Plants (Ancillary Services
Ordinance - SDLWindV),”[9]
Mandatory requirement for new wind power plants to meet specified requirements by March 31, 2011, i.e., 19 months after
ordinance entered into force.
•
o
ERCOT, “Issue NOGRR245. Inverter-Based Resource (IBR) Ride-Through Requirements. Report of Board Meeting on
June 18, 2024,”[10] and ERCOT, “Nodal Operating Guide Revision Request (NOGRR) 245, Inverter-Based Resource (IBR)
Ride-Through Requirements. ERCOT Update,” August 8, 2024.”[11]
All new IBRs with a Standard Generation Interconnection Agreement (SGIA) after August 1, 2024, i.e., immediately once the NOGRR
enters into force (subject to change until ERCOT board approval and until there is a non-appealable Public Utility Commission of Texas
(PUCT) final order is in place)
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Extension of exemption from requirements new IBRs with a Standard Generation Interconnection Agreement (SGIA) after
August 1, 2024, does not exceed December 31, 2028, i.e., 4 years and 4 months (subject to change until ERCOT board approval and until
there is a non-appealable Public Utility Commission of Texas (PUCT) final order is in place)
•
The proposed revised effective date and newly added phased-in compliance date of the Requirement R4 as specified in
PRC-029-1 for primarily legacy IBRs of,
o “the first day of the first calendar quarter that is twelve months [emphasis added by EPRI] after” either “the effective date
of the applicable governmental authority’s order approving” or “the date the standard is adopted by the NERC Board of
Trustees” for (primarily legacy) Bulk Electric System IBRs, and
o “until the later of: (1) January 1, 2027; or (2) the effective date of the standard” for (primarily legacy) Applicable Non-BES
IBRs
are either not applicable, or—for re-configurations that do not require replacement of hardware—comparable, or—for retrofits that do
require replacement of hardware—they are different from transition periods found in national and international practice of similarly
significant retro-active enforcements for legacy IBRs. Examples for reference include, but are not limited to:
•
o
(European) Commission Regulation (EU) 2016/631 of 14 April 2016 establishing a network code on requirements for grid
connection of generators, Article 4 (Application to existing power-generating modules) states, [12]
-
“Existing power-generating modules are not subject to the requirements of this Regulation, except where: … .”
-
“For the purposes of this Regulation, a power-generating module shall be considered existing if:
·
(a) it is already connected to the network on the date of entry into force of this Regulation; or
·
(b) the power-generating facility owner has concluded a final and binding contract for the purchase of the main generating plant by
two years [emphasis added by EPRI] after the entry into force of the Regulation.
•
o
German Government, “Verordnung zu Systemdienstleistungen durch Windenergieanlagen
(Systemdienstleistungsverordnung – SDLWindV) (Ordinance for Ancillary Services of Wind Power Plants (Ancillary Services
Ordinance – SDLWindV)),”[13]
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-
Financial incentive for voluntary retrofits of legacy wind power plants between July 11, 2009, and January 1, 2011, i.e., 1.5-years.
•
o
German Government, “Verordnung zur Gewährleistung der technischen Sicherheit und Systemstabilität des
Elektrizitätsversorgungsnetzes (Systemstabilitätsverordnung - SysStabV) (System Stability Regulation – SysStabV)),“[14]
Mandatory requirement for reconfiguration of legacy IBRs and distributed energy resources (DERs) larger than 100 kW by August 31,
2013, i.e., 13 months after ordinance entered into force.
•
o
ERCOT, “Issue NOGRR245. Inverter-Based Resource (IBR) Ride-Through Requirements. Report of Board Meeting on
June 18, 2024,”[15] and ERCOT, “Nodal Operating Guide Revision Request (NOGRR) 245, Inverter-Based Resource (IBR)
Ride-Through Requirements. ERCOT Update,” August 8, 2024.”[16]
Mandatory requirement for legacy IBRs with an SGIA executed prior to August 1, 2024 to maximize the performance of their
protection systems, controls, and other plant equipment (within equipment limitations) to achieve, as close as reasonably possible, the
capability and performance set forth in IEEE 2800-2022 no later than December 31, 2025, i.e., 17 months after NOGRR enters into force.
Extension of exemption from requirements for legacy IBRs with a Standard Generation Interconnection Agreement (SGIA) prior to
August 1, 2024, does not exceed December 31, 2027, i.e., 3 years and 4 months (subject to change until ERCOT board approval and until
there is a non-appealable Public Utility Commission of Texas (PUCT) final order is in place)
•
P.
The first use of the word “or” in the sentence under the section Effective Date and Phased-in Compliance Dates, PRC-029-1
Phased-in Compliance Dates, Requirement 4, Applicable Non-BES IBRs on page 5 of the Implementation Plan could be replaced for
clarity with the word “for” to then read: Entities shall not be required to comply with Requirement R4 for their non-BES IBRs until
the later of: (1) January 1, 2027; or (2) the effective date of the standard.
Technical Rationale
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•
IEEE Std 2800™-2022, a voluntary industry standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs)
Interconnecting with Associated Transmission Electric Power Systems is mentioned in the Technical Rationale document for
PRC-029-1 but not cited properly. In all instances where the document refers to that IEEE standard, referencing could be
improved by following our guidance offered below. Where appropriate, reference to and proper citation of IEEE P2800.2, an
active IEEE Standards Association project for developing of a Recommended Practice for Test and Verification Procedures for
Inverter-based Resources (IBRs) Interconnecting with Bulk Power Systems, may serve as an additional reference.
o Suggested referencing of IEEE Std 2800™-2022:
For the initial citation within any document, we suggest citing the standard as follows: IEEE Std 2800™, IEEE Standard for
Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power
Systems
-
Subsequent mentions of the standard could refer to it as: IEEE 2800
•
o
Similar guidelines could be applied to IEEE Std 2800.2™:
We recommend citing the standard in full on first reference as: IEEE P2800.2, Draft Recommended Practice for Test and Verification
Procedures for Inverter-based Resources (IBRs) Interconnecting with Bulk Power Systems
-
Followed by subsequent mentions as: IEEE P2800.2
•
•
Considering the explicit statements in the "PRC-029-1_Technical_Rationale" document about the intended alignment with IEEE
Std 2800™-2022 requirements in formulating the technical content of PRC-029-1 by the drafting team, references to specific
clauses of IEEE Std 2800™-2022 could provide more clarity to industry stakeholders about which parts of the IEEE standard the
PRC-029-1 aims to incorporate. It may also be helpful to identify areas where they are not aligned. Refer to the examples in our
general comments above.
IEEE 2800-2022 may not be the only industry standard with scope that overlaps with the proposed PRC-029 standard. ANSI and
CIGRE currently may not have related standards. While IEC does have standards and technical specifications with related scope,
these documents tend to be less specific in their technical requirements compared to IEEE standards like IEEE 2800-2022.[17]
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Q. Justifications
•
•
The table for “VRF Justifications for PRC-029-1, Requirement R3” on page 11 of the Justifications lists a Proposed VRF of “Lower”;
but the draft PRC-029 standard assigns R3 a “[Violation Risk Factor: High]”. Consider resolving inconsistency across the two
documents.
Refer further to the comment on the VRF assignment for Requirement R4 above.
[1] Grid Codes for Interconnection of Inverter-Based Distributed Energy Resources by Country: Recent Trends and Developments. EPRI.
Palo Alto, CA: November 2014. 3002003283. [Online] https://www.epri.com/research/products/000000003002003283 (last accessed,
January 24, 2023)
[2] Dispersed Generation Impact on CE Region Security: Dynamic Study. 2014 Report Update. European Network of Transmission System
Operators for Electricity (ENTSO-E), ENTSO-E SPD Report, Brussels, Belgium: December 2014. [Online]
https://eepublicdownloads.entsoe.eu/cleandocuments/Publications/SOC/Continental_Europe/141113_Dispersed_Generation_Impact_on_Continental_Europe_Region_Security.pdf
(last accessed, January 24, 2023)
[3] LBNL (2024) [Online] https://emp.lbl.gov/generation-storage-and-hybrid-capacity
[4] E-1-RM22-12-000.pdf [Online] https://www.ferc.gov/media/e-1-rm22-12-000 (last accessed, August 6, 2024)
[5] 20230206-5094_ACP-SEIA IBR NOPR comments (Final).pdf [Online]
https://elibrary.ferc.gov/eLibrary/filedownload?fileid=49DB8845-A3E3-CEEA-A6D8-86289C500000 (last accessed, August 6, 2024)
[6] E-2-RM22-12-000.pdf [Online] https://www.ferc.gov/media/e-2-rm22-12-000 (last accessed, August 6, 2024)
[7] EPRI is currently working on case studies relevant to these topics and is also aware of others doing similar work.
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[8] ENTSO-E: Requirements for Generators. [Online] https://www.entsoe.eu/network_codes/rfg/ (last accessed, August 6, 2024)
[9] Federal Law Gazette I (no. 39) (2009): 1734–46. [Online] https://www.clearingstelle-eeg-kwkg.de/gesetz/695 (last accessed,
August 6, 2024)
[10] ERCOT, “Issue NOGRR245. [Online] https://www.ercot.com/mktrules/issues/NOGRR245 (last accessed, August 9, 2024)
[11] ERCOT, “Nodal Operating Guide Revision Request (NOGRR) 245, Inverter-Based Resource (IBR) Ride-Through Requirements. ERCOT
Update,” August 8, 2024 [Online] https://www.ercot.com/calendar/08082024-NOGRR245-_-Review-of (last accessed, August 9, 2024)
[12] Ref. Footnote 10
[13] Federal Law Gazette I (no. 39) (2009): 1734–46. [Online] https://www.clearingstelle-eeg-kwkg.de/gesetz/695 (last accessed,
August 6, 2024)
[14] Federal Law Gazette I (no. 40) (2012): 1635. [Online] https://www.gesetze-im-internet.de/sysstabv/BJNR163510012.html (last
accessed, August 6, 2024)
[15] Ref. Footnote 16
[16] Ref. Footnote 17
[17] Example IEC standards and technical specifications with related scope may include IEC 61400-27, IEC 62934:2021, IEC TS 63102:2021, and
IEC TR 63401-4:2022.
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0
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0
Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
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Regarding VSC-HVDC equipment for a dedicated connection to IBR, please see PRC-028-1 for the requirements regarding when
disturbance monitoring equipment and data is needed.
Grid conditions are not within scope of this project and may be pursued in future revisions with supporting technical information.
IEEE 2800-2022 was not developed through the Standards Development process, cannot be adopted by NERC, nor are mandatory and
enforceable requirements. Future revisions to PRC-029-1 may be pursued with supporting technical information to substantiate the
reliability need.
The scope of ride-through expectations are consistent with FERC Order No. 901 and the scope of the SAR assigned to the drafting team.
See responses to Q1 regarding the definition.
“Ensuring the operation” is consistent with a GOs ownership responsibilities and they may not be the GOPs in all instances.
Additional performance guidance may continue to be pursued and is not necessary for Reliability Standards.
Voltage support on unaffected phases is not required.
R2 does not set transformer configurations as described. R2 uses Real and Reactive Power and not specify current performance.
Note 5 states: The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of phase-to-neutral or phase-to-phase
fundamental root mean square (RMS) voltage at the high-side of the main power transformer.
PRC-030 details the analytical responsibilities and not PRC-029.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
The risk factor language in R4 has been corrected.
VRF are set in accordance with FERC Guidelines – see VSL/VRF Justifications for more detail.
Recommended usage of “primarily new” would add ambiguity to comply.
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Yes
Document Name
Comment
PNM agrees with the comments of EEI.
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0
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0
Response
Thank you. Please see the response to EEI.
Nick Leathers - Ameren - Ameren Services - 3 - SERC
Answer
Yes
Document Name
Comment
Ameren recommends that the drafting team clarify the phrase "current block mode." Additionally, there is some concern that the
technical requirements are so rigid that it might become challenging for utilities to implement a cost effective solution for the entity and
customers. Additionally, Ameren supports the responses from both EEI and NAGF for this question.
R1, bullet point #2:
R1 suggests that we have to set protection so that we do not trip until capabilities are exceeded, which is not how Ameren sets protection.
Ameren sets protection systems to operate before capabilities of equipment are exceeded. In addition, engineers should be setting
relays per capabilities of equipment to prevent damage and to maximize their capability. We do not suggest using a generic capability
when equipment may have higher capabilities. We suggest replacing the second bullet with the following and removing the last bullet.
"The applicable in-service protection system devices are set to operate to isolate or de-energize equipment in order to limit or prevent
damage when the voltage or Volts per Hz (V/Hz) at the high-side of the main power transformer exceed accepted equipment capabilities
in accordance with requirement R4; or"
Then add a footnote:
"If the Volts per Hz (V/Hz) withstand capability of the main power transformer is not available for an existing facility, then the applicable
in-service protection system may be set to isolate or de-energize equipment if the volts per Hz at the high-side of the main power
transformer exceed 1.1 per unit for longer than 45 seconds or exceed 1.18 per-unit for longer than 2 seconds"
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R4, 4.1.2:
In Ameren's experience, manufacturers are unwilling to share hardware capabilities on the inverter and claim it is proprietary or some
other reason. We suggest a re-write of 4.1.2 to add an exclusion such as the following:
"...If the Functional Entity has requested the capability of the hardware limitation, but the manufacturer will not provide the capability,
the Functional Entity must provide evidence that they have made the effort to request this information from the manufacturer and
provide this in lieu of the capability."
Ameren requests the SDT to provide 2 years to verify compliance with R1, R2, R3 and R4 of the standard since the requirements are
extensive.
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Response
Thank you for your comments.
The DT believes usage of current block mode is generally understood.
The DT agrees that protection systems and controllers should be set in accordance with their physical capabilities. PRC-029-1 specifies
minimum performance requirements.
Additional language has been included concerning “proprietary information”.
Mohamad Elhusseini - DTE Energy - Detroit Edison Company - 5
Answer
Yes
Document Name
Comment
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0
Response
Thank you.
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer
Yes
Document Name
Comment
Thank you.
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0
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0
Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Yes
Document Name
Comment
Thank you.
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0
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0
Response
Thank you.
Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
Yes
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Document Name
Comment
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0
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Response
Thank you.
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Casey Jones - Berkshire Hathaway - NV Energy - 5 - WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento
Municipal Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal
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Utility District, 3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility
District, 3, 6, 4, 1, 5; - Tim Kelley, Group Name SMUD and BANC
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Thank you.
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Yes
Document Name
Comment
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0
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Response
Thank you.
Bobbi Welch - Midcontinent ISO, Inc. - 2
Answer
Document Name
Comment
MISO supports the addition of Part 4.2.2.:
4.2.2 Provide a copy of the acceptance of an hardware limitation by the CEA to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s).
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Thank you.
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Southern Company appreciates the work of the SDT but would like to offer the follwing changes for consideration:
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•
•
•
•
•
•
There is a risk that changes to the IBR definition under Project 2020-06 may alter the definition for that contained in PRC-029,
thus complicating standard implementation.
Without providing technical justification, a FRT curve is more stringent than IEEE2800. In addition, industry has not been provided with
any technical studies justifying the need for the proposed 6-second FRT bands. Southern Company recommends that the SDT
align the FRT requirements with IEEE 2800. Individual Regions should be allowed to adopt more stringent FRT standards based on
their respective system needs and resource capabilities.
There is no technical justification for No FRT exemptions. (other than the “Regulatory Rationale” provided from FERC 901
Order). Section 215(d)(2) of the FPA requires FERC to give “due weight” to the technical expertise of the ERO when evaluating the
content of a proposed Reliability Standard or modification to a Standard.
The ROCOF requirement may be infeasible for certain legacy IBRs that are unable to disable ROCOF protection and distinguish
between fault and non-fault conditions.
Table 1 and 2 footnote 6 states that the voltage ride through charts are only valid when frequency is within the “must
Ride-through zone” as specified in Figure 1 of Attachment 2. The SDT should add a similar footnote to Attachment 2 Table 3 FRT
table stating that the frequency ride through charts are only valid when voltage is within the “must Ride-through zone”.
Illustrated in the Voltage Ride-through figures.
In the Implementation Plan, Southern Company recommends extending the capability due date from 12 months of effective date
of standard to 18 – 24 months due to expected complexity of solution development and deployment.
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Response
Thank you.
The definition for IBR has passed and is used exclusively in this draft.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Expected Ride-through performance during a frequency and voltage excursion necessitates requiring compliance with frequency
Ride-through requirements.
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Extension of implementation is not substantiated. A GO would be required to provide such documentation 12 months following the
effective date, which is 12 months following the approval of PRC-029-1.
Martin Sidor - NRG - NRG Energy, Inc. - 6
Answer
Document Name
Comment
NRG agrees with and refers the SDT to the EPSA comments.
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0
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0
Response
Thank you. Please see the response to EPSA.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has the following clarifying comments on PRC-029-1:
•
Texas RE recommends correcting Requirement R2 subpart 2.3.1:
2.3.1 If a an IBR enters current blocking mode, it shall restart current exchange in less than or equal to five cycles of positive sequence
voltage returning to a continuous operation region or mandatory operation region
•
In Requirement Part 4.1.1, Texas RE recommends changing “facility #” to “facility unique identifier” or “facility unique number”.
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•
Texas RE recommends Compliance Enforcement Authority (CEA) should be spelled out in Requirement R4 subpart 4.2 since it is
the first time seeing that term in the requirement language.
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0
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0
Response
Thank you for your comments.
The article “an” has been corrected as well as the # in 4.1.1. CEA has also been spelled out.
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3. Provide any additional comments for the Drafting Team to consider, if desired.
Bruce Walkup - Arkansas Electric Cooperative Corporation - 6
Answer
Document Name
Comment
None.
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0
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0
Response
Thank you.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
None
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0
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0
Response
Thank you.
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
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Answer
Document Name
Comment
N/A
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0
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0
Response
Thank you.
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name
Comment
Section 4: Applicability:
4.2 is not aligned with the PRC-028. The DT should consider the alignment of the applicability section between all IBR standards.
1)
It is not clear what “The Elements associated with..” means in 4.2.1. Does it mean power system elements?
R2:
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The new wording in Section 2.1.3 is unclear.
MH recommends it be changed to “Prioritize Real Power or Reactive Power delivery when the voltage is less than 0.95 per unit, the voltage
is within the continuous operating region, and the IBR cannot deliver both Real Power and Reactive Power due to a current limit or Reactive
Power limit unless otherwise specified through other mechanisms by an associated Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator.”
R3:
MH is still concerned with the lack of provisions for exemptions for frequency limitation (RoCoF) that may put some of the legacy IBR in a
non-compliant state and may require a costly upgrade to meet R3 requirements.
MH recommends the following:
Extending the implementation date for R3 for legacy IBR to 18 months
or/and
Lowering the RoCoF for legacy IBR from 5 Hz /second to 3Hz/ second
R4:
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The CEA is not a defined NERC term in the Glossary of Terms Used in NERC standard list, MH recommends spelled out Compliance
Enforcement Authority (CEA) in Requirement R4 subpart 4.2 since it is the first time seeing that term in the requirement language.
Attachment #1:
MH agrees with removing the previous figures 1 and 2 from attachment # 1 but we recommend adding at least three voltage waveform
examples into TR to illustrate how the Table 1 and 2 should be used to determine the compliance with voltage ride through
TR:
More information should be added to some frequency waveform examples in TR to illustrate how to calculate the RoCoF
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0
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0
Response
Thank you for your comments.
The applicability sections have been aligned.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
CEA has been spelled out.
The figures in attachment 1 were removed to prevent confusion with setting curves (like PRC-024).
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
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Comment
Tri-State agrees with the additional comments provided by the MRO NSRF.
Likes
0
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0
Response
Thank you, please see the response to MRO NSRF.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Dominion Energy supports EEI comments.
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0
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0
Response
Thank you, please see the response to EEI.
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Document Name
Comment
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AZPS supports the following comments that were submitted by EEI on behalf of its members:
EEI offers the following additional comments on the proposed 3rd draft of PRC-029-1:
·
EEI does not support the inclusion of the phrase “The Elements associated with” as contained in the Facilities Section (4.2.1). The
inclusion of this phrase expands the scope in ways that are unclear creating unnecessary compliance confusion.
·
Bullet 1 under Requirement R1 is unnecessary and should be deleted, noting that facilities are never obligated to stay connected to a
fault.
·
EEI asks that the DT provide additional clarity to Requirement R4, subpart 4.2.2 noting that there is insufficient clarity regarding what is
needed to support a hardware limitation and what the deadline is for the submission of a limitation.
Likes
0
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0
Response
Thank you, please see the response to EEI.
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Duke Energy agrees with and supports submitted EEI Additional Comments.
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0
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Thank you, please see the response to EEI.
Robert Follini - Avista - Avista Corporation - 3
Answer
Document Name
Comment
none
Likes
0
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0
Response
Thank you.
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento
Municipal Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility
District, 3, 6, 4, 1, 5; - Tim Kelley, Group Name SMUD and BANC
Answer
Document Name
Comment
The language in Section 4, Applicability does not match the language used in the latest proposed version of PRC-028-1. Although the
language in PRC-029-1 is cleaner and preferred, it is not quite clear what is meant by the inclusion of the words “The Elements associated
with” in Section 4.2.1. These words are unnecessary.
SMUD would prefer that the drafting team delete these words and change Section 4, Applicablity to the language below. The language used
in Section 4, Applicability for the currently proposed PRC-028-1, PRC-029-1 and PRC-030-1 should match. This change is non-substantive
and could be made in the final ballot.
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The existing language in PRC-029-1 (and PRC-030-1) is as follows:
4.1 Functional Entities:
4.1.1. Generator Owner
4.2 Facilities:
4.2.1. The Elements associated with (1) Bulk Electric System (BES) IBRs; and (2) Non-BES IBRs that either have or contribute to an aggregate
nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.
The existing language in PRC-028-1 is as follows:
4.1. Functional Entities:
4.1.1. Generator Owner that owns equipment as identified in section 4.2
4.2. Facilities:
4.2.1 BES Inverter-Based Resources
4.2.2 Non-BES Inverter-Based Resources that either have or contribute to an aggregate nameplate capacity of greater than or equal to 20
MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater
than or equal to 60 kV
SMUD’s preferred language in PRC-029-1 Section 4, Applicability is as follows:
4.1 Functional Entities:
4.1.1. Generator Owner
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134
4.2. Facilities:
4.2.1 BES Inverter-Based Resources
4.2.2 Non-BES Inverter-Based Resources that either have or contribute to an aggregate nameplate capacity of greater than or equal to 20
MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater
than or equal to 60 kV.
SMUD also agrees with the comments submitted by the MRO NSRF on Requirements R2, R3, R4, and Attachment 1.
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Response
Thank you for your comments.
The applicability sections have been aligned.
Please see the responses to MRO NSRF.
Casey Jones - Berkshire Hathaway - NV Energy - 5 - WECC
Answer
Document Name
Comment
NV Energy agrees with the NSRF comments especially on the lack of exceptions for legacy IBR systems (R3)
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Thank you, please see the response to MRO NSRF.
Brian Van Gheem - Radian Generation - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
We believe NERC should coordinate the Implementation Plans for the three standard development projects associated with
Milestone 2 of its work plan to address the directives within FERC Order No. 901. This would give most Generator Owners one set of
compliance implementation dates to track. The phased-in compliance dates should align with those proposed under NERC Standard
Development Project 2021-04, Reliability Standards PRC-002-5 and PRC-028-1, as those dates have been well vented across industry.
As that project has proposed for some Generator Owners, this can be as much as within three (3) calendar years of the standard’s
effective date for 50% of those Generator Owners’ BES Inverter‐Based Resources. Then the rest of their BES Inverter‐Based
Resources must be compliant by January 1, 2030. The SDT Project 2021-04 SDT made similar simplifications for other Generator
Owners with future IBRs yet to commission and for Category 2 Generator Owners.
2. We point out a misspelling of the work “ride-through” within the first paragraph of the Background Section of the Implementation
Plan.
3. Thank you for the opportunity to comment.
1.
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0
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Response
Thank you for the comments.
The Implementation Plans for Milestone 2 projects are aligned for demonstration of performance.
The misspelling has been corrected.
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5,
1, 6; Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
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Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and Midwest Reliability Organization's
NERC Standards Review Forum (MRO NSRF) on question 3
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Response
Thank you, please see the response to EEI, the MRO NSRF.
Ruchi Shah - AES - AES Corporation - 5
Answer
Document Name
Comment
•
•
•
AES CE is concerned by the language in several Measures reading “Each Generator Owner and Transmission Owner have evidence
of actual disturbance monitoring…”. There will be many plants that do not experience an applicable disturbance before this
Standard becomes effective and therefore cannot demonstrate adherence to ride-through requirements as prescribed. We are also
concerned about expectations for this Measure as time goes on, are we expected to document and record every applicable
disturbance and the asset’s performance? Setting up monitoring/tracking/retention for this portion of the Measures is a huge
additional burden that will be ongoing unless clarification is provided.
OEMs have not been forthcoming with operating limit data/equipment trip capabilities, and will not comment on or approve
alternative proposed settings without a significant amount of studies and simulations from the GO first. Due to the lack of
information from OEMs, we are concerned that the exemption process in R4 will be impossible to meet within the 12 month
timeframe for larger GOs.
Quality EMT models including all equipment information needed are not available for legacy equipment (inverters, PPCs). Many
legacy inverters do not have an EMT model, and those that do have models are not adequately validated against equipment
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•
performance. Creation of models is either not supported or can be developed at very high cost. Models created after the inverters
were initially released are of inadequate quality because the equipment is no longer able to be in a lab environment.
To consider this, AESCE suggests that the SDT include exceptions for legacy equipment where the performance may not be
predictable specifically due to a lack of modeling or inverter information.
Likes
0
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0
Response
Thank you, please see the responses to PRC-028-1 regarding data requirements and preservation of disturbance monitoring data as well as
PRC-030-1 for analytical triggers. A GO is not required to independently determine when a system disturbance has occurred nor does PRC029-1 requirements make those determinations. As such demonstration of compliance with PRC-028-1 should be leverage to demonstrate
when a grid disturbance occurred.
A GO would be required to provide such documentation 12 months following the effective date, which is 12 months following the approval
of PRC-029-1; allowing for 24 months to complete the requirement.
Model quality will be required as part of Milestone 3 directives.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1
Answer
Document Name
Comment
TAL understands that the committee was following previous precedent of the 20MVA or greater facilities; however, we believe this
standard will create undue hardship on utilities who will be required to meet this standard. 20MVA seems like a low threshold for the size
of IBRs. TAL believes the impact of IBRs as small as 20 MVA seems minimal to the integrity of the BES.
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Response
Thank you for your comment. This applicability is consistent with the approved changes to registration within NERC’s Rules of Procedure as
well as directives from FERC Order No. 901.
Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
Comment
The NAGF has no additional comments.
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Thank you for your comment.
Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation has no additional comments.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Response
Thank you for your comment.
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
Comment
Section 4: Applicability:
4.2 is not aligned with the PRC-028. The DT should consider the alignment of the applicability section between all IBR standards.
1) It is not clear to me what “The Elements associated with...” means in 4.2.1. Does it mean power system elements?
R2 The new wording in Section 2.1.3 is unclear.
MRO NSRF recommends it be changed to “Prioritize Real Power or Reactive Power delivery when the voltage is less than 0.95 per unit, the
voltage is within the continuous operating region, and the IBR cannot deliver both Real Power and Reactive Power due to a current limit or
Reactive Power limit unless otherwise specified through other mechanisms by an associated Transmission Planner, Planning Coordinator,
Reliability Coordinator, or Transmission Operator.”
R3 The MRO NSRF is still concerned with the lack of provisions for exemptions for frequency limitation (RoCof) that may put some of the
legacy IBR in a non-compliant state and may require a costly upgrade to meet R3 requirements.
MRO NSRF Recommends the adoption of a frequency ride requirement for legacy equipment be delayed until Generator Owners can
properly evaluate the capability of legacy equipment.
R4 The CEA is not a defined NERC term in the Glossary of Terms Used in NERC standard list, MRO NSRF recommends spelling out
Compliance Enforcement Authority (CEA) in Requirement R4 subpart 4.2 since it is the first time seeing that term in the requirement
language.
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Attachment #1
MRO NSRF agrees with removing the previous figures 1 and 2 from attachment # 1 but we recommend adding at least three voltage
waveform examples into TR to illustrate how the Table 1 and 2 should be used to determine the compliance with voltage ride through
TR More information should be added to some frequency waveform examples in TR to illustrate how to calculate the RoCoF.
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Response
Thank you for your comments.
The applicability sections have been aligned.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
CEA has been spelled out.
The figures in attachment 1 were removed to prevent confusion with setting curves (like PRC-024).
Junji Yamaguchi - Hydro-Quebec (HQ) - 1,5
Answer
Document Name
2020-02_Unoffical_Comment_Form_07222024(HQ).docx
Comment
see attached file
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Thank you for your comment.
Gail Elliott - Gail Elliott On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Gail Elliott
Answer
Document Name
Comment
R3 refers to “must Ride-through zone” but Attachment 2 does not identify what this zone is.
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Response
Thank you for your comment. See Figure 1 of attachment 2.
Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
Constellation has no additional comments.
Kimberly Turco on behalf of Constellation Energy Segments 5 and 6.
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Response
Thank you for your comment.
Benjamin Widder - MGE Energy - Madison Gas and Electric Co. - 3
Answer
Document Name
Comment
Madison Gas and Electric supports the comments of the MRO NSRF.
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Thank you, please see the response to MRO NSRF.
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
MP agrees with MRO’s NERC Standards Review Forum’s (NSRF) additional comments.
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Thank you, please see the response to MRO NSRF.
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer
Document Name
Comment
RF appreciates the improvements made in this version.
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Response
Thank you for your comment.
Romel Aquino - Edison International - Southern California Edison Company - 3
Answer
Document Name
EEI Near Final Draft Comments _ Project 2020-02 PRC-029 Draft 3 _ Rev 0f __ 8_09_2024.docx
Comment
See comments submitted by the Edison Eclectic Institute in the attached file.
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Thank you, please see the response to EEI.
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI Comments
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Thank you, please see the response to EEI.
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI offers the following additional comments on the proposed 3rd draft of PRC-029-1:
•
•
•
EEI does not support the inclusion of the phrase “The Elements associated with” as contained in the Facilities Section (4.2.1). The
inclusion of this phrase expands the scope in ways that are unclear creating unnecessary compliance confusion.
Bullet 1 under Requirement R1 is unnecessary and should be deleted, noting that facilities are never obligated to stay connected to
a fault.
EEI asks that the DT provide additional clarity to Requirement R4, subpart 4.2.2 noting that there is insufficient clarity regarding
what is needed to support a hardware limitation and what the deadline is for the submission of a limitation.
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Response
Thank you for your comments.
“The Elements” have been removed.
Without the clarification, the requirement could be misinterpreted that an IBR is required to Ride-through if connected to a fault.
The deadline for submissions for 4.2.2. has been added. It is appropriate for this requirement to be “objective-based”. Language in M4 has
been adjusted to clarify.
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
LG&E/KU greatly appreciates the SDT’s work and is providing feedback with the intent of providing helpful input that will assist in creating a
clearer and more consistent standard to meet the FERC directives. We acknowledge the large number of comments provided and thank the
drafting team for their work on this standard. A summary of our most substantive feedback is below:
1.
2.
3.
4.
5.
6.
7.
8.
Change R1 to apply to voltage and frequency Ride-through (and renumber R1 -> R3, R2 -> R1, and R3 -> R2).
Remove footnote 3 or, at minimum, clarify that current blocking is allowed only if not prohibited by the associated functional
entities.
Ensure M1 addresses all of the exemptions in R1.
Replace “Reactive Power limit” with “apparent power limit” in R2 Part 2.1.3, and restore the “according to the requirements …”
language.
R2 Part 2.3 should clarify that current blocking is acceptable only if not prohibited by the associated functional entities.
All mentions of continuous, mandatory, and/or permissive operating regions should include a reference to Attachment 1 (e.g.,
“specified in Attachment 1”) since these terms are no longer defined terms.
Move R4 Part 4.2.2 up a level (i.e., 4.2.2 -> 4.3, 4.3 -> 4.4) and include a timeline for the GO to notify the associated functional
entities after it has received an acceptance or rejection of its hardware limitation.
Modify items 1 and 2 in Attachment 1 to better address hybrid plants.
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9.
10.
11.
12.
13.
14.
15.
Remove the second sentence of item 7 in Attachment 1.
Add an item in Attachment 1 defining “deviation”.
Add an item in Attachment 1 permitting IBRs to trip for consecutive voltage deviations subject to the requirements of the associated
functional entities.
Add an item in Attachment 2, “Table 3 is only applicable when the voltage is within the “must Ride-through zone” as specified in
Attachment 1.”
Modify Table 3 to match IEEE 2800 requirements.
Remove Figure 1.
In locations where alternative performance requirements are discussed, either add Transmission Owner to the list of entities or
replace the list (TP, PC, RC, or TOP) with “the associated functional entities”. It is the TO that is responsible for establishing and
evaluating interconnection requirements for interconnecting generation Facilities (FAC-001/002).
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Thank you for your comments.
1.
R1 is maintained separate for clarity on the exemptions.
Current blocking mode is allowable in these circumstances in regard to PRC-029-1 and does not supersede or replace a restriction
set by the associated functional entities.
2.
3.
R1 exemptions are optional.
It is encouraged to use defined terms when appropriate. Previous industry comments also significantly preferred usage of Real
Power and Reactive Power.
4.
Current blocking mode is allowable in these circumstances in regard to PRC-029-1 and does not supersede or replace a restriction
set by the associated functional entities.
5.
6.
Language of the requirement states “as specified in attachment 1”.
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7.
A timeline for this step has been added.
8.
It is unclear what is asked to be modified within the attachments to add clarity.
9.
It is unclear why this sentence should be removed.
10.
“deviation” in this context is considered to be understood and does not necessitate a defined term.
11.
PRC-029-1 establishes the minimum requirements to ride-through.
The expectation for an IBR to Ride-through during a voltage and frequency excursion, is to comply with frequency ride-through
requirements.
12.
Frequency criteria and exemptions have been addressed in the latest draft to address significant OEM design capability limits
regarding frequency thresholds.
13.
14.
The DT has retained Figure 1.
15.
The inclusions of these specifics is to assure no ambiguity regarding who must be notified.
Nick Leathers - Ameren - Ameren Services - 3 - SERC
Answer
Document Name
Comment
Ameren does not have any additional comments for consideration by the drafting team.
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Response
Thank you for your comment.
Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
Document Name
Comment
Each requirement contains statement “…shall ensure the design and operation is such that …”. The statement has no quantitative meaning
nor direct requirements. Let’s take R2.2. or R2.3. for example:
Assuming SDT members own and operate IBRs, please explain WHAT YOU WILL DO to comply with R2.2. and R2.3.
WEC Energy Group requests that the Implementation Guidance document be created and published to help industry better understand this
convoluted and unclear standard and how to implement it. Following is an example of a standard being unclear:
R2. “Each Generator Owner shall ensure the design and operation is such that the voltage performance for each IBR adheres to the following
during a voltage excursion, unless a documented hardware limitation exists in accordance with Requirement R4.”
What is defined as “voltage excursion”? Is it the voltage outside the region identified in Attachment 1, or is it something else?
Further, R2.1. goes on to state: “While the voltage at the high-side of the main power transformer remains within the continuous operation
region as specified in Attachment 1, each IBR shall..”.
If the voltage remains within the “continuous operating region”, how is that a “voltage excursion”.
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Thank you for your comment.
Implementation Guidance may be developed by industry and submitted through CMEP mechanisms. Establishing how to comply with
requirements is not within the scope of a standard drafting team.
R2.1 applies to only the period of time following a system disturbance. Please see the responses to PRC-028-1 regarding data requirements
and preservation of disturbance monitoring data as well as PRC-030-1 for analytical triggers. A GO is not required to independently
determine when a system disturbance has occurred and the values at their IBR may not have exceeded Attachment 1 or 2 thresholds in all
instances.
Carver Powers - Utility Services, Inc. - 4
Answer
Document Name
Comment
In our entity’s review of this project, we are voting in the affirmative. We understand and appreciate that this project addresses important
considerations for reliability and security responsiveness. However, we also recognize that this project in its current form presents
compliance and performance risks that remain unresolved. While affirmatively supporting this project to address the immediate regulatory
assignments tied to FERC Order 901, NERC and the ERO must continue a constructive dialog with industry beyond this vote to truly optimize
the impacts of this project on reliability, sustainability, and affordability. We encourage NERC to permit extending the SDT team and project
to offer prospective enhancements or revisions to satisfy these compliance and performance risks.
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Thank you for your comment.
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Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Document Name
Comment
PNM agrees with the comments made by EEI.
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Thank you, please see the response to EEI.
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
2020-02_EPRI Comments on Draft 3 of NERC PRC-029 (IBR ride-through) Reliability Standard.pdf
Comment
I.
Introduction
1.
The Electric Power Research Institute (EPRI)[1] respectfully submits these comments (This Response) in response to North
American Electric Reliability Corporation (NERC)’s request for formal comment on Project 2020-02 Modifications to PRC-024 (Generator
Ride-through), issued on July 22, 2024.
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2.
EPRI closely collaborates with its members inclusive of electric power utilities, Independent System Operators (ISOs), and Regional
Transmission Organizations (RTOs), as well as numerous other stakeholders, domestically and internationally. In its role, EPRI conducts
independent research and development relating to the generation, delivery, and use of electricity for public benefit by working to help
make electricity more reliable, affordable and environmentally safe. EPRI’s comments on this topic are technical in nature based upon EPRI’s
research, development, and demonstration experience over the last 50 years in planning, analyzing, and developing technologies for
electric power.
3.
EPRI research and technology transfer deliverables are generally accessible on its website to the public, either for free or for
purchase, and occasionally subject to licensing, export control, and other requirements.[2] The publicly available and free-of-charge
milestone reports from a U.S. Department of Energy (DOE)- and EPRI member-funded research project, Adaptive Protection and Validated
Models to Enable Deployment of High Penetrations of Solar PV (“PV-MOD”), [3] and other research deliverables substantiate many of the
comments made in This Response.
4.
While not a standards development organization (SDO), EPRI conducts research and demonstration projects in relevant areas as
well as facilitates knowledge transfer and collaboration that SDOs may, at times, use to inform technical and regulatory standards
development, such as in Institute of Electrical and Electronics Engineers (IEEE), International Electrotechnical Commission (IEC),
International Council on Large Electric Systems (CIGRE), and NERC.[4]
5.
EPRI’s comments in This Response address reliability and NERC’s draft PRC-029 Reliability Standards for IBRs ride-through
requirements developed under project 2020-02. All comments are aimed at providing independent technical information to respond to the
draft published by NERC based on EPRI’s research and development results and associated staff expertise and do not necessarily reflect the
opinions of those supporting and working with EPRI to conduct collaborative research and development. Where appropriate, EPRI’s
comments do not only address the specific questions of the NOPR but also related scope that may help to inform a final order. Some of
EPRI’s comments presented in This Response have also been submitted in response to the previous Federal Energy Regulatory Commission’s
(FERC) Notice of Proposed Rulemaking (NOPR) to direct North American Electric Reliability Corporation (NERC) to develop Reliability
Standards for inverter-based resources (IBRs) that cover data sharing, model validation, planning and operational studies, and performance
requirements (RM22-12), issued on November 17, 2022.
6.
EPRI also submitted comments on the initial draft of PRC-029 which was issued on March 27, 2024, and on Draft 2 which was
issued June 18, 2024. This 3rd set of EPRI comments supports the same direction as the previously submitted comments and offers a
technical analysis based on the latest “Draft 3”.[5]
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II.
Conclusion
7.
EPRI appreciates the opportunity to provide NERC with its technical recommendations and comments on these important topics
related to Reliability Standards for IBRs. EPRI looks forward to working with its members, NERC, and other stakeholders on providing further
independent technical information on these important questions.
III.
Contact Information
Jens C. Boemer, Technical Executive
Manish Patel, Technical Executive
Anish Gaikwad, Deputy Director
Aidan Tuohy, Director, R&D
EPRI
3420 Hillview Ave
Palo Alto, CA 94304
Email: JBoemer@epri.com, ManPatel@epri.com, AGaikwad@epri.com, ATuohy@epri.com
Robert Chapman, Senior Vice President, Corporate Affairs
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EPRI
3420 Hillview Ave
Palo Alto, CA 94304
Email: RChapman@epri.com
[1] EPRI is a nonprofit corporation organized under the laws of the District of Columbia Nonprofit Corporation Act and recognized as a taxexempt organization under Section 501(c)(3) of the U.S. Internal Revenue Code of 1996, as amended, and acts in furtherance of its public
benefit mission. EPRI was established in 1972 and has principal offices and laboratories located in Palo Alto, Calif.; Charlotte, N.C.; Knoxville,
Tenn.; and Lenox, Mass. EPRI conducts research and development relating to the generation, delivery, and use of electricity for the benefit
of the public. An independent, nonprofit organization, EPRI brings together its scientists and engineers as well as experts from academia
and industry to help address challenges in electricity, including reliability, efficiency, health, safety, and the environment. EPRI also provides
technology, policy and economic analyses to inform long-range research and development planning, as well as supports research in
emerging technologies.
[2] https://www.epri.com (last accessed, August 6, 2024)
[3] PV-MOD Project Website. EPRI. Palo Alto, CA: 2024. [Online] https://www.epri.com/pvmod (last accessed, August 6, 2024)
[4] For transparency, we would like to disclose that EPRI collaborates with other organizations such as IEEE, IEC, CIGRE, and NERC; however,
EPRI is not a regulatory- or standard-setting organization. EPRI research is often considered in the development of recommendations,
guidelines, and best practices that are not determinative.
[5] https://www.nerc.com/pa/Stand/Pages/Project_2020-02_Transmission-connected_Resources.aspx
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Response
Thank you for your comments. Please see previous responses.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
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Response
Thank you. Pease see the response to NPCC RSC.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment
NPCC RSC supports the project.
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Thank you for your comment.
Mike Magruder - Avista - Avista Corporation - 1
Answer
Document Name
Comment
We concur with EEI's comments.
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Thank you. Please see the response to EEI.
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Southern Company received the following feedback from one of our OEM providers relating to the Frequency Ride-Through requirements
in PRC-029:
“...confirms that neither its legacy nor new turbines can meet the proposed frequency ride-through requirements. Wind turbines contain
hundreds of electromechanical devices that must be redesigned and tested before any new stringent frequency ride-through zones can be
confirmed."
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"...is currently designing and evaluating our turbines' capabilities according to IEEE 2800 standards. Consequently, any new requirements
deviating from IEEE 2800 will be unfeasible in the near term.”
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Response
Thank you for your comment.
Frequency criteria and exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding
frequency thresholds.
Colin Chilcoat - Invenergy LLC - 6
Answer
Document Name
Comment
Invenergy thanks the drafting team for the opportunity to provide the above comments.
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Thank you for your comment.
Rhonda Jones - Invenergy LLC - 5
Answer
Document Name
Comment
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Invenergy thanks the drafting team for the opportunity to provide the above comments.
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Thank you for your comment.
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Document Name
Comment
Thank you for the opportunity to comment.
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Response
Thank you for your comment.
George E Brown - Pattern Operators LP - 5
Answer
Document Name
Comment
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Pattern Energy supports Edison Electric Institute’s and Grid Strategies LLC’s comments.
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Response
Thank you for your comment.
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Document Name
Comment
Thank you for the opportunity to comment.
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Response
Thank you for your comment.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC,Texas RE,NPCC,SERC,RF, Group Name SRC 2024
Answer
Document Name
Comment
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In the previous posting, the SRC provided this comment which was not addressed in the current version for comment and ballot:
Attachment 1 lists a minimum ride-through time of 1800 seconds for the continuous operation voltage region between 1.05 pu and 1.1
pu (<= 1.1 and >1.05) in Tables 1 and 2. The SRC requests that, consistent with IEEE 2800, an exception for 500 kV systems be allowed such
that the minimum ride-through time for 1.05 pu < voltage <= 1.1 pu for 500 kV systems is “Continuous,” because the 1.05 pu < voltage
<= 1.1 pu voltage range is within the normal operation range for some systems, such as PJM’s system.
The SRC again requests the exception for 500KV systems be incorporated. The SDT has not explainedwhy this difference from the
IEEE 2800 is appropriate for 500 KV reliability.
We recommend the M1 references to Sequence Event Recorder, Dynamic Disturbance Recorder, and Fault Recorder be adjusted to lower
case terms, as these are not defined in the Glossary of Terms. PRC 28 utilizes acronyms for these that may be appropriate for this
standard. Similarly a change was made in R4 to replace Regional Entity with CEA, which is an undefined term and acronym in the
Glossary. Suggest spelling this out and considering defining or pointing to the Rules of Procedure.
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Response
Thank you for your comment.
IEEE 2800-2022 is not a mandatory nor enforceable standard. NERC cannot adopt the standard per the Rules of Procedure and the DT
cannot be required to reference other material. Specific revisions to PRC-029-1 may be pursued in future revisions with technically
supporting information documenting the reliability need.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
These terms have been lowercased and CEA has been spelled out as noted.
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Srinivas Kappagantula - Arevon Energy - 5
Answer
Document Name
Comment
None.
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Thank you for your comment.
Bobbi Welch - Midcontinent ISO, Inc. - 2
Answer
Document Name
Comment
MISO understands the increased need for Ride-through capabilities as system inertia decreases. We also see challenges for equipment to
demonstrate compatibility with the frequency requirements (Attachment 2) which go beyond industry standards (IEEE 2800) and MISO’s
current Tariff requirements. MISO’s plan for conformity currently relies on IEEE P2800.2 and we are planning to use that as the basis for
testing to ensure IBRs meet MISO Tariff requirements. We ask that consideration be given to aligning PRC-029 with other existing industry
standards.
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Response
Thank you for your comment.
Frequency exemptions have been addressed in the latest draft to address significant OEM design capability limits regarding frequency
thresholds.
Marty Hostler - Northern California Power Agency - 3,4,5,6
Answer
Document Name
Comment
Regarding the Implementation Plan. Six months after FERC approval is unreasonable to have equipment and procedures in place and
changes made. Especially considering several entities will need to order and install new monitoring equipment from most likely the same
companies. This implementation plan should be the same as PRC-28.
NCPA understands Ferc Order 901. The SDT has not provided any cost or expected reliability indices improvement estimates. Consequently,
it is impossible for entities to determine if this proposal is cost effective to address recommendations of FERC order 901 or if, or to what
extent, this proposal will improve reliability.
Reliability standards should not be added or changed until the SDT provides said information so that Registered Entities can make educated
determinations related to the cost and benefits of reliability standard modifications or new proposals.
The SDT has not provide a cost or tangible reliability benefit estimate. Thus we are unable to analyze the cost and reliability benefits this
proposal would provide without any data. And, ironically GO/GOP IBR Entities are being asked to spend money to procure and install a
bunch of devices to record data and/or to perform new activities that may, or may not, improve reliability. And if they do improve
reliability, we don't have any idea if the reliability benefits are worth the cost. Electricity customers' rates would need to be raised and
there is no justification or hard evidence related to the improved reliability increase magnitude; i.e. no cost/benefit justification to provide
electricity customers as to why their rates are increasing.
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Thank you for your comments.
It is unclear what is meant in reference to “six months” or the gap noted, as these are not in the implementation plan. A GO would be
required to comply with the design portions of PRC-029-1 12 months after approval, and would align the performance based aspects of
those requirements with PRC-028. This was intended to allow entities to align their compliance with both standards.
Please refer to the NERC Rules of Procedure regarding NERC’s development of Reliability Standards to comply with directives from FERC.
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
WECC believes that PRC-029 does a good job being consistent on use of IBR (and PRC-028 and PRC-030 DTs should take note on
consistency.) Note that the redlined version of the posted Standard did not capitalize “reactive power” in M2 but the clean version
did. Another example is Footnote 11 in the redline version used “active power” but clean version was changed to “Real Power”. DT could
receive responses based on either document and needs to ensure consistency in the clean version or note the differences.
WECC suggests that Requirement 4 could be removed and listed as actions to be done within the Implementation Plan. From an auditing
perspective, noncompliance is based on administrative issues (failure to provide in 12 months) and is only applicable to units already “inservice” as of the effective date. “In-service” is meant to be exactly what? (WECC has an applicable temr in the NERC Glossary, but that is
only appliable in the Western Interconnection. Different entites may have a differend definition of "in-service." Suggest a defintion be
developed.) First synch date the IBR is “in-service”. Reliability issues can happen with units not at the COD date and this issue should not be
ignored or exacerbated by assuming, if that is the case, that “in-service” equated to COD. There will be discussions as to what the effective
date is (for R4 specifically) due to the Implementation Plan dependence provided by the DT. This again calls for a timeline to be provided for
each Standard being considered especially for these IBR-related Standards as the IPs are not clearly defined. Still not clear why CEAs need
notification of hardware limitations within a Standard. A onetime Alert for R4 may be appropriate followed up by a Periodic Data Submittal
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
163
when hardware issues are alleviated (currently no response to CEA is required which begs the question why inform them in the first
place?). Severe VSL needs to remove CEA as a result of not being in the section for responses required.
VSLs for R3 need to be adjusted to use “IBR” versus “facility”. VSLs for R4 indicated a basis of effective date of R4 versus effective date of
Standard as the language of the Standard states. This needs corrected as those dates may be different. Another clear reason to provide a
timeline diagram of Implementation Plan dates.
Attachment 2 Bullet 1 for Voltage- Is the “that include wind” limited to type 3 and type 4 for the hybrid aspect?
Attachment 2 Bullet 4 for frequency—Need to replace “facility” with IBR.
PRC-029 Implementation Plan Requirement 4 “Non-BES IBRs”- Need to change “or” to “for” in the sentence describing R4’s timeline for
implementation. Bottom of page 5 capitalize “ride-through”.
All BES IBRs, including those that have repeatedly failed from a performance perspective, default to the PRC-028 timeline which employs an
extended timeframe for phased-in implementation.
PRC-029 Implementation Plan- Separating the Requirements compliance obligation timeframe out by design and operation is not realistic
and gives the false appearance of being partially applicable prior to Jan 1, 2030. The language of the Requirements, as written, will be
contested by entities as the language requires both the “design and operation” for BES IBRs and non-BES IBRs. Effectively a review of the
design will be an administrative effort for an item that could be designed today but there is no quality or accuracy language for the design
aspects. The proof that design was completed in an effective manner to mitigate the risk can only be determined if an event occurs. R4 has
additional implementation time built into the Requirement language which provides a false appearance of being applicable on the effective
date of the Standard.
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Response
Thank you for your comments.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
164
The drafting team finds “in-service” to generally understood and does not require a definition. Commercial operation dates will always be
on or after the in-service, so the DT retains usage of “in-service”.
The initial documentation submittal in R4 is stated within the requirement to be 12 months after the effective date of PRC-029-1, which is
12 months following the approval date of PRC-029-1.
As an entity will be required to inform and remove hardware limitations beyond the dates of the implementation plan, a required is
necessary.
The CEA was included within the standard as the approach to comply with the Order No. 901 directive to only allow for a limited and
documented set of exemptions.
IBR is now used in the R3 VSL table and bullet 4 of attachment 2.
The phased-in implementation alignment with PRC-028 is to allow for a single strategy to install disturbance monitoring equipment and not
create compliance gaps with demonstrating performance during a system disturbance.
Comments in previous drafts significantly desired to include design capability within PRC-029-1 to assist in determinations of compliance
outside of experience. Entities will be required to have accurate models based on performance following the implementation of Milestone 3
directives of FERC Order No. 901.
Jennifer Neville - Western Area Power Administration - 1,6
Answer
Document Name
Comment
Section 4: Applicability:
{C}4.2 {C}is not aligned with the PRC-028. The DT should consider the alignment of the applicability section between all IBR standards.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
165
{C}1)
R2
It is not clear to me what “The Elements associated with...” means in 4.2.1. Does it mean power system elements?
The new wording in Section 2.1.3 is unclear.
MRO NSRF recommends it be changed to “Prioritize Real Power or Reactive Power delivery when the voltage is less than 0.95 per unit, the
voltage is within the continuous operating region, and the IBR cannot deliver both Real Power and Reactive Power due to a current limit or
Reactive Power limit unless otherwise specified through other mechanisms by an associated Transmission Planner, Planning Coordinator,
Reliability Coordinator, or Transmission Operator.”
R3
The MRO NSRF is still concerned with the lack of provisions for exemptions for frequency limitation (RoCof) that may put some of
the legacy IBR in a non-compliant state and may require a costly upgrade to meet R3 requirements.
MRO NSRF Recommends the adoption of a frequency ride requirement for legacy equipment be delayed until Generator Owners can
properly evaluate the capability of legacy equipment.
R4
The CEA is not a defined NERC term in the Glossary of Terms Used in NERC standard list, MRO NSRF recommends spelling out
Compliance Enforcement Authority (CEA) in Requirement R4 subpart 4.2 since it is the first time seeing that term in the requirement
language.
Attachment #1
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
166
MRO NSRF agrees with removing the previous figures 1 and 2 from attachment # 1 but we recommend adding at least three voltage
waveform examples into TR to illustrate how the Table 1 and 2 should be used to determine the compliance with voltage ride through
TR
More information should be added to some frequency waveform examples in TR to illustrate how to calculate the RoCoF.
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Response
Thank you for your comments.
“The Elements” have been removed.
Without the clarification, the requirement could be misinterpreted that an IBR is required to Ride-through if connected to a fault.
The deadline for submissions for 4.2.2. has been added. It is appropriate for this requirement to be “objective-based”. Language in M4 has
been adjusted to clarify.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own. In addition, ERCOT encourages NERC to consider defining
the averaging window for Rate of Change of Frequency, as leaving the averaging window open ended will result in measurement
inconsistencies in protection systems and post-event analysis.
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Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
167
Thank you, please see the response to IRC SRC.
Kyle Thomas - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Elevate continues to strongly encourage NERC to reconsider adoption of IEEE 2800-2022. The unwillingness to adopt IEEE 2800-2022 by
NERC is leading to entirely duplicative efforts that are not serving any additional value as compared to the work conducted in the IEEE 28002022 developments. It does not appear that a holistic approach and strategy is being taken to meet the FERC Order No. 901 directives,
which is leading to very low ballot scores, significant rework, and misalignment with industry recommended practices.
The draft NERC PRC-029 is duplicative with IEEE 2800-2022 Clause 7 yet only covers a small fraction of the IBR-specific capability/
performance requirements and necessary equipment limitation details that are outlined in that clause. Therefore, there is no clear reliability
benefit versus the cost of implementation PRC-029 as compared with IEEE 2800-2022 and the recommendations set forth in the NERC
disturbance reports and guidelines. There are three core items that should be addressed in the draft NERC PRC-029 standard:
•
•
•
Requirement R4 of the standard be updated to include frequency ride-through criteria exemptions for IBRs in-service by the
effective date of the standard that have known hardware limitations.
The draft PRC-029 standard should align the FRT curve with the IEEE 2800 standard’s FRT curve
If necessary, the "maximization" concept could be introduced to maximize the capabilities of legacy IBRs to the available
software/firmware/setting limits.
Elevate strongly recommends a single NERC standard that adopts IEEE 2800-2022 in a uniform and consistent manner. NERC can also
issue a reliability guideline or implementation guidance that supports industry implementation of the standard. Rather than recreate parts
of IEEE 2800-2022 inconsistently over multiple different standards, Elevate recommends a singular standard for BPS-connected IBR
capability and performance requirements related to IEEE 2800-2022. Additional NERC standards can be developed where needed in
situations where they are not covered directly with IEEE 2800-2022 (e.g., NERC PRC-030).
Concerns with Draft PRC-029
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
168
If the draft PRC-029 standard is to be pursued as currently structured, Elevate would like to highlight the following concerns:
·
Inconsistencies with PRC-029 and IEEE 2800-2022: There are numerous inconsistencies in the draft standard language and attachment
1 and 2 when compared to IEEE 2800-2022. These should be considered and reviewed for clarity and completeness in the standard.
•
•
•
•
•
•
•
•
•
IEEE 2800 recognizes FRT requirement limitations, but the standard does not
IEEE 2800 recognizes limitations with VSC-HVDC equipment in meeting consecutive votlage deviation ride-through capabilite, the
PRC-029 standard does not.
IEEE 2800 allows for an exception for “self-protection” when negative-sequence voltage is greater than specified duration and
threshold, which may be required for Type III WTG based plants. PRC-029 does not have this exception.
IEEE 2800 recognizes 500kV system voltages are actually operated in the range of 525kV and therefore has equipment rated to
550kV. These 500kV operating conditions and corresponding updated voltage ride-through curves should be considered in the
standard.
In IEEE 2800 the frequency ride-through criteria defines 10-minute time periods for the cumulative specifications of FRT, whereas
the standard defines them in a 15 minute time period (Table 3 of Attachment 2). This should be clarified and identified.
IEEE 2800 has an exception on IBR post-disturbance current limitations for voltage disturbances that reduce RPA voltage to less than
50% of nominal, but the standard does not have this exception.
A ride-through duration of 1800 seconds is specified in both IEEE 2800 and draft PRC-029 for V > 1.05 and ≤ 1.10. PRC-029 is
silent on the cumulative time period for this requirement, whereas IEEE 2800-2022 specifies that this is cumulative over a 3600
second time period.
Attachment 2: frequency ride-through criteria should be updated to fully match with IEEE 2800. Creating a different FRT ride-through
curve without adequate technical justification will continue to challenge the industry.
The standard should be updated to explicitly state that the voltage ride-through curves are to be interpreted as voltage vs time
duration as is stated in IEEE 2800. This is to ensure that there is no incorrect interpretation that these curves are “envelope” curves.
This could be done by adding a new note to explicitly call out the voltage vs time duration interpretation of the curves.
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Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
169
IEEE 2800-2022 is not a mandatory nor enforceable standard. NERC cannot adopt the standard per the Rules of Procedure and the DT
cannot be required to reference other material. Specific revisions to PRC-029-1 may be pursued in future revisions with technically
supporting information documenting the reliability need.
Bill Zuretti - Electric Power Supply Association - 5
Answer
Document Name
EPSA FINAL Comments on IBR Standards .pdf
Comment
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Response
Thank you for your comments. Please see previous responses.
Consideration of Comments
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
170
Reminder
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough) | PRC-029-1
Additional Ballots and Non-binding Poll Open through August 12, 2024
Now Available
The additional ballots and non-binding poll for PRC-029-1 - Frequency and Voltage Ride-through
Requirements for Inverter-based Resources is open through 8 p.m. Eastern, Monday, August 12,
2024.
This will be the last opportunity for NERC to ballot these projects through traditional mechanisms.
The Board may take requisite action during the August 2024 Board of Trustees meeting to ensure
directives are met.
The Standards Committee approved waivers to the Standard Processes Manual at their December 2023
meeting. These waivers were sought by NERC Standards staff for reduced formal comment and ballot
periods. This will assist the drafting teams in expediting the standards development process due to firm
timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket No. RM22-12000 on October 19, 2023.
To assist industry in this upcoming comment and ballot period, NERC has released a Milestone 2
Summary that provides high-level overview of the current state of the associated projects and their
interrelationships. The standard drafting team’s considerations of the responses received from the
previous comment period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot pool.
Contact ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
RELIABILITY | RESILIENCE | SECURITY
Balloting
Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m.
Eastern) for problems regarding accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Manager of Standards Development, Jamie Calderon (via email)
or at 404-960-0568 Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
(Generator Ride-through) observer list” in the Title and Description Boxes.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Ballot Open Reminder
Project 2020-02 Modifications to PRC-024 (Generator Ride-through | August 2, 2024
2
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough) | PRC-024-4 and PRC-029-1
Formal Comment Period Open through August 12, 2024
Now Available
A formal comment period for PRC-029-1 - Frequency and Voltage Ride-through Requirements for
Inverter-based Resources, is open through 8 p.m. Eastern, Monday, August 12, 2024.
This will be the last opportunity for NERC to ballot these projects through traditional mechanisms. The
Board may take requisite action during the August 2024 Board of Trustees meeting to ensure
directives are met.
The Standards Committee approved waivers to the Standard Processes Manual at their December 2023
meeting. These waivers were sought by NERC Standards staff for reduced formal comment and ballot
periods. This will assist the drafting teams in expediting the standards development process due to firm
timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket No. RM22-12-000
on October 19, 2023.
To assist industry in this upcoming comment and ballot period, NERC has released a Milestone 2
Summary that provides high-level overview of the current state of the associated projects and their
interrelationships. The standard drafting team’s considerations of the responses received from the
previous comment period are reflected in this draft of the standard.
Note: PRC-024-4 passed the recent additional ballot (conducted June 28 – July 8, 2024). The drafting
team will be moving this standard to a final ballot when the PRC-029-1 ballots open (August 2-12, 2024)
as only non-substantive revision(s) were made.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
RELIABILITY | RESILIENCE | SECURITY
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
Additional ballots for the standard and implementation plan, as well as the non-binding poll of the
associated Violation Risk Factors and Violation Severity Levels will be conducted August 2-12, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Manager of Standards Development, Jamie Calderon (via email)
or at 404-960-0568 Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
(Generator Ride-through) observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Formal Comment Period Open
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | July 22, 2024
2
NERC Balloting Tool (/)
Dashboard (/)
Users
Ballots
Comment Forms
Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/342)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 AB 3 ST
Voting Start Date: 8/2/2024 12:01:00 AM
Voting End Date: 8/12/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 3
Total # Votes: 239
Total Ballot Pool: 267
Quorum: 89.51
Quorum Established Date: 8/12/2024 3:33:21 PM
Weighted Segment Value: 52.89
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
74
1
21
0.457
25
0.543
0
20
8
Segment:
2
8
0.8
6
0.6
2
0.2
0
0
0
Segment:
3
54
1
19
0.463
22
0.537
0
7
6
Segment:
4
14
1
7
0.7
3
0.3
0
3
1
Segment:
5
67
1
14
0.318
30
0.682
0
15
8
Segment:
6
45
1
10
0.294
24
0.706
0
6
5
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.5
5
0.5
0
0
0
0
0
Totals:
267
6.3
82
3.332
106
2.968
0
51
28
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren
Services
Tamara Evey
Affirmative
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Negative
Comments
Submitted
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Affirmative
N/A
1
Austin Energy
Thomas
Standifur
Abstain
N/A
Negative
Comments
Submitted
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
NERC
Memo
Affirmative
N/A
Adrian Andreoiu
Abstain
N/A
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
Affirmative
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Abstain
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Third-Party
Comments
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Third-Party
Comments
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Negative
Comments
Submitted
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Abstain
N/A
1
Exelon
Daniel Gacek
Abstain
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Negative
Comments
Submitted
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Ballot
Carly Miller
Ellese Murphy
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Glencoe Light and Power
Commission
Terry Volkmann
Negative
Third-Party
Comments
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Emma Halilovic
Abstain
N/A
1
IDACORP - Idaho Power
Company
Sean Steffensen
Abstain
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Denise Sanchez
Abstain
N/A
1
International
Transmission Company
Holdings Corporation
Michael Moltane
Gail Elliott
Affirmative
N/A
1
JEA
Joseph McClung
Affirmative
N/A
1
KAMO Electric
Cooperative
Micah Breedlove
Affirmative
N/A
1
Lakeland Electric
Larry Watt
None
N/A
1
Lincoln Electric System
Josh Johnson
Abstain
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Matt Lewis
Abstain
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Nazra Gladu
Jay Sethi
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Andy Fuhrman
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Abstain
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
Negative
Third-Party
Comments
1
National Grid USA
Michael Jones
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ijad Dewan
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
NB Power Corporation
Jeffrey Streifling
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Negative
Comments
Submitted
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
None
N/A
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Negative
Third-Party
Comments
1
Omaha Public Power
District
Doug Peterchuck
Abstain
N/A
1
Oncor Electric Delivery
Byron Booker
Abstain
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
None
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Negative
Comments
Submitted
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Negative
Comments
Submitted
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
None
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Broc Bruton
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
None
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley
Authority
David Plumb
Negative
Comments
Submitted
1
Tri-State G and T
Association, Inc.
Donna Wood
Negative
Comments
Submitted
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Affirmative
N/A
1
Western Area Power
Administration
Ben Hammer
Negative
Comments
Submitted
1
Xcel Energy, Inc.
Eric Barry
Negative
Third-Party
Comments
2
California ISO
Darcy O'Connell
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Affirmative
N/A
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
2
Midcontinent ISO, Inc.
Bobbi Welch
Negative
Comments
Submitted
2
New York Independent
System Operator
Gregory Campoli
Affirmative
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
Affirmative
N/A
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Negative
Comments
Submitted
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Lovita Griffin
Affirmative
N/A
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs Utilities
Hillary Dobson
None
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Negative
Third-Party
Comments
Affirmative
N/A
3
DTE Energy - Detroit
Marvin Johnson
EdisonMachine
Company
© 2024 - NERC Ver 4.2.1.0
Name: ATLVPEROWEB02
Elizabeth Davis
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
Negative
Comments
Submitted
3
Entergy
James Keele
Negative
Comments
Submitted
3
Evergy
Marcus Moor
Negative
Comments
Submitted
3
Eversource Energy
Vicki O'Leary
Abstain
N/A
3
Exelon
Kinte Whitehead
Abstain
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Negative
Comments
Submitted
3
Great River Energy
Michael
Brytowski
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
Abstain
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Abstain
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
None
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Affirmative
N/A
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Abstain
N/A
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
Affirmative
N/A
3
Nebraska Public Power
Tony Eddleman
District
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
3
North Carolina Electric
Membership Corporation
Chris Dimisa
3
NW Electric Power
Cooperative, Inc.
3
Designated
Proxy
Ballot
NERC
Memo
Negative
Comments
Submitted
Negative
Third-Party
Comments
Heath Henry
Affirmative
N/A
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Negative
Third-Party
Comments
3
Omaha Public Power
District
David Heins
Abstain
N/A
3
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
3
Pacific Gas and Electric
Company
Sandra Ellis
Negative
Comments
Submitted
3
Platte River Power
Authority
Richard Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Negative
Comments
Submitted
3
PPL - Louisville Gas and
Electric Co.
James Frank
None
N/A
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Negative
Third-Party
Comments
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Usama Tahir
None
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Negative
Comments
Submitted
3
Tri-State G and T
Association, Inc.
Ryan Walter
Negative
Comments
Submitted
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Nicholas Friebel
None
N/A
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Abstain
N/A
4
Austin Energy
Tony Hua
Abstain
N/A
4
Buckeye Power, Inc.
Jason Procuniar
Negative
Third-Party
Comments
4
CMS Energy Consumers Energy
Company
Aric Root
Affirmative
N/A
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Negative
Comments
Submitted
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Negative
Third-Party
Comments
4
Oklahoma Municipal
Power Authority
Michael Watt
Affirmative
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Affirmative
N/A
Affirmative
N/A
4
Sacramento Municipal
Foung Mua
Utility District
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB02
Ryan Strom
Scott Brame
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Seminole Electric
Cooperative, Inc.
Ken Habgood
None
N/A
4
Utility Services, Inc.
Carver Powers
Affirmative
N/A
4
Western Power Pool
Kevin Conway
Abstain
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
AES - AES Corporation
Ruchi Shah
Negative
Comments
Submitted
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
American Municipal
Power
Amy Ritts
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Affirmative
N/A
5
Austin Energy
Michael Dillard
Abstain
N/A
5
Avista - Avista
Corporation
Glen Farmer
None
N/A
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
None
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
5
Bonneville Power
Administration
Juergen Bermejo
Affirmative
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
Negative
Third-Party
Comments
Affirmative
N/A
5
CMS Energy David
Consumers
Energy
Greyerbiehl
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB02
Company
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Negative
Third-Party
Comments
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Abstain
N/A
5
Decatur Energy Center
LLC
Megan Melham
Negative
Comments
Submitted
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Negative
Comments
Submitted
5
Enel Green Power
Natalie Johnson
Abstain
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
Negative
Comments
Submitted
5
Evergy
Jeremy Harris
Negative
Comments
Submitted
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Negative
Comments
Submitted
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
None
N/A
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Abstain
N/A
5
Invenergy LLC
Rhonda Jones
Negative
Comments
Submitted
5
JEA
John Babik
Affirmative
N/A
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
5
Lincoln Electric System
Brittany Millard
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Los Angeles Department
of Water and Power
Robert Kerrigan
None
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Abstain
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Manitoba Hydro
Kristy-Lee Young
None
N/A
5
Muscatine Power and
Water
Chance Back
Abstain
N/A
5
National Grid USA
Robin Berry
Negative
Third-Party
Comments
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Abstain
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Negative
Third-Party
Comments
5
NRG - NRG Energy, Inc.
Patricia Lynch
Abstain
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Negative
Third-Party
Comments
5
Oglethorpe Power
Corporation
Donna Johnson
Abstain
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
None
N/A
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Negative
Comments
Submitted
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Affirmative
N/A
5
Pacific Gas and Electric
Company
Tyler Brun
Negative
Comments
Submitted
5
Pattern Operators LP
George E Brown
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Negative
Comments
Submitted
5
PSEG Nuclear LLC
Tim Kucey
None
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Affirmative
N/A
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
Abstain
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Abstain
N/A
5
Tennessee Valley
Authority
Darren Boehm
Negative
Comments
Submitted
5
TransAlta Corporation
Ashley Scheelar
Negative
Comments
Submitted
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
Negative
Comments
Submitted
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Abstain
N/A
5
Vistra Energy
Daniel
Roethemeyer
Negative
Comments
Submitted
5
WEC Energy Group, Inc.
Michelle Hribar
Negative
Comments
Submitted
5
Xcel Energy, Inc.
Gerry Huitt
Negative
Third-Party
Comments
6
AEP
Mathew Miller
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Adam Burlock
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Negative
Comments
Submitted
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Imane Mrini
Abstain
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
Negative
Comments
Submitted
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Third-Party
Comments
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
6
Edison International Southern California
Edison Company
Stephanie Kenny
Negative
Comments
Submitted
6
Entergy
Julie Hall
Negative
Comments
Submitted
6
Evergy
Tiffany Lake
Negative
Comments
Submitted
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Negative
Comments
Submitted
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
6
Great River Energy
Brian Meloy
Hayden Maples
Segment
Organization
Voter
6
Imperial Irrigation District
Diana Torres
6
Invenergy LLC
6
Designated
Proxy
NERC
Memo
Abstain
N/A
Colin Chilcoat
Negative
Comments
Submitted
Lakeland Electric
Paul Shipps
Affirmative
N/A
6
Lincoln Electric System
Eric Ruskamp
None
N/A
6
Los Angeles Department
of Water and Power
Anton Vu
None
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Negative
Third-Party
Comments
6
Manitoba Hydro
Brandin Stoesz
Affirmative
N/A
6
Muscatine Power and
Water
Nicholas Burns
None
N/A
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Negative
Comments
Submitted
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Abstain
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Negative
Third-Party
Comments
6
Omaha Public Power
District
Shonda McCain
Abstain
N/A
6
Portland General Electric
Co.
Stefanie Burke
Abstain
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
Comments
Submitted
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
None
N/A
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Denise Sanchez
Ballot
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Affirmative
N/A
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
None
N/A
6
Snohomish County PUD
No. 1
John Liang
Affirmative
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
Negative
Comments
Submitted
6
WEC Energy Group, Inc.
David Boeshaar
Negative
Comments
Submitted
6
Xcel Energy, Inc.
Steve Szablya
Negative
Third-Party
Comments
10
Northeast Power
Coordinating Council
Gerry Dunbar
Affirmative
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Affirmative
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
Greg Sorenson
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/342)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan AB 3 OT
Voting Start Date: 8/2/2024 12:01:00 AM
Voting End Date: 8/12/2024 8:00:00 PM
Ballot Type: OT
Ballot Activity: AB
Ballot Series: 3
Total # Votes: 242
Total Ballot Pool: 271
Quorum: 89.3
Quorum Established Date: 8/12/2024 3:33:38 PM
Weighted Segment Value: 60.04
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
75
1
23
0.5
23
0.5
0
21
8
Segment:
2
8
0.7
7
0.7
0
0
0
1
0
Segment:
3
55
1
21
0.512
20
0.488
0
8
6
Segment:
4
14
1
8
0.8
2
0.2
0
3
1
Segment:
5
68
1
18
0.419
25
0.581
0
16
9
Segment:
6
46
1
13
0.371
22
0.629
0
6
5
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.3
3
0.3
0
0
0
2
0
Totals:
271
6
93
3.602
92
2.398
0
57
29
Segment
BALLOT POOL MEMBERS
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All
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entries
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Designated
Proxy
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Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren
Services
Tamara Evey
Affirmative
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Negative
Comments
Submitted
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Affirmative
N/A
1
Austin Energy
Thomas
Standifur
Abstain
N/A
Negative
Comments
Submitted
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
NERC
Memo
Affirmative
N/A
Adrian Andreoiu
Abstain
N/A
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
Affirmative
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Abstain
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Third-Party
Comments
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Third-Party
Comments
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Negative
Comments
Submitted
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Abstain
N/A
1
Exelon
Daniel Gacek
Abstain
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Ballot
Carly Miller
Ellese Murphy
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Glencoe Light and Power
Commission
Terry Volkmann
Abstain
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Emma Halilovic
Abstain
N/A
1
IDACORP - Idaho Power
Company
Sean Steffensen
Abstain
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Denise Sanchez
Abstain
N/A
1
International
Transmission Company
Holdings Corporation
Michael Moltane
Gail Elliott
Affirmative
N/A
1
JEA
Joseph McClung
Affirmative
N/A
1
KAMO Electric
Cooperative
Micah Breedlove
Affirmative
N/A
1
Lakeland Electric
Larry Watt
None
N/A
1
Lincoln Electric System
Josh Johnson
Abstain
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Matt Lewis
Abstain
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Nazra Gladu
Jay Sethi
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Andy Fuhrman
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Abstain
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
Negative
Third-Party
Comments
1
National Grid USA
Michael Jones
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ijad Dewan
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
NB Power Corporation
Jeffrey Streifling
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Negative
Comments
Submitted
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
None
N/A
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Negative
Third-Party
Comments
1
Omaha Public Power
District
Doug Peterchuck
Abstain
N/A
1
Oncor Electric Delivery
Byron Booker
Abstain
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
None
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Negative
Comments
Submitted
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Negative
Comments
Submitted
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
None
N/A
1
Public Utility District No. 1
of Chelan County
Diane E Landry
Affirmative
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Broc Bruton
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
SaskPower
Wayne
Guttormson
Abstain
N/A
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
None
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley
Authority
David Plumb
Negative
Comments
Submitted
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Negative
Comments
Submitted
1
Western Area Power
Administration
Ben Hammer
Negative
Comments
Submitted
1
Xcel Energy, Inc.
Eric Barry
Negative
Third-Party
Comments
2
California ISO
Darcy O'Connell
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Affirmative
N/A
Affirmative
N/A
2
Independent Electricity
Helen Lainis
System
Operator
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Abstain
N/A
2
New York Independent
System Operator
Gregory Campoli
Affirmative
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
Affirmative
N/A
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Negative
Comments
Submitted
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Lovita Griffin
Abstain
N/A
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs Utilities
Hillary Dobson
None
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Negative
Third-Party
Comments
Affirmative
N/A
3
DTE Energy - Detroit
Marvin Johnson
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Edison Company
Elizabeth Davis
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
Negative
Comments
Submitted
3
Entergy
James Keele
Negative
Comments
Submitted
3
Evergy
Marcus Moor
Negative
Comments
Submitted
3
Eversource Energy
Vicki O'Leary
Abstain
N/A
3
Exelon
Kinte Whitehead
Abstain
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Affirmative
N/A
3
Great River Energy
Michael
Brytowski
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
Abstain
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Abstain
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
None
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Affirmative
N/A
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Abstain
N/A
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
Affirmative
N/A
3
Nebraska Public Power
Tony Eddleman
District
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
3
North Carolina Electric
Membership Corporation
Chris Dimisa
3
NW Electric Power
Cooperative, Inc.
3
Designated
Proxy
Ballot
NERC
Memo
Negative
Comments
Submitted
Negative
Third-Party
Comments
Heath Henry
Affirmative
N/A
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Negative
Third-Party
Comments
3
Omaha Public Power
District
David Heins
Abstain
N/A
3
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
3
Pacific Gas and Electric
Company
Sandra Ellis
Negative
Comments
Submitted
3
Platte River Power
Authority
Richard Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Negative
Comments
Submitted
3
PPL - Louisville Gas and
Electric Co.
James Frank
None
N/A
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Negative
Third-Party
Comments
3
Public Utility District No. 1
of Chelan County
Joyce Gundry
Affirmative
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Usama Tahir
None
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Affirmative
N/A
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Negative
Comments
Submitted
3
Tri-State G and T
Association, Inc.
Ryan Walter
Affirmative
N/A
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Nicholas Friebel
None
N/A
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Abstain
N/A
4
Austin Energy
Tony Hua
Abstain
N/A
4
Buckeye Power, Inc.
Jason Procuniar
Negative
Third-Party
Comments
4
CMS Energy Consumers Energy
Company
Aric Root
Affirmative
N/A
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Affirmative
N/A
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Negative
Third-Party
Comments
4
Oklahoma Municipal
Power Authority
Michael Watt
Affirmative
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
Affirmative
N/A
4
Public Utility District No. 2
Karla Weaver
of Grant County,
Washington
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB02
Ryan Strom
Scott Brame
Segment
Organization
Voter
4
Sacramento Municipal
Utility District
Foung Mua
4
Seminole Electric
Cooperative, Inc.
4
Designated
Proxy
NERC
Memo
Affirmative
N/A
Ken Habgood
None
N/A
Utility Services, Inc.
Carver Powers
Affirmative
N/A
4
Western Power Pool
Kevin Conway
Abstain
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
AES - AES Corporation
Ruchi Shah
Affirmative
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
American Municipal
Power
Amy Ritts
Abstain
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Affirmative
N/A
5
Austin Energy
Michael Dillard
Abstain
N/A
5
Avista - Avista
Corporation
Glen Farmer
None
N/A
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
None
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
5
Bonneville Power
Administration
Juergen Bermejo
Affirmative
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
Negative
Third-Party
Comments
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Ballot
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
CMS Energy Consumers Energy
Company
David
Greyerbiehl
Affirmative
N/A
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Negative
Third-Party
Comments
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Abstain
N/A
5
Decatur Energy Center
LLC
Megan Melham
Negative
Comments
Submitted
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Negative
Comments
Submitted
5
Enel Green Power
Natalie Johnson
Abstain
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
Negative
Comments
Submitted
5
Evergy
Jeremy Harris
Negative
Comments
Submitted
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Affirmative
N/A
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
None
N/A
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Abstain
N/A
Affirmative
N/A
5 - NERC Ver 4.2.1.0
Invenergy
LLC Name: ATLVPEROWEB02
Rhonda Jones
© 2024
Machine
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Abstain
N/A
5
Los Angeles Department
of Water and Power
Robert Kerrigan
None
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Abstain
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Manitoba Hydro
Kristy-Lee Young
None
N/A
5
Muscatine Power and
Water
Chance Back
Abstain
N/A
5
National Grid USA
Robin Berry
Negative
Third-Party
Comments
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Abstain
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Negative
Third-Party
Comments
5
NRG - NRG Energy, Inc.
Patricia Lynch
Abstain
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
None
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
Abstain
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
None
N/A
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Negative
Comments
Submitted
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Affirmative
N/A
Negative
Comments
Submitted
5
Pacific Gas and Electric
Tyler Brun
Company
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Pattern Operators LP
George E Brown
Negative
Comments
Submitted
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Negative
Comments
Submitted
5
PSEG Nuclear LLC
Tim Kucey
None
N/A
5
Public Utility District No. 1
of Chelan County
Rebecca Zahler
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Affirmative
N/A
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
Abstain
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Abstain
N/A
5
Tennessee Valley
Authority
Darren Boehm
Negative
Comments
Submitted
5
TransAlta Corporation
Ashley Scheelar
Negative
Comments
Submitted
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
Affirmative
N/A
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Abstain
N/A
5
Vistra Energy
Daniel
Roethemeyer
Negative
Comments
Submitted
5
WEC Energy Group, Inc.
Michelle Hribar
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Adam Burlock
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Xcel Energy, Inc.
Gerry Huitt
Negative
Third-Party
Comments
6
AEP
Mathew Miller
Negative
Comments
Submitted
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Negative
Comments
Submitted
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Imane Mrini
Abstain
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
Negative
Comments
Submitted
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Third-Party
Comments
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
6
Edison International Southern California
Edison Company
Stephanie Kenny
Negative
Comments
Submitted
6
Entergy
Julie Hall
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
Hayden Maples
Negative
Comments
Submitted
6
Evergy
Tiffany Lake
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Affirmative
N/A
6
Great River Energy
Brian Meloy
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Abstain
N/A
6
Invenergy LLC
Colin Chilcoat
Affirmative
N/A
6
Lakeland Electric
Paul Shipps
Affirmative
N/A
6
Lincoln Electric System
Eric Ruskamp
None
N/A
6
Los Angeles Department
of Water and Power
Anton Vu
None
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
Negative
Third-Party
Comments
6
Manitoba Hydro
Brandin Stoesz
Affirmative
N/A
6
Muscatine Power and
Water
Nicholas Burns
None
N/A
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Negative
Comments
Submitted
6
NiSource - Northern
Indiana Public Service
Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Abstain
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Negative
Third-Party
Comments
6
Omaha Public Power
District
Shonda McCain
Abstain
N/A
6
Portland General Electric
Co.
Stefanie Burke
Abstain
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
Comments
Submitted
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
None
N/A
6
Public Utility District No. 1
of Chelan County
Robert Witham
Affirmative
N/A
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Affirmative
N/A
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
None
N/A
6
Snohomish County PUD
No. 1
John Liang
Affirmative
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Negative
Comments
Submitted
6
Tennessee Valley
Authority
Armando
Rodriguez
Negative
Comments
Submitted
6
WEC Energy Group, Inc.
David Boeshaar
Negative
Comments
Submitted
6
Xcel Energy, Inc.
Steve Szablya
Negative
Third-Party
Comments
10
Northeast Power
Coordinating Council
Gerry Dunbar
Abstain
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Affirmative
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Greg Sorenson
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BALLOT RESULTS
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 | Non-binding Poll AB 3 NB
Voting Start Date: 8/2/2024 12:01:00 AM
Voting End Date: 8/12/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 3
Total # Votes: 221
Total Ballot Pool: 251
Quorum: 88.05
Quorum Established Date: 8/12/2024 3:33:47 PM
Weighted Segment Value: 42.58
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
1
71
1
18
0.462
21
0.538
24
8
Segment:
2
7
0.4
3
0.3
1
0.1
3
0
Segment:
3
51
1
15
0.429
20
0.571
11
5
Segment:
4
14
1
7
0.7
3
0.3
3
1
Segment:
5
62
1
13
0.361
23
0.639
17
9
Segment:
6
41
1
7
0.259
20
0.741
7
7
Segment:
7
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
Segment:
9
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
10
5
0.4
3
0.3
1
0.1
1
0
Totals:
251
5.8
66
2.81
89
2.99
66
30
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren
Services
Tamara Evey
Abstain
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Negative
Comments
Submitted
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Negative
Comments
Submitted
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Affirmative
N/A
1
Austin Energy
Thomas
Standifur
Abstain
N/A
1
Avista - Avista
Corporation
Mike Magruder
Negative
Comments
Submitted
1
Balancing Authority of
Northern California
Kevin Smith
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
BC Hydro and Power
Authority
Adrian Andreoiu
Abstain
N/A
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Micah Runner
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
Affirmative
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Abstain
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Comments
Submitted
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Negative
Comments
Submitted
1
Duke Energy
Katherine Street
Negative
Comments
Submitted
1
Edison International Southern California
Edison Company
Robert Blackney
Negative
Comments
Submitted
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Negative
Comments
Submitted
1
Eversource Energy
Joshua London
Abstain
N/A
1
Exelon
Daniel Gacek
Abstain
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Negative
Comments
Submitted
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
1
Glencoe Light and Power
Commission
Terry Volkmann
Abstain
N/A
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
1
Great River Energy
Gordon Pietsch
Carly Miller
Ellese Murphy
Hayden Maples
Stephen
Stafford
Segment
Organization
Voter
1
Hydro One Networks, Inc.
Emma Halilovic
1
IDACORP - Idaho Power
Company
Sean Steffensen
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
1
International Transmission
Company Holdings
Corporation
Michael Moltane
1
JEA
1
Designated
Proxy
NERC
Memo
Abstain
N/A
Abstain
N/A
Denise Sanchez
Abstain
N/A
Gail Elliott
Affirmative
N/A
Joseph McClung
Affirmative
N/A
KAMO Electric
Cooperative
Micah Breedlove
Affirmative
N/A
1
Lakeland Electric
Larry Watt
None
N/A
1
Lincoln Electric System
Josh Johnson
Abstain
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Matt Lewis
Abstain
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Abstain
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Negative
Comments
Submitted
1
NB Power Corporation
Jeffrey Streifling
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ijad Dewan
Ballot
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
None
N/A
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Negative
Comments
Submitted
1
Omaha Public Power
District
Doug Peterchuck
Abstain
N/A
1
Oncor Electric Delivery
Byron Booker
Broc Bruton
Abstain
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Bob Cardle
Negative
Comments
Submitted
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
None
N/A
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
None
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
Abstain
N/A
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
None
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
Affirmative
N/A
1
Sho-Me Power Electric
Olivia Olson
Cooperative
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Abstain
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Negative
Comments
Submitted
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Negative
Comments
Submitted
1
Western Area Power
Administration
Ben Hammer
Negative
Comments
Submitted
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Abstain
N/A
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Abstain
N/A
2
New York Independent
System Operator
Gregory Campoli
Abstain
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
Affirmative
N/A
3
APS - Arizona Public
Service Co.
Jessica Lopez
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Elizabeth Davis
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Negative
Comments
Submitted
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Lovita Griffin
Abstain
N/A
3
Avista - Avista
Corporation
Robert Follini
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
CMS Energy - Consumers
Energy Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs Utilities
Hillary Dobson
None
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Negative
Comments
Submitted
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Negative
Comments
Submitted
3
Edison International Southern California
Edison Company
Romel Aquino
Negative
Comments
Submitted
3
Entergy
James Keele
Negative
Comments
Submitted
3
Evergy
Marcus Moor
Negative
Comments
Submitted
3
Eversource Energy
Vicki O'Leary
Abstain
N/A
Abstain
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
3
Exelon
Kinte Whitehead
Carly Miller
Hayden Maples
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Negative
Comments
Submitted
3
Great River Energy
Michael
Brytowski
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
Abstain
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
None
N/A
3
Lincoln Electric System
Sam Christensen
Abstain
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
None
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Abstain
N/A
3
National Grid USA
Brian Shanahan
Negative
Comments
Submitted
3
Nebraska Public Power
District
Tony Eddleman
Abstain
N/A
3
NiSource - Northern
Indiana Public Service
Co.
Steven
Taddeucci
Negative
Comments
Submitted
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Negative
Comments
Submitted
3
NW Electric Power
Cooperative, Inc.
Heath Henry
Affirmative
N/A
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Negative
Comments
Submitted
3
Omaha Public Power
District
David Heins
Abstain
N/A
Negative
Comments
Submitted
3
Pacific Gas and Electric
Sandra Ellis
Company
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Platte River Power
Authority
Richard Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Negative
Comments
Submitted
3
PPL - Louisville Gas and
Electric Co.
James Frank
None
N/A
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Abstain
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Usama Tahir
None
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Affirmative
N/A
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
Comments
Submitted
3
Tennessee Valley
Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Ryan Walter
Negative
Comments
Submitted
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
4
Alliant Energy Corporation
Services, Inc.
Larry Heckert
Abstain
N/A
4
Austin Energy
Tony Hua
Abstain
N/A
4
Buckeye Power, Inc.
Jason Procuniar
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ryan Strom
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
CMS Energy - Consumers
Energy Company
Aric Root
Affirmative
N/A
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Negative
Comments
Submitted
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Negative
Comments
Submitted
4
Oklahoma Municipal
Power Authority
Michael Watt
Affirmative
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Affirmative
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Ken Habgood
None
N/A
4
Utility Services, Inc.
Carver Powers
Affirmative
N/A
4
Western Power Pool
Kevin Conway
Abstain
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
AES - AES Corporation
Ruchi Shah
Affirmative
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Abstain
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Affirmative
N/A
5
Austin Energy
Michael Dillard
Abstain
N/A
None
N/A
5
Avista - Avista
Glen Farmer
Corporation
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Scott Brame
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
None
N/A
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
5
Bonneville Power
Administration
Juergen Bermejo
Affirmative
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
Negative
Comments
Submitted
5
CMS Energy - Consumers
Energy Company
David
Greyerbiehl
Abstain
N/A
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Negative
Comments
Submitted
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Abstain
N/A
5
Decatur Energy Center
LLC
Megan Melham
Negative
Comments
Submitted
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Negative
Comments
Submitted
5
Edison International Southern California
Edison Company
Selene Willis
Negative
Comments
Submitted
5
Enel Green Power
Natalie Johnson
Abstain
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
Hayden Maples
Negative
Comments
Submitted
5
Evergy
Jeremy Harris
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Negative
Comments
Submitted
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
None
N/A
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Abstain
N/A
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Abstain
N/A
5
Los Angeles Department
of Water and Power
Robert Kerrigan
None
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Abstain
N/A
5
LS Power Development,
LLC
C. A. Campbell
Abstain
N/A
5
Muscatine Power and
Water
Chance Back
Abstain
N/A
5
National Grid USA
Robin Berry
Negative
Comments
Submitted
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Abstain
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Comments
Submitted
5
North Carolina Electric
Membership Corporation
Reid Cashion
Negative
Comments
Submitted
5
NRG - NRG Energy, Inc.
Patricia Lynch
Abstain
N/A
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Oglethorpe Power
Corporation
Donna Johnson
Abstain
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
None
N/A
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Affirmative
N/A
5
Pacific Gas and Electric
Company
Tyler Brun
Negative
Comments
Submitted
5
Pattern Operators LP
George E Brown
Negative
Comments
Submitted
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
None
N/A
5
PSEG Nuclear LLC
Tim Kucey
None
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
Affirmative
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Affirmative
N/A
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
Abstain
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
Comments
Submitted
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Abstain
N/A
5
Tennessee Valley
Authority
Darren Boehm
None
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Bob Cardle
Segment
Organization
Voter
5
U.S. Bureau of
Reclamation
Wendy Kalidass
5
Vistra Energy
Daniel
Roethemeyer
5
WEC Energy Group, Inc.
6
Designated
Proxy
Ballot
NERC
Memo
Abstain
N/A
Negative
Comments
Submitted
Michelle Hribar
Negative
Comments
Submitted
AEP
Mathew Miller
Negative
Comments
Submitted
6
Ameren - Ameren
Services
Robert Quinlivan
Abstain
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Negative
Comments
Submitted
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Negative
Comments
Submitted
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Imane Mrini
Abstain
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
Negative
Comments
Submitted
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Negative
Comments
Submitted
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
6
Duke Energy
John Sturgeon
Negative
Comments
Submitted
Negative
Comments
Submitted
6
Edison International Stephanie Kenny
Southern California
EdisonMachine
Company
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 4 of PRC-029-1 is posted for a formal comment and additional ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
25-day formal comment period and initial ballot
March 27 – April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
15-day formal comment period and additional ballot
July 22 – August 12, 2024
Anticipated Actions
Date
14-day formal comment period and additional ballot
September 17 –
September 30, 2024
Final Ballot
None Required
Board adoption
October 8, 2024
Draft 4 of PRC-029-1
September 2024
Page 1 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Ride-through: The plant/facility remains connected and continues to operate through voltage
or frequency system disturbances.
Draft 4 of PRC-029-1
September 2024
Page 2 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
A. Introduction
1. Title:
Frequency and Voltage Ride-through Requirements for Inverter-based
Resources
2. Number:
PRC-029-1
3. Purpose:
To ensure that IBRs Ride-through to support the Bulk Power System (BPS)
during and after defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.2
Facilities:
4.2.1. Bulk Electric System (BES) IBRs
4.2.2. Non-BES IBRs that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system
designed primarily for delivering such capacity to a common point of
connection at a voltage greater than or equal to 60 kV.
Effective Date: See Implementation Plan for Project 2020-02 – PRC-029-1
Standard-only Definition: None
Draft 4 of PRC-029-1
September 2024
Page 3 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
B. Requirements and Measures
R1.
Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements, in accordance with the “must Ridethrough 1 zone” as specified in Attachment 1, except in the following conditions:
[Violation Risk Factor: High] [Time Horizon: Operations Assessment]
•
The IBR needed to electrically disconnect in order to clear a fault;
•
The voltage at the high-side of the main power transformer 2 went outside an
accepted hardware limitation, in accordance with Requirement R4;
•
The instantaneous positive sequence voltage phase angle change is more than
25 electrical degrees at the high-side of the main power transformer and is
initiated by a non-fault switching event on the transmission system 3; or
•
The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than
2 seconds.
M1. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R1. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner
shall retain evidence of actual disturbance monitoring (i.e., sequence of event
recorder, dynamic disturbance recorder, and fault recorder) to demonstrate that the
operation of each IBR did adhere to Ride-through requirements, as specified in
Requirement R1. If the Generator Owner choose to utilize Ride-through exemptions
that occur within the “must Ride-through zone” and are caused by non-fault initiated
phase jumps of greater than 25 electrical degrees, then each Generator Owner shall
also retain evidence of actual disturbance monitoring (i.e., sequence of event
recorder, dynamic disturbance recorder, and fault recorder) data to demonstrate that
the IBR failed to Ride-through during a phase jump of greater than or equal to 25
electrical degrees, and documentation from their Transmission Planner, Reliability
Coordinator, Planning Coordinator, or Transmission Operator that a non-fault initiated
switching event occurred.
R2. Each Generator Owner shall ensure the design and operation is such that the voltage
performance for each IBR adheres to the following during a voltage excursion, unless a
documented hardware limitation exists in accordance with Requirement R4. [Violation
Risk Factor: High] [Time Horizon: Operations Assessment]
Includes no tripping associated with phase lock loop loss of synchronism.
For the purpose of this standard, the main power transformer is the power transformer that steps up voltage from the
collection system voltage to the nominal transmission/interconnecting system voltage for IBRs. In case of IBR connecting via a
dedicated Voltage Source Converter High Voltage Direct Current (VSC-HVDC), the main power transformer is the main power
transformer on the receiving end.
3 Current blocking mode may be used for non-fault initiated phase jumps greater than 25 degrees in order to prevent tripping.
1
2
Draft 4 of PRC-029-1
September 2024
Page 4 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
2.1.
While the voltage at the high-side of the main power transformer remains
within the continuous operation region as specified in Attachment 1, each IBR
shall:
2.1.1 Continue to deliver the pre-disturbance level of Real Power or available
Real Power 4, whichever is less. 5
2.1.2 Continue to deliver Reactive Rower up to its Reactive Power limit and
according to its controller settings.
2.1.3 Prioritize Real Power or Reactive Power when the voltage is less than
0.95 per unit, the voltage is within the continuous operating region, and
the IBR cannot deliver both Real Power and Reactive Power due to a
current limit or Reactive Power limit, unless otherwise specified
through other mechanisms by an associated Transmission Planner,
Planning Coordinator, Reliability Coordinator, or Transmission
Operator.
2.2.
2.3.
While voltage at the high-side of the main power transformer is within the
mandatory operation region as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support,
on the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under 6:
•
Reactive Power priority by default; or
•
Real Power priority if required through other mechanisms by an
associated Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator.
While voltage at the high-side of the main power transformer is within the
permissive operation region, as specified in Attachment 1, each IBR may
operate in current blocking mode if necessary to avoid tripping. Otherwise,
each IBR shall follow the requirements for the mandatory operation region in
Requirement R2.2.
2.3.1 If an IBR enters current blocking mode, it shall restart current exchange
in less than or equal to five cycles of positive sequence voltage
returning to a continuous operation region or mandatory operation
region.
2.4.
Each IBR shall not itself cause voltage at the high-side of the main power
transformer to exceed the applicable high voltage thresholds and time
“Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
5 Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
6 In either case and if required, the magnitude of Real Power and reactive current shall be as specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
4
Draft 4 of PRC-029-1
September 2024
Page 5 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
durations in its response as voltage recovers from the mandatory or permissive
operation regions to the continuous operation region.
2.5.
Each IBR shall restore Real Power output to the pre-disturbance or available
level 7 (whichever is lesser) within 1.0 second when the voltage at the high-side
of the main power transformer returns from the mandatory operation region
or permissive operation region (including operating in current blocking mode)
to the continuous operation region, as specified in Attachment 1, unless an
associated Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator requires a lower post-disturbance Real Power level
requirement or requires a different post-disturbance Real Power restoration
time through other mechanisms. 8
M2. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to requirements, as specified in Requirement R2. Examples of evidence may
include, but are not limited to dynamic simulations, studies, plant protection settings,
and control settings design evaluation. Each Generator Owner shall also retain
evidence of actual disturbance monitoring (i.e., sequence of event recorder, dynamic
disturbance recorder, and fault recorder) data to demonstrate that the operation of
each IBR did adhere to performance requirements, as specified in Requirement R2,
during each voltage excursion measured at the high-side of the main power
transformer. Regarding R2.1.3, R2.2, and R2.5, the Generator Owner shall retain
evidence of receiving such performance requirements, (e.g., email exchange, contract
information) if the Transmission Planner, Transmission Operator, Reliability
Coordinator, or Planning Coordinator has required the Generator Owner through
other mechanisms to follow performance requirements other than those in
Requirement R2 (e.g., ramp rates, Reactive Power prioritization).
R3. Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements during a frequency excursion event
whereby the System frequency remains within the “must Ride-through zone”
according to Attachment 2 and the absolute rate of change of frequency (RoCoF) 9
magnitude is less than or equal to 5 Hz/second, unless a documented hardware
limitation exists in accordance with Requirement R4. [Violation Risk Factor: High]
[Time Horizon: Operations Assessment]
M3. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R3. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner
shall also retain evidence of actual disturbance monitoring (i.e., sequence of event
recorder, dynamic disturbance recorder, and fault recorder) data to demonstrate the
“Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
8 Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
9 Rate of change of frequency (RoCoF) is calculated as the average rate of change for multiple calculated system frequencies for
a time period of greater than or equal to 0.1 second. RoCoF is not calculated during the fault occurrence and clearance.
7
Draft 4 of PRC-029-1
September 2024
Page 6 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
operation of each IBR did adhere to Ride-through requirements, as specified in
Requirement R3, during each frequency excursion event measured at the high-side of
the main power transformer.
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of
PRC-029-1, has known hardware limitations that prevent the IBR from meeting Ridethrough criteria as detailed in Requirements R1-R3, and requires an exemption from
specific Ride-through criteria shall: 10 [Violation Risk Factor: Lower] [Time Horizon:
Long-term Planning]
4.1.
Document information supporting the identified hardware limitation no later
than 12 months following the effective date of PRC-029-1. This documentation
shall include:
4.1.1 Identifying information of the IBR (name and facility number);
4.1.2 Which aspects of Ride-through requirements that the IBR would be
unable to meet and the capability of the hardware due to the
limitation;
4.1.3 Identification of the specific piece(s) of hardware causing the limitation;
4.1.4 Technical documentation verifying the limitation is due to hardware
that would need to be physically replaced to meet all Ride-through
criteria, and that the limitation cannot be remedied by software
updates or setting changes; and
4.1.5 Information regarding any plans to remedy the hardware limitation
(such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1, except for any
material considered by the original equipment manufacture to be proprietary
information, to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), Reliability Coordinator(s), and the
Compliance Enforcement Authority (CEA) no later than 12 months following
the effective date of PRC-029-1.11
4.2.1 Provide any response for additional information requested by the
associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA to the
requestor within 90 days of the request.
4.2.2 Provide a copy of the acceptance of a hardware limitation by the CEA to
the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s) within 90 days
of receiving the acceptance. 12
10 The exemption requests for a non-US Registered Entity should be implemented in a manner that is consistent with, or under
the direction of, the applicable governmental authority or its agency in the non-US jurisdiction.
11 To the extent the original equipment manufacturer considers any material to be proprietary, the Generator Owner is
required to share this proprietary material only with the CEA.
12 Acceptance by the CEA is verification that the information provided includes all information listed in Requirement R4.1.
Draft 4 of PRC-029-1
September 2024
Page 7 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
4.3.
Each Generator Owner with a previously accepted limitation that replaces the
hardware causing the limitation shall document and communicate such a
hardware change to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s) within 90
days of the hardware change.
4.3.1 When existing hardware causing the limitation is replaced, the
exemption for that Ride-through criteria no longer applies.
M4. Each Generator Owner submitting for an exemption for an IBR that is in-service by the
effective date of PRC-029-1, shall have evidence of submission to the CEA consistent
with the information listed in Requirement R4.1. Each Generator Owner shall have
evidence of communicated copies of each submission in accordance with Requirement
R4.2 and to the associated entities described in Requirement R4.2. Acceptable types of
evidence for submittals include, but are not limited to, meeting minutes, agreements,
copies of procedures or protocols in effect, or email correspondence. Acceptable
types of evidence for a hardware limitation may include, but is not limited to damage
curves provided by the original equipment manufacturer. Each Generator Owner that
receives a request for additional information under Requirement R4.2.1 shall have
evidence of providing that information within 90 days. Each Generator Owner that
replaces hardware at an IBR that is directly associated with an accepted exemption
and that hardware is the cause for the limitation, shall have evidence of
communicating the hardware change to the associated entities described in
Requirement R4.3 within 90 days of the hardware replacement.
Draft 4 of PRC-029-1
September 2024
Page 8 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
Each Generator Owner shall retain evidence with Requirements R1, R2, and
R3 in this standard for 36 calendar months or the date of the last audit,
whichever is greater.
•
Each Generator Owner shall retain evidence with Requirement R4 in this
standard for five calendar years or the date of the last audit, whichever is
greater.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Draft 4 of PRC-029-1
September 2024
Page 9 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to
Ride-through in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to Ride-through
requirements in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
R2.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to adhere
to performance requirements
during voltage excursions, as
specified in Requirement R2,
unless a documented
hardware limitation exists in
accordance with Requirement
R4.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to performance
requirements during voltage
excursions, as specified in
Requirement R2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
R3.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to
Ride-through in accordance
with Attachment 2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to Ride-through
requirements in accordance
with Attachment 2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
Draft 4 of PRC-029-1
September 2024
Page 10 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
R#
R4.
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 12 months, but less than
or equal to 15 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 15 months, but less than
or equal to 18 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 18 months, but less than
or equal to 24 months after
the effective date of
Requirement R4.
The Generator Owner failed to
document complete
information for IBR identified
with known hardware
limitations that prevent the
IBR from meeting Ridethrough criteria as detailed in
Requirements R1, R2, or R3.
OR
OR
OR
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
90 days but less than or equal
to 120 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
120 days, but less than or
equal to 150 days after
receiving a request for
additional information by an
entity listed in Requirement
R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
150 days but less than or equal
to 180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
provide a copy to the
applicable entities as detailed
in Requirement R4.2 within 24
months after the effective
date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
90 days but less than or equal
to 120 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
Draft 4 of PRC-029-1
September 2024
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
120 days but less than or equal
to 150 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
150 days but less than or equal
to 180 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
OR
The Generator Owner failed to
respond to the applicable
Page 11 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
R#
Lower VSL
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), Reliability
Coordinator(s), and CEA more
than 90 calendar days but less
than or equal to 120 calendar
days after the change to the
hardware.
Moderate VSL
OR
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 120 calendar days but
less than or equal to 150
calendar days after the change
to the hardware.
High VSL
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 150 calendar days but
less than or equal to 180
calendar days after the change
to the hardware.
Severe VSL
entities as detailed in
Requirement R4.2.2 more than
180 days after receiving the
acceptance of a hardware
limitation by the CEA.
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s),Reliability
Coordinator(s), and CEA more
than 180 days after the change
to the hardware.
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
Draft 4 of PRC-029-1
September 2024
Page 12 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Version History
Version
Date
Initial Draft
3/27/24
Draft
Draft 2
6/4/24
Revised following initial comment review
Draft 3
7/22/24
Revised following additional comment review
Draft 4
9/12/24
Revised following additional comment review
Draft 4 of PRC-029-1
September 2024
Action
Change
Tracking
Page 13 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-through Requirements for AC-Connected Wind IBR
13
Voltage
(per unit) 14
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 15
N/A
≥ 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
3.00
< 0.70
Mandatory Operation Region
2.50
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.16
< 0.10
Permissive Operation Region
0.16
Table 2: Voltage Ride-through Requirements for All Other IBR
Voltage
(per unit) 16
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 17
N/A
> 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
6.00
< 0.70
Mandatory Operation Region
3.00
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.32
< 0.10
Permissive Operation Region
0.32
Type 3 and type 4 wind resources directly connected to the AC Transmission System.
Refer to bullet #4 below.
15 These conditions are referred to as the “may Ride-through zone”.
16 Refer to bullet #4 below.
17 These conditions are referred to as the “may Ride-through zone”.
13
14
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
1. Table 1 applies to type 3 and type 4 wind IBR or hybrid IBR that include wind, unless
connected via a dedicated Voltage Source Converter - High Voltage Direct Current
(VSC-HVDC) transmission facility.
2. Table 2 applies to all other IBR types not covered in Table 1; including, but not
limited to, the following facilities:
a. IBR, regardless of their energy resource, interconnecting via a dedicated VSCHVDC transmission facility.
b. Other IBR or hybrid IBR consisting of photovoltaic (PV) and BESS.
3. The applicable voltage for VSC-HVDC system with a dedicated connection to an IBR
is on the AC side of the transformer(s) that is (are) used to connect the VSC-HVDC
system to the interconnected transmission system.
4. The voltage base for per unit calculation is the nominal phase-to-ground or
phase-to-phase transmission system voltage unless otherwise defined by the
Planning Coordinator, Transmission Planner, or Transmission Owner.
5. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase-to-neutral or phase-to-phase fundamental root mean square (RMS) voltage at
the high-side of the main power transformer.
6. Tables 1 and 2 are only applicable when the frequency is within the “must
Ride-through zone” as specified in Figure 1 of Attachment 2.
7. At any given voltage value, each IBR shall Ride-through unless the time duration at
that voltage has exceeded the specified minimum Ride-through time duration. If the
voltage is continuously varying over time, it is necessary to add the duration within
each band of Tables 1 and 2 over any 10 second time period.
8. The specified duration of the mandatory operation regions and the permissive
operation regions in Tables 1 and 2 is cumulative over one or more disturbances
within any 10 second time period.
9. The IBR may trip for more than four deviations of the applicable voltage at the highside of the main power transformer outside of the continuous operation region
within any 10 second time period.
10. Instantaneous trip settings based on instantaneously calculated voltage
measurements with less than filtering lengths of one cycle (16.6 millisecond) are not
permissible.
11. The “must Ride-through zone” is the combined area of the mandatory operating
regions, the continuous operating regions, and the permissive operating region. All
area outside of these operating regions is referred to as the “may Ride-through
zone”.
Draft 4 of PRC-029-1
September 2024
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 2: Frequency Ride-Through Criteria
Table 3: Frequency Ride-through Capability Requirements
System Frequency (Hz)
Minimum Ride-Through
Time (sec)
> 61.8
May trip
> 61.2
299
≤ 61.2 and ≥ 58.8
Continuous
< 58.8
299
< 57.0
May trip
1. Frequency measurements are taken at the high-side of the main power transformer.
2. Frequency is measured over a period of time (typically 3-6 cycles) to calculate system
frequency at the high-side of the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency value, each IBR shall Ride-through unless the time duration at
that frequency has exceeded the specified minimum ride-through time duration.
5. The specified durations of Table 3 are cumulative over one or more disturbances within
a 10-minute time period.
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
63
May Ride-through Zone
62
Frequency (Hz)
61
Must Ride-through Zone
60
59
58
May Ride-through Zone
57
56
0
100
200
300
299
400
500
600
700
800
900
∞
1000
Time (seconds)
Figure 1: PRC-029 Frequency Ride-through Requirements
Draft 4 of PRC-029-1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 4 of PRC‐029‐1 is posted for a formal comment and additional ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
25‐day formal comment period and initial ballot
March 27 – April 22, 2024
15‐day formal comment period and additional ballot
June 18 – July 8, 2024
15‐day formal comment period and additional ballot
July 22 – August 12, 2024
Anticipated Actions
Date
14‐day formal comment period and additional ballot
September 17 –
September 30, 2024
Final Ballot
None Required
Board adoption
October 8, 2024
Draft 4 of PRC‐029‐1
September 2024
Page 1 of 19
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Ride‐through: The entire plant/facility remainsing connected to the Bulk Power System and
continuesing in its entirety to operate through voltage and frequency Ssystem Ddisturbances.
The term Inverter‐based Resource (IBR) refers to proposed definitions being developed under
the Project 2020‐06 Verifications of Models and Data for Generators. As of this posting, the
proposed definition of an IBR is:
IBR: A plant/facility consisting of individual devices that are capable of exporting Real Power
through a power electronic interface(s) such as inverter or converter, and that are operated
together as a single resource at a common point of interconnection to the electric system. IBRs
include, but are not limited to, plants/facilities with solar photovoltaic (PV), Type 3 and Type 4
wind, battery energy storage system (BESS), and fuel cell devices.
Draft 4 of PRC‐029‐1
September 2024
Page 2 of 19
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
A. Introduction
1. Title:
Frequency and Voltage Ride‐through Requirements for Inverter‐based
Resources
2. Number:
PRC‐029‐1
3. Purpose:
To ensure that IBRs Ride‐through to support the Bulk Power System (BPS)
during and after defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.2
Facilities:
4.2.1. The Elements associated with (1) Bulk Electric System (BES) IBRs; and (2)
4.2.1.4.2.2. Non‐BES IBRs that either have or contribute to an aggregate
nameplate capacity of greater than or equal to 20 MVA, connected
through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.
Effective Date: See Implementation Plan for Project 2020‐02 – PRC‐029‐1
Standard‐only Definition: None
Draft 4 of PRC‐029‐1
September 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
B. Requirements and Measures
R1.
Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride‐through requirements, in accordance with the “must Ride‐
through1 zone” as specified in Attachment 1, except forin the following conditions:
[Violation Risk Factor: High] [Time Horizon: Operations Assessment]
• The IBR needed to electrically disconnect in order to clear a fault; or
•
The voltage at the high‐side of the main power transformer2 went outside an
accepted hardware limitation, in accordance with Requirement R4; or
•
The instantaneous positive sequence voltage phase angle change is more than
25 electrical degrees at the high‐side of the main power transformer and is
initiated by a non‐fault switching event on the transmission system3; or
•
The Volts per Hz (V/Hz) at the high‐side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than
2 seconds.
M1. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride‐through requirements, as specified in Requirement R1. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner
shall retain evidence of actual disturbance monitoring (i.e. Ssequence of Eevent
Rrecorder, Ddynamic Ddisturbance Rrecorder, and Ffault Rrecorder) to demonstrate
that the operation of each IBR did adhere to Ride‐through requirements, as specified
in Requirement R1. If the Generator Owner choose to utilize Ride‐through exemptions
that occur within the “must Ride‐through zone” and are caused by non‐fault initiated
phase jumps of greater than 25 electrical degrees, then each Generator Owner shall
also retain evidence of actual disturbance monitoring (i.e. Ssequence of Eevent
Rrecorder, Ddynamic Ddisturbance Rrecorder, and Ffault Rrecorder) data to
demonstrate that the IBR failed to Ride‐through during a phase jump of greater than
or equal to 25 electrical degrees, and documentation from their Transmission Planner,
Reliability Coordinator, Planning Coordinator, or Transmission Operator that a non‐
fault initiated switching event occurred.
R2. Each Generator Owner shall ensure the design and operation is such that the voltage
performance for each IBR adheres to the following during a voltage excursion, unless a
documented hardware limitation exists in accordance with Requirement R4. [Violation
Risk Factor: High] [Time Horizon: Operations Assessment]
1 Includes no tripping associated with phase lock loop loss of synchronism.
2 For the purpose of this standard, the main power transformer is the power transformer that steps up voltage from the
collection system voltage to the nominal transmission/interconnecting system voltage for IBRs. In case of IBR connecting via a
dedicated Voltage Source Converter High Voltage Direct Current (VSC‐HVDC), the main power transformer is the main power
transformer on the receiving end.
3 Current blocking mode may be used for non‐fault initiated phase jumps greater than 25 degrees in order to prevent tripping.
Draft 4 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
2.1.
While the voltage at the high‐side of the main power transformer remains
within the continuous operation region as specified in Attachment 1, each IBR
shall:
2.1.1 Continue to deliver the pre‐disturbance level of Real Power or available
Real Power4, whichever is less.5
2.1.2 Continue to deliver Reactive Rower up to its Reactive Power limit and
according to its controller settings.
2.1.3 Prioritize Real Power or Reactive Power when the voltage is less than
0.95 per unit, the voltage is within the continuous operating region, and
the IBR cannot deliver both Real Power and Reactive Power due to a
current limit or Reactive Power limit, unless otherwise specified
through other mechanisms by an associated Transmission Planner,
Planning Coordinator, Reliability Coordinator, or Transmission
Operator.
2.2.
2.3.
While voltage at the high‐side of the main power transformer is within the
mandatory operation region as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support,
on the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under6:
Reactive Power priority by default; or
Real Power priority if required through other mechanisms by an
associated Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator.
While voltage at the high‐side of the main power transformer is within the
permissive operation region, as specified in Attachment 1, each IBR may
operate in current blocking mode if necessary to avoid tripping. Otherwise,
each IBR shall follow the requirements for the mandatory operation region in
Requirement R2.2.
2.3.1
2.4.
If an IBR enters current blocking mode, it shall restart current
exchange in less than or equal to five cycles of positive sequence
voltage returning to a continuous operation region or mandatory
operation region.
Each IBR shall not itself cause voltage at the high‐side of the main power
transformer to exceed the applicable high voltage thresholds and time
4 “Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
5 Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
6 In either case and if required, the magnitude of Real Power and reactive current shall be as specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
Draft 4 of PRC‐029‐1
September 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
durations in its response as voltage recovers from the mandatory or permissive
operation regions to the continuous operation region.
2.5.
Each IBR shall restore Real Power output to the pre‐disturbance or available
level7 (whichever is lesser) within 1.0 second when the voltage at the high‐side
of the main power transformer returns from the mandatory operation region
or permissive operation region (including operating in current blocking mode)
to the continuous operation region, as specified in Attachment 1, unless an
associated Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator requires a lower post‐disturbance Real Power level
requirement or requires a different post‐disturbance Real Power restoration
time through other mechanisms.8
M2. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to requirements, as specified in Requirement R2. Examples of evidence may
include, but are not limited to dynamic simulations, studies, plant protection settings,
and control settings design evaluation. Each Generator Owner shall also retain
evidence of actual disturbance monitoring (i.e. Ssequence of Eevent Rrecorder,
Ddynamic Ddisturbance Rrecorder, and Ffault Rrecorder) data to demonstrate that the
operation of each IBR did adhere to performance requirements, as specified in
Requirement R2, during each voltage excursion measured at the high‐side of the main
power transformer. In regard to R2.1.3, R2.2, and R2.5, the Generator Owner shall
retain evidence of receiving such performance requirements, (e.g. email exchange,
contract information) if the Transmission Planner, Transmission Operator, Reliability
Coordinator, or Planning Coordinator has required the Generator Owner through
other mechanisms to follow performance requirements other than those in
Requirement R2 (e.g. ramp rates, Reactive Power prioritization).
R3. Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride‐through requirements during a frequency excursion event
whereby the System frequency remains within the “must Ride‐through zone”
according to Attachment 2 and the absolute rate of change of frequency (RoCoF)9
magnitude is less than or equal to 5 Hz/second, unless a documented hardware
limitation exists in accordance with Requirement R4. [Violation Risk Factor: High]
[Time Horizon: Operations Assessment]
M3. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride‐through requirements, as specified in Requirement R3. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner
shall also retain evidence of actual disturbance monitoring (i.e. Ssequence of Eevent
Rrecorder, Ddynamic Ddisturbance Rrecorder, and Ffault Rrecorder) data to
7 “Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
8 Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
9 Rate of change of frequency (RoCoF) is calculated as the average rate of change for multiple calculated system frequencies for
a time period of greater than or equal to 0.1 second. RoCoF is not calculated during the fault occurrence and clearance.
Draft 4 of PRC‐029‐1
September 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
demonstrate the operation of each IBR did adhere to Ride‐through requirements, as
specified in Requirement R3, during each frequency excursion event measured at the
high‐side of the main power transformer.
R4. Each Generator Owner identifying an IBR that is in‐service by the effective date of
PRC‐029‐1, has known hardware limitations that prevent the IBR from meeting voltage
Ride‐through criteria as detailed in Requirements R1 and ‐R32, and requires an
exemption from specific voltage Ride‐through criteria shall:10 [Violation Risk Factor:
Lower] [Time Horizon: Long‐term Planning]
4.1.
Document information supporting the identified hardware limitation no later
than 12 months following the effective date of PRC‐029‐1. This documentation
shall include:
4.1.1 Identifying information of the IBR (name and facility number#);
4.1.2 Which aspects of voltage Ride‐through requirements that the IBR
would be unable to meet and the capability of the hardware due to the
limitation;
4.1.3 Identify the specific piece(s) of hardware causing the limitation;
4.1.4 Supporting tTechnical documentation verifying the limitation is due to
hardware that would needs to be physically replaced to meet all Ride‐
through criteria, and or that the limitation cannot be removed by
software updates or setting changes, and;
4.1.5 Information regarding any plans to remedy the hardware limitation
(such as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1, except for any
material considered by the original equipment manufacture to be proprietary
information, to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), Reliability Coordinator(s), and the
Compliance Enforcement Authority (CEA) no later than 12 months following
the effective date of PRC‐029‐1.11
4.2.1
4.2.2
Provide Aany response tfor additional information requested by the
associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA
shall be provided back to the requestor within 90 days of the
request.
Provide a copy of the acceptance of an hardware limitation by the
CEA to the associated Planning Coordinator(s), Transmission
10 The exemption requests for a non‐US Registered Entity should be implemented in a manner that is consistent with, or under
the direction of, the applicable governmental authority or its agency in the non‐US jurisdiction.
11 To the extent the original equipment manufacturer considers any material to be proprietary, the Generator Owner is
required to share this proprietary material only with the CEA.
Draft 4 of PRC‐029‐1
September 2024
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Planner(s), Transmission Operator(s), and Reliability Coordinator(s)
within 90 days of receiving the acceptance.12
4.3.
Each Generator Owner with a previously accepted limitation that replaces the
hardware causing the limitation shall document and communicate such a
hardware change to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s) within 90
days of the hardware change.
4.3.1
When existing hardware causing the limitation is replaced, the
exemption for that Ride‐through criteria no longer applies.
M4. Each Generator Owner submitting for an exemption for an IBR that is in‐service by the
effective date of PRC‐029‐1, shall have evidence of submission to the CEA consistent
with the information listed in Requirement R4.1. Each Generator Owner shall have
evidence of communicated copies of each submission in accordance with Requirement
R4.2 and to the associated entities described in Requirement R4.2. Acceptable types of
evidence for submittals include but are not limited to, meeting minutes, agreements,
copies of procedures or protocols in effect, or email correspondence. Acceptable
types of evidence for a hardware limitation may include, but is not limited to damage
curvesdocumentation that contains study results, experience from an actual event, or
provided by the original equipment manufacturer’s advice. Each Generator Owner
that receives a request for additional information under Requirement R4.2.1 shall
have evidence of providing that information within 90 calendar days. Each Generator
Owner that replaces hardware at an IBR that is directly associated with an accepted
exemption and that hardware is the cause for the limitation, shall have evidence of
communicating the hardware change to the associated entities described in
Requirement R4.3 within 90 calendar days of the hardware replacement.
12 Acceptance by the CEA is verification that the information provided includes all information listed in Requirement R4.1.
Draft 4 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full‐time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
Each Generator Owner shall retain evidence with Requirements R1, R2, and
R3 in this standard for 36 calendar months or the date of the last audit,
whichever is greater.
Each Generator Owner shall retain evidence with Requirement R4 in this
standard for five calendar years or the date of the last audit, whichever is
greater.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Draft 4 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Generator Owner failed to N/A
demonstrate ensure the
design capability of each
applicable IBR to Ride‐through
in accordance with
Attachment 1, except for
those conditions identified in
Requirement R1.
N/A
The Generator Owner failed to
ensure demonstrate each
applicable IBR adhered to
Ride‐through requirements in
accordance with Attachment
1, except for those conditions
identified in Requirement R1.
R2.
The Generator Owner failed to N/A
ensure demonstrate the
design capability of each
applicable IBR to adhere to
performance requirements
during voltage excursions, as
specified in Requirement R2,
unless a documented
hardware limitation exists in
accordance with Requirement
R4.
N/A
The Generator Owner failed to
ensure demonstrate each
applicable IBR adhered to
performance requirements
during voltage excursions, as
specified in Requirement R2,
unless a documented
hardware limitation exists in
accordance with Requirement
R4.
R3.
The Generator Owner failed to N/A
ensure demonstrate the
design capability of each
applicable IBR to Ride‐through
in accordance with
Attachment 2, unless a
documented hardware
N/A
The Generator Owner failed to
ensure demonstrate each
applicable IBR adhered to
Ride‐through requirements in
accordance with Attachment
2, unless a documented
hardware limitation exists in
Draft 4 of PRC‐029‐1
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
limitation exists in accordance
with Requirement R4.
R4.
Severe VSL
accordance with Requirement
R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 12 months, but less than
or equal to 15 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 15 months, but less than
or equal to 18 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 18 months, but less than
or equal to 24 months after
the effective date of
Requirement R4.
OR
OR
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
90 days but less than or equal
to 120 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
120 days, but less than or
equal to 150 days after
receiving a request for
additional information by an
entity listed in Requirement
R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
150 days but less than or equal
to 180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
document complete
information for IBR identified
with known hardware
limitations that prevent the
IBR from meeting voltage
Ride‐through criteria as
detailed in Requirements R1,
or R2, or R3.
OR
The Generator Owner failed to
provide a copy to the
applicable entities as detailed
in Requirement R4.2 within 24
months after the effective
date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable
OR
The Generator Owner failed to
The Generator Owner failed to entities as detailed in
respond to the applicable
The Generator Owner failed to respond to the applicable
Requirement R4.2.1 more than
entities as detailed in
respond to the applicable
entities as detailed in
180 days after receiving a
Requirement R4.2.2 more than entities as detailed in
Requirement R4.2.2 more than request for additional
90 days but less than or equal Requirement R4.2.2 more than 150 days but less than or equal information by an entity listed
to 120 days after receiving the 120 days but less than or equal to 180 days after receiving the in Requirement R4.2.1.
to 150 days after receiving the
OR
Draft 4 of PRC‐029‐1
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OR
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PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
acceptance of a hardware
limitation by the CEA.
acceptance of a hardware
limitation by the CEA.
acceptance of a hardware
limitation by the CEA.
OR
OR
OR
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), Reliability
Coordinator(s), and CEA more
than 90 calendar days but less
than or equal to 120 calendar
days after the change to the
hardware.
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 120 calendar days but
less than or equal to 150
calendar days after the change
to the hardware.
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 150 calendar days but
less than or equal to 180
calendar days after the change
to the hardware.
OR
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 12 months but less than
or equal to 15 months after
the effective date of
Requirement R4.
OR
Draft 4 of PRC‐029‐1
September 2024
Severe VSL
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
180 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s),Reliability
OR
OR
Coordinator(s), and CEA more
The Generator Owner failed to The Generator Owner failed to
than 180 calendar days after
respond to the applicable
respond to the applicable
the change to the hardware.
entities as detailed in
entities as detailed in
Requirement R4.2.1 more than Requirement R4.2.1 more than OR
120 days but less than or equal 150 days but less than or equal
The Generator Owner failed to
to 150 days after receiving a
to 180 days after receiving a
provide a copy to the
request for additional
request for additional
applicable entities as detailed
information by an entity listed information by an entity listed
in Requirement R4.2 within 24
in Requirement R4.2.1.
in Requirement R4.2.1.
Page 12 of 19
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Violation Severity Levels
R#
Lower VSL
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
90 days but less than or equal
to 120 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
Moderate VSL
High VSL
Severe VSL
months after the effective
date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
Draft 4 of PRC‐029‐1
September 2024
Page 13 of 19
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Version History
Change
Tracking
Version
Date
Initial Draft
3/27/24
Draft
Draft 2
6/4/24
Revised following initial comment review
Draft 3
7/22/24
Revised following additional comment review
Draft 4
9/12/24
Revised following additional comment review
Draft 4 of PRC‐029‐1
September 2024
Action
Page 14 of 19
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-through Requirements for AC-Connected Wind IBR 13
Voltage
(per unit)14
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A15
N/A
≥ 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
3.00
< 0.70
Mandatory Operation Region
2.50
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.16
< 0.10
Permissive Operation Region
0.16
Table 2: Voltage Ride-through Requirements for All Other IBR
Voltage
(per unit)16
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A17
N/A
> 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
6.00
< 0.70
Mandatory Operation Region
3.00
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.32
< 0.10
Permissive Operation Region
0.32
13 Type 3 and type 4 wind resources directly connected to the AC Transmission System.
14 Refer to bullet #4 below.
15 These conditions are referred to as the “may Ride‐through zone”.
16 Refer to bullet #4 below.
17 These conditions are referred to as the “may Ride‐through zone”.
Draft 4 of PRC‐029‐1
September 2024
Page 15 of 19
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
1. Table 1 applies to type 3 and type 4 wind IBR or hybrid IBR that include wind, unless
connected via a dedicated Voltage Source Converter ‐ High Voltage Direct Current
(VSC‐HVDC) transmission facility.
2. Table 2 applies to all other IBR types not covered in Table 1; including, but not
limited to, the following facilities:
a. IBR, regardless of their energy resource, interconnecting via a dedicated VSC‐
HVDC transmission facility.
b. Other IBR or hybrid IBR consisting of photovoltaic (PV) and BESS.
3. The applicable voltage for VSC‐HVDC system with a dedicated connection to an IBR
is on the AC side of the transformer(s) that is (are) used to connect the VSC‐HVDC
system to the interconnected transmission system.
4. The voltage base for per unit calculation is the nominal phase‐to‐ground or
phase‐to‐phase transmission system voltage unless otherwise defined by the
Planning Coordinator, Transmission Planner, or Transmission Owner.
5. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase‐to‐neutral or phase‐to‐phase fundamental root mean square (RMS) voltage at
the high‐side of the main power transformer.
6. Tables 1 and 2 are only applicable when the frequency is within the “must
Ride‐through zone” as specified in Figure 1 of Attachment 2.
7. At any given voltage value, each IBR shall Ride‐through unless the time duration at
that voltage has exceeded the specified minimum Ride‐through time duration. If the
voltage is continuously varying over time, it is necessary to add the duration within
each band of Tables 1 and 2 over any 10 second time period.
8. The specified duration of the mandatory operation regions and the permissive
operation regions in Tables 1 and 2 is cumulative over one or more disturbances
within any 10 second time period.
9. The IBR may trip for more than four deviations of the applicable voltage at the high‐
side of the main power transformer outside of the continuous operation region
within any 10 second time period.
10. Instantaneous trip settings based on instantaneously calculated voltage
measurements with less than filtering lengths of one cycle (16.6 millisecond) are not
permissible.
11. The “must Ride‐through zone” is the combined area of the mandatory operating
regions, the continuous operating regions, and the permissive operating region. All
area outside of these operating regions is referred to as the “may Ride‐through
zone”.
Draft 4 of PRC‐029‐1
September 2024
Page 16 of 19
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Attachment 2: Frequency Ride-Through Criteria
Table 3: Frequency Ride-through Capability Requirements
System Frequency (Hz)
Minimum Ride-Through
Time (sec)
> 61.8
May trip
> 61.2
299
≤ 61.2 and ≥ 58.8
Continuous
< 58.8
299
< 57.0
May trip
System Frequency (Hz)
Minimum Ride-Through
Time (sec)
> 64.0
May trip
≥ 61.8
6
≥ 61.5
299
> 61.2
660
≤ 61.2 and > 58.8
Continuous
≤ 58.8
660
≤ 58.5
299
≤ 57.0
6
< 56.0
May trip
1. Frequency measurements are taken at the high‐side of the main power transformer.
2. Frequency is measured over a period of time (typically 3‐6 cycles) to calculate system
frequency at the high‐side of the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency value, each IBR shall Ride‐through unless the time duration at
that frequency has exceeded the specified minimum ride‐through time duration.
5. The specified durations of Table 3 are cumulative over one or more disturbances within
a 105‐minute time period.
Draft 4 of PRC‐029‐1
September 2024
Page 17 of 19
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
63
62
May Ride‐through Zone
Frequency (Hz)
61
Must Ride‐through Zone
60
59
58
May Ride‐through Zone
57
56
0
100
200
300
299
400
500
600
700
800
900
∞
1000
Time (seconds)
Draft 4 of PRC‐029‐1
September 2024
Page 18 of 19
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based Resources
Figure 1: PRC‐029 Frequency Ride‐through Requirements
Draft 4 of PRC‐029‐1
September 2024
Page 19 of 19
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Reliability Standards PRC-024-4 and PRC-029-1
Applicable Standard(s)
•
PRC-024-4 – Frequency and Voltage Protection Settings for Synchronous Generators, Type 1
and Type 2 Wind Resources, and Synchronous Condensers
•
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based
Generating Resources
Requested Retirement(s)
•
PRC-024-3 Frequency and Voltage Protection Settings for Generating Resources
Prerequisite Standard(s)
•
None
Proposed Definition(s)
•
None
Applicable Entities
•
See subject Reliability Standards.
Background
The purpose of Project 2020-02 is to modify Reliability Standard PRC-024-3 or replace it with a
performance-based Ride-through standard that ensures generators remain connected to the
Bulk Power System (BPS) during system disturbances. Specifically, the project focuses on using
disturbance monitoring data to substantiate inverter-based resource (IBR) ride-through performance
during grid disturbances. The project also ensures associated generators that fail to Ride-through
system events are addressed with a corrective action plan (if possible) and reported to necessary
entities for situational awareness.
The purpose for this project is based on the culmination of multiple analyses conducted by the ERO
Enterprise regarding widespread IBR tripping events. Furthermore, the NERC Inverter-Based Resource
Performance Subcommittee 1 has developed comprehensive recommendations for improved
See documents at the NERC IRPS website: https://www.nerc.com/comm/RSTC/Pages/IRPS.aspx and the previous Inverter-Based
Resource Performance Working Group website https://www.nerc.com/comm/RSTC/Pages/IRPWG.aspx
1
RELIABILITY | RESILIENCE | SECURITY
performance of IBRs, including the recommendation to develop comprehensive ride-through
requirements.
In October 2023, FERC issued Order No. 901 2 which directs the development of new or modified
Reliability Standards that include new requirements for disturbance monitoring, data sharing, postevent performance validation, and correction of IBR performance. In January 2024, NERC submitted a
filing to FERC outlining a comprehensive work plan to address the directives within Order No. 901. 3
Within the work plan, NERC identified three active Standards Development projects that would need to
be filed for regulatory approval with FERC by November 4, 2024. These projects include 2020-02
Modifications to PRC-024 (Generator Ride-through) 4, 2021-04 Modifications to PRC-002-2 5, and 202302 Analysis and Mitigation of BES Inverter-based Resource Performance Issues 6.
Project 2020-02
Proposed Reliability Standard PRC-029-1 is a new Reliability Standard that includes Ride-through
requirements and performance requirements for IBRs. The scope of this project was adjusted to align
with associated regulatory directives from FERC Order No. 901 and the scope of the other projects
related to “Milestone 2” of the NERC work plan. The components of this project’s Standard
Authorization Request (SAR) that related to the inclusions of new data recording requirements are
covered in Project 2021-04 and the proposed new PRC-028-1 Reliability Standard. Components of this
project’s SAR that relate to analytics and corrective actions plans are covered in Project 2023-02 and the
proposed new PRC-030-1 Reliability Standard.
PRC-029-1 includes requirements for Generator Owner IBR to continue to inject current and perform
voltage support during a BPS disturbance. The standard also specifically requires Generator Owner IBR
to prohibit momentary cessation in the no-trip zone during disturbances.
PRC-024-4 includes modifications to revise applicable facility types to remove IBR, retain type 1 and
type 2 wind, and to include synchronous condensers.
See FERC Order 901, Docket No. RM22-12-000; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=202310193157&optimized=false; October 19, 2023
3 See INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF
RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%2
0901%20Work%20Plan_packaged%20-%20public%20label.pdf; January 17, 2024
4 See NERC Standards Development Project page for Project 2002-02; https://www.nerc.com/pa/Stand/Pages/Project_202002_Transmission-connected_Resources.aspx
5 See NERC Standards Development Project page for Project 2021-04; https://www.nerc.com/pa/Stand/Pages/Project-2021-04Modifications-to-PRC-002-2.aspx
6 See NERC Standards Development Project page for Project 2023-02; https://www.nerc.com/pa/Stand/Pages/Project-2023-02Performance-of-IBRs.aspx
2
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
2
General Considerations
This implementation plan recognizes the urgent need for Reliability Standards to address IBR ride
through performance, as demonstrated by multiple event reports of the last decade, while providing a
reasonable period of time for entities to develop the necessary procedures and change their protection
and control settings to meet the new requirements. The ERO Enterprise acknowledges that there are
IBRs currently in operation and unable to meet voltage Ride-through requirements due to their inability
to modify their coordinated protection and control settings. Consistent with FERC Order No. 901, a
limited and documented exemption process for those IBR is appropriate and included within this
Implementation Plan. Other NERC Standards Development projects will be pursued to address ongoing
identification and mitigation of any potential reliability impacts to the BPS for such exemptions.
This implementation plan also recognizes that certain requirements (Requirements R1, R2, and R3) call
for entities to “ensure the design and operation” of their IBR units meets certain criteria. Design
elements may be implemented more expeditiously than operation requirements; the latter of which
will require entities to show compliance through use of actual disturbance monitoring data. Therefore,
this implementation plan provides staggered timeframes by which entities shall first ensure the design
of their IBR units meets the criteria (12 months following regulatory approval). Subsequent compliance
with the “operation” elements of these requirements shall become due as entities install disturbance
monitoring equipment on each applicable IBR in accordance with the implementation plan for proposed
Reliability Standard PRC-028-1 Disturbance Monitoring and Reporting Requirements for Inverter-based
Resources.
The ERO Enterprise acknowledges that Generator Owners and Generator Operators owning or
operating Bulk Power System connected IBRs that do not meet NERC’s current definition of Bulk Electric
System (“BES”) will be registered no later than May 2026 in accordance with the IBR Registration
proceeding in FERC Docket No. RR24-2. To ensure an orderly registration and compliance process for
these entities, as well as fairness and consistency in the standard’s application among similar asset
types, this implementation plan provides additional time for both new and existing registered entities to
come into compliance with Reliability Standard PRC-029-1’s requirements for their applicable IBRs not
meeting the BES definition. In so doing, this implementation plan advances an orderly process for new
registrants while allowing existing entities to focus their immediate efforts on their assets posing the
highest risk to the reliable operation of the Bulk Power System.
Effective Date and Phased-in Compliance Dates
The effective dates for the proposed Reliability Standards are provided below. Where the standard
drafting team identified the need for a longer implementation period for compliance with a particular
section of a proposed Reliability Standard (i.e., an entire Requirement or a portion thereof), the
additional time for compliance with that section is specified below. The phased-in compliance dates for
those particular sections represent the date that entities must begin to comply with that particular
section of the Reliability Standard, even where the Reliability Standard goes into effect at an earlier
date.
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
3
PRC-024-4
Where approval by an applicable governmental authority is required, Reliability Standard PRC-024-4
shall become effective on the first day of the first calendar quarter that is twelve months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC024-4 shall become effective on the first day of the first calendar quarter that is twelve months after
the date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1
Where approval by an applicable governmental authority is required, Reliability Standard PRC-029-1
shall become effective on the first day of the first calendar quarter that is twelve months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC029-1 shall become effective on the first day of the first calendar quarter that is twelve months after the
date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1 Phased-in Compliance Dates
Requirements R1, R2, and R3
Capability-Based Elements
Bulk Electric System IBRs
Entities shall comply with the portion of Requirements R1, R2, and R3 relating to the design of their
BES IBRs to meet the requirements by the effective date of the standard.
Applicable Non-BES IBRs 7
Entities shall not be required to comply with Requirements R1, R2, and R3 relating to the design of
their applicable non-BES IBRs until the later of: (1) January 1, 2027; or (2) the effective date of the
standard.
Performance-Based Elements (all applicable IBRs)
Entities shall not be required to comply with the portion of Requirements R1, R2, and R3 relating to
the operation of IBRs to meet the requirements until the entity has established the required
The standard defines such as IBRs as “Non-BES Inverter-Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.”
7
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
4
disturbance monitoring equipment capabilities for those IBRs in accordance with the
implementation plan for Reliability Standard PRC-028-1.
Requirement R4
Bulk Electric System IBRs
Entities shall comply with Requirement R4 for their BES IBRs by the effective date of the standard.
Applicable Non-BES IBRs
Entities shall not be required to comply with Requirement R4 or their non-BES IBRs until the later of:
(1) January 1, 2027; or (2) the effective date of the standard.
Retirement Date
PRC-024-3
Reliability Standard PRC-024-3 shall be retired immediately prior to the effective date of Reliability
Standards PRC-024-4 and PRC-029-1 in the particular jurisdiction in which the revised standard is
becoming effective.
Equipment Limitations and Process for Requirement R4
Consistent with FERC Order No. 901, a limited and documented exemption for some legacy IBR with
certain documented equipment limitations are acceptable. Per the Order, these IBRs are
“…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.” 8
To ensure compliance with Requirement R4 and alignment with FERC Order No. 901, only those IBR that
are in operation as of the effective date of PRC-029-1 may be considered for potential exemption.
Further, only those IBR that are unable to meet voltage ride-through requirements due to their inability
to modify their coordinated protection and control settings may be considered for potential exemption.
8
Order No. 901 at p. 193.
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
5
To:
NERC Board of Trustees and Stakeholders
From:
NERC Staff and Representatives from the Standards Committee
Re:
Summary of Issues and Alternatives Considered, Proposed Reliability Standard PRC-029-1
(Frequency and Voltage Ride-through Requirements for Inverter-based Resources)
September 24, 2024
Date:
In Order No. 901, the Federal Energy Regulatory Commission (“FERC”) directed the development of new or
revised Reliability Standards to address certain reliability issues related to inverter-based resources
(“IBRs”), including IBR ride-through performance. 1 To address the IBR ride-through directives, Project 202002 Modifications to PRC-024-4 initiated development of proposed Reliability Standard PRC-029-1
(Frequency and Voltage Ride-through Requirements for Inverter-based Resources). However, proposed
Reliability Standard PRC-029-1 has failed to pass ballot through the usual standard development process.
Section 321 of the NERC Rules of Procedure allows the NERC Board of Trustees to take special actions when
a ballot pool has failed to approve a proposed Reliability Standard that contains a provision to adequately
address a specific matter identified in a directive issued by an Applicable Governmental Authority. The NERC
Board of Trustees took such action for the proposed PRC-029-1 standard at its August 2024 meeting. 2
Consistent with Section 321.2 of the NERC Rules of Procedure, the Standards Committee and NERC staff
convened a technical conference from September 4-5, 2024 to discuss the issues surrounding the FERC
Order No. 901 directives, including whether or not the proposed Reliability Standard PRC-029-1 is just,
reasonable, not unduly discriminatory or preferential, in the public interest, helpful to reliability, practical,
technically sound, technically feasible, and cost-justified. This memorandum discusses the issues, an
analysis of alternatives considered, and other appropriate matters.
Background
On October 19, 2023, the Commission issued Order No. 901 directing the development of new or revised
Reliability Standards to address reliability issues associated with the growth of IBRs on the Bulk-Power
Reliability Standards to Address Inverter-Based Resources, Order No. 901, 185 FERC ¶ 61,042, Docket No. RM22-12-000 (Oct. 19,
2023) [hereinafter Order No. 901]. Available here.
1
2
NERC Board of Trustees, Minutes of the August 15, 2024, available here.
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
RELIABILITY | RESILIENCE | SECURITY
System. 3 The Commission directed NERC to develop new or revised Reliability Standards addressing IBR
reliability issues as follows:
1) IBR disturbance monitoring data sharing and post-event performance validation 4 and ridethrough performance requirements 5 by November 4, 2024;
2) IBR data and model validation 6 by November 4, 2025; and
3) planning and operational studies 7 for IBRs by November 4, 2026.
The Commission also directed NERC to develop and submit a work plan to develop new and revised
Reliability Standards to address these issues in accordance with the specified timeframe. 8
On January 17, 2024, NERC submitted its Order No. 901 Work Plan, 9 which consists of key milestones to
meet the Commission’s directives by the filing deadlines mentioned above. Milestone 2, in progress,
focuses on the development of Reliability Standards to address disturbance monitoring, performancebased ride-through requirements and post-event performance validation for registered IBRs by November
4, 2024.
The Reliability Standards being proposed to address Milestone 2 of FERC Order 901 are being developed
through the following projects:
•
Project 2020-02 Modifications to PRC-024 (Generator Ride-through),
•
Project 2021-04 Modifications to PRC-002,
•
Project 2023-02 Analysis and Mitigation of BES Inverter-Based Resource Performance Issues
As of this writing, Projects 2021-04 and 2023-02 are on track for timely completion through the usual NERC
standard development process. Project 2020-02, addressing generator ride-through directives from Order
No. 901, is the subject of special Board action under Section 321.
Specifically, proposed Reliability Standard PRC-029-1 (Frequency and Voltage Ride-through Requirements
for Inverter-based Resources) is a draft standard designed to establish capability-based and performancebased ride-through requirements for IBRs during grid disturbances, to address the Commission directives
from Order No. 901. The draft standard failed to achieve consensus from the Registered Ballot Body over
3
See Order No. 901, supra, at PP 229.
4
See id. at PP 66-109 (discussing directives related to data sharing requirements).
5
See id. at PP 178-211 (discussing directives related to performance requirements).
6
See id. at PP 110-161 (discussing directives related to data and model validation requirements).
7
See id. at PP 162-177 (discussing directives related to planning and operational studies requirements).
8
See id. at P 222.
Informational Filing of the North American Electric Reliability Corporation Regarding the Development of Reliability Standards
Responsive to Order No. 901, (Docket No. RM22-12-000) (2024) [hereinafter Order No. 901 Work Plan].
9
RELIABILITY | RESILIENCE | SECURITY
multiple ballots, the latest of which occurred between August 2, 2024 to August 12, 2024. This called into
question whether development would be completed by FERC’s filing deadline of November 4, 2024.
As a result, the NERC Board of Trustees initiated the use of Section 321 at its August 15, 2024 meeting.
Under this special authority, the Board directed the Standards Committee to work with NERC Staff to
convene a technical conference to gather input from industry to address the outstanding issues and revise
PRC-029-1. This memorandum describes the issues that led to the technical conference convening and the
alternative solutions that were considered. The proposed PRC-029-1 standard has been revised using input
from the technical conference and is submitted for stakeholder ballot. This process must be completed
within 45 days of being initiated, which is September 30, 2024. If the re-balloted proposed Reliability
Standard achieves at least an affirmative 60% majority vote of the weighted Segment votes cast, then the
Board may consider it for adoption under Section 321.
Order No. 901 Directives for Ride-through
In Order No. 901, the Commission cites to multiple event reports as the reason that IBRs should have
Reliability Standards for 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. 10 Below you will find the Commission’s specific directives on
how IBRs should ride-through disturbances and how exceptions should be applied to certain IBRs. Finding
consensus around these directives were a part of the main issues addressed during the technical
conference.
“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 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.” 11
“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
10
See Order No. 901 at PP 190.
11
See id.
RELIABILITY | RESILIENCE | SECURITY
modify their coordinated protection and control settings to meet the requirements without physical
modification of the IBRs’ equipment.” 12
Summary of Issues and Alternatives Considered
The technical conference took place on September 4-5, 2024, and focused on unresolved issues raised by
stakeholders raised during the PRC-029-1 comment periods. Specifically, the technical conference focused
on: (1) the proposed definition of “Ride-through”; (2) the proposed criteria for frequency ride-through
performance; and (3) the feasibility of allowing hardware-based exemptions from the frequency ridethrough requirements, similar to the voltage ride-through exemption FERC directed NERC to consider in
Order No. 901. 13 These issues, and the alternatives considered, are discussed below.
Ride-Through Definition
The most recent Standard Authorization Request for Project 2020-02 included direction to the drafting
team to define the term “ride-through” as necessary. During the development of Milestone 2 projects, a
definition for “ride-through” was considered by the drafting teams of both PRC-029 and PRC-030 as both
Reliability Standards leverage the term to refer to acceptable performance criteria outlined in PRC-029. Per
the Standards Process Manual (NERC Rules of Procedure Appendix 3A), definitions themselves may not
include statements of performance requirements. As such, the specific performance requirements and
measures to demonstrate ride-through are to be found within the Requirements and Attachments of PRC029-1. References to “Ride-through criteria” in PRC-030-1, allow for those additional analytics to include
further evaluations with PRC-029-1 Ride-through performance requirements as appropriate while
preventing duplication of those performance requirements in different Reliability Standards.
Comments from Draft 3 of PRC-029-1 concerning the proposed definition of “Ride-through” were reviewed.
In the previously proposed definition, many stakeholders argued that the proposed definition was too
broad and ambiguous, particularly with the inclusion of phrases like “entire” and “in its entirety.” Those
stakeholders recommended revisions to clarify the definition and ensure it aligns better with IEEE Std
2800™, IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs)
Interconnecting with Associated Transmission Electric Power Systems. 14 The Draft 3 proposed definition of
“Ride-through” was discussed at the technical conference and presented on by a member of the original
drafting team. 15 The Draft 3 definition was presented as follows: “The entire plant/facility remaining
connected to the Bulk Power System and continuing in its entirety to operate through System
Disturbances.”
As part of the presentation, ten (10) alternative definitions were presented as proposed by commenters
during the previous rounds of ballot and formal comment. After the presentation, four (4) of the most
12
13
14
See Order No 901 at PP 193.
See Order No 901 at PP 199.
Hereinafter referred to as “IEEE 2800-2022”.
See “Outlining Objectives of a Ride-through Definition” of posted Standards Committee and NERC Ride-through Technical
Conference material; page 94/129.
15
RELIABILITY | RESILIENCE | SECURITY
distinct definitions were opened to technical conference attendees as a straw poll to gauge overall industry
preference. When asked “Which of the following proposed definitions for Ride-through do you think is most
correct?”:
•
•
•
•
68% voted in favor of the “Ability to withstand voltage or frequency disturbances inside defined
limits and to continue operating as specified.”;
16% voted in favor of “The plant/facility remaining connected to the Bulk Power System and
continuing to operate through System Disturbances as defined in applicable reliability standards.”;
12% voted in favor of “The entire plant/facility remaining connected to the Bulk Power System and
continuing in its entirety to operate through System Disturbances.”; and
4% voted in favor of “The plant/facility shall remain connected and in service, maintaining the predisturbance equipment configuration in operation, throughout the entirety of the system
disturbance and recovery.”
Following the technical conference, NERC staff, Standards Committee representatives, some members of
the drafting team, and FERC staff met to discuss the results of the straw poll as well as previously reviewed
material. Based on that discussion, language in the preferred definition such as “ability to withstand”,
“defined limits” and “as specified” were unclear and were inherently challenging for use in a definition that
must be leveraged by multiple Reliability Standards. It was determined that the final draft would proceed
with the 2nd most preferred definition, with slight modifications to remove usage of other defined terms
that had an embedded usage of the Bulk Electric System defined term. The final definition as proposed in
Draft 4 of PRC-029-1 is as follows: “The plant/facility remains connected and continues to operate through
voltage or frequency system disturbances.”
Proposed Criteria for Frequency Ride-Through Performance
As described in the Project 2020-02 Standard Authorization Request and assigned directives from Order No.
901, the drafting team was tasked with developing new or modified Reliability Standards to assure a
performance-based approach to generator ride-through. This scope included requirements that generating
resources shall ride-through grid disturbances and include quantitative measures on expectations for ridethrough that address all possible causes of tripping and power reductions from generating resources
(particularly generator, turbine, inverter, and all plant-level protection and controls).
The proposed new Reliability Standard PRC-029-1 requires generator owners of IBR to both design and
operate their IBR plants to ride-through voltage and frequency system disturbances. Requirement R3 and
Attachment 2 of PRC-029-1 define the quantitative frequency ride-through criteria by use of measured
frequency magnitude and time duration of sustaining that magnitude for all conditions. As discussed during
the development of PRC-029-1, many stakeholders commented in previous ballots a preference to leverage
those quantitative values as currently established in IEEE 2800-2022.
Frequency ride-through criteria was a prominent discussion of the technical conference. Members of the
drafting team presented on the decisions made during the development of these criteria during the
technical conference. 16 The presentation explained that the voltage and frequency ride-through zones
See “Review of Voltage and Frequency Ride-through Criteria in PRC-029-1” of posted Standards Committee and NERC Ride-through
Technical Conference material; page 47/129.
16
RELIABILITY | RESILIENCE | SECURITY
proposed in Draft 3 of the standard were based on the IEEE 2800-2022 no-trip zones and were established
in view of drafting team member experience with frequency excursions in planning and operations. The
drafting team also stated the proposed frequency criteria were reasonable and were practical limits of IBR
frequency tolerances, inclusive of adequate margins for worst-case conditions.
Following the presentation by the drafting team, NERC staff presented on voltage and frequency Ridethrough evaluations taken from recent NERC disturbance reports and the report results from the March
2023 Level 2 Alert. 17 The NERC presentation stressed balancing Bulk Power System needs with reasonable
criteria that account for technical capabilities of currently designed equipment. NERC also highlighted a
continued need to coordinate messaging during the design and interconnection phases of new IBR to have
protection and controller equipment set in accordance with the hardware capability of the IBR rather than
only in relation to minimum values established in NERC Reliability Standards.
Two panels regarding frequency criteria were held during the technical conference. The first panel included
representatives of various IBR original equipment manufacturers, and the second panel included other
members of industry. 18 Discussions from both panels highlighted the following key issues: 19
•
•
•
Many IBR designed before 2014 would be unable to meet frequency Ride-through magnitude and
duration criteria proposed in Attachment 2 of Draft 3. It was estimated by one panelist that
approximately 20 GW of installed capacity would not be able to meet the criteria, indicating
significant challenges for legacy IBR without substantial hardware replacement and redesign.
Many IBR had not been designed to meet a rate of change of frequency (RoCoF) of 5 Hz per second.
Of concern from the panelist was the technical basis for determining the need for a 5 Hz RoCoF did
not include a study or more thorough evaluation of potential system strength benefits and that
different parts of the Bulk Power System have not been demonstrated to require it.
Recent event reports presented by NERC were all related to voltage excursions, potentially
indicating that frequency-based disturbances were less likely to occur. Some panelists contended
that this potential lower likelihood of experiencing a frequency event did not align with the
expansion of frequency criteria beyond those currently established in IEEE 2800-2022.
After the panels of this topic, two straw polls were opened for attendees of the Ride-through technical
conference to provide their feedback for consideration regarding “legacy” IBR and future IBR.
When attendees were asked “Based on the conversation you heard today from our panels, for legacy assets,
what should PRC-029 voltage and frequency criteria follow that assures reliability and is reasonable for
industry?”:
•
64% voted in favor of “Maintain PRC-024 criteria for IBR”;
See “Review of Voltage and Frequency Ride-through” of posted Standards Committee and NERC Ride-through Technical Conference
material; page 67/129.
17
See “Panel Discussion: Original Equipment Manufacturer Perspectives on Voltage and Frequency Ride-through Criteria” of posted
Standards Committee and NERC Ride-through Technical Conference material; pages 85/129 and 86/129.
18
See Day 1 Recording and Transcript of the Standards Committee & NERC Ride-through Technical Conference; Project 2020-02
Modifications to PRC-024 (Generator Ride-through) Related Files; posted September 18, 2024.
19
RELIABILITY | RESILIENCE | SECURITY
•
•
29% voted in favor of “Adopt voltage and frequency bands proposed in IEEE 2800-2022”; and
6% voted in favor of “Retain currently proposed PRC-029 criteria”.
When attendees were asked “Based on the conversation you heard today from our panels, for assets being
brought online in the future, what should PRC-029 voltage & frequency criteria follow that assures reliability
and is reasonable for industry?”:
•
•
90% voted in favor of “Adopt voltage and frequency bands proposed in IEEE 2800-2022”; and
10% voted in favor of “Retain currently proposed PRC-029 criteria”.
Following the technical conference, NERC staff, Standards Committee representatives, some members of
the drafting team, and FERC staff met to discuss the results of the straw polls as well as previously reviewed
material. The team discussed that the term “legacy assets”, as used during the technical conference, aligned
with the date for seeking potential exemption within PRC-029-1; meaning those IBR that were “in-service”
by the effective date of PRC-029-1. While respondents at the technical conference did vote more favorably
to retaining existing PRC-024 criteria for legacy assets, other information submitted by commenters and
highlighted during the panel of original equipment manufacturers, indicated that a significant majority of
IBR have been designed to meet IEEE 2800-2022 values. 20, 21
Additional information provided during the NERC staff presentation 22 identified that many IBR were still
being designed and installed without setting their protection and controls in accordance with their physical
capabilities. Due to a concern of lowering the bar of performance by requiring that IBR perform less than
what the significant majority of IBR are being designed and manufactured to, it was determined that the
proposed standard should not align with previous PRC-024-3 criteria.
Based on the more clearly understood hardware-based capability limitation established due to manufacture
design for a significant amount of installed IBR, there was a reliability concern to proceed with Draft 3 PRC029-1 frequency criteria as that same amount of IBR could necessitate disconnection and retrofitting in
order to comply. It was also identified that the potential disconnection of a large amount of installed IBR
capacity did not substantially outweigh unstudied reliability benefits potentially resulting from setting
frequency ride-through bands wider than those established in IEEE 2800-2022 and overwhelmingly
identified by manufacturers during our comment review when designing IBR throughout the past decade.
Due to these reliability concerns, the frequency criteria in Attachment 2 of the draft has been adjusted to
align with those values in IEEE 2800-2022.
Feasibility of Hardware-Based Exemptions from Frequency Ride-Through Requirements
Potential hardware-based exemptions were discussed during each formal comment period of PRC-029-1,
with a significant majority of commenters supporting some exemptions from frequency ride-through
See Industry Submitted Comments for the Standards Committee & NERC Ride-through Technical Conference; Project 2020-02
Modifications to PRC-024 (Generator Ride-through) Related Files; posted September 2024.
20
See Day 1 Recording and Transcript of the Standards Committee & NERC Ride-through Technical Conference; Project 2020-02
Modifications to PRC-024 (Generator Ride-through) Related Files; posted September 18, 2024.
21
See “Review of Voltage and Frequency Ride-through” of posted Standards Committee and NERC Ride-through Technical Conference
material; page 67/129.
22
RELIABILITY | RESILIENCE | SECURITY
criteria for legacy IBR. The drafting team and industry were advised that Order No. 901 only included and
only allowed for exemptions of voltage ride-through performance requirements, based on the following
discussion of allowable exemptions within the order:
“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.” 23
“Further, we direct NERC to ensure that any such exemption would be applicable for only existing
equipment that is unable to meet voltage ride-through 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.).” 24
While the order spoke only to exemptions from voltage ride-through requirements and was silent regarding
any exemptions for frequency ride-through criteria, industry continued to identify that there was a need to
include such exemptions in PRC-029-1. It was determined that the details shared leading up to and during
the technical conference provided clarity as well as a more substantiated basis for why hardware-based
exemptions of frequency ride-through criteria was needed.
Prior to the technical conference, NERC solicited comments from industry as well as original equipment
manufacturers. 25 In particular, any information on hardware-based limitations that would prevent IBR from
meeting the proposed frequency criteria within PRC-029-1 was requested. 21 individual comments were
received including six (6) from different original equipment manufacturers of IBR. NERC and representatives
from the Standards Committee reviewed the submitted material and confirmed that IBR are being designed
by original equipment manufacturers to be able to meet those voltage and frequency ride-through curves
established in IEEE 2800-2022. As Draft 3 of PRC-029-1 proposed frequency criteria were beyond those
established in IEEE 2800-2022, there was a concern that IBR would not be able to meet those proposed
frequency criteria as IBR capability limits were hardware-based and inherent to a manufacturer’s design.
While many comments received during the formal comment periods stressed a desire to align PRC-029-1
with IEEE 2800-2022, there was little differentiation between comments that sought to leverage other
industry volunteer guidelines that have been significantly adopted with those comments that sought
exemptions due to the fact that manufacturers are designing IBR capabilities to the IEEE 2800-2022 values.
Moreover, comments submitted by manufacturers provided a better understanding and approximation of
what percentage of the installed fleets of IBR would be unable to meet PRC-029-1 frequency criteria. While
additional information regarding specific amounts of affected IBR is still sought by NERC, from the
23
See id. at P 153.
24
See id. at P 153.
See Standards Committee and NERC Ride-through Technical Conference; Conference Details; publicly announced August 21, 2024;
https://www.nerc.com/pa/Stand/Documents/SC_and_NERC%20Ride-through_Technical_Conference_Details_08212024.pdf
25
RELIABILITY | RESILIENCE | SECURITY
information provided, it appears that a significant percentage of IBR 26 – specifically Type 3 wind turbine
facilities – would need to retrofit to avoid noncompliance with PRC-029-1 as proposed in Draft 3.
The technical conference included a panel discussion on frequency exemptions. Panelists discussed various
challenges related to legacy IBR, such as difficulties obtaining more detailed information on equipment
capabilities; specifically for manufacturers who are no longer in business and for IBR that are no longer
supported by the manufacturer. In such instances, additional time and cost would be expected to conduct
more detailed capability testing. Other concerns raised included the possibility that manufacturers would
not be willing to provide design or hardware limitation documentation should they identify the information
to be proprietary information. Other discussions substantiated information received during the solicitation
of comments for the conference and provided more clarity as to the alignment of the IEEE 2800-2022 curves
with inherent capability limitations. 27
Following the technical conference, NERC staff, Standards Committee representatives, some members of
the drafting team, and FERC staff met to discuss the discussions during the conference as well as previously
reviewed material. Based on the more clearly understood hardware-based capability limitation established
due to manufacture design for a significant amount of installed IBR, there was a reliability concern to
proceed with no potential for hardware-based limitations for frequency criteria, as that same amount of
IBR could necessitate disconnection and retrofitting to comply.
It was determined that this potential disconnection of a large amount of installed IBR capacity
overwhelmingly indicated a reliability need to allow for a documented and limited set of exemptions for
IBR from voltage and frequency ride-through criteria. In light of this reliability concern, Requirement R4 of
PRC-029-1 has been modified to allow for a documented, and limited set of exemptions for IBR from
frequency criteria. Further modifications were made to allow Generator Owners to exclude information
considered to be proprietary from submittals to anyone other than the Compliance Enforcement Authority,
to facilitate the sharing of requisite information from manufacturers.
Conclusion
After following the process described in Section 321 of the NERC Rules of Procedure, as directed by the
NERC Board of Trustees at the August 15, 2024 meeting, proposed Reliability Standard PRC-029-1 has been
revised to: include revised definition for the new proposed term “Ride-through”, align frequency ridethrough criteria with IEEE 2800-2022 values, allow for a limited documented set of exemptions for
hardware-based limitations for frequency ride-through criteria, and to allow Generator Owners to only
share information deemed by the original equipment manufacturer as proprietary with the Compliance
Enforcement Authority..
These revisions in proposed Reliability Standard PRC-029-1 reflect a fulsome consideration of the technical,
reliability, and implementation considerations raised in the underlying development proceeding and during
Analysis of the data collected through NERC’s Level 2 Alert: Industry Recommendation for IBR Performance Issues showed that the
number of resources that are not able to meet PRC-029 Draft 3 is approximately double when compared to those same resources ability to
comply with the updated criteria in PRC-029 Draft 4 which align with IEEE 2800-2022. Information submitted through the comment period
and the technical conference discussions indicated that this ratio would be higher for wind resources, specifically Type 3 wind.
26
See Day 2 Recording and Transcript of the Standards Committee & NERC Ride-through Technical Conference; Project 2020-02
Modifications to PRC-024 (Generator Ride-through) Related Files; posted September 18, 2024.
27
RELIABILITY | RESILIENCE | SECURITY
the technical conference, with the intent of addressing the Order No. 901 directives in a manner that is just,
reasonable, not unduly discriminatory or preferential, in the public interest, helpful to reliability, practical,
technically sound, technically feasible, and cost-justified.
RELIABILITY | RESILIENCE | SECURITY
Unofficial Comment Form
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on Project 2020-02 Modifications to PRC-024 (Generator Ride-through) by 8
p.m. Eastern, Monday, September 30, 2024.
Additional information is available on the project page. If you have questions, contact Director of
Standards Development, Jamie Calderon (email), or at 404-960-0568.
Background Information
The goal of Project 2020-02 is to mitigate the recent and ongoing disturbance ride-through performance
issues identified across multiple Interconnections and numbers of disturbances analyzed by NERC and the
Regions. These issues have been associated with Inverter-Based Resources (IBR) with many causes of their
tripping or cessation unrelated to voltage and frequency protection settings requirements in the currently
effective version of PRC-024 and PRC-024-3. Proposed Reliability Standard PRC-024-4 includes revisions to
limit its applicability to synchronous generators and synchronous condensers only and remains as a
protection-based standard. A new standard, PRC-029-1, is proposed as a true disturbance ride-through
Reliability Standard with applicability to inverter-based resources.
In October 2023, FERC issued Order No. 901, which directed NERC to develop new or modified existing
Reliability Standards that include new requirements for disturbance monitoring, data sharing, post-event
performance validation, and correction of IBR performance. Project 2020-02 was one of three projects
identified by NERC that must be completed and filed with FERC by November 4, 2024 to address Order
No. 901 directives. At the December 2023 Standards Committee (SC) meeting, the SC approved waivers
for Project 2020-02, allowing formal comment periods to be reduced from 45 days to 25 calendar days,
and final ballot periods to be reduced from 10 days to as few as 5 calendar days.
On August 15, 2024, the NERC Board of Trustees (Board) invoked Section 321 of the NERC Rules of
Procedure (ROP) to address critical and rapidly growing risk to the reliability of the Bulk Power System
associated with inverter-based resources (IBR) in response to FERC Order No. 901 directives. PRC-029-1
(Frequency and Voltage Ride-through Requirements for Inverter-based Resources) is a draft standard
designed to establish capability-based and performance-based Ride-through requirements for IBRs during
grid disturbances. The draft standard failed to achieve consensus from the Registered Ballot Body over
multiple ballots, calling into question whether development would be completed by FERC’s filing deadline
of November 4, 2024, which resulted in the Board acting under Section 321 of the ROP. Under this special
authority, the Board directed the SC to work with NERC to host a technical conference and to ballot an
additional ballot of PRC-029-1 within 45-days of the August 15 Board action.
RELIABILITY | RESILIENCE | SECURITY
Questions
1. Do you agree that the revisions accurately represent the changes discussed at the September
Standards Committee and NERC Ride-through Technical Conference?
Yes
No
Comments:
2. Provide any additional comments for consideration, if desired.
Comments:
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Unofficial Comment Form | September 2024
2
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1 – Frequency and Voltage Ride-through Requirements for
Inverter-based Generating Resources
General Rationale
The drafting team has created a new Reliability Standard (PRC-029-1) to address inverter-based resource
(IBR) disturbance Ride-through performance criteria. This proposal is a consequence of both the different
natures of synchronous and inverter-based generation resources and several recent events exhibiting
significant IBR Ride-through deficiencies1. The proposed PRC-029-1 aligns with certain Ride-through
requirements of IEEE Std 2800™, IEEE Standard for Interconnection and Interoperability of Inverter-Based
Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems, primarily for
frequency Ride-through, and is structured to follow language from FERC Order No. 901, which states that
“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
The lack of standardization of IBR performance and the software-based nature of the technologies has
created reliability challenges associated with the interconnection of IBR facilities to the power grid. The
nature of the fast switching of power electronics of IBR generation, IBR’s software-based nature, and the
electronic interface to the transmission system is such that disturbance Ride-through behavior is largely
determined by manufacturer-specific equipment and controls system designs. These controls may be
programmed, but also have more restrictive limits on current, both in magnitude and duration. IBR
responses to grid disturbances are highly controlled and managed by using fast switching of power
electronics devices dependent upon manufacturer specific control system design software that can be
programmed in many ways and with various and concurrent Ride-through performance objectives. Rather
than attempting to restrict the myriad of control approaches, protections, and settings, it is more
straightforward to require Ride-through during defined frequency and voltage excursions.
In contrast to synchronous generation, the need for IBR Ride-through requirements has been heightened
by recent events during which IBRs have not met PRC-024-3 frequency and voltage Ride-through
expectations, often due to controls and protection only indirectly associated with the system voltage and
frequency excursions. In addition to Ride-through, there is the question of what IBRs should be doing as
they Ride-through. IBR responses to system disturbances can be beneficial or detrimental to both their
own Ride-through and system reliability, often depending on adjustable control settings. Thus, it is
essential to set expectations on performance during Ride-through as well as Ride-through capability.
Event Reports (nerc.com)
P 195, FERC Order No. 901; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019-3157&optimized=false; October 17,
2023
1
2
RELIABILITY | RESILIENCE | SECURITY
A further reason for proposing a separate IBR standard is that the inertial and short circuit contributions
from IBR are significantly different than synchronous machines. The drafting team thinks that IBRs should
Ride through voltage and frequency excursions up to their maximum capability, while using expanded
voltage and frequency Ride-through criteria to drive those enhancements. These differences between
synchronous machines and IBR contribute to the differences in the frequency and voltage tables and
graphs between the PRC-024-4 and PRC-029-1 standards.
The proposed PRC-029-1 must be understood generally as an event-based standard though it is also
required to provide evidence of the ability to Ride-through disturbance events by means of dynamic
models and simulation results. Compliance with PRC-029-1 is determined chiefly, though not exclusively,
from IBR Ride-through performance during transmission system events in the field. An IBR becomes
noncompliant with PRC-029-1 when an event in the field occurs that shows that one or more
requirements were not satisfied. This intent is clarified by Operations Assessment as the Time Horizon
designation of requirements R1-R3.
FERC Order No. 901 Directives
PRC-029-1 is proposed in consideration of directives from FERC Order No. 901 that were assigned to the
Project 2020-02 drafting team. The following directives were assigned to this drafting team for inclusion in
this standards project (paragraph numbers of the FERC Order are included for reference):
•
Paragraph 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.”
•
Paragraph 190: “The new or modified Reliability Standards must require registered IBRs to
continue to inject current and perform frequency support during a Bulk-Power System
disturbance.”
•
Paragraph 190: “Any new or modified Reliability Standard must also require registered IBR
generator owners and operators to prohibit momentary cessation in the must Ride-through zone
during disturbances.”
•
Paragraph 190: “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.”
•
Paragraph 193: “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.”
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
2
•
Paragraph 193: “Further, we direct NERC to ensure that any such exemption would be applicable
for only existing equipment that is unable to meet voltage Ride-through 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.).”
•
Paragraph 193: “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).”
•
Paragraph 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, we direct NERC to
develop new or modified Reliability Standards to mitigate the reliability impacts to the Bulk-Power
System of such an exemption.”
•
Paragraph 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 pre-disturbance output level
in a quick and stable manner after a Bulk-Power System.”
•
Paragraph 209: “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 predisturbance levels during a disturbance, consistent with the IBR Interconnection Requirements
Guideline and Canyon 2 Fire Event Report recommendations.”
•
Paragraph 209: “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.”
•
Paragraph 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.”
•
Paragraph 226: “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 rule prior to
that date.” (pertains to multiple projects)
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
3
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for assuring acceptable Ride-through performance of IBR is the
Generator Owner.
Facilities (4.2)
Applicability Facilities include only IBR that also meet NERC registration criteria. Language used within
PRC-029-1 applicability only refers to IBR as a whole plant/facility. Consistent with FERC Order No. 901,
IBR performance is based on the overall IBR plant and disturbance monitoring equipment requirements
established under the proposed PRC-028-1. Requirements within PRC-029-1 do not apply to individual
inverter units or measurements taken at individual inverter unit terminals.
Rationale for Requirement R1
The objective of Requirement R1 is to ensure that all applicable IBRs will Ride-through grid voltage
disturbances consistent with the must Ride-through zone and operation regions specified in Attachment
1. IBRs must be able to demonstrate Ride-through performance, that they remain electrically connected,
i.e., shall not trip, and continue to exchange current, i.e., shall not enter momentary cessation.
The drafting team determined that the definition of “must Ride-through zones” and “operation regions”
should be consistent with those terms as used within IEEE 2800-2022. Additionally, the team determined
that the voltage thresholds of each operation region should be based on measurements taken on the
high-side of the main power transformer in PRC-029-1, also consistent with IEEE 2800-2022.
Battery Energy Storage Systems (BESS) units also must comply with Requirement R1 in all operating
modes including charging, discharging, and idle (energized, but not charging or discharging). A BESS in idle
mode must be capable of responding to system voltage and frequency excursions as it does in charging or
discharging modes.
Exceptions to Attachment 1 performance criteria are allowable when 1) an IBR needs to trip to clear a
fault, 2) voltage at the high-side of the main power transformer goes outside an accepted and a
documented hardware equipment limitation established in accordance with Requirement R4, 3)
instantaneous positive sequence voltage phase angle jumps more than 25 electrical degrees at the highside of the main power transformer initiated by a non-fault switching events occur on the transmission
system, or 4) volts per Hz (V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for
longer than 45 seconds or exceed 1.18 per unit for longer than 2 seconds.
When a grid disturbance occurs, such as a close-in fault or a relatively large switching event, the grid
voltage may experience a rapid phase angle shift. In such cases, the phase displacement Δθ can be large
enough to pose challenges for the phase lock loop (PLL) to track the terminal voltage, cause control
instability within the inverter, such as the inner current control loop or the DC link control loop, and even
lead to tripping of the inverter due to the malfunction of the controls.
Technical Rationale for Reliability Standard PRC-029-1
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4
Since phase angle jumps are common occurrences on the BPS, this standard requires the IBR to be
designed and operated to Ride-through a minimum phase angle jump of 25 electrical degrees. This is a
typical value and aligns with the requirement in IEEE 2800-2022.
Some IBR equipment has PLL loss of synchronism protection, referring to a protective function that
operates when the angle displacement Δθ exceeds a threshold for a predetermined period of time (on the
order of a couple of milliseconds). Historically, this protection has been used by some inverter
manufacturers, especially for inverters in distribution systems. For the IBR connected to the BPS, this
protection function should be disabled. If it is enabled, the phase angle jump protection setting should be
configured such that the IBR shall only trip to prevent equipment damage.
Rationale for Requirement R2
In addition to having minimum voltage Ride-through capability specified in Requirement R1, all applicable
IBRs are also required to adhere to certain voltage Ride-through performance criteria during system
disturbances. Acceptable performance criteria depend on the operation region that an IBR is presently in
or when in transition from one operation region to another operation region. Requirement R2 includes
specific performance criteria and is needed to assure consistent IBR performance within and each
operation region in Attachment 1 and when in transition between regions.
R ationale for R equirem ent R2.1
This subpart of Requirement R2 ensures that when the voltage at the high-side of the main power
transformer (MPT) recovers to the continuous operation region from either the mandatory operation
region or the permissive operation region, an IBR delivers the pre-disturbance level of Real Power or
available Real Power, whichever is less. Available Real Power allows for changes of facility Real Power
output attributed to factors such as weather patterns, change of wind, and change in irradiance, but not
changes attributed to IBR tripping in whole or part. This requires an IBR to exit the “High Voltage Ride
Through (HVRT)” or “Low Voltage Ridge Through (LVRT)” modes properly such that it does not cause
reduction in the Real Power when the high-side of MPT voltage recovers to within the continuous
operation region.
When the voltage at the high-side of the MPT is greater than 0.90 per-unit and less than 0.95 per-unit,
IBRs are expected to exit the LVRT mode and come back to “normal operating mode”. If an IBR has a
default total current limit of 1.0 per-unit, the apparent power production of an IBR will be limited below
1.0 per-unit (e.g., the per-unit value of IBR terminal voltage). In such case, the IBR needs to configure a
preference setting, either to maintain pre-disturbance Real Power or maximize the Reactive Power in
order to further help with voltage recovery, or according to requirements specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
R ationale for R equirem ent R2.2
This subpart of Requirement R2 ensures that when the voltage at the high-side of the MPT is within the
mandatory operation region, IBRs inject or absorb reactive current proportional to the level of terminal
voltage deviations they measure. IBRs shall follow Transmission Planner, Planning Coordinator, Reliability
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
5
Coordinator, or Transmission Operator specified certain magnitude of Reactive Power response to voltage
changes, if available.
By default, reactive current prioritization shall be configured unless Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator requires Real Power priority.
R ationale for R equirem ent R2.3
This subpart of Requirement R2 ensures that when the voltage at the high-side of the MPT is within the
permissive operation region, IBRs continue to Ride-through, though they are briefly allowed to enter the
current block mode if necessary to avoid tripping off from the grid. The drafting team takes into
consideration the physical operational capability of the power electronics devices under such low voltage
conditions. However, the IBR facility shall restart current exchange in less than or equal to five cycles of
positive sequence voltage returning to the continuous operation region or mandatory operation region. If
the interconnecting entity has performance requirements that are more stringent than the standard, the
Generator Owner should follow the requirements set by the interconnecting entity.
R ationale for R equirem ent R2.4
This subpart of Requirement R2 ensures when a fault is cleared on the transmission system, the voltage
regulators of connected IBRs must adjust the reactive current injection to restore the transmission system
voltage to the pre-disturbance voltage as defined by the automatic voltage regulator (AVR) setpoint. The
drafting team acknowledges that tuning of the AVR requires a balance between multiple competing
physical factors, e.g., rise time, overshoot, and transient stability. However, it is anticipated that IBR
controls will be tuned to allow for a stable post-disturbance voltage recovery without causing excessive
overshoot or undershoot of the setpoint. When such overshoots do occur, they must not exceed the
magnitude and duration of the applicable table given in Attachment 1. Furthermore, this standard
anticipates that control system tuning to prevent such over/under voltages will focus on the speed at
which the controller responds to setpoint changes rather than on the magnitude of the reactive current
response. For example, reductions in k-factor to prevent over/under voltages should only be considered
as a last resort.
R ationale for R equirem ent R2.5
This subpart of Requirement R2 ensures that the IBR returns to effective pre-disturbance operation unless
otherwise specified or needed by the Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator.
Rationale for Requirement R3
The objective of Requirement R3 is to ensure that IBRs Ride-through frequency excursion events with
magnitude and time durations as defined in Attachment 2.
Grid frequency reflects the balance of system generation and load. A system event that causes a
generation/load imbalance will cause system frequency to deviate from nominal. The system may
experience an over-frequency event (in the case of more generation than load) or an under-frequency
event (in the case of less generation than load). Inertia resists the deviation from nominal frequency,
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
6
giving the operators additional time to rebalance generation and load. With the current resource mix,
system inertia is dependent on the amount of rotating mass connected to the system (i.e., synchronous
generators or motors). The larger the system inertia, the slower the system frequency will deviate from
the nominal value and the lower the grid Rate Of Change Of Frequency (ROCOF), giving more time to try to
rebalance generation and load.
A reduction in system inertia is an inevitable consequence of a power system transiting toward more IBR
and less synchronous generators, however the utilization of IBR-specific control features (i.e., advanced
control modes and Grid Forming technologies) can provide additional stability benefits to help mitigate
the loss of inertia. As discussed in the previous paragraph, less system inertia means the frequency will
deviate from the nominal value more quickly during a generation/load imbalance event and will expose
the system to a higher ROCOF. A wider frequency Ride-through capability for IBR may be required to
avoid the risk of widespread tripping.
When considering an expansion of Ride-through capability, it is important to balance the expansion with
the feasibility of producing and installing equipment that can meet the newly proposed criteria. Failure to
adequately consider this could result in resource adequacy deficiencies if expanded criteria lead to
widespread non-compliance of legacy IBR due to hardware limitations. Further, for newly interconnecting
IBR, expanded Ride-through criteria often result in significant design changes that have production time
and cost implications. If proposed Ride-through criteria are too stringent and result in costly design
changes, those costs could result in a slowing of IBR penetration on the BPS.
For the reasons above, it is imperative that newly created Ride-through criteria are reasonable for both
BPS reliability and for the IBR equipment. To date, NERC has analyzed numerous major events including
both winter storms Uri and Elliot. No IBR tripped offline for frequency threshold criteria (because the
system frequency caused a trip due to exceeding equipment frequency limits) and all frequency-related
tripping observed were due to mis-parameterization or the use of instantaneous measurements in
protection schemes. Additionally, the deviations in frequency observed during the events listed above did
not exceed the PRC-024 criteria. It should be noted that winter storm Uri did produce a frequency
excursion extremely close to, and even touching, the criteria in PRC-024.
With no “benchmark events” to inform criteria expansions, studies could be used to assess future BPS
needs. These studies would need a detailed list of scenarios, including different IBR penetrations and load
levels, and are dependent on the ability to accurately model current and future IBR technologies,
including GFM functions. NERC has issued two level 2 alerts related to IBR, one on IBR performance and
the second on modeling. These alerts seek to obtain data from IBR while also giving recommendations to
mitigate the observed systemic modeling and performance deficiencies of IBR. Given these observed
deficiencies and the lack of recently conducted detailed system-wide studies, there is insufficient studybased evidence to inform widely expanded Ride-through criteria.
It is clear however that the performance of the BPS during disturbance will change as the IBR penetration
increases. How this performance will change can be predicted with detailed studies, but an incremental
Technical Rationale for Reliability Standard PRC-029-1
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7
approach to expanding Ride-through criteria adds additional stability margin while modeling deficiencies
are addressed and detailed studies are conducted.
The frequency Ride-through times and thresholds in IEEE 2800-2022 are more stringent (wider) than
those presently in PRC-024-3 and contain continuous operation ranges that exceed the frequency
excursions observed during major BPS disturbances. Detailed feedback from original equipment
manufacturers (OEM) provides insight that they are already designing IBR equipment that conforms with
the criteria in IEEE 2800-2022. For this reason, the frequency Ride-through criteria in the PRC-029
standard are in alignment with those criteria in IEEE 2800-2022, which provides an expansion of Ridethrough criteria compared to PRC-024 while also minimizing cost and timeline implications as OEM are
already designing conforming equipment.
Requirement R3 does not prescribe specific frequency protection settings for IBR equipment. IBR
frequency protection settings should only be set to protect the IBR from damage caused by operation at
off-nominal frequency. An IBR owner must ensure that the IBR frequency protection does not prevent an
IBR from meeting the R3 Ride-through requirement.
This standard requires that IBRs remain electrically connected and continue to exchange current during a
frequency excursion event in which the frequency remains within the must Ride-through zone according
to Attachment 3 and while the absolute ROCOF magnitude is less than or equal to 5 Hz/second. Some IBR
controllers and their ability to remain electrically connected and continue to exchange current with the
grid are sensitive to ROCOF, particularly auxiliary equipment that are essential for IBR performance,
during a frequency excursion event. If needed to maintain the stability of the IBR or prevent equipment
damage, the R3 requirement allows the IBR to trip for an absolute ROCOF exceeding 5Hz/sec within the
must Ride-through zone of Attachment 2. Failure to Ride-through due to ROCOF exceeding 5Hz/sec shall
only be allowed during a generator/load imbalance event that causes the frequency to deviate from
nominal.
To minimize the misoperation tripping of the IBR on the ROCOF setting, the rate of change of frequency
(ROCOF) must be calculated as the average rate of change over multiple calculated system frequencies for
some time greater than or equal to 0.1 seconds. The ROCOF calculation is not applicable during the fault
occurrence and clearance (i.e., protection should not trip due to any perceived ROCOF during the entire
disturbance and recovery period) and should not operate at the onset of a fault, during a fault, or at fault
clearance, i.e., it should be disabled during faults. The IBR shall Ride-through any system disturbance
while the voltage at the high-side of the main power transformer remains within the must Ride-through
zones as specified in Attachment 1. The ROCOF measurement should begin after fault clearance and is
only applicable for generation/load imbalance disturbances such as a system separation, an island
condition, or the loss of a large load or generator.
Rationale for Requirement R4
The objective of Requirement R4 is to ensure legacy IBR (IBR existing as of the enforcement date of PRC029-1) are able to obtain an exemption to the voltage and frequency Ride-through requirements if
hardware replacements or other costly upgrades would be necessary to comply with Requirements R1
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
8
through Requirement R3. This provision allows such exemptions as long as such limitations are
documented and communicated to the Planning Coordinator, Transmission Planner, Reliability
Coordinator, and Transmission Operator of the respective footprints in which the IBR project is located.
The Planning Coordinator, Transmission Planner, Reliability Coordinator, and Transmission Operator will
then need to take the voltage Ride-through limitations into account in planning and operations.
Limitations must not be construed as complete exemptions from the applicable tables, but must be
specific as to which voltage or frequency band(s) and associated duration(s) cannot be satisfied or specific
as to the number of cumulative voltage deviations within a ten-second time period that the equipment
can Ride-through if less than four. Limitation descriptions should identify the specific equipment and
explain the characteristic(s) of that equipment that prevent Ride-through. If any equipment limitation is
removed or otherwise corrected, it is likewise necessary to communicate to the Planning Coordinator,
Transmission Planner, Reliability Coordinator, and Transmission Operator of this.
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
9
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1 – Frequency and Voltage Ride-through Requirements for
Inverter-based Generating Resources
General Rationale
The drafting team has created a new Reliability Standard (PRC-029-1) to address inverter-based resource
(IBR) disturbance Ride-through performance criteria. This proposal is a consequence of both the different
natures of synchronous and inverter-based generation resources and several recent events exhibiting
significant IBR Ride-through deficiencies1. The proposed PRC-029-1 coincidesaligns with certain Ridethrough requirements of IEEE Std 2800-2022 but™, IEEE Standard for Interconnection and Interoperability
of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems,
primarily for frequency Ride-through, and is structured to follow language from FERC Order No. 901,
which states that “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
The lack of standardization of IBR technology (equipment/controller behavior)performance and the
software-based nature of the technologies has created reliability challenges associated with the
interconnection of IBR facilities to the power grid. The nature of the fast switching of power electronics of
IBR generation, IBR’s software-based nature, and the electronic interface to the transmission system is
such that disturbance Ride-through behavior is largely determined by manufacturer-specific equipment
and controls system designs. These controls may be programmed, but also have more restrictive limits on
current, both in magnitude and duration. IBR responses to grid disturbances are highly controlled and
managed by using fast switching of power electronics devices dependent upon manufacturer specific
control system design software that can be programmed in many ways and with various and concurrent
Ride-through performance objectives. Rather than attempting to restrict the myriad of control
approaches, protections, and settings, it is more straightforward to require Ride-through during defined
frequency and voltage excursions.
In contrast to synchronous generation, the need for IBR Ride-through requirements has been heightened
by recent events during which IBRs have not met PRC-024-3 frequency and voltage Ride-through
expectations, often due to controls and protection only indirectly associated with the system voltage and
frequency excursions. In addition to Ride-through, there is the question of what IBRs should be doing as
they Ride-through. IBR responses to system disturbances can be beneficial or detrimental to both their
own Ride-through and system reliability, often depending on adjustable control settings. Thus, it is
essential to set expectations on performance during Ride-through as well as Ride-through capability.
Event Reports (nerc.com)
P 195, FERC Order No. 901; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019-3157&optimized=false; October 17,
2023
1
2
RELIABILITY | RESILIENCE | SECURITY
A further reason for proposing a separate IBR standard is that IBRs do not provide inertia orthe inertial
and short circuit contributions, unlike from IBR are significantly different than synchronous machines. The
drafting team thinks that IBRs should compensate for their lack of inertia and short circuit contributions
with wider tolerances for Ride through voltage and frequency and voltage excursions. This is the reason
for up to their maximum capability, while using expanded voltage and frequency Ride-through criteria to
drive those enhancements. These differences between synchronous machines and IBR contribute to the
differences in the frequency and voltage tables and graphs between the PRC-024-4 and PRC-029-1
standards.
The proposed PRC-029-1 must be understood generally as an event-based standard though it is also
required to provide evidence of the ability to Ride-through disturbance events by means of dynamic
models and simulation results. Compliance with PRC-029-1 is determined chiefly, though not exclusively,
from IBR Ride-through performance during transmission system events in the field. An IBR becomes
noncompliant with PRC-029-1 when an event in the field occurs that shows that one or more
requirements were not satisfied. This intent is clarified by Operations Assessment as the Time Horizon
designation of requirements R1-R3.
FERC Order No. 901 Directives
PRC-029-1 is proposed in consideration of directives from FERC Order No. 901 that were assigned to the
Project 2020-02 drafting team. The following directives were assigned to this drafting team for inclusion in
this standards project (paragraph numbers of the FERC Order are included for reference):
•
Paragraph 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.”
•
Paragraph 190: “The new or modified Reliability Standards must require registered IBRs to
continue to inject current and perform frequency support during a Bulk-Power System
disturbance.”
•
Paragraph 190: “Any new or modified Reliability Standard must also require registered IBR
generator owners and operators to prohibit momentary cessation in the must Ride-through zone
during disturbances.”
•
Paragraph 190: “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.”
•
Paragraph 193: “Therefore, we direct NERC through its standard development process to
determine whether the new or modified Reliability Standards should provide for a limited and
Technical Rationale for Reliability Standard PRC-029-1
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2
documented exemption for certain registered IBRs from voltage ride through performance
requirements.”
•
Paragraph 193: “Further, we direct NERC to ensure that any such exemption would be applicable
for only existing equipment that is unable to meet voltage Ride-through 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.).”
•
Paragraph 193: “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).”
•
Paragraph 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, we direct NERC to
develop new or modified Reliability Standards to mitigate the reliability impacts to the Bulk-Power
System of such an exemption.”
•
Paragraph 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 pre-disturbance output level
in a quick and stable manner after a Bulk-Power System.”
•
Paragraph 209: “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 predisturbance levels during a disturbance, consistent with the IBR Interconnection Requirements
Guideline and Canyon 2 Fire Event Report recommendations.”
•
Paragraph 209: “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.”
•
Paragraph 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.”
•
Paragraph 226: “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
Technical Rationale for Reliability Standard PRC-029-1
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3
ensure an orderly industry transition for complying with the IBR directives in this final rule prior to
that date.” (pertains to multiple projects)
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for assuring acceptable Ride-through performance of IBR is either the
Generator Owner.
Facilities (4.2)
Applicability Facilities include only IBR that also meet NERC registration criteria. Language used within
PRC-029-1 applicability only refers to IBR as a whole plant/facility. Consistent with FERC Order No. 901,
IBR performance is based on the overall IBR plant and disturbance monitoring equipment requirements
established under the proposed PRC-028-1. Requirements within PRC-029-1 do not apply to individual
inverter units or measurements taken at individual inverter unit terminals.
Rationale for Requirement R1
The objective of Requirement R1 is to ensure that all applicable IBRs will Ride-through grid voltage
disturbances consistent with the must Ride-through zone and operation regions specified in Attachment
1. IBRs must be able to demonstrate Ride-through performance, that they remain electrically connected,
i.e., shall not trip, and continue to exchange current, i.e., shall not enter momentary cessation.
The drafting team determined that the definition of “must Ride-through zones” and “operation regions”
should be consistent with those terms as used within IEEE 2800-2022. Additionally, the team determined
that the voltage thresholds of each operation region should be based on measurements taken on the
high-side of the main power transformer in PRC-029-1, also consistent with IEEE 2800-2022.
Battery Energy Storage Systems (BESS) units also must comply with Requirement R1 in all operating
modes including charging, discharging, and idle (energized, but not charging or discharging). A BESS in idle
mode must be capable of responding to system voltage and frequency excursions as it does in charging or
discharging modes.
Exceptions to Attachment 1 performance criteria are allowable when 1) an IBR needs to trip to clear a
fault, 2) voltage at the high-side of the main power transformer goes outside an accepted and a
documented hardware equipment limitation established in accordance with Requirement R4, 3)
instantaneous positive sequence voltage phase angle jumps more than 25 electrical degrees at the highside of the main power transformer initiated by a non-fault switching events occur on the transmission
system, or 4) volts per Hz (V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for
longer than 45 seconds or exceed 1.18 per unit for longer than 2 seconds.
When a grid disturbance occurs, such as a close-in fault or a relatively large switching event, the grid
voltage may experience a rapid phase angle shift. In such cases, the phase displacement Δθ can be large
enough to pose challenges for the phase lock loop (PLL) to track the terminal voltage, cause control
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
4
instability within the inverter, such as the inner current control loop or the DC link control loop, and even
lead to tripping of the inverter due to the malfunction of the controls.
Since phase angle jumps are common occurrences on the BPS, this standard requires the IBR to be
designed and operated to Ride-through a minimum phase angle jump of 25 electrical degrees. This is a
typical value and aligns with the requirement in IEEE 2800-2022.
Some IBR equipment has PLL loss of synchronism protection, referring to a protective function that
operates when the angle displacement Δθ exceeds a threshold for a predetermined period of time (on the
order of a couple of milliseconds). Historically, this protection has been used by some inverter
manufacturers, especially for inverters in distribution systems. For the IBR connected to the BPS, this
protection function should be disabled. If it is enabled, the phase angle jump protection setting should be
configured such that the IBR shall only trip to prevent equipment damage.
Rationale for Requirement R2
In addition to having minimum voltage Ride-through capability specified in Requirement R1, all applicable
IBRs are also required to adhere to certain voltage Ride-through performance criteria during system
disturbances. Acceptable performance criteria depend on the operation region that an IBR is presently in
or when in transition from one operation region to another operation region. Requirement R2 includes
specific performance criteria and is needed to assure consistent IBR performance within and each
operation region in Attachment 1 and when in transition between regions.
R ationale for R equirem ent R2.1
This subpart of Requirement R2 ensures that when the voltage at the high-side of the main power
transformer (MPT) recovers to the continuous operation region from either the mandatory operation
region or the permissive operation region, an IBR delivers the pre-disturbance level of Real Power or
available Real Power, whichever is less. Available Real Power allows for changes of facility Real Power
output attributed to factors such as weather patterns, change of wind, and change in irradiance, but not
changes attributed to IBR tripping in whole or part. This requires an IBR to exit the “High Voltage Ride
Through (HVRT)” or “Low Voltage Ridge Through (LVRT)” modes properly such that it does not cause
reduction in the Real Power when the high-side of MPT voltage recovers to within the continuous
operation region.
When the voltage at the high-side of the MPT is greater than 0.90 per-unit and less than 0.95 per-unit,
IBRs are expected to exit the LVRT mode and come back to “normal operating mode”. If an IBR has a
default total current limit of 1.0 per-unit, the apparent power production of an IBR will be limited below
1.0 per-unit (e.g., the per-unit value of IBR terminal voltage). In such case, the IBR needs to configure a
preference setting, either to maintain pre-disturbance Real Power or maximize the Reactive Power in
order to further help with voltage recovery, or according to requirements specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
R ationale for R equirem ent R2.2
Technical Rationale for Reliability Standard PRC-029-1
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5
This subpart of Requirement R2 ensures that when the voltage at the high-side of the MPT is within the
mandatory operation region, IBRs inject or absorb reactive current proportional to the level of terminal
voltage deviations they measure. IBRs shall follow Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator specified certain magnitude of Reactive Power response to voltage
changes, if available.
By default, reactive current prioritization shall be configured unless Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator requires Real Power priority.
R ationale for R equirem ent R2.3
This subpart of Requirement R2 ensures that when the voltage at the high-side of the MPT is within the
permissive operation region, IBRs continue to Ride-through, though they are briefly allowed to enter the
current block mode if necessary to avoid tripping off from the grid. The drafting team takes into
consideration the physical operational capability of the power electronics devices under such low voltage
conditions. However, the IBR facility shall restart current exchange in less than or equal to five cycles of
positive sequence voltage returning to the continuous operation region or mandatory operation region. If
the interconnecting entity has performance requirements that are more stringent than the standard, the
Generator Owner should follow the requirements set by the interconnecting entity.
R ationale for R equirem ent R2.4
This subpart of Requirement R2 ensures when a fault is cleared on the transmission system, the voltage
regulators of connected IBRs must adjust the reactive current injection to restore the transmission system
voltage to the pre-disturbance voltage as defined by the automatic voltage regulator (AVR) setpoint. The
drafting team acknowledges that tuning of the AVR requires a balance between multiple competing
physical factors, e.g., rise time, overshoot, and transient stability. However, it is anticipated that IBR
controls will be tuned to allow for a stable post-disturbance voltage recovery without causing excessive
overshoot or undershoot of the setpoint. When such overshoots do occur, they must not exceed the
magnitude and duration of the applicable table given in Attachment 1. Furthermore, this standard
anticipates that control system tuning to prevent such over/under voltages will focus on the speed at
which the controller responds to setpoint changes rather than on the magnitude of the reactive current
response. For example, reductions in k-factor to prevent over/under voltages should only be considered
as a last resort.
R ationale for R equirem ent R2.5
This subpart of Requirement R2 ensures that the IBR returns to effective pre-disturbance operation unless
otherwise specified or needed by the Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator.
Rationale for Requirement R3
The objective of Requirement R3 is to ensure that IBRs Ride -through frequency excursion events with
magnitude and time durations as defined in Attachment 2.
Technical Rationale for Reliability Standard PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
6
Grid frequency reflects the balance of system generation and load. A system event that causes a
generation/load imbalance will cause system frequency to deviate from nominal. The system may
experience an over-frequency event (in the case of more generation than load) or an under-frequency
event (in the case of less generation than load). Inertia resists the deviation from nominal frequency,
giving the operators additional time to rebalance generation and load. System With the current resource
mix, system inertia dependsis dependent on the amount of rotating mass connected to the system (such
as thei.e., synchronous generators or motors). The larger the system inertia, the slower the system
frequency will deviate from the nominal value and the lower the grid Rate Of Change Of Frequency
(ROCOF), giving more time to try to rebalance generation and load. Also, higher system inertia may
minimize the risk of Cascading generation loss caused by the operation of generator frequency protection.
A reduction in system inertia is an inevitable consequence of a power system transiting toward more IBR
and less synchronous generators., however the utilization of IBR-specific control features (i.e., advanced
control modes and Grid Forming technologies) can provide additional stability benefits to help mitigate
the loss of inertia. As discussed in the previous paragraph, less system inertia means the frequency will
deviate from the nominal value more quickly during a generation/load imbalance event and will expose
the system to a higher ROCOF. A wider frequency Ride-through capability for IBR may be required to
avoid the risk of widespread tripping. To reduce the risk of widespread IBR tripping during frequency
disturbances, and more generally to ensure the reliability of future grids with high IBR penetration, the
drafting team proposes a 6-second frequency Ride-through capability requirement for frequencies in the
ranges of 61.8Hz to 64Hz or 57.0Hz to 56.0Hz range. The proposed 6-second time frame of the frequency
Ride-through capability requirement is beyond the IEEE 2800 standard frequency Ride-through
requirement and beyond frequency Ride-through requirements for synchronous machines under PRC024.
IBRs lack the inertia and short circuit contributions of synchronous machines. To compensate for the lack
of inertia and short circuit contributions, they should have wider tolerances for frequency and voltage
excursions to meet the needs of future power systems with a higher percentage of IBR. Synchronous
resources are more sensitive to frequency deviations than IBR resources. All IBR resources (except for
type 3 wind turbines) interface to the grid through fast switching of power electronics devices. These
power electronic devices are much less sensitive to the transmission system frequency excursion than
non-hydraulic turbine synchronous resources (steam turbines and combustion turbines). In the case of
the non-hydraulic turbine synchronous resources, the turbine is usually considered to be more restrictive
than the generator in limiting IBR frequency Ride-through because of possible mechanical resonances in
the many stages of turbine blades. Off-nominal frequencies may bring blade vibrational frequencies closer
to a mechanical resonate frequency and cause damage due to the vibration stresses. However, inverterinterfaced-IBR does not share this vibrational failure mode. Therefore, IBR should be capable of riding
through the increased proposed 6-second frequency Ride-through requirement without risk of equipment
damage or need for frequency protection to operate.
When considering an expansion of Ride-through capability, it is important to balance the expansion with
the feasibility of producing and installing equipment that can meet the newly proposed criteria. Failure to
adequately consider this could result in resource adequacy deficiencies if expanded criteria lead to
widespread non-compliance of legacy IBR due to hardware limitations. Further, for newly interconnecting
Technical Rationale for Reliability Standard PRC-029-1
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7
IBR, expanded Ride-through criteria often result in significant design changes that have production time
and cost implications. If proposed Ride-through criteria are too stringent and result in costly design
changes, those costs could result in a slowing of IBR penetration on the BPS.
For the reasons above, it is imperative that newly created Ride-through criteria are reasonable for both
BPS reliability and for the IBR equipment. To date, NERC has analyzed numerous major events including
both winter storms Uri and Elliot. No IBR tripped offline for frequency threshold criteria (because the
system frequency caused a trip due to exceeding equipment frequency limits) and all frequency-related
tripping observed were due to mis-parameterization or the use of instantaneous measurements in
protection schemes. Additionally, the deviations in frequency observed during the events listed above did
not exceed the PRC-024 criteria. It should be noted that winter storm Uri did produce a frequency
excursion extremely close to, and even touching, the criteria in PRC-024.
With no “benchmark events” to inform criteria expansions, studies could be used to assess future BPS
needs. These studies would need a detailed list of scenarios, including different IBR penetrations and load
levels, and are dependent on the ability to accurately model current and future IBR technologies,
including GFM functions. NERC has issued two level 2 alerts related to IBR, one on IBR performance and
the second on modeling. These alerts seek to obtain data from IBR while also giving recommendations to
mitigate the observed systemic modeling and performance deficiencies of IBR. Given these observed
deficiencies and the lack of recently conducted detailed system-wide studies, there is insufficient studybased evidence to inform widely expanded Ride-through criteria.
It is clear however that the performance of the BPS during disturbance will change as the IBR penetration
increases. How this performance will change can be predicted with detailed studies, but an incremental
approach to expanding Ride-through criteria adds additional stability margin while modeling deficiencies
are addressed and detailed studies are conducted.
The frequency Ride-through times and thresholds in IEEE 2800-2022 are more stringent (wider) than
those presently in PRC-024-3 and contain continuous operation ranges that exceed the frequency
excursions observed during major BPS disturbances. Detailed feedback from original equipment
manufacturers (OEM) provides insight that they are already designing IBR equipment that conforms with
the criteria in IEEE 2800-2022. For this reason, the frequency Ride-through criteria in the PRC-029
standard are in alignment with those criteria in IEEE 2800-2022, which provides an expansion of Ridethrough criteria compared to PRC-024 while also minimizing cost and timeline implications as OEM are
already designing conforming equipment.
Requirement R3 does not prescribe specific frequency protection settings for IBR equipment. IBR
frequency protection settings should only be set to protect the IBR from damage caused by operation at
off-nominal frequency. An IBR owner must ensure that the IBR frequency protection does not prevent an
IBR from meeting the R3 Ride-through requirement.
This standard requires that IBRs remain electrically connected and continue to exchange current during a
frequency excursion event in which the frequency remains within the must Ride-through zone according
Technical Rationale for Reliability Standard PRC-029-1
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8
to Attachment 3 and while the absolute ROCOF magnitude is less than or equal to 5 Hz/second. Some IBR
controllers and their ability to remain electrically connected and continue to exchange current with the
grid are sensitive to ROCOF, particularly auxiliary equipment that are essential for IBR performance,
during a frequency excursion event. If needed to maintain the stability of the IBR or prevent equipment
damage, the R3 requirement allows the IBR to trip for an absolute ROCOF exceeding 5Hz/sec within the
must Ride-through zone of Attachment 2. Failure to Ride-through due to ROCOF exceeding 5Hz/sec shall
only be allowed during a generator/load imbalance event that causes the frequency to deviate from
nominal.
To minimize the misoperation tripping of the IBR on the ROCOF setting, the rate of change of frequency
(ROCOF) must be calculated as the average rate of change over multiple calculated system frequencies for
some time greater than or equal to 0.1 seconds. The ROCOF calculation is not applicable during the fault
occurrence and clearance (i.e., protection should not trip due to any perceived ROCOF during the entire
disturbance and recovery period) and should not operate at the onset of a fault, during a fault, or at fault
clearance, i.e., it should be disabled during faults. The IBR shall Ride-through any system disturbance
while the voltage at the high-side of the main power transformer remains within the must Ride-through
zones as specified in Attachment 1. The ROCOF measurement should begin after fault clearance and is
only applicable for generation/load imbalance disturbances such as a system separation, an island
condition, or the loss of a large load or generator.
Rationale for Requirement R4
The objective of Requirement R4 is to ensure legacy IBR (IBR existing as of the enforcement date of PRC029-1) are able to obtain an exemption to the voltage and frequency Ride-through requirements if
hardware replacements or other costly upgrades would be necessary to comply with Requirements R1
orthrough Requirement R2R3. This provision allows such exemptions as long as such limitations are
documented and communicated to the Planning Coordinator, Transmission Planner, Reliability
Coordinator, and Transmission Operator of the respective footprints in which the IBR project is located.
The Planning Coordinator, Transmission Planner, Reliability Coordinator, and Transmission Operator will
then need to take the voltage Ride-through limitations into account in planning and operations.
Limitations must not be construed as complete exemptions from the applicable Attachment 1 tabletables,
but must be specific as to which voltage or frequency band(s) and associated duration(s) cannot be
satisfied or specific as to the number of cumulative voltage deviations within a ten-second time period
that the equipment can Ride-through if less than four. Limitation descriptions should identify the specific
equipment and explain the characteristic(s) of that equipment that prevent Ride-through. If any
equipment limitation is removed or otherwise corrected, it is likewise necessary to communicate to the
Planning Coordinator, Transmission Planner, Reliability Coordinator, and Transmission Operator of this.
FERC Order No. 901 states that this provision would be limited to exempting “certain registered IBRs from
voltage Ride-through performance requirements.” This is the reason that no similar provisions are
included for exemptions for frequency or ROCOF Ride-through requirements per R3.
Technical Rationale for Reliability Standard PRC-029-1
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Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1
This document provides the drafting team’s (DT’s) justification for assignment of violation risk factors (VRFs) and violation severity levels
(VSLs) for each requirement in PRC-029-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in the
Electric Reliability Organizations (ERO) Sanction Guidelines. The DT applied the following NERC criteria and FERC Guidelines when developing
the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Power System (BPS) instability, separation, or a cascading sequence
of failures, or could place the BPS at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning time
frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to BPS instability, separation, or a cascading sequence of failures, or could place the BPS at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the BPS, or the ability to effectively monitor and
control the BPS. However, violation of a medium risk requirement is unlikely to lead to BPS instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or restore
the BPS. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by
the preparations, to lead to BPS instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the BPS, or the ability to effectively monitor and control the BPS; or, a requirement that is administrative in nature and a
requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by
the preparations, be expected to adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or
restore the BPS.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the BPS. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the BPS:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
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Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the
requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for PRC-029-1, Requirement R1
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R1
Lower
Moderate
N/A
The Generator Owner failed to
ensure the design capability of
each applicable IBR to Ride-through
in accordance with Attachment 1,
except for those conditions
identified in Requirement R1.
High
N/A
Severe
The Generator Owner failed to
ensure each applicable IBR adhered
to Ride-through requirements in
accordance with Attachment 1,
except for those conditions
identified in Requirement R1.
VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
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VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
Definitions of VRFs
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R2
Lower
The Generator Owner failed to
ensure the design capability of
each applicable IBR to adhere to
performance requirements during
voltage excursions, as specified in
Requirement R2, unless a
documented hardware limitation
exists in accordance with
Requirement R4.
Moderate
N/A
High
N/A
Severe
The Generator Owner failed to
ensure each applicable IBR adhered
to performance requirements
during voltage excursions, as
specified in Requirement R2, unless
a documented hardware limitation
exists in accordance with
Requirement R4.
VSL Justifications for PRC-029-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
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VSL Justifications for PRC-029-1, Requirement R2
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R3
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is appropriate that if violated, it would be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R3
Lower
Moderate
The Generator Owner IBR to
N/A
ensure the design capability of
each applicable IBR to Ride-through
in accordance with Attachment 2,
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High
N/A
Severe
The Generator Owner IBR to
ensure each applicable IBR adhered
to Ride-through requirements in
accordance with Attachment 2,
10
unless a documented hardware
limitation exists in accordance with
Requirement R4.
unless a documented hardware
limitation exists in accordance with
Requirement R4.
VSL Justifications for PRC-029-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Each VSL is based on a single violation and not cumulative violations.
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VSL Justifications for PRC-029-1, Requirement R3
Number of Violations
VRF Justifications for PRC-029-1, Requirement R4
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R4
Lower
The Generator Owner provided a
copy to the applicable entities as
detailed in Requirement R4.2 more
than 12 months but less than or
equal to 15 months after the
effective date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 90 days but less than or
equal to 120 days after receiving a
request for additional information
by an entity listed in Requirement
R4.2.1.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 90 days but less than or
equal to 120 days after receiving
the acceptance of a hardware
limitation by the CEA.
OR
The Generator Owner with a
previously communicated
hardware limitation that replaces
Moderate
High
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 120 days but less than
or equal to 150 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 150 days but less than
or equal to 180 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
OR
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 120 days but less than
or equal to 150 days after receiving
the acceptance of a hardware
limitation by the CEA.
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 150 days but less than
or equal to 180 days after receiving
the acceptance of a hardware
limitation by the CEA.
OR
OR
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
120 calendar days but less than or
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
150 calendar days but less than or
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
Severe
The Generator Owner failed to
document complete information
for IBR identified with known
hardware limitations that prevent
the IBR from meeting Ride-through
criteria as detailed in Requirements
R1 or R2.
OR
The Generator Owner failed to
provide a copy to the applicable
entities as detailed in Requirement
R4.2 within 24 months after the
effective date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 180 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 180 days after receiving
the acceptance of a hardware
limitation by the CEA.
13
VSLs for PRC-029-1, Requirement R4
Lower
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),
Reliability Coordinator(s), and CEA
more than 90 calendar days but
less than or equal to 120 calendar
days after the change to the
hardware.
Moderate
equal to 150 calendar days after
the change to the hardware.
High
equal to 180 calendar days after
the change to the hardware.
Severe
OR
The Generator Owner failed to
document complete information
for IBR identified with known
hardware limitations that prevent
the IBR from meeting Ride-through
criteria as detailed in Requirements
R1 or R2.
VSL Justifications for PRC-029-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
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VSL Justifications for PRC-029-1, Requirement R4
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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15
Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1
This document provides the drafting team’s (DT’s) justification for assignment of violation risk factors (VRFs) and violation severity levels
(VSLs) for each requirement in PRC-029-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in the
Electric Reliability Organizations (ERO) Sanction Guidelines. The DT applied the following NERC criteria and FERC Guidelines when developing
the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Power System (BPS) instability, separation, or a cascading sequence
of failures, or could place the BPS at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning time
frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to BPS instability, separation, or a cascading sequence of failures, or could place the BPS at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the BPS, or the ability to effectively monitor and
control the BPS. However, violation of a medium risk requirement is unlikely to lead to BPS instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or restore
the BPS. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by
the preparations, to lead to BPS instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the BPS, or the ability to effectively monitor and control the BPS; or, a requirement that is administrative in nature and a
requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by
the preparations, be expected to adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or
restore the BPS.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the BPS. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the BPS:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
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2
Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the
requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for PRC-029-1, Requirement R1
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
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5
VSLs for PRC-029-1, Requirement R1
Lower
Moderate
N/A
The Generator Owner failed to
ensure the design capability of
each applicable IBR to Ride-through
in accordance with Attachment 1,
except for those conditions
identified in Requirement R1.
High
N/A
Severe
The Generator Owner failed to
ensure each applicable IBR adhered
to Ride-through requirements in
accordance with Attachment 1,
except for those conditions
identified in Requirement R1.
VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride-through system
disturbances. Failure to ride-through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
Similar requirements in PRC-024-3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
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VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
Definitions of VRFs
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R2
Lower
The Generator Owner failed to
ensure the design capability of
each applicable IBR to adhere to
performance requirements during
voltage excursions, as specified in
Requirement R2, unless a
documented hardware limitation
exists in accordance with
Requirement R4.
Moderate
N/A
High
N/A
Severe
The Generator Owner failed to
ensure each applicable IBR adhered
to performance requirements
during voltage excursions, as
specified in Requirement R2, unless
a documented hardware limitation
exists in accordance with
Requirement R4.
VSL Justifications for PRC-029-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
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VSL Justifications for PRC-029-1, Requirement R2
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R3
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is appropriate that if violated, it would be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R3
Lower
Moderate
The Generator Owner IBR to
N/A
ensure the design capability of
each applicable IBR to Ride-through
in accordance with Attachment 2,
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High
N/A
Severe
The Generator Owner IBR to
ensure each applicable IBR adhered
to Ride-through requirements in
accordance with Attachment 2,
10
unless a documented hardware
limitation exists in accordance with
Requirement R4.
unless a documented hardware
limitation exists in accordance with
Requirement R4.
VSL Justifications for PRC-029-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Each VSL is based on a single violation and not cumulative violations.
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VSL Justifications for PRC-029-1, Requirement R3
Number of Violations
VRF Justifications for PRC-029-1, Requirement R4
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub-requirement VRFs.
FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation
This requirement does not co-mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R4
Lower
The Generator Owner provided a
copy to the applicable entities as
detailed in Requirement R4.2 more
than 12 months but less than or
equal to 15 months after the
effective date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 90 days but less than or
equal to 120 days after receiving a
request for additional information
by an entity listed in Requirement
R4.2.1.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 90 days but less than or
equal to 120 days after receiving
the acceptance of a hardware
limitation by the CEA.
OR
The Generator Owner with a
previously communicated
hardware limitation that replaces
Moderate
High
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 120 days but less than
or equal to 150 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 150 days but less than
or equal to 180 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
OR
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 120 days but less than
or equal to 150 days after receiving
the acceptance of a hardware
limitation by the CEA.
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 150 days but less than
or equal to 180 days after receiving
the acceptance of a hardware
limitation by the CEA.
OR
OR
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
120 calendar days but less than or
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
150 calendar days but less than or
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Violation Risk Factors and Violation Severity Levels | September 2024
Severe
The Generator Owner failed to
document complete information
for IBR identified with known
hardware limitations that prevent
the IBR from meeting Ride-through
criteria as detailed in Requirements
R1 or R2.
OR
The Generator Owner failed to
provide a copy to the applicable
entities as detailed in Requirement
R4.2 within 24 months after the
effective date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 180 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 180 days after receiving
the acceptance of a hardware
limitation by the CEA.
13
VSLs for PRC-029-1, Requirement R4
Lower
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),
Reliability Coordinator(s), and CEA
more than 90 calendar days but
less than or equal to 120 calendar
days after the change to the
hardware.
Moderate
equal to 150 calendar days after
the change to the hardware.
High
equal to 180 calendar days after
the change to the hardware.
Severe
OR
The Generator Owner failed to
document complete information
for IBR identified with known
hardware limitations that prevent
the IBR from meeting Ride-through
criteria as detailed in Requirements
R1 or R2.
VSL Justifications for PRC-029-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
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VSL Justifications for PRC-029-1, Requirement R4
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-029-1
This document provides the drafting team’s (DT’s) justification for assignment of violation risk factors (VRFs) and violation severity levels
(VSLs) for each requirement in PRC‐029‐1. Each requirement is assigned a VRF and a VSL. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in the
Electric Reliability Organizations (ERO) Sanction Guidelines. The DT applied the following NERC criteria and FERC Guidelines when developing
the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Power System (BPS) instability, separation, or a cascading sequence
of failures, or could place the BPS at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning time
frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to BPS instability, separation, or a cascading sequence of failures, or could place the BPS at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the BPS, or the ability to effectively monitor and
control the BPS. However, violation of a medium risk requirement is unlikely to lead to BPS instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or restore
the BPS. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by
the preparations, to lead to BPS instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the BPS, or the ability to effectively monitor and control the BPS; or, a requirement that is administrative in nature and a
requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by
the preparations, be expected to adversely affect the electrical state or capability of the BPS, or the ability to effectively monitor, control, or
restore the BPS.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the BPS. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the BPS:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the
requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non‐compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for PRC-029-1, Requirement R1
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride‐through system
disturbances. Failure to ride‐through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
Similar requirements in PRC‐024‐3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R1
Lower
Moderate
N/A
The Generator Owner failed to
ensure the design capability of
each applicable IBR to Ride‐through
in accordance with Attachment 1,
except for those conditions
identified in Requirement R1.
High
Severe
N/A
The Generator Owner failed to
demonstrate ensure each
applicable IBR adhered to
Ride‐through requirements in
accordance with Attachment 1,
except for those conditions
identified in Requirement R1.
VSL Justifications for PRC-029-1, Requirement R1
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
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VSL Justifications for PRC-029-1, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
NERC VRF Discussion
A VRF of High is appropriate as applicable generating resources must be able to ride‐through system
disturbances. Failure to ride‐through has been documented in multiple NERC reports leading to exacerbated
system conditions, resulting in the electrical disconnecting of additional generation and widespread outages.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
Similar requirements in PRC‐024‐3 are identified as Medium but are based on equipment protection setting
documentation rather than actual, recorded performance during a grid disturbance. Therefore, this VRF is in
line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
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VRF Justifications for PRC-029-1, Requirement R2
Proposed VRF
High
Definitions of VRFs
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R2
Lower
The Generator Owner failed to
demonstrate ensure the design
capability of each applicable IBR to
adhere to performance
requirements during voltage
excursions, as specified in
Requirement R2, unless a
documented hardware limitation
exists in accordance with
Requirement R4.
Moderate
N/A
High
Severe
N/A
The Generator Owner failed to
demonstrate ensure each
applicable IBR adhered to
performance requirements during
voltage excursions, as specified in
Requirement R2, unless a
documented hardware limitation
exists in accordance with
Requirement R4.
VSL Justifications for PRC-029-1, Requirement R2
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
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VSL Justifications for PRC-029-1, Requirement R2
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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VRF Justifications for PRC-029-1, Requirement R3
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is appropriate that if violated, it would be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of High VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a High VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
VSLs for PRC-029-1, Requirement R3
Lower
The Generator Owner IBR to
demonstrate ensure the design
capability of each applicable IBR to
Ride‐through in accordance with
Moderate
N/A
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High
Severe
The Generator Owner IBR to
demonstrate ensure each
applicable IBR adhered to
Ride‐through requirements in
N/A
10
accordance with Attachment 2,
unless a documented hardware
limitation exists in accordance with
Requirement R4.
Attachment 2, unless a
documented hardware limitation
exists in accordance with
Requirement R4.
VSL Justifications for PRC-029-1, Requirement R3
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
FERC VSL G2
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Each VSL is based on a single violation and not cumulative violations.
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VSL Justifications for PRC-029-1, Requirement R3
Number of Violations
VRF Justifications for PRC-029-1, Requirement R4
Proposed VRF
Lower
NERC VRF Discussion
A VRF of Lower is appropriate that if violated, it would not be expected to adversely affect the electrical state or
capability of the BPS.
FERC VRF G1 Discussion
Guideline 1‐ Consistency with
Blackout Report
This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a
Reliability Standard
The assignment of Lower VRF is consistent with the VRF assignments for other requirements in the proposed
Reliability Standard. This requirement has only a main VRF and no different sub‐requirement VRFs.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among
Reliability Standards
This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC
Definitions of VRFs
This VRF is in line with the definition of a Lower VRF requirement per the criteria filed with FERC as part of the
ERO’s Sanctions Guidelines.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐mingle More
than One Obligation
This requirement does not co‐mingle a higher risk reliability objective and a lesser risk reliability objective.
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VSLs for PRC-029-1, Requirement R4
Lower
Moderate
High
Severe
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),
Reliability Coordinator(s), and CEA
more than 90 calendar days but
less than or equal to 120 calendar
days after the change to the
hardware.
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
120 calendar days but less than or
equal to 150 calendar days after
the change to the hardware.
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more than
150 calendar days but less than or
equal to 180 calendar days after
the change to the hardware.
The Generator Owner failed to
document complete information
for IBR identified with known
hardware limitations that prevent
the IBR from meeting Ride‐through
criteria as detailed in Requirements
R1, R2, or R32.
OR
OR
The Generator Owner provided a
copy to the applicable entities as
detailed in Requirement R4.2 more
than 15 months, but less than or
equal to 18 months after the
effective date of Requirement R4.
The Generator Owner provided a
copy to the applicable entities as
detailed in Requirement R4.2 more
than 18 months, but less than or
equal to 24 months after the
effective date of Requirement R4.
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),Reliability
Coordinator(s), and CEA more than
180 calendar days after the change
to the hardware.
OR
OR
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 120 days but less than
or equal to 150 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 150 days but less than
or equal to 180 days after receiving
a request for additional
information by an entity listed in
Requirement R4.2.1.
The Generator Owner failed to
provide a copy to the applicable
entities as detailed in Requirement
R4.2 within 24 months after the
effective date of Requirement R4.
OR
The Generator Owner provided a
copy to the applicable entities as
detailed in Requirement R4.2 more
than 12 months but less than or
equal to 15 months after the
effective date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.1
more than 90 days but less than or
equal to 120 days after receiving a
request for additional information
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OR
OR
13
VSLs for PRC-029-1, Requirement R4
Lower
by an entity listed in Requirement
R4.2.1.
OR
The Generator Owner failed to
respond to the applicable entities
as detailed in Requirement R4.2.2
more than 90 days but less than or
equal to 120 days after receiving
the acceptance of a hardware
limitation by the CEA.
OR
The Generator Owner with a
previously communicated
hardware limitation that replaces
the documented limiting hardware
but failed to document and
communicate the change to its
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),
Reliability Coordinator(s), and CEA
more than 90 calendar days but
less than or equal to 120 calendar
days after the change to the
hardware.
Moderate
OR
High
Severe
OR
The Generator Owner failed to
respond to the applicable entities
The Generator Owner failed to
The Generator Owner failed to
as detailed in Requirement R4.2.1
respond to the applicable entities
respond to the applicable entities
more than 180 days after receiving
as detailed in Requirement R4.2.2
as detailed in Requirement R4.2.2
a request for additional
more than 120 days but less than
more than 150 days but less than
or equal to 150 days after receiving or equal to 180 days after receiving information by an entity listed in
Requirement R4.2.1.
the acceptance of a hardware
the acceptance of a hardware
limitation by the CEA.
limitation by the CEA.
OR
OR
OR
The Generator Owner failed to
The Generator Owner with a
The Generator Owner with a
respond to the applicable entities
previously communicated
previously communicated
as detailed in Requirement R4.2.2
hardware limitation that replaces
hardware limitation that replaces
more than 180 days after receiving
the documented limiting hardware the documented limiting hardware the acceptance of a hardware
but failed to document and
but failed to document and
limitation by the CEA.
communicate the change to its
communicate the change to its
OR
Planning Coordinator(s),
Planning Coordinator(s),
Transmission Planner(s), Reliability Transmission Planner(s), Reliability The Generator Owner with a
previously communicated
Coordinator(s), Transmission
Coordinator(s), Transmission
hardware limitation that replace
Operator(s), and CEA more than
Operator(s), and CEA more than
120 calendar days but less than or 150 calendar days but less than or the documented limiting hardware
but failed to document and
equal to 150 calendar days after
equal to 180 calendar days after
communicate the change to its
the change to the hardware.
the change to the hardware.
Planning Coordinator(s),
Transmission Planner(s),
Transmission Operator(s),Reliability
Coordinator(s), and CEA more than
180 days after the change to the
hardware.
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VSL Justifications for PRC-029-1, Requirement R4
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of lowering
FERC VSL G1
Violation Severity Level Assignments the level of compliance.
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
Violation Severity Level Assignments consistency in the determination of similar penalties for similar violations.
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
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Standards Development Consideration of Directives from
FERC Order 901
June 2024
Background
The Federal Energy Regulatory Commission (FERC) issued Order No. 901 on October 19, 2023, which includes directives on new or modified NERC Reliability
Standard projects. Order No. 901 addresses a wide spectrum of reliability risks to the grid from the application of inverter-based resources (IBR); including
both utility scale and behind the-meter or distributed energy resources. Within the Order, are four milestones that include sets of directives to NERC. The
first milestone was achieved on January 17, 2024 as NERC filed its initial work plan to address all aspects of Order No. 901 throughout the next three years. 1
The filed work plan includes extensive detail on Standards Development approach and next steps to accomplish the suite of directives addressing IBR. The
work plan was intended to be an initial roadmap to guide development for each of the Reliability Standards Projects identified as a 901-related project.
This document includes specifics for how each directive assigned to Project 2020-02 Modifications to PRC-024 (Generator Ride-through) drafting team have
been addressed.
Resources
FERC Order No. 901 – Final Rule Reliability Standards to Address Inverter-Based Resources
NERC Mapping Document for FERC Order 901 Directives to Standards Development Projects, Draft SARs, and Pending SARs
1
INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901; 01/17/2024;
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%20901%20Work%20Plan_packaged%20%20public%20label.pdf
RELIABILITY | RESILIENCE | SECURITY
Index
Paragraph
Milestone
of Order
49
190
2
50
190
2
Directive Subpart Summary
“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 support
during a Bulk-Power System
disturbance.”
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
The new standard PRC-029-1 will require registered generator
owners of IBRs to both design and operate their IBR plants to ride
through voltage and frequency excursions within “must ridethrough zones” according to how these zones are defined in the
standard. The must ride-through zones are defined in terms of
voltage and frequency magnitude and time duration. Tripping of
IBR plants is permitted only outside of the defined must ridethrough zones. The voltage and frequency must ride-through
zones are based on IEEE 2800-2022 no-trip zones and are
established in view of experience with voltage and frequency
excursions in planning and operating criteria disturbances, underfrequency load shedding stages, reasonable and practical limits of
IBR voltage and frequency tolerances, PRC-024-3 voltage and
frequency relay setting graphs, and include adequate margins
against worst-case conditions that could be brought about during
system disturbances.
In association with the new PRC-029 standard, a definition of the
term ride-through is proposed for addition to the NERC Glossary of
Terms that essentially states that IBR facilities must remain
connected and continue to fulfill their established control and
regulation functions (which generally involve exchange of current)
in order to qualify as riding through system disturbances. Support
of frequency is predicated on, and to a large degree achieved by
the riding through of system disturbances.
Frequency regulation (or governing) is presently not a continentwide necessity and not a requirement on individual generating
2
Index
Paragraph
Milestone
of Order
51
190
2
52
190
2
53
193
2
Directive Subpart Summary
“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, postdisturbance ramp rates, phase
lock loop synchronization, and
other known causes of IBR
tripping or momentary
cessation.”
“Therefore, we direct NERC
through its standard
development process to
determine whether the new
or modified Reliability
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
plants/facilities in NERC standards. RTO/ISO requirements may
apply.
Momentary cessation, understood as inverter temporary current
blocking while still remaining connected, is restricted to only two
system conditions: 1) non-fault line switching caused voltage
phase angle jumps in excess of 25 degrees that could result in
tripping unless the inverter goes into current blocking, and 2)
while voltage at the plant-system interface is less than 0.10 per
unit during which time it may be difficult or impractical to
maintain current exchange.
IBR frequency and voltage ride through requirements are
established in the new PRC-029 standard as noted above. A
default post-disturbance ramp rate of 1.0 second is specified
unless a faster or slower rate is specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator to accommodate specific system postdisturbance recovery needs. Any Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator
specified ramp rate becomes the standard requirement. Tripping
due to phase lock loop loss of synchronism is specifically not
permitted within voltage and frequency must ride through zones.
Exemption from the voltage must ride-through zone requirement
of PRC-029-1 is permitted for IBR plants/facilities that are in
service at the enforcement date of the standard. The IBR
Generator Owner must document the need for an exemption and
the documentation must explain what hardware prevents the IBR
3
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
Standards should provide for a
limited and documented
exemption for certain
registered IBRs from voltage
ride through performance
requirements.”
54
193
2
“Further, we direct NERC to
ensure that any such
exemption would be
applicable for only existing
equipment that is unable to
meet voltage ride-through
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
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
from meeting the requirement and must be specific as to what
aspect of the voltage must ride-through zone cannot be met. The
Compliance Enforcement Authority checks that all aspects of the
documentation specified in the standard have been provided by
the GO and the GO is required to supply further information on
the need for and the nature of the exemption if requested by the
Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator. The implementation plan
provides a 12-month time window for exemption requests to be
submitted following the enforcement date. Following the 12month window, further exemption requests will either not be
accepted or could be considered an admission of non-compliance.
The exemption provision of PRC-029-1 is available only for IBR
plants/facilities that are in service at the enforcement date as
noted above. The exemption provision also stipulates that once
the plant/facility hardware causing the inability to comply with the
voltage must ride-through requirement is replaced, the exemption
is withdrawn (“no longer applies”).
4
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
through, phase lock loop,
ramp rates, etc.).”
55
193
2
“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).”
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
The exemption provision of PRC-029-1 requires an IBR Generator
Owner to supply its exemption request documentation to its
Transmission Planner, Planning Coordinator, Reliability
Coordinator, and Transmission Operator within the 12-month
window following the enforcement date as noted above.
5
Index
Paragraph
Milestone
of Order
56
199
2
57
208
2
Directive Subpart Summary
“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, we
direct NERC to develop new or
modified Reliability Standards
to mitigate the reliability
impacts to the Bulk-Power
System of such an
exemption.”
“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
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Description of How This Directive has Been Addressed
Mitigation of the reliability impacts of voltage must ride-through
exemptions are existing NERC standard responsibilities of
Transmission Planners, Planning Coordinators, Reliability
Coordinators, and Transmission Operators under TPL, IRO, TOP,
and other standards. These entities may need to restrict the
operation of exempted IBRs where and when their tripping may
result in detrimental reliability impacts.
As indicated above, a default post-disturbance ramp rate of 1.0
second is specified unless a faster or slower rate is specified by the
Transmission Planner, Planning Coordinator, Reliability
Coordinator, or Transmission Operator to accommodate specific
system post-disturbance recovery needs. Any Transmission
Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator specified ramp rate becomes the standard
requirement.
6
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
programmed to artificially
interfere with the resource
returning to a pre-disturbance
output level in a quick and
stable manner after a BulkPower System.”
59
209
2
60
209
2
“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-
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Description of How This Directive has Been Addressed
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
Phase lock loop loss of synchronism is not allowed as a cause of
tripping while voltage remains within the must ride-through zone
unless there are phase jumps more than 25 degrees caused by
non-fault switching events. A footnote under R1 also specifically
states that phase lock loop loss of synchronism as not a
permissible condition for tripping while voltage remains within the
must ride-through zone.
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
As indicated above, tripping due to phase lock loop loss of
synchronism is specifically not permitted within voltage and
frequency must ride-through zones. The requirement to return to
pre-disturbance power also includes a provision for return to
“available active power" to allow for “changes of facility
active power output attributed to factors such as weather
patterns, change of wind, and change in irradiance,” but
“changes of facility active power attributed to IBR tripping in
7
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
Power System at predisturbance levels during a
disturbance, consistent with
the IBR Interconnection
Requirements Guideline and
Canyon 2 Fire Event Report
recommendations.”
61
209
2
63A
226
2
“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.”
“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
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
Description of How This Directive has Been Addressed
whole or part” are not permitted. Injecting current at predisturbance levels during a disturbance is not always
practical or desirable. PRC-029-1 R2 specifies IBR required
active and reactive power performance during voltage
disturbances.
Project 2020-02
Modifications to
PRC-024
(Generator Ridethrough)
IBRs are non-synchronous but can exhibit forms of instability other
than loss of synchronism. System stability is a shared responsibility
of Transmission Planners, Planning Coordinators, Reliability
Coordinators, and Transmission Operators. IBR generation levels
may need to be restricted by these entities to maintain system
stability including IBR stability.
Each of the
identified
Reliability
Standards Projects
in Milestone 2 will
include
implementation
plans that assure
The PRC-029-1 implementation is a staggered implementation
beginning twelve months following governmental approval with
enforcement of all provisions within the twelve months following
approval except as necessary to coordinate with the PRC-028-1
implementation plan that extends to 2030.
8
Index
Paragraph
Milestone
of Order
Directive Subpart Summary
sequentially stagger the
effective and enforceable
dates to ensure an orderly
industry transition for
complying with the IBR
directives in this final rule
prior to that date.”
Standards Development Consideration of Directives from FERC Order 901
Active Project #
Draft SAR # or
Pending SAR
name
all new or
modified
Reliability
Standards are
effective and
enforceable
before 2030.
Description of How This Directive has Been Addressed
9
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough)
Formal Comment Period Open through September 30, 2024
Now Available
A formal comment period for PRC-029-1 - Frequency and Voltage Ride-through Requirements for
Inverter-based Resources, is open through 8 p.m. Eastern, Monday, September 30, 2024.
On August 15, 2024, the NERC Board of Trustees (Board) invoked Section 321 of the NERC Rules of
Procedure (ROP) to address critical and rapidly growing risk to the reliability of the Bulk Power
System associated with inverter-based resources (IBR) in response to FERC Order No. 901 directives.
PRC-029-1 (Frequency and Voltage Ride-through Requirements for Inverter-based Resources) is a
draft standard designed to establish capability-based and performance-based Ride-through
requirements for IBRs during grid disturbances. The draft standard failed to achieve consensus from
the Registered Ballot Body over multiple ballots, calling into question whether development would
be completed by FERC’s filing deadline of November 4, 2024, which resulted in the Board acting
under Section 321 of the ROP. Under this special authority, the Board directed the Standards
Committee to work with NERC to host a technical conference and to ballot an additional ballot of
PRC-029-1 within 45-days of the August 15 Board action.
The Standards Committee approved waivers to the Standard Processes Manual at their December
2023 meeting. These waivers were sought by NERC Standards staff for reduced formal comment and
ballot periods. This will assist the drafting teams in expediting the standards development process
due to firm timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket
No. RM22-12-000 on October 19, 2023.
Note: PRC-024-4 passed the recent additional ballot (conducted June 28 – July 8, 2024). This
standard will move to a final ballot when the PRC-029-1 ballots open (September 24-30, 2024) as
only non-substantive revision(s) were made.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
RELIABILITY | RESILIENCE | SECURITY
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
Additional ballots for the standard and implementation plan, as well as the non-binding polls of the
associated Violation Risk Factors and Violation Severity Levels will be conducted September 24-30,
2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Director of Standards Development, Jamie Calderon (via email)
or at 404-960-0568. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
(Generator Ride-through) observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
2
Comment Report
Project Name:
2020-02 Modifications to PRC-024 (Generator Ride-through) | Draft 4 - PRC-029-1
Comment Period Start Date:
9/17/2024
Comment Period End Date:
10/4/2024
Associated Ballots:
2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan AB 4 OT
2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 AB 4 ST
There were 58 sets of responses, including comments from approximately 150 different people from approximately 100 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
Questions
1. Do you agree that the revisions accurately represent the changes discussed at the September Standards Committee and NERC Ridethrough Technical Conference?
2. Provide any additional comments for consideration, if desired.
Organization
Name
MRO
Name
Anna
Martinson
Segment(s)
1,2,3,4,5,6
Region
MRO
Group Name
MRO Group
Group
Member
Name
Group
Group
Member
Member
Organization Segment(s)
Group
Member
Region
Shonda
McCain
Omaha Public 1,3,5,6
Power District
(OPPD)
MRO
Michael
Brytowski
Great River
Energy
1,3,5,6
MRO
Jamison
Cawley
Nebraska
Public Power
District
1,3,5
MRO
Jay Sethi
Manitoba
Hydro (MH)
1,3,5,6
MRO
Husam AlHadidi
Manitoba
1,3,5,6
Hydro
(System
Preformance)
MRO
Kimberly
Bentley
Western Area 1,6
Power
Adminstration
MRO
Jaimin Patal
Saskatchewan 1
Power
Coporation
(SPC)
MRO
George Brown Pattern
5
Operators LP
MRO
Larry Heckert Alliant Energy 4
(ALTE)
MRO
Terry Harbour MidAmerican
Energy
Company
(MEC)
1,3
MRO
Dane Rogers
Oklahoma
Gas and
Electric
(OG&E)
1,3,5,6
MRO
Seth
Shoemaker
Muscatine
Power &
Water
1,3,5,6
MRO
Michael
Ayotte
ITC Holdings
1
MRO
Andrew
Coffelt
Board of
1,3,5,6
Public
UtilitiesKansas (BPU)
MRO
Peter Brown
WEC Energy Christine
Group, Inc.
Kane
3
Dane Rogers Dane
Rogers
ACES Power Jodirah
Marketing
Green
5,6
MRO
Angela Wheat Southwestern 1
Power
Administration
MRO
Bobbi Welch
Midcontinent
ISO, Inc.
2
MRO
Joshua
Phillips
Southwest
Power Pool
2
MRO
Patrick Tuttle
Oklahoma
Municipal
Power
Authority
4,5
MRO
WEC Energy Christine
Group
Kane
WEC Energy
Group, Inc.
3
RF
Michelle
Hribar
WEC Energy
Group, Inc.
5
RF
David
Boeshaar
WEC Energy
Group, Inc.
6
RF
Candace
Morakinyo
WEC Energy
Group, Inc.
4
RF
Terri Pyle
OGE Energy - 1
Oklahoma
Gas and
Electric Co.
MRO
Donald
Hargrove
OGE Energy - 3
Oklahoma
Gas and
Electric Co.
MRO
Patrick Wells
OGE Energy - 5
Oklahoma
Gas and
Electric Co.
MRO
Ashley F
Stringer
OGE Energy - 6
Oklahoma
Gas and
Electric Co.
MRO
OG&E
1,3,4,5,6
Invenergy
MRO,NPCC,RF,SERC,Texas ACES
Bob Soloman Hoosier
RE,WECC
Collaborators
Energy
Electric
Cooperative
1
RF
1
MRO
Kevin Lyons
Central Iowa
Power
Cooperative
Kris Carper
Arizona
1
Electric Power
WECC
Cooperative,
Inc.
Eversource
Energy
Joshua
London
1
Eversource
FirstEnergy - Mark Garza 4
FirstEnergy
Corporation
Southern
Pamela
Company Hunter
Southern
Company
Services, Inc.
1,3,5,6
FE Voter
SERC
Southern
Company
Jason
Procuniar
Buckeye
Power, Inc.
4
RF
Jolly Hayden
East Texas
Electric
Cooperative,
Inc.
NA - Not
Applicable
Texas RE
Joshua
London
Eversource
Energy
1
NPCC
Vicki O'Leary
Eversource
Energy
3
NPCC
Julie Severino FirstEnergy FirstEnergy
Corporation
1
RF
Aaron
Ghodooshim
FirstEnergy FirstEnergy
Corporation
3
RF
Robert Loy
FirstEnergy FirstEnergy
Solutions
5
RF
Mark Garza
FirstEnergyFirstEnergy
1,3,4,5,6
RF
Stacey
Sheehan
FirstEnergy FirstEnergy
Corporation
6
RF
Matt Carden
Southern
1
Company Southern
Company
Services, Inc.
SERC
Joel
Dembowski
Southern
Company Alabama
Power
Company
3
SERC
Ron Carlsen
Southern
Company Southern
Company
Generation
6
SERC
Leslie Burke
Southern
Company Southern
Company
Generation
5
SERC
Black Hills
Corporation
Northeast
Power
Coordinating
Council
Rachel
Schuldt
Ruida Shu
6
1,2,3,4,5,6,7,8,9,10 NPCC
Black Hills
Travis
Corporation - Grablander
All Segments Josh Combs
NPCC RSC
Black Hills
Corporation
1
WECC
Black Hills
Corporation
3
WECC
Rachel
Schuldt
Black Hills
Corporation
6
WECC
Carly Miller
Black Hills
Corporation
5
WECC
Sheila
Suurmeier
Black Hills
Corporation
5
WECC
Gerry Dunbar Northeast
Power
Coordinating
Council
10
NPCC
Deidre Altobell Con Edison
1
NPCC
Michele
Tondalo
United
Illuminating
Co.
1
NPCC
Stephanie
UllahMazzuca
Orange and
Rockland
1
NPCC
Michael
Ridolfino
Central
1
Hudson Gas &
Electric Corp.
NPCC
Randy
Buswell
Vermont
1
Electric Power
Company
NPCC
James Grant
NYISO
2
NPCC
Dermot Smyth Con Ed 1
Consolidated
Edison Co. of
New York
NPCC
David Burke
Orange and
Rockland
3
NPCC
Peter Yost
Con Ed 3
Consolidated
Edison Co. of
New York
NPCC
Salvatore
Spagnolo
New York
Power
Authority
1
NPCC
Sean Bodkin
Dominion Dominion
Resources,
Inc.
6
NPCC
David Kwan
Ontario Power 4
Generation
NPCC
Silvia Mitchell NextEra
1
Energy Florida Power
and Light Co.
NPCC
Sean Cavote
PSEG
4
NPCC
Jason
Chandler
Con Edison
5
NPCC
Tracy
MacNicoll
Utility
Services
5
NPCC
Shivaz
Chopra
New York
Power
Authority
6
NPCC
Vijay Puran
New York
6
State
Department of
Public Service
NPCC
David Kiguel
Independent
7
NPCC
Joel
Charlebois
AESI
7
NPCC
Joshua
London
Eversource
Energy
1
NPCC
Jeffrey
Streifling
NB Power
Corporation
1,4,10
NPCC
Joel
Charlebois
AESI
7
NPCC
John Hastings National Grid
1
NPCC
Erin Wilson
NB Power
1
NPCC
James Grant
NYISO
2
NPCC
Michael
Couchesne
ISO-NE
2
NPCC
Kurtis Chong
IESO
2
NPCC
Michele
Pagano
Con Edison
4
NPCC
Bendong Sun Bruce Power
4
NPCC
Carvers
Powers
5
NPCC
7
NPCC
Hydro Quebec 1
NPCC
Utility
Services
Wes Yeomans NYSRC
Chantal
Mazza
Nicolas
Turcotte
Dominion Dominion
Resources,
Inc.
Sean
Bodkin
Western
Electricity
Coordinating
Council
Steven
Rueckert
Tim Kelley
Tim Kelley
6
Dominion
10
WECC
WECC
SMUD and
BANC
Hydro Quebec 2
NPCC
Victoria Crider Dominion
Energy
3
NA - Not
Applicable
Sean Bodkin
Dominion
Energy
6
NA - Not
Applicable
Steven Belle
Dominion
Energy
1
NA - Not
Applicable
Barbara
Marion
Dominion
Energy
5
NA - Not
Applicable
Steve
Rueckert
WECC
10
WECC
Curtis Crews
WECC
10
WECC
Nicole Looney Sacramento
Municipal
Utility District
3
WECC
Charles
Norton
Sacramento
Municipal
Utility District
6
WECC
Wei Shao
Sacramento
Municipal
Utility District
1
WECC
Foung Mua
Sacramento
Municipal
Utility District
4
WECC
Nicole Goi
Sacramento
Municipal
Utility District
5
WECC
Kevin Smith
Balancing
Authority of
Northern
California
1
WECC
1. Do you agree that the revisions accurately represent the changes discussed at the September Standards Committee and NERC Ridethrough Technical Conference?
Jeffrey Streifling - NB Power Corporation - 1
Answer
No
Document Name
Comment
The broad alignment of the technical requirements of PRC-029-1 with IEEE-2800-2022 represents the changes discussed at the NERC Ride-through
Technical Conference; however, the wording of Footnote 10 to Tables 1 and 2 in Attachment 1 of PRC-029-1 Draft 4 appears to disallow the subcycle
transient overvoltage tripping permitted in Section 7.2.3 and Figure 11 of IEEE 2800-2022 in a manner that could unnecessarily complicate the process
of overvoltage coordination.
Likes
0
Dislikes
0
Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
No
Document Name
Comment
See FirstEnergy's Q2 response.
We feel there are still unclear intentions and obligations under this standard.
Likes
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
No
Document Name
Comment
Dominion Energy’s view is that the Technical Conference reinforced stakeholder comments from the multiple previous comment periods for this project,
which generally noted that an exception process was necessary due to the technical infeasibility of implementing the prescribed ride through criteria on
existing inverters. The common theme at the technical conference was that OEMs need sufficient time periods to design, engineer, and produce
equipment that is compliant with new regulatory requirements. OEMs stated that they are currently in the process of integrating IEEE2800-2022 criteria
into devices, but that this process takes on average five years or more. Accordingly, it is unclear when PRC-029-1-compliant devices will become
commercially available. While Dominion Energy supports Project 2020-02’s goal of mitigating disturbance ride-through performance issues, Generator
Owners that are developing public policy mandated, reliability-enhancing, clean energy projects will not have a path to compliance until PRC-029-1
compliant devices become commercially available.
Dominion Energy recognizes the positive changes made by NERC staff in the current version of PRC-029-1, however, the new limited exceptions
process for commissioned IBR devices does not address projects that are in active development, with already contracted inverters that are not
technically capable of meeting the proposed PRC-029-1 criteria. For IBR projects with extended lead times, like large offshore wind projects, equipment
was contracted for and designed multiple years ago and may not be commissioned until after the effective date of the proposed PRC-029-1. NERC’s
failure to address this technical feasibility issue in the current draft could result in large amounts of clean, reliable energy that has been mandated by
public policy being put at risk.
Dominion Energy recommends that the NERC Board of Trustees adhere to its Section 321 mandate, which it exercised for this proposed Standard, and
remand PRC-029-1 back for further revisions so that it can approve a version that, as required under Section 321, subsection 5.2, “is just, reasonable,
not unduly discriminatory or preferential, and in the public interest, considering (among other things) whether it is practical, technically sound, technically
feasible, cost-justified and serves the best interests of reliability of the Bulk Power System,…”.
To achieve this goal, Dominion Energy recommends expanding the exception criteria set forth in Requirement 4 to include IBRs that are already
contracted. Additionally, until PRC-029-1 compliant devices are readily available commercially for the applicable project (e.g. Solar vs. Wind),
exceptions should be permitted for these projects.
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Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
No
Document Name
Comment
Black Hills Corporation agrees with both NAGF and EEI, in that: PRC-029 Draft 4 does not address important concerns identified during the Technical
Conference regarding software limits, balance of plant equipment issues, and the need to consider exemptions for IBR facilities that are in the
procurement process (i.e. “in flight”). Additionally, we are concerned that Requirement R4 overlooks the impacts to GOs who are developing large,
multi-year IBR projects that may not be completed by the effective date of this Reliability Standard. Resource equipment specifications are typically
locked down at the time the interconnection agreement is signed, and a change in requirements/specifications after that point can require changes in
the design of the equipment that are impossible to achieve without triggering a material modification, resulting in interconnection restudies and delaying
or potentially canceling the project
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Michael Goggin - Grid Strategies LLC - 5
Answer
No
Document Name
Comment
1. We appreciate the two significant changes in the latest draft of PRC-029-1: revision of R3 and R4 to add a hardware limitation exemption from
frequency ride-through requirements for existing resources, and adoption of frequency ride-through curves in Attachment 2 that properly balance
reliability needs with the capabilities of IBRs. As explained at length in the discussion of R3 in the updated Technical Rationale document, these
changes properly balance reliability needs by ensuring resources will ride through disturbances while also avoiding resource adequacy concerns that
could result from unnecessarily stringent requirements forcing the premature retirement of existing IBRs or preventing new IBRs from
interconnecting.{C}[1] Retention of those two changes is essential for this standard to be workable, and for it to improve and not impede electric
reliability. Because those two changes significantly improve the standard, we are voting for the revised standard, with the ask that the important
clarifications and changes to the Implementation Plan discussed below be made. These changes are necessary to address serious concerns that were
raised at the September 4-5, 2024, Ride-through Technical Conference regarding the effective date of the Standard and the evidence requirements for
demonstrating a hardware limitation. These concerns are not adequately addressed in the current draft of the Standard or Implementation Plan.
2. We are seriously concerned that the revision to R4 we have requested in all three PRC-029-1 comment periods has not been adopted: R4 should
allow hardware limitation exemptions for IBRs that have signed interconnection agreements, and not just IBRs that are in-service, as of the effective
date of the standard. This change is needed because resource equipment decisions are typically locked down at the time the interconnection
agreement is signed, and a change in requirements after that point can require a costly change in equipment or settings that may also trigger a material
modification and resulting interconnection restudies. In certain cases, the IBR performance requirements referenced in the fully executed
interconnection agreement contradict the NERC PRC-029 requirements.
The Implementation Plan for PRC-029 indicates that the effective date for the Standard will be the first day of the first quarter twelve months after FERC
approval. Many resources take significantly longer than that to move from a signed interconnection agreement to being placed in service, so R4 should
allow equipment limitation exemptions for resources that have a signed interconnection agreement as of the effective date of the Standard. This
concern is explained at greater length in the comments Orsted submitted in this formal comment period on September 20, 2024.
This need can be most directly addressed by revising the first sentence of R4 to read “Each Generator Owner identifying an IBR that has signed a
Generator Interconnection Agreement by the effective date of PRC‐029‐1…,” with the bolded language above replacing “is in-service.”
Alternatively, if NERC believes that there is no time for revisions to the draft of PRC-029-1, the Implementation Plan can be revised to make the
effective date 48 months after regulatory approval of PRC-029-1 (and 36 months after the effective date for other BES resources) for offshore wind and
other resources that can demonstrate that they require a long lead time between when equipment is procured and the plant is brought into service,
instead of 12 months after regulatory approval as proposed for all BES resources in the Implementation Plan. The current draft of the Implementation
Plan already proposes different compliance dates for BES and non-BES resources, so adding a third category for offshore wind and other Bulk Electric
System IBRs with a long lead time for plant completion should not cause concern.
This change can be incorporated by adding language similar to the following in the Implementation Plan under the heading PRC-029-1 Phased-in
Compliance Dates: “Offshore wind and other Bulk Electric System IBRs with a long lead time for plant completion: Entities shall comply with the
portion of Requirements R1, R2, and R3 relating to the design of their BES IBRs to meet the requirements by 36 months after the effective date of the
standard.”
In light of the significant improvements in this draft standard, and to draw attention to this important unresolved issue that can be addressed by revising
the Implementation Plan, we are voting for the proposed standard but against the Implementation Plan.
We would note that the Implementation Plan needs revision anyway, due to the apparently inadvertent inclusion of the following section at the end of
the document. This section is inconsistent with the revision of the standard to include a hardware exemption from frequency ride-through requirements
for existing resources, and thus should be removed or significantly revised:
Equipment Limitations and Process for Requirement R4
Consistent with FERC Order No. 901, a limited and documented exemption for some legacy IBR with certain documented equipment limitations are
acceptable. Per the Order, these IBRs are
“…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.”
To ensure compliance with Requirement R4 and alignment with FERC Order No. 901, only those IBR that are in operation as of the effective date of
PRC-029-1 may be considered for potential exemption. Further, only those IBR that are unable to meet voltage ride-through requirements due to their
inability to modify their coordinated protection and control settings may be considered for potential exemption.
3. NERC should clarify that existing equipment that has received an exemption from ride-through requirements due to a hardware limitation will not lose
that exemption if separate new equipment is added at that plant. For example, adding a battery to an existing solar or wind plant that has received a
hardware limitation exemption would not remove the exemption for the existing solar or wind equipment, though the new battery and its associated
power conversion equipment would not be exempt from PRC-029-1’s ride-through requirements. In that example, the existing wind or solar equipment
would only lose the exemption if it and its associated power conversion equipment were replaced with new equipment. If NERC adopts the solution
proposed above to revise the first sentence of R4 PRC-029-1 to allow hardware limitation exemptions for IBRs that have signed interconnection
agreements (and not just IBRs that are in-service) as of the effective date of the standard, it must also clarify that a subsequent amendment to the
interconnection agreement to allow the addition of separate new equipment does not remove the exemption for the existing equipment. These
clarifications are important to ensure that PRC-029-1 does not impede the addition of separate new equipment at existing sites to expand their
capability to provide energy, capacity, and other reliability services. If a revision to PRC-029-1 is not feasible at this point, an addition to the
Implementation Plan or issuance of a Compliance Guidance document could help clarify this point.
4. As documented in Section C of the comments Orsted submitted in this formal comment period on September 20, 2024, additional clarification and
consideration is needed to respect hardware limitations that may prevent both new HVDC- and AC-connected offshore wind plants from meeting some
aspects of PRC-029-1. The proposal above to provide offshore wind and other long lead-time resources 48 months following regulatory approval to
meet PRC-029-1 may not provide sufficient time for the offshore wind industry to develop technology solutions to meet these aspects of the PRC-029-1
requirements, so additional consideration for these hardware limitations will likely be needed. While offshore wind manufacturers are working to improve
ride-through capability to meet IEEE 2800 and PRC-029-1, at least some new HVDC-connected offshore wind plants cannot meet the cumulative
voltage ride-through requirements because consecutive fault events can overheat the DC chopper, posing a safety concern. Similarly, some ACconnected IBRs cannot meet the voltage or frequency ride-through requirements because the plants include synchronous condensers, which are
designed to meet PRC-024-3.
If a revision to PRC-029-1 is not feasible at this point, an addition to the Implementation Plan or issuance of a Compliance Guidance document could
help clarify these issues. For example, NERC could clarify that for new and existing IBRs, plant-level hardware limitations to meeting PRC-029-1 due to
use of synchronous condensers within a plant are allowed if the synchronous condenser meets PRC-024. Similarly, NERC could clarify that, until
adequate technology is developed, hardware limitations will be respected for new and existing offshore wind plants that cannot meet the cumulative
voltage ride-through requirements of PRC-029-1, if the Planning Coordinator and Transmission Provider interconnecting that plant are informed of that
limitation and determine that the plant can be reliably interconnected and operated.
In light of the significant improvements in this draft standard, and to draw attention to this important unresolved issue that can likely be addressed by
revising the Implementation Plan or issuing a Compliance Guidance document, we are voting for the proposed standard but against the Implementation
Plan. As noted above, the section entitled Equipment Limitations and Process for Requirement R4 of the Implementation Plan already requires
significant revision or removal, so that section could be repurposed to provide these important clarifications.
5. NERC should clarify the evidence requirements for demonstrating a hardware limitation in R4 and M4, potentially through a revision to the standard,
an addition to the Implementation Plan, or by issuing a Compliance Guidance document. NERC should clarify that a resource can demonstrate a
hardware limitation with a declaration or attestation from a manufacturer stating that the equipment was designed to meet the standards in place at the
time it was installed and was not designed to meet the more rigorous standard proposed in PRC-029-1. As manufacturers explained at length at the
September Ride-through Technical Conference, it is often challenging if not impossible to prove the negative that a piece of equipment cannot meet a
requirement it was not designed to meet. Physical testing of operating equipment outside of a laboratory is often impractical or excessively costly,
particularly for resources that have been operating for many years with varying degrees of degradation. In many cases the manufacturer of IBR
equipment or its components no longer supports those legacy models, or the manufacturer may no longer be in business. Instead, it is much more
practical for manufacturers to provide a positive attestation regarding the requirements the equipment was designed to meet.
Relatedly, NERC should clarify that the type of positive attestation discussed above is sufficient for meeting section 4.1.4 of R4, which calls for
“Supporting Technical documentation verifying the limitation is due to hardware that would need to be physically replaced to meet all Ride‐ through
criteria, and that the limitation cannot be removed by software updates or setting changes…”. As discussed at the technical workshop, it is difficult to
prove the negative that software or settings changes alone cannot remove a limitation.
In light of the significant improvements in this draft standard, and to draw attention to this important unresolved issue that can be addressed by revising
the Implementation Plan or by issuing a Compliance Guidance document, we are voting for the proposed standard but against the Implementation Plan.
As noted above, the section entitled Equipment Limitations and Process for Requirement R4 of the Implementation Plan already requires significant
revision or removal, so that section could be repurposed to provide these important clarifications.
{C}[1]{C} https://www.nerc.com/pa/Stand/202002_Transmissionconnected_Resources_DL/2020-02_PRC-029-1_Technical_Rationale_09172024.pdf, at
7: When considering an expansion of Ride-through capability, it is important to balance the expansion with the feasibility of producing and installing
equipment that can meet the newly proposed criteria. Failure to adequately consider this could result in resource adequacy deficiencies if expanded
criteria lead to widespread non-compliance of legacy IBR due to hardware limitations. Further, for newly interconnecting IBR, expanded Ride-through
criteria often result in significant design changes that have production time and cost implications. If proposed Ride-through criteria are too stringent and
result in costly design changes, those costs could result in a slowing of IBR penetration on the BPS.
For the reasons above, it is imperative that newly created Ride-through criteria are reasonable for both BPS reliability and for the IBR equipment. To
date, NERC has analyzed numerous major events including both winter storms Uri and Elliot. No IBR tripped offline for frequency threshold criteria
(because the system frequency caused a trip due to exceeding equipment frequency limits) and all frequency-related tripping observed were due to misparameterization or the use of instantaneous measurements in protection schemes. Additionally, the deviations in frequency observed during the events
listed above did not exceed the PRC-024 criteria.
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Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
GE Vernova’s Onshore Wind business is a leading wind turbine original equipment manufacturer (OEM) with over 75GW of wind turbines installed in
North America. We appreciate the opportunity NERC has provided to submit comments to PRC-029-1 Draft 4. We appreciated the opportunity to
participate in the Technical Conference in Washington, DC, on September 4- 5. The discussions promoted by NERC are extremely critical to develop
appropriate regulations to set minimum IBR performance requirements to support the needs of the electrical system. While GE Vernova’s Onshore
Wind Business recognizes that important changes were made in Draft 4 to reflect the comments discussed during the Technical Conference, including
frequency ride-through requirement alignment with IEEE 2800-2020, allowance of exemption for frequency ride-through requirement and others, there
are still concerns which we believe are important to restate through these comments. Please refer to comments on Question 2.
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
No
Document Name
Comment
The NAGF supports the proposed changes to PRC-029 Draft 4 Requirements R3 and R4 that provide the frequency ride-through exemption for
hardware limitation associated with existing resources. In addition, the NAGF supports the revised of frequency ride-through curves in Attachment 2.
However, the PRC-029 Draft 4 does not address important concerns identified during the Technical Conference regarding software limits, balance of
plant equipment issues, and the need to consider exemptions for IBR facilities that are in the procurement process (i.e. “in flight”).
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Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
No
Document Name
Comment
The SDT failed to address industry concerns related to ROCOF capabilities. The SDT should be reminded of comments provided by industry and the
equipment manufacturer panelists during the technical conference that ROCOF requirements listed in R3 may not be able to be met by the legacy
equipment. As many pointed out, the ROCOF capability may not be known at the present time and that lab and field testing potentially must be done to
prove the capabilities. Even though R3 is added to R4, it will be very difficult to provide evidence for hardware limitation related to ROCOF. In addition,
past IBR disturbance reports did not identify rate of change of frequency being an issue during the disturbances, it is not part of FERC order 901.
Therefore there is no technical rationale to include it.
The SDT failed to address concerns from equipment manufacturer panelists about phase jump requirement listed in R1. Panelists expressed concern
about differences between IEEE-2800 wording and PRC-029 wording. As confirmed by panelist, the inverter cannot differentiate between a non-fault
switching event and a fault event as both can trigger the phase jump angle to increase.
The SDT failed to address concerns from equipment manufacturer panelists about 1 cycle voltage measurement filtering requirements.
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Brian Lindsey - Entergy - 1
Answer
No
Document Name
Comment
We concur with the comments NAGF provided.
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Martin Sidor - NRG - NRG Energy, Inc. - 6
Answer
No
Document Name
Comment
NRG supports the proposed changes to PRC-029 Draft 4 Requirements R3 and R4 that provide the frequency ride-through exemption for hardware
limitation associated with existing resources. In addition, NRG supports the revised of frequency ride-through curves in Attachment 2. However, the
PRC-029 Draft 4 does not address important concerns identified during the Technical Conference regarding software limits, balance of plant equipment
issues, and the need to consider exemptions for IBR facilities that are currently in the procurement process.
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Patricia Lynch - NRG - NRG Energy, Inc. - 5
Answer
No
Document Name
Comment
NRG is in alignment with NAGF's comments regarding the changes discussed at the Technical Conference. Although we support the proposed
changes, the PRC-029 Draft 4 does not address important concerns identified during the Technical Conference regarding software limits, balance of
plant equipment issues, and the need to consider exemptions for IBR facilities that are in the procurement process (i.e. “in flight”).
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David Vickers - David Vickers On Behalf of: Daniel Roethemeyer, Vistra Energy, 5; - David Vickers
Answer
No
Document Name
Comment
Vistra supports comments made by NRG Energy.
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
No
Document Name
Comment
NIPSCO supports the proposed changes to PRC-029 Draft 4 Requirements R3 and R4 that provide the frequency ride-through exemption for hardware
limitation associated with existing resources. In addition, NIPSCO supports the revised frequency ride-through curves in Attachment 2. However,
NIPSCO also supports the comments of the NAGF that the PRC-029 Draft 4 does not address important concerns identified during the Technical
Conference regarding software limits, balance of plant equipment issues, and the need to consider exemptions for IBR facilities that are in the
procurement process (i.e. “in flight”).
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Keith Smith - Orsted Americas - 5
Answer
No
Document Name
Comment
Orsted and associated vendors provided comments to NERC prior to the technical conference that were not discussed during the technical conference
and are not addressed in the latest version of the Standard.
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Colin Chilcoat - Invenergy LLC - 6
Answer
No
Document Name
Comment
Invenergy would like to thank the Standard Drafting Team (SDT), the Standards Committee, and NERC management for their work on this standard and
the organization of the ride-through technical conference. The technical conference was an excellent example of the unique rulemaking collaboration
between regulators and industry afforded by the NERC Rules of Procedure, and we are encouraged by the significant revisions made in response to
discussions at the conference. That said, there remain some problematic requirements that don’t reflect the understanding reached at the technical
conference regarding the alignment of PRC-029-1 criteria with Generator Owner and OEM capabilities.
Requirement R4
Invenergy believes the most effective way to address remaining industry concerns surrounding limited exceptions and the exceptions process is to carry
over the language from Requirement R3 of PRC-024-3 (now PRC-024-4). As we noted in our comments on previous ballots and at the technical
conference, FERC recommend this path in paragraph 193 of Order 901, stating, “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.” Absent adoption of
the same or similar language, we have the following suggestions to implement to more accurately represent the changes discussed at the technical
conference.
The revisions to Requirement R4 to include limited exemptions from the frequency ride-through requirements due to hardware limitations are greatly
appreciated and introduce a path to compliance for legacy IBRs that may be unable to meet the ride-through criteria that was not provided in earlier
drafts of PRC-029-1. Still, many aspects of Requirement R4, identified below, are overly prescriptive and cause the path to compliance to be
unreasonable to impossible to fulfill.
•
“In-service”: The ability for an IBR to apply for a limited exemption should not be based on the in-service date of that IBR for a few reasons. 1)
In-service is not a defined term in NERC’s Glossary of Terms and is used inconsistently across various NERC materials. 2) It fails to consider
the fact that equipment procurement occurs years, oftentimes many years, prior to an IBR being placed in-service or achieving commercial
operations. If a threshold date must be established, Invenergy recommends using the execution date of the Generator Interconnection
Agreement, which would ensure that equipment procured years before the effective date of PRC-029-1 is not held to ride-through requirements
it may not have been designed to meet. Additionally, it should be clarified that any subsequent amendment to the Generator Interconnect
Agreement that incorporates new generation resources does not void any previously approved exemption for the existing equipment associated
with that Generator Interconnection Agreement.
•
R4.1: 12 months may be insufficient time to collect all the required documentation, much of which cannot be independently provided by the
Generator Owner. To the extent an OEM can identify the specific piece(s) of hardware causing the limitation, extensive analysis and/or
laboratory testing may require more time than the currently allotted 12 months. Invenergy fails to see the benefit of requiring this documentation
be provided within a prescribed timeframe – the limitation will still exist regardless of whether all the intricacies are documented within 12
months – and recommends this time requirement be removed or extended to a minimum of 24 months.
•
R4.1.3 & R4.1.4: As attested by many OEMs at the technical conference, it may be exceedingly difficult to impossible to identify the specific
piece(s) of hardware causing a ride-through capability limitation. The hardware limitation could be the result of a combination of factors with
several unknowns and interdependencies on auxiliary equipment that could not be validated by either the Generator Owner or the OEM. Even
in situations where the OEM still supports a legacy model, the necessary testing to validate its capabilities vis-a-vis the requirements of PRC029-1 is unfeasible, cost prohibitive, and may divert resources away from current or future product lines designed to meet more stringent ridethrough requirements. Simply put, existing IBRs were developed and installed to meet the ride-through standards effective at that time and
requirements, like R4.1.3 and R4.1.4, that effectively mandate a complete re-testing of the capabilities of each component and subcomponent
should be removed.
•
R4.2: Requirement R4.2 and the additional detail provided in Footnote 11 impose an unreasonable expectation that the Generator Owner share
material it does not own and that is considered to be proprietary by the OEM. Invenergy recommends the removal of Footnote 11.
Attachment 1, Note 10: To date, Invenergy has not received any response from the SDT regarding our comments on Attachment 1, Note 10, which
were submitted in response to Draft 2 and Draft 3 of PRC-029-1. Further, Invenergy and OEM comments on this matter at the technical conference are
not reflected in Draft 4 of PRC-029-1.
Attachment 1 Note 10 is vague and subjects equipment to potential damage. Paragraphs 179 and 190 of FERC Order 901 establish that IBR tripping
shall be permitted when necessary to protect the IBR equipment. Many protection decisions must be made in a matter of micro-seconds, and as
drafted, Note 10 would adversely impact reliability by subjecting equipment to potentially damaging surges of current or voltage that near instantaneous
protection settings are designed to mitigate. Can the SDT clarify if this requirement applies at the inverter level? If this requirement is to be applied at
the plant level, note 10 should be amended to reflect that.
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Nick Leathers - Ameren - Ameren Services - 1,3,5,6 - MRO,SERC
Answer
No
Document Name
Comment
Please correct the 1.1 per-unit voltage threshold row in table 1 to be greater than 1.1 rather than greater than or equal to match table 2.
The technical rationale states, "An IBR becomes noncompliant with PRC-029-1 when an event in the field occurs that shows that one or more
requirements were not satisfied. This intent is clarified by the Operations Assessment as the Time Horizon designation of requirements R1-R3". This
statement suggests that if a plant fails to ride through, it can become a self-report. Is it FERC's intent that entities are to self-report if a PRC-029 study of
the design shows compliance, but field data indicates otherwise? We suggest updating the technical rationale to clarify this part.
Ameren also supports EEI and NAGF's comments.
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Rhonda Jones - Invenergy LLC - 5
Answer
Document Name
Comment
No
Comments: Invenergy would like to thank the Standard Drafting Team (SDT), the Standards Committee, and NERC management for their work on this
standard and the organization of the ride-through technical conference. The technical conference was an excellent example of the unique rulemaking
collaboration between regulators and industry afforded by the NERC Rules of Procedure, and we are encouraged by the significant revisions made in
response to discussions at the conference. That said, there remain some problematic requirements that don’t reflect the understanding reached at the
technical conference regarding the alignment of PRC-029-1 criteria with Generator Owner and OEM capabilities.
Requirement R4
Invenergy believes the most effective way to address remaining industry concerns surrounding limited exceptions and the exceptions process is to carry
over the language from Requirement R3 of PRC-024-3 (now PRC-024-4). As we noted in our comments on previous ballots and at the technical
conference, FERC recommend this path in paragraph 193 of Order 901, stating, “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.” Absent adoption of
the same or similar language, we have the following suggestions to implement to more accurately represent the changes discussed at the technical
conference.
The revisions to Requirement R4 to include limited exemptions from the frequency ride-through requirements due to hardware limitations are greatly
appreciated and introduce a path to compliance for legacy IBRs that may be unable to meet the ride-through criteria that was not provided in earlier
drafts of PRC-029-1. Still, many aspects of Requirement R4, identified below, are overly prescriptive and cause the path to compliance to be
unreasonable to impossible to fulfill.
•
“In-service”: The ability for an IBR to apply for a limited exemption should not be based on the in-service date of that IBR for a few reasons. 1)
In-service is not a defined term in NERC’s Glossary of Terms and is used inconsistently across various NERC materials. 2) It fails to consider
the fact that equipment procurement occurs years, oftentimes many years, prior to an IBR being placed in-service or achieving commercial
operations. If a threshold date must be established, Invenergy recommends using the execution date of the Generator Interconnection
Agreement, which would ensure that equipment procured years before the effective date of PRC-029-1 is not held to ride-through requirements
it may not have been designed to meet. Additionally, it should be clarified that any subsequent amendment to the Generator Interconnect
Agreement that incorporates new generation resources does not void any previously approved exemption for the existing equipment associated
with that Generator Interconnection Agreement.
•
R4.1: 12 months may be insufficient time to collect all the required documentation, much of which cannot be independently provided by the
Generator Owner. To the extent an OEM can identify the specific piece(s) of hardware causing the limitation, extensive analysis and/or
laboratory testing may require more time than the currently allotted 12 months. Invenergy fails to see the benefit of requiring this documentation
be provided within a prescribed timeframe – the limitation will still exist regardless of whether all the intricacies are documented within 12
months – and recommends this time requirement be removed or extended to a minimum of 24 months.
•
R4.1.3 & R4.1.4: As attested by many OEMs at the technical conference, it may be exceedingly difficult to impossible to identify the specific
piece(s) of hardware causing a ride-through capability limitation. The hardware limitation could be the result of a combination of factors with
several unknowns and interdependencies on auxiliary equipment that could not be validated by either the Generator Owner or the OEM. Even
in situations where the OEM still supports a legacy model, the necessary testing to validate its capabilities vis-a-vis the requirements of PRC029-1 is unfeasible, cost prohibitive, and may divert resources away from current or future product lines designed to meet more stringent ridethrough requirements. Simply put, existing IBRs were developed and installed to meet the ride-through standards effective at that time and
requirements, like R4.1.3 and R4.1.4, that effectively mandate a complete re-testing of the capabilities of each component and subcomponent
should be removed.
•
R4.2: Requirement R4.2 and the additional detail provided in Footnote 11 impose an unreasonable expectation that the Generator Owner share
material it does not own and that is considered to be proprietary by the OEM. Invenergy recommends the removal of Footnote 11.
Attachment 1, Note 10: To date, Invenergy has not received any response from the SDT regarding our comments on Attachment 1, Note 10, which
were submitted in response to Draft 2 and Draft 3 of PRC-029-1. Further, Invenergy and OEM comments on this matter at the technical conference are
not reflected in Draft 4 of PRC-029-1.
Attachment 1 Note 10 is vague and subjects equipment to potential damage. Paragraphs 179 and 190 of FERC Order 901 establish that IBR tripping
shall be permitted when necessary to protect the IBR equipment. Many protection decisions must be made in a matter of micro-seconds, and as
drafted, Note 10 would adversely impact reliability by subjecting equipment to potentially damaging surges of current or voltage that near instantaneous
protection settings are designed to mitigate. Can the SDT clarify if this requirement applies at the inverter level? If this requirement is to be applied at
the plant level, note 10 should be amended to reflect that.
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Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
No
Document Name
Comment
The broad alignment of the technical requirements of PRC-029-1 with IEEE-2800-2022 represents the changes discussed at the NERC Ride-through
Technical Conference; however, the wording of Footnote 10 to Tables 1 and 2 in Attachment 1 of PRC-029-1 Draft 4 appears to disallow the sub cycle
transient overvoltage tripping permitted in Section 7.2.3 and Figure 11 of IEEE 2800-2022 in a manner that could unnecessarily complicate the process
of overvoltage coordination.
Likes
0
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0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
No
Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
Likes
0
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Response
0
Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
No
Document Name
Comment
PNM Agrees with comments of EEI:
•
EEI appreciates the revisions to PRC-029-1 and generally agrees that the changes align with many aspects of the discussions held during the
NERC Technical Ride-through Conference. However, we are concerned that Requirement R4 overlooks the impacts to GOs who are
developing large, multi-year IBR projects that may not be completed by the effective date of this Reliability Standard. Resource equipment
specifications are typically locked down at the time the recourse contracts are finalized, and a change in requirements/specifications after that
point can require changes in the design of the equipment that are impossible to achieve without triggering a material modification, resulting
interconnection restudies and delaying or potentially canceling the project. To address this concern, we suggest the following modifications be
made to Requirement R4 (in boldface below).
R4. Each Generator Owner identifying an IBR that is in-service or has a contract for an IBR that is in effect by the effective date of PRC-029-1, has
known hardware limitations that prevent the IBR from meeting Ride- through criteria as detailed in Requirements R1-R3, and requires an exemption
from specific Ride-through criteria shall:10 [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
Likes
0
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0
Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Document Name
Comment
The revisions appear to reflect some of the viewpoints presented at the conference, but not others.
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0
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0
Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Yes
Duke Energy endorses and requests the incorporation of EEI comments.
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0
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0
Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Yes
Document Name
Comment
The voltage ride-through requirements are more restrictive than PRC-024 and will require additional studies to determine whether existing IBR facilities
are compliant. Both the standard and the implementation plan require compliance within 12 months after the effective date of PRC-029-1. This is not
sufficient time to have studies completed and if needed, obtain additional documentation from IBR manufacturers, and submit that data to the Planning
Coordinator, Transmission Planner, Transmission Operator, Reliability Coordinator and Compliance Enforcement Authority. A minimum of three years
should be allowed.
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0
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0
Response
Karl Blaszkowski - CMS Energy - Consumers Energy Company - 3
Answer
Yes
Document Name
Comment
The voltage ride-through requirements are more restrictive than PRC-024 and will require additional studies to determine whether existing IBR facilities
are compliant. Both the standard and the implementation plan require compliance within 12 months after the effective date of PRC-029-1. This is not
sufficient time to have studies completed and if needed, obtain additional documentation from IBR manufacturers, and submit that data to the Planning
Coordinator, Transmission Planner, Transmission Operator, Reliability Coordinator and Compliance Enforcement Authority. A minimum of three years
should be allowed.
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0
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0
Response
Natalie Johnson - Enel Green Power - 5
Answer
Yes
Document Name
Comment
Enel North America agrees with comments submitted by the MRO NSRF.
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0
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0
Response
Kimberly Turco - Constellation - 6
Answer
Yes
Document Name
Comment
yes, Legacy inverters will not be able to ride through voltage and frequency events. It’s important to include exemption for legacy inverters.
Kimberly Turco on behalf of Constellation Segments 5 and 6.
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0
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0
Response
Alison MacKellar - Constellation - 5
Answer
Yes
Document Name
Comment
Legacy inverters will not be able to ride through voltage and frequency events. It’s important to include exemption for legacy inverters.
Alison Mackellar on behalf of Constellation Segments 5 and 6.
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0
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0
Dane Rogers - Dane Rogers On Behalf of: Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 1, 5, 6; - Dane Rogers, Group
Name OG&E
Answer
Yes
Document Name
Comment
OG&E Supports comments submitted by MRO NSRF.
Likes
0
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0
Response
Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Yes
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of their members:
EEI appreciates the revisions to PRC-029-1 and generally agrees that the changes align with many aspects of the discussions held during the NERC
Technical Ride-through Conference. However, we are concerned that Requirement R4 overlooks the impacts to GOs who are developing large, multiyear IBR projects that may not be completed by the effective date of this Reliability Standard. Resource equipment specifications are typically locked
down at the time the recourse contracts are finalized, and a change in requirements/specifications after that point can require changes in the design of
the equipment that are impossible to achieve without triggering a material modification, resulting interconnection restudies and delaying or potentially
canceling the project. To address this concern, we suggest the following modifications be made to Requirement R4 (in boldface below).
R4. Each Generator Owner identifying an IBR that is in-service or has a contract for an IBR that is in effect by the effective date of PRC-029-1, has
known hardware limitations that prevent the IBR from meeting Ride- through criteria as detailed in Requirements R1-R3, and requires an exemption
from specific Ride-through criteria shall:10 [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
Likes
0
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0
Response
Ruchi Shah - AES - AES Corporation - 5
Answer
Document Name
Comment
Yes
AES Clean Energy agrees that the major changes have been accurately represented. Some concerns on changes that have not been included are
listed below.
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0
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0
Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Yes
Document Name
Comment
MRO NSRF appreciates the work that the SC and SDT put in to drafting this standard and feel that much of what was covered at the technical
conference was represented in the most recent draft, however we feel that there were some issues brought up during the conference which may have
been overlooked and are addressed in question 2.
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0
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0
Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Yes
Document Name
Comment
Minnesota Power (MP) supports EEI’s comments
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0
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0
Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
Yes
See EEI comments
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0
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0
Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Yes
Document Name
Comment
PG&E recommends the DT to consider development of a Implementation Guide and/or a Compliance Monitoring and Enforcement Program (CMEP)
Practice Guide. Of particular benefit would be including examples of what would demonstrate compliance with Requirement R2.
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0
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0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Yes
Document Name
Comment
see EEI comments
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0
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0
Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Yes
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and the Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 1
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0
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0
Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
See comments submitted by EEI.
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0
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0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
The PRC-024-4 and PRC-029-1 Implementation Plan should be amended to reflect both voltage and frequency Ride-through requirements as modified
in PRC-029-1. This oversight should be made consistent with the revised standard. Accordingly, the following sections should be modified to remedy
this concern: (1) General Considerations and (2) Equipment Limitations and Process for Requirement R4.
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0
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0
Response
Nazra Gladu - Manitoba Hydro - 1
Answer
Document Name
Comment
Yes
MH appreciates the work that the SC and SDT put in to drafting PRC-029-1 and generally agrees that the changes align with aspects of the discussions
held during the NERC Technical Ride-through Conference.
Likes
0
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0
Response
Kyle Thomas - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
While two key important items from the Technical Conference were incorporated in the latest draft of the standard (hardware limitation exemptions for
existing resources for frequency requirements; and aligned the frequency ride-through requirements with the IEEE 2800 standard), there were two
additional key items from the Technical Conference that have not been captured in the latest draft of the standard:
1) Requirement R4 should be updated to allow hardware equipment limitations for any IBRs that already have a signed interconnection agreement (IA)
as of the effective date of the standard. Given that equipment purchases/decisions and IBR plant designs are already locked down at the time the IA is
signed, this will cause significant issues for these IBRs to meet the new requirements of PRC-029 if they were not designed that way. Reference
comments submitted by SEIA and Orsted that explain this concern at greater length.
2) Further clarification of the evidence requirements for R4 hardware limitations. While the M4 measures were updated to add the damage curves from
OEMs as possible evidence, during the Technical Conference the industry discussed that R4 evidence for PRC-029 should ultimately be aligned with
the evidence requirements as detailed in the PRC-024 standard. Aligning the PRC-029 evidnece to the same as PRC-024 will support clarifty and
efficiency of implementation/evidence gather of the standard by the industry.
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0
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0
Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Yes
Document Name
Comment
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0
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0
Response
Mike Magruder - Avista - Avista Corporation - 1
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Kevin Conway - Western Power Pool - 4
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Response
Carver Powers - Utility Services, Inc. - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer
Yes
Document Name
Comment
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0
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0
Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer
Document Name
Comment
Eversource supports the comments of EEI.
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0
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0
Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
NV Energy appreciates the revisions to PRC-029-1 and generally agrees that changes align with many aspects of the discussions held during the
NERC Technical Ride-through Conference. However, we are concerned that Requirement R4 overlooks the impacts to GOs who are developing large,
multi-year IBR projects that may not be completed by the effective date of this Reliability Standard. Resource equipment specifications are typically
locked down at the time the interconnection agreement is signed, and a change in requirements/specifications after that point can require changes in
the design of the equipment that are impossible to achieve without triggering a material modification, resulting interconnection restudies and delaying or
potentially canceling the project. To address this concern, we suggest the following modifications be made to Requirement R4 (in boldface below).
R4. Each Generator Owner identifying an IBR that is in-service or has signed a Large Generator Interconnection Agreement by the effective date of
PRC-029-1, has known hardware limitations that prevent the IBR from meeting Ride- through criteria as detailed in Requirements R1-R3, and requires
an exemption from specific Ride-through criteria shall:10 [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
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0
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0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI appreciates the revisions to PRC-029-1 and generally agrees that the changes align with many aspects of the discussions held during the NERC
Technical Ride-through Conference. However, we are concerned that Requirement R4 overlooks the impacts to GOs who are developing large, multiyear IBR projects that may not be completed by the effective date of this Reliability Standard. Resource equipment specifications are typically locked
down at the time the recourse contracts are finalized, and a change in requirements/specifications after that point can require changes in the design of
the equipment that are impossible to achieve without triggering a material modification, resulting interconnection restudies and delaying or potentially
canceling the project. To address this concern, we suggest the following modifications be made to Requirement R4 (in boldface below).
R4. Each Generator Owner identifying an IBR that is in-service or has a contract for an IBR that is in effect by the effective date of PRC-029-1, has
known hardware limitations that prevent the IBR from meeting Ride- through criteria as detailed in Requirements R1-R3, and requires an exemption
from specific Ride-through criteria shall:10 [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
Likes
0
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0
Response
Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
The work and efforts of this standard drafting team are much appreciated. Thank you for considering EPRI comments on the previous drafts as
submitted previously. The new Draft 4 appears to be improved based on discussions that took place at the Standards Committee and NERC Ridethrough Technical Conference on September 4-5, 2024. However, further improvements and alignment could be considered as follows:
A.
General comments:
•
•
•
•
Aligned with the directives to NERC in FERC order 901, the draft PRC-029 standard and the Implementation Plan for Project 2020-02 propose
that the requirements apply to all applicable IBRs upon the standard’s revised effective date or the newly added phased-in compliance dates.
Applicable IBRs include existing (Legacy) IBRs that are already in operation prior to the specified dates. Requirement R4 provides a path for
each Generator Owner to request a limited and documented exemption of a legacy IBR from the voltage ride-through criteria specified in R1
and R2 and frequency ride-through criteria specified in R3. According to the Implementation Plan of Project 2020-02, “[o]ther NERC Standards
Development projects will be pursued to address ongoing identification and mitigation of any potential reliability impacts to the BPS for such
exemptions.”
o The proposed approach may require documentation of hardware limitations or reconfiguration for a significant number of legacy IBRs
across North America. Neither the draft Technical Rationale nor the FERC record under RM22-12 present or cite sufficient technical
evidence that supports this broad application of the proposed standard to existing IBRs in all applicable NERC regions.
o International experience has shown that documentation of hardware limitations to support exemption from, or the retroactive application
of similarly stringent ride-through capability requirements on legacy IBRs are associated with significant uncertainties, potential
technical and procedural challenges, and costs. Justification of similarly ambitious regulations enforced in other countries required the
production of evidence like post-mortem disturbance analysis or case studies that quantified the potential impact of non-compliant
existing IBRs on the bulk power system stability and reliability.[1],[2]
o Consequently, stakeholder concerns contribute to low approval rates for the draft PRC-029, possibly causing delays in moving the draft
standard through the NERC process toward timely and effective enforcement for at least all new IBRs. Considering the approx. 2,600
GW of new IBRs in the interconnection queues across North America[3], these delays bear potentially significant risk for the BPS.
o Furthermore, the proposed revised effective date and newly added phased-in compliance date of the capability-based elements of
Requirements R1, R2, and R3 as specified in the draft PRC-029 are different from the transition periods found in international practice
of similarly ambitious rule changes for new and legacy IBRs (see the comments on Implementation Plan below for further details).
The term Inverter‐based Resource (IBR) to which the draft standard is intended to apply refers to proposed definitions being developed under
the Project 2020‐06 Verifications of Models and Data for Generators. Although the new draft includes redlines that strike the explicit mentioning
of VSC-HVDC transmission facilities that are dedicated connections for IBR to the BPS, the definition proposed by Project 2020-06 is
sufficiently broad that it could cover such facilities. For further clarity on the scope and application of the proposed PRC-029 standard, it could
be helpful to add a clarifying sentence or to copy parts of Footnote 2 that clarifies the location of the “main power transformer” in case of IBR
connecting via a dedicated VSC-HVDC transmission facility into the terms section on page 2 of the standard.
For the purpose of clarity, harmonization, and compliance of IBR across North America, proposed requirements could even further align with
requirements that are testable and verifiable as specified in voluntary industry standards developed through an open process such as ANSI,
CIGRE, IEC, or IEEE. The drafting team is encouraged to review these standards and where applicable further align, for example:
o Requirement R1 and R2 relate to IEEE Std 2800™-2022, Clause 7.2.2 (Voltage disturbance ride-through requirements), with
consideration of Clause 7.3.2.4 (Voltage phase angle changes ride-through) as a stated exception in R1.
o Requirement R3 relates to IEEE Std 2800™-2022, Clause 7.3.2 (Frequency disturbance ride-through requirements), with consideration
of Clause 7.3.2.3.5 (Rate of change of frequency (ROCOF) ride-through) as a stated exception in R3.
o Measures M1–M3 relate to IEEE P2800.2 Draft 1.0a, Clause 5 (Type tests), Clause 6 (Validation procedures for IBR unit models and
supplemental IBR device models), and Clause 7 (Design evaluations), Clause 8 (As-built installation evaluations), Clause 9
(Commissioning tests), Clause 10 (Post commission model validation), and Clause 11 (Post-commissioning monitoring).
o Measure M4, additionally, relates to IEEE P2800.2 Draft 1.0a, Clause 12 (Periodic tests), and Clause 13 (Periodic verification).
The draft standard does not specify grid conditions for which the specified ride-through requirements apply. During its lifetime, a plant may
experience many different operational conditions, along with changes to the grid, and may fail to ride-through an event if the plant was operating
in a grid condition vastly different from that which it was designed for. The standard could include an exception for such situations based on
leading industry practices, or a requirement for the TP, PC, etc. to specify such an exception.
•
•
•
B.
IEEE 2800-2022 allows for an exception for “self-protection” when negative-sequence voltage is greater than specified duration and threshold
within continuous operation region. There is no such exception in draft PRC-029. Such an exception may be necessary for type III wind turbine
generator (WTG) based plants.
Standard does not allow any flexibility for failure of ride-through resulting from misoperation of protection system. The misoperation of protection
system may occur for many reasons over the life of a plant. For example, for a fault on a transmission system, if differential protection for the
main step-up transformer misoperates due to environmental issues such as damage due to water from a leaking roof or animal intrusion, then
plant would be considered out of compliance. If a synchronous machine based generating plant trips because of similar issue, it would not be
out of compliance with PRC-024.
Requirements R1–R4 call out both “design and operation”. If the plant is designed to ride-through, then is it necessary to specifically call out
and include IBR “operation” into the scope of PRC-029?
o The inclusion of “operation” in PRC-029 would put a Generator Owner out of compliance with the standard whenever one of their IBR
plants fails to ride-through real world disturbances, including incidents where failure of ride-through within the specified abnormal
voltage and frequency conditions was beyond the GO’s control.
o An alternative approach could be to narrow the scope of PRC-029 to require a Generator Owner to adequately design each IBR to have
the capability to ride-through the specified abnormal conditions. The GO could then be further required by PRC-028 and PRC-030 to
monitor IBR performance during operations and for real world events. If an IBR was found to have failed ride-through during operations,
then PRC-030 could require the GO to identify the underlying issues and to take corrective action.
Ride-through definition
·
Consider adopting definition from IEEE 2800, which is from IEEE 1547, and well understood by the industry. This was supported by about 68% of
the respondents to the Slido poll during the NERC Technical Conference.
C.
Requirement R1:
•
•
D.
Requirement calls out “design and operation”. If the plant is designed to ride-through then is it necessary to specifically call out “operation”?
o The Reliability Standard PRC-006, Requirement R3, requires PC to develop UFLS program. Several assumptions are made here. If an
event occurs, then R11 requires assessment of an event and if deficiency in UFLS program is identified then PC is required to consider
deficiencies in R12. If UFLS program was deficient then PC is not out of compliance with R3 (or any other requirements in the
standard). This is a good-faith approach: Design UFLS program and if actual event shows deficiency in UFLS Program then fix it. No
compliance issues, as far as UFLS program was designed per Requirement R3.
o Same approach could be taken in PRC-029, where R1 could require that plant is designed to ride-through specified voltage
disturbance. The PRC-028 and PRC-030 then requires monitoring of plant performance and take corrective actions when necessary.
o The same approach could be extended to requirements R2 and R3.
If IBR operation remains within the scope of PRC-029, then consider revising the beginning of the sentence as following for better readability:
Each Generator Owner shall design and operate each IBR to meet or exceed Ride-through requirements…
o The same changes could be extended to requirements R2 and R3.
Requirement R2
•
E.
Refer to comments on R1 that could be extended to requirement R2.
Requirement R2, Part 2.1
•
Why is it necessary to specify a performance requirement when voltage is in the continuous operation region? The standard remains silent on
performance expectation for frequency ride-through requirements. For performance requirement for voltage ride-through mandatory operation
region is also very brief. The intent of this standard is to focus on ride-through during voltage and frequency disturbances. If there is a desire to
•
•
F.
Requirement R2, Part 2.2
•
•
•
G.
The intent of this requirement is understood. However, if there are multiple plants in the area, then one plant misbehaving may cause
overvoltage on high-side terminals of the main power transformer of other plants in the area. Also, the post-fault dynamics greatly depend on
system operating condition (peak, shoulder, off-peak, etc.) along with transmission outages, status of capacitor banks, etc. The Generator
Owner usually does not have system data to evaluate post-fault system dynamics and to determine if plant’s behavior is or not a contributing
factor to overvoltage.
Requirement R3
•
•
J.
Per language in attachment 1, permissive operation is allowed when line-to-ground or line-to-line voltage is below 10%. But per Part 2.3.1, IBR
is required to restart current exchange when positive-sequence voltage enters continuous or mandatory operation region. This is conflicting. For
example, for a line-to-ground fault on high-side terminals of main power transformer, the positive-sequence voltage would be more than 10%,
i.e., in the mandatory operation region.
Requirement R2, Part 2.4
•
I.
Part 2.2 applies at the high-side of the main power transformer. The IBR is required to exchange current, up to the maximum capability. How is
the “maximum capability” of an IBR determined? There could be some explanation, perhaps with examples, in the technical rationale document.
The phrase “provide voltage support on affected phases during both symmetrical and unsymmetrical voltage disturbances” is confusing.
o It is understood that intent is to require to inject “unbalanced current” or “negative-sequence” current during asymmetrical faults.
However, as written, injection of balanced reactive current into an unbalanced fault meets the requirement to provide voltage support on
affected phases, in addition to unaffected phase. The standard does not prohibit voltage support on unaffected phases. The voltage
support on unaffected phase is usually problematic. But the requirement, as written, does not prohibit this.
o During a L-G fault, current in a faulted phase is dependent on transformer winding configuration. Does this requirement, unintentionally,
specify specific transformer configuration?
During mandatory operation, voltage is abnormal and could be almost zero for close-in faults. As such, “current” over “power” is more
appropriate. Power in faulted and unfaulted phases could be different as well. Replace real and reactive power with active (real) and reactive
current respectively.
Requirement R2, Part 2.3.1
•
H.
address performance then one option could be to simply state that performance shall be as specified by TP, PC, etc. That is in Part 2.1.3
anyway.
Part 2.1.2: remove “and according to its controller settings”. It is not incorrect but “according to its controller settings” inherently apply to all
performance requirements.
Part 2.1.3: this requirement in IEEE 2800 was necessary and was tied to reactive power capability requirement as shown in Figure 8 of IEEE
2800. Given PRC-029 does not include reactive power capability requirements, perhaps PRC-029 could remain silent.
Refer to comments on R1 that could be extended to requirement R3.
Footnote 9 could be simplified as following: The ROCOF is an average rate of change of frequency over an averaging window of at least 0.1
second.
Requirement R4
•
We re-iterate the following observations related to the Effective Date and Phased-in Compliance Dates stated in the Implementation Plan of the
project, as previously offered in our EPRI comments on the initial draft of PRC-029:
o Aligned with the directives to NERC in FERC order 901, the draft proposes that all requirements specified in PRC-029 apply to all applicable IBRs
upon the standard’s effective date, including Legacy IBRs that were already in operation prior to that date. This approach may require reconfiguration or
documentation of hardware limitations for a significant number of existing IBRs across North America. In some cases, for example where the original
equipment manufacturer (OEM) of hardware used in Legacy IBRs has gone out of business, or the OEM has ceased to support a legacy hardware
product line, documentation of hardware limitations and development of models accurately representing Legacy IBR performance may be challenging.
Additional exemptions to address these challenges could be included in R4 of the draft standard or the implementation plan.
o One example for an alternative approach to the one proposed in the draft PRC-029 could be that TOs and reliability coordinators were to discern on
a regional or case-by-case basis about the application of PRC-029 to Legacy IBRs, preferably based on technical evidence like case studies assessing
and quantifying the potential BPS reliability impacts from Legacy IBR in their regions.[4] If documentation of Legacy IBR hardware limitations was not
available, worst-case assumptions could be made in these case studies. If such studies indicated a viable reliability risk, R4 could be applied to selected
or all Legacy IBRs. This could produce documentation of hardware limitations to refine study assumptions to produce more realistic case study results.
If refined results still indicated a viable reliability risk, R1-R3 could be applied to Legacy IBRs selectively.
•
•
K.
Violation Risk Factors
•
•
L.
For further comments on the Effective Date and Phased-in Compliance Dates refer to below comments on the Implementation Plan.
Parts 4.1 and 4.2 refers to exemption for a plant but part 4.3 refers to hardware in plant. If few of many wind-turbine generators in a plant are
replaced, then plant still has limitation because most of the wind-turbine generators still have limited capability. Perhaps some clarification could
be added that if “all hardware with documented capability limitation” is replaced, only then an exemption for a legacy IBR would not apply any
longer.
The language for the assignment of a VRF to Requirement R4 in the draft standard is truncated. Consider revising to: [Violation Risk Factor:
Lower]
Each Generator Owner is required per Requirement R4 to identify, document, and communicate about legacy IBRs that have hardware
limitations related to the voltage ride-through criteria specified in R1 and R2. Why is a VRF of “Lower” assigned to R4 and not a VRF of
“Medium”? Could the uncertainty related to the capability and performance of legacy IBRs associated with a violation of R4 (a requirement that
is administrative in nature and a requirement in a planning time frame) by a Generator Owner not, under the abnormal conditions, be expected
to directly and adversely affect the electrical state or capability of the Bulk‐Power System, or the ability to effectively control the Bulk Power
System?
Violation Severity Levels
•
R1, R2, and R3: The lower VSL for each of these requirements is for failure to demonstrate the design capability to ride-through. There are two
reasons for which this could arise:
(1) Plant is capable to ride-through but is not demonstrated in design evaluation or interconnection studies.
(2) Plant is not capable to ride-through and that is demonstrated in design evaluation or interconnection studies.
•
•
Reason (1) is not a problem for grid reliability, it is just that studies are not adequate to demonstrate ride-through capability, and hence lower
VSL is justified. But reason (2) is not any different from a case in severe VSL where an entity fails to demonstrate that IBR adhered to ridethrough requirements (based on actual system disturbance event data).
The VSLs could be rephrased to read:
o Lower VSL: The Generator Owner failed to produce adequate evidence demonstrating for each applicable IBR that it was designed to
Ride-through in accordance with …
o
Severe VSL: The Generator Owner either produced evidence demonstrating for any of their applicable IBR that it was not adequately
designed to adhere to Ride-through, or the Generator Owner failed to produce evidence of actual disturbance monitoring data for a
specific event that demonstrate each applicable IBR adhered to Ride-through requirements in accordance with …
M. Attachment 1
•
•
•
•
•
•
N.
Attachment 2:
•
•
O.
Tables 1 and 2 are inconsistent. Table 1 states “>= 1.10” whereas Table 2 states “>1.10”.
Clarify that cumulative window, for voltage band where ride-through duration is 1800-second, is 3600-second. Also, consider clarifying that
1800-second ride-through duration is only applicable to nominal voltages other than 500 kV.
Numbered item #3: states that applicable voltage is “… on the AC side of the transformer(s) that is (are) used to connect…..”. Both sides of
transformer are AC, one is on DC-AC converter side and another on AC grid side. As written, voltage on either side of transformer is applicable.
Please clarify that applicable voltage is on AC “grid” side of the transformer.
Numbered item #5: Consider revising as following - The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of phase-to[strike: neutral] [add: ground] or phase-to-phase fundamental [add: frequency] root mean square (RMS) voltage at the high-side of the main
power transformer.
Numbered item #7: The interpretation of ride-through curves/points needs further clarification. Would a wind-based IBR plant be required to
ride-through an event where at t=0 voltage drops from nominal to zero, then @t=0.16 s voltage rises to 25%, @t=1.2 s voltage rises to 50%,
@t=2.5 s voltage rises to 70%, @t=3 s voltage rises to 90%? The item (8) is also tied to item (12), where a combined “area” is stated. Does
must ride-through zone represent an “area” (represented by deviation in voltage multiplied by time duration)? Consider adding a few examples
in the technical rationale.
o Note that IEEE 2800-2022, informative Annex D, Section D.1 (Interpretation of voltage ride-through capability requirements specifies)
states that the interpretation used in the standard is a “voltage versus time curve.” However, the same Annex includes a Figure D.4 that
intends to show “a realistic and complex trajectory of a voltage during a disturbance” for which the informative annex then further states
that an IBR plant “is required to ride through,” effectively interpreting the IEEE 2800-2022 ride-through curves as a “voltage versus time
envelope.” Thus, there seems to be some ambiguity in IEEE 2800-2022 as to how to interpret its ride-through curves, a finding that
could be considered and resolved in a potential future revision or amendment of IEEE 2800.
o If the voltage ride-through requirements proposed in Attachment 1 were to be specified or interpreted as a “voltage versus time
envelope,”, and considering that an unknown number of IEEE SA balloters that voted affirmatively on IEEE 2800-2022 may have
interpreted the IEEE 2800-2022 requirements as the less stringent “voltage versus time curves” explained in Annex D of the standard,
the proposed PRC-029 could be perceived as more stringent than IEEE 2800-2022.
o Adding a few examples in the technical rationale could help clarify the correct interpretation of the voltage ride-through curves specified
in Attachment 1.
Numbered item 10: Please clarify if this statement applies to protection applied to high side of main power transformer only OR everywhere in
the plant. An alternative could be to state that voltage protection of any type applied within the IBR shall not limit IBR from meeting the Ridethrough requirements specified in this standard.
Consider adding a statement that frequency ride-through requirements apply only when voltage is in the must ride-through zone.
Numbered item 3: What is meant by control settings? Is the intent to state protection settings instead?
Implementation Plan
•
The proposed effective date and phased-in compliance date of the capability-based elements of Requirements R1, R2, and R3 as specified in
PRC-029-1 for primarily new IBRs of,
o
o
“the first day of the first calendar quarter that is twelve months [emphasis added by EPRI] after” either “the effective date of the
applicable governmental authority’s order approving” or “the date the standard is adopted by the NERC Board of Trustees” for (primarily
new) Bulk Electric System IBRs, and
“until the later of: (1) January 1, 2027; or (2) the effective date of the standard” for (primarily new) Applicable Non-BES IBRs
are different from transition periods found in international practice of similarly significant rule changes for new IBRs. Examples for reference include, but
are not limited to:
•
o
o
(European) Commission Regulation (EU) 2016/631 of 14 April 2016 establishing a network code on requirements for grid connection of
generators, Article 72 (Entry into force) states, “the requirements of this Regulation shall apply from three years [emphasis added by
EPRI] after publication.” [5]
German Government, “Verordnung zu Systemdienstleistungen durch Windenergieanlagen (Systemdienstleistungsverordnung –
SDLWindV) (Ordinance for Ancillary Services of Wind Power Plants (Ancillary Services Ordinance - SDLWindV),”[6]
Mandatory requirement for new wind power plants to meet specified requirements by March 31, 2011, i.e., 19 months after ordinance entered into
force.
•
o
ERCOT, “Issue NOGRR245. Inverter-Based Resource (IBR) Ride-Through Requirements. Report of Board Meeting on June 18,
2024,”[7] and ERCOT, “Nodal Operating Guide Revision Request (NOGRR) 245, Inverter-Based Resource (IBR) Ride-Through
Requirements. ERCOT Update,” August 8, 2024.”[8]
All new IBRs with a Standard Generation Interconnection Agreement (SGIA) after August 1, 2024, i.e., immediately once the NOGRR enters into
force (subject to change until ERCOT board approval and until there is a non-appealable Public Utility Commission of Texas (PUCT) final order is in
place)
Extension of exemption from requirements new IBRs with a Standard Generation Interconnection Agreement (SGIA) after August 1, 2024, does
not exceed December 31, 2028, i.e., 4 years and 4 months (subject to change until ERCOT board approval and until there is a non-appealable Public
Utility Commission of Texas (PUCT) final order is in place)
•
The proposed effective date and phased-in compliance date of the Requirement R4 as specified in PRC-029-1 for primarily legacy IBRs of,
o “the first day of the first calendar quarter that is twelve months [emphasis added by EPRI] after” either “the effective date of the
applicable governmental authority’s order approving” or “the date the standard is adopted by the NERC Board of Trustees” for (primarily
legacy) Bulk Electric System IBRs, and
o “until the later of: (1) January 1, 2027; or (2) the effective date of the standard” for (primarily legacy) Applicable Non-BES IBRs
are either not applicable, or—for re-configurations that do not require replacement of hardware—comparable—they are different from transition periods
found in national and international practice of similarly significant retro-active enforcements for legacy IBRs. Examples for reference include, but are not
limited to:
•
o
(European) Commission Regulation (EU) 2016/631 of 14 April 2016 establishing a network code on requirements for grid connection of
generators, Article 4 (Application to existing power-generating modules) states, [9]
-
“Existing power-generating modules are not subject to the requirements of this Regulation, except where: … .”
-
“For the purposes of this Regulation, a power-generating module shall be considered existing if:
·
(a) it is already connected to the network on the date of entry into force of this Regulation; or
·
(b) the power-generating facility owner has concluded a final and binding contract for the purchase of the main generating plant by two years
[emphasis added by EPRI] after the entry into force of the Regulation.
•
-
o
German Government, “Verordnung zu Systemdienstleistungen durch Windenergieanlagen (Systemdienstleistungsverordnung –
SDLWindV) (Ordinance for Ancillary Services of Wind Power Plants (Ancillary Services Ordinance – SDLWindV)),”[10]
Financial incentive for voluntary retrofits of legacy wind power plants between July 11, 2009, and January 1, 2011, i.e., 1.5-years.
•
o
German Government, “Verordnung zur Gewährleistung der technischen Sicherheit und Systemstabilität des
Elektrizitätsversorgungsnetzes (Systemstabilitätsverordnung - SysStabV) (System Stability Regulation – SysStabV)),“[11]
Mandatory requirement for reconfiguration of legacy IBRs and distributed energy resources (DERs) larger than 100 kW by August 31, 2013, i.e.,
13 months after ordinance entered into force.
•
o
ERCOT, “Issue NOGRR245. Inverter-Based Resource (IBR) Ride-Through Requirements. Report of Board Meeting on June 18,
2024,”[12] and ERCOT, “Nodal Operating Guide Revision Request (NOGRR) 245, Inverter-Based Resource (IBR) Ride-Through
Requirements. ERCOT Update,” August 8, 2024.”[13]
Mandatory requirement for legacy IBRs with an SGIA executed prior to August 1, 2024 to maximize the performance of their protection systems,
controls, and other plant equipment (within equipment limitations) to achieve, as close as reasonably possible, the capability and performance set forth
in IEEE 2800-2022 no later than December 31, 2025, i.e., 17 months after NOGRR enters into force.
Extension of exemption from requirements for legacy IBRs with a Standard Generation Interconnection Agreement (SGIA) prior to August 1, 2024,
does not exceed December 31, 2027, i.e., 3 years and 4 months (subject to change until ERCOT board approval and until there is a non-appealable
Public Utility Commission of Texas (PUCT) final order is in place)
•
•
P.
Per the Implementation Plan, IBR plants under construction now and entering commercial operation after the effective date of this standard are
required to fully comply with this standard. Such plants are not allowed an exemption as permitted by Requirement R4. Prior to FERC Order
2023, the development and design-freeze for IBR plants does not occur until months or years after an interconnection agreement is signed.
Large IBR plants, especially wind plants, could need a few years for construction, testing, trail operation, etc., before entering commercial
operation. The equipment for plants under construction currently may have been purchased a year or two before the construction began and
typically soon after signing an interconnection agreement. Consider revising Requirement R4 to allow hardware limitation exemptions for IBRs
that have signed interconnection agreements, and not just IBRs that are in-service, as of the effective date of the standard.
The first use of the word “or” in the sentence under the section Effective Date and Phased-in Compliance Dates, PRC-029-1 Phased-in
Compliance Dates, Requirement 4, Applicable Non-BES IBRs on page 5 of the Implementation Plan could be replaced for clarity with the word
“for” to then read: Entities shall not be required to comply with Requirement R4 for their non-BES IBRs until the later of: (1) January 1, 2027; or
(2) the effective date of the standard.
Technical Rationale
•
IEEE Std 2800™-2022, a voluntary industry standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs)
Interconnecting with Associated Transmission Electric Power Systems is mentioned in the Technical Rationale document for PRC-029-1 but not
cited properly. In all instances where the document refers to that IEEE standard, referencing could be improved by following our guidance
offered below. Where appropriate, reference to and proper citation of IEEE P2800.2, an active IEEE Standards Association project for
developing of a Recommended Practice for Test and Verification Procedures for Inverter-based Resources (IBRs) Interconnecting with Bulk
Power Systems, may serve as an additional reference.
o Suggested referencing of IEEE Std 2800™-2022:
For the initial citation within any document, we suggest citing the standard as follows: IEEE Std 2800™, IEEE Standard for Interconnection and
Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
-
Subsequent mentions of the standard could refer to it as: IEEE 2800
•
o
Similar guidelines could be applied to IEEE Std 2800.2™:
We recommend citing the standard in full on first reference as: IEEE P2800.2, Draft Recommended Practice for Test and Verification Procedures
for Inverter-based Resources (IBRs) Interconnecting with Bulk Power Systems
-
Followed by subsequent mentions as: IEEE P2800.2
•
•
Q.
Considering the explicit statements in the "PRC-029-1_Technical_Rationale" document about the intended alignment with IEEE Std 2800™2022 requirements in formulating the technical content of PRC-029-1 by the drafting team, references to specific clauses of IEEE Std 2800™2022 could provide more clarity to industry stakeholders about which parts of the IEEE standard the PRC-029-1 aims to incorporate. It may also
be helpful to identify areas where they are not aligned. Refer to the examples in our general comments above.
IEEE 2800-2022 may not be the only industry standard with scope that overlaps with the proposed PRC-029 standard. ANSI and CIGRE
currently may not have related standards. While IEC does have standards and technical specifications with related scope, these documents
tend to be less specific in their technical requirements compared to IEEE standards like IEEE 2800-2022.[14]
Justifications
•
•
The table for “VRF Justifications for PRC-029-1, Requirement R3” on page 11 of the Justifications lists a Proposed VRF of “Lower”; but the draft
PRC-029 standard assigns R3 a “[Violation Risk Factor: High]”. Consider resolving inconsistency across the two documents.
Refer further to the comment on the VRF assignment for Requirement R4 above.
[1] Grid Codes for Interconnection of Inverter-Based Distributed Energy Resources by Country: Recent Trends and Developments. EPRI. Palo Alto, CA:
November 2014. 3002003283. [Online] https://www.epri.com/research/products/000000003002003283 (last accessed, January 24, 2023)
[2] Dispersed Generation Impact on CE Region Security: Dynamic Study. 2014 Report Update. European Network of Transmission System Operators
for Electricity (ENTSO-E), ENTSO-E SPD Report, Brussels, Belgium: December 2014. [Online] https://eepublicdownloads.entsoe.eu/cleandocuments/Publications/SOC/Continental_Europe/141113_Dispersed_Generation_Impact_on_Continental_Europe_Region_Security.pdf (last
accessed, January 24, 2023)
[3] LBNL (2024) [Online] https://emp.lbl.gov/generation-storage-and-hybrid-capacity
[4] EPRI is currently working on case studies relevant to these topics and is also aware of others doing similar work.
[5] ENTSO-E: Requirements for Generators. [Online] https://www.entsoe.eu/network_codes/rfg/ (last accessed, August 6, 2024)
[6] Federal Law Gazette I (no. 39) (2009): 1734–46. [Online] https://www.clearingstelle-eeg-kwkg.de/gesetz/695 (last accessed, August 6, 2024)
[7] ERCOT, “Issue NOGRR245. [Online] https://www.ercot.com/mktrules/issues/NOGRR245 (last accessed, August 9, 2024)
[8] ERCOT, “Nodal Operating Guide Revision Request (NOGRR) 245, Inverter-Based Resource (IBR) Ride-Through Requirements. ERCOT Update,”
August 8, 2024 [Online] https://www.ercot.com/calendar/08082024-NOGRR245-_-Review-of (last accessed, August 9, 2024)
[9] Ref. Footnote 10
[10] Federal Law Gazette I (no. 39) (2009): 1734–46. [Online] https://www.clearingstelle-eeg-kwkg.de/gesetz/695 (last accessed, August 6, 2024)
[11] Federal Law Gazette I (no. 40) (2012): 1635. [Online] https://www.gesetze-im-internet.de/sysstabv/BJNR163510012.html (last accessed, August 6,
2024)
[12] Ref. Footnote 16
[13] Ref. Footnote 17
[14] Example IEC standards and technical specifications with related scope may include IEC 61400-27, IEC 62934:2021, IEC TS 63102:2021, and IEC
TR 63401-4:2022.
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2. Provide any additional comments for consideration, if desired.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT generally supports incorporating as much of the IEEE 2800-2022 language and parameters into PRC-029-1 as possible, and commends
NERC’s and the Standards Committee’s use of material drawn from IEEE 2800-2022. Consistent with the approach taken in IEEE 2800-2022, ERCOT
encourages any future revisions to PRC-029-1 and its attachments that clarify that entities are not precluded from exceeding the minimum requirements
of any ride-through curves and performance measures if their equipment is capable of doing so. Much progress has been made, however ERCOT is
voting against this draft of PRC-029-1 due to the substantive issues raised in these comments and previous comments that have not been addressed.
Nonetheless, ERCOT recognizes and appreciates NERC’s, the Standards Committee’s, and the Project 2020-02 drafting team’s extraordinary level of
effort in developing these critically needed ride-through performance requirements.
As an initial matter, the ride-through definition proposed in draft 4 of PRC-029-1 continues to only require a facility to remain connected and continue “to
operate,” which is inadequate; the definition needs to require the facility to maintain performance beneficial (or, at the very least, not detrimental) to
overall grid reliability. The Standards Committee’s response to previous comments on this topic stated that the definition cannot specify exact
performance. ERCOT’s comment was not intended to suggest that performance requirements be stated in the definition. Rather, ERCOT believes the
definition of ride-through needs to include qualifications on what it means to operate in the context of ride-through, just as the existing defined term
“Reliable Operation” places qualifications on what it means to reliably operate elements of the Bulk-Power System. ERCOT believes that similar
qualifications are necessary in the context of ride-through because ERCOT has encountered arguments that IBRs that performed poorly during events
where ride-through was needed were operational despite their poor response and poor performance simply because at least part of the plant did not trip
during the event.
Similarly, the concept of ride-through also ought to recognize that the continued operation associated with ride-through must be maintained not only
through the Disturbance but all the way through recovery to a new operating point. The existing Disturbance definition does not clearly include the
recovery period.
In addition, ERCOT believes that partial trips are inconsistent with the concept of ride-through, not simply performance parameters to be addressed
solely under PRC-030. The requirement to ride through should apply to both the IBR facility and the individual IBR units (inverters and turbines), and
ERCOT is concerned that the removal of “in its entirety” from the ride-through definition in draft 4 of PRC-029-1 reduces the effectiveness of the
definition. While the requirements in draft 4 of PRC-029-1 provide some indication that partial tripping is not permissible, specifying that ride-through
includes individual inverters and turbines will provide clarity in PRC-029-1 and consistency if the definition is used in other places in the
Standards. Most—if not all—IBR ride-through events observed in the ERCOT Region include some level of partial IBR tripping (i.e., some percentage
of inverters/turbines tripping while the overall plant remains connected).
To address these concerns, ERCOT recommends the ride-through definition be revised as follows:
Definition Proposed in Draft 4 of PRC-029-1:
Ride-through: The plant/facility remains connected and continues to operate through voltage or frequency system disturbances.
ERCOT’s Proposed Definition:
Ride-through: The entire plant/facility (including individual inverters and turbines) remains connected and injects current to the Bulk Power System and
continues operating to support grid reliability through a System Disturbance, including the period of recovery to a normal operating condition.
Requirement R1 does not clarify whether partial trips (individual IBR unit trips) would be allowed. ERCOT believes Requirement R1 should not allow
individual turbine/inverter trips and should clearly indicate “ride-through” does not occur when individual turbines or inverters trip offline during a
Disturbance. Requirement R2 provides some level of clarity that partial tripping is not allowed if it would result in more than 10% loss of real power for
voltage ride-through requirements, and revising Requirement R1 to indicate that ride-through precludes individual turbine/inverter trips would be
consistent with Requirement R2.
ERCOT recommends replacing the term “adheres” in Requirement R2 with “meets or exceeds,” which is used in Requirement R1, to clarify that
protection and control settings can be configured to exceed the minimum requirements when the equipment in question is capable of better
performance. This would be consistent with recommendations NERC has made through multiple channels for many years.
ERCOT also recommends reviewing and revising Requirement R2, Part 2.1 and the surrounding language to clarify the facility should continue to
deliver the pre-disturbance level of current, as appropriate, because power depends on voltage. In principle, during a Disturbance, active power should
only reduce proportionally to voltage such that active current is consistent unless needed for frequency response. Reactive current should adjust as
needed to support voltage (lead or lag, as appropriate) up to its current limits. In general, the Requirement should neither incentivize entities to
undersize inverters/converters nor impose onerous requirements to oversize the equipment. This lack of clarity may cause issues in enforcing this
requirement and miss the reliability objective. Using “current” where appropriate also aligns with paragraph 209 of FERC Order 901.
In addition, requiring a facility to deliver reactive power “according to its controller settings” is impractical and misses the objective. The requirement
should be designed to ensure the proper response performance, as each facility will always, by definition, “operate according to its controller settings,”
even if those settings happen to be incorrect. To make Requirement R2, Part 2.1 truly be a performance-based requirement, it should be revised to
require generators to meet or exceed performance requirements instead of simply requiring them to operate according to their settings.
PRC-029-1 Requirement R2, Part 2.2, should not simply specify reactive/active power priority because not all priority implementations perform the same
way. As proposed, Part 2.2 does not prohibit dropping active current to zero even for shallow voltage dips (e.g. 0.7-0.9 per unit), but seems to allow the
Transmission Planner (TP), Planning Coordinator (PC), Reliability Coordinator (RC), or Transmission Operator (TOP) to specify the desired
performance. ERCOT requests that Part 2.2 be revised as necessary to clarify that excessive or full momentary cessation of active current is not
allowed or to specify the circumstances under which it is allowed (e.g., extremely low voltage deviations).
ERCOT also recommends that the Implementation Plan be revised to clarify what constitutes being “in operation” (unit synchronization, full commercial
operations, or some other milestone) for purposes of determining whether an IBR may be considered for a potential exemption under the
Implementation Plan.
ERCOT encourages NERC to consider defining the averaging window for Rate of Change of Frequency (RoCoF) because leaving the averaging
window open-ended will result in measurement inconsistencies in protection systems and post-event analysis. Defining the averaging window will also
ensure that the 5 Hz/second RoCoF proposed in Requirement R3 of draft 4 of PRC-029-1 is sufficient. For example, using the Odessa 2022 event as a
benchmark, the minimum averaging window of IEEE 2800-2022 of 0.1 seconds yields a RoCoF between 5 – 12 Hz/second at some stations, suggesting
5 Hz/second is not sufficient and the Reliability Standard should contain a higher requirement as allowed by IEEE 2800-2022. However, if a longer
averaging window—such as 0.5 seconds—is used, observed RoCoF for the Odessa 2022 event would have been under 5 Hz/second and the RoCoF
requirement proposed in draft 4 of PRC-029-1 would suffice. Having a sufficient averaging window can also prevent transient measurements during the
normal fault and fault clearing times from causing erroneous trips.
NERC should ensure the proposed 5 Hz/second RoCoF requirement does not conflict with footnote 3 in cases where the IBR does not monitor RoCoF
in its protection settings, but its PLL controls are not properly set to ride-through.
ERCOT, as an RC, PC, and TOP, generally opposes PRC-029-1’s broad approach of allowing hardware exemptions without some level of
confirmation of the exemption’s impact (such as an evaluation of the reliability impact of the exemption by a PC, RC, TP, or TOP). ERCOT believes
reliability specifically requires that limitations be modeled and provided to the PC/RC/TP/TOP. Accurate modeling is important enough to be explicitly
referenced in the Standard and should be required if a limitation is to be allowed/confirmed. There are a growing number of presentations and
communications from generation owners regarding current models not reflecting all limitations. Reliability entities should not be required to accept
models that do not reflect actual or expected performance. Instead, the Reliability Standard should require models (both positive sequence and EMT
models) to be improved to include all limitations (e.g., inverter DC protections). Otherwise, the PC/RC/TP/TOP will be unable to model all of a facility’s
limitations and will incorrectly conclude that the facility demonstrates acceptable performance when, in fact, the IBR will not ride through. Reliability
entities may not be able to assess a limitation that is merely described without also being modeled, which may limit their ability to perform determination
studies, resulting in a gap that reliability entities must address. This places the burden on the PC/RC/TP/TOP instead of on Generator Owners (GOs),
who should be responsible for removing the limitation or improving the model fidelity. Consequently, ERCOT believes the proposed approach in draft 4
of PRC-029-1 misses the objective of FERC’s directive that the RC/PC/TP/TOP should ensure that reliability is maintained while any allowed
exemptions are in effect. Additionally, ERCOT believes PRC-029-1 should incentivize facility owners to explore the availability of less expensive
upgrades (including hardware upgrade kits) that can remove limitations rather than allowing them to pass the burden of unmodeled limitations onto
reliability entities that do not have the means to secure the system against limitations they cannot properly model. ERCOT has received information
from some OEMs that some less costly upgrades (e.g., communication speed capabilities, control card updates, etc.) are available that could efficiently
and cost-effectively address some limitations.
ERCOT is also concerned that the language added to Requirement R4 that allows GOs to withhold information from PCs, TPs, TOPs, and RCs if the
original equipment manufacturer considers the information to be proprietary could significantly hamper efforts by these reliability-focused functional
entities to accurately assess the impact of an exemption under Requirement R4. As detailed in the preceding paragraph, properly understanding the
impact of an exemption is essential to reliable system operations, and it is unclear what reliability purpose is served by allowing GOs to withhold
information from PCs, TPs, TOPs, and RCs, especially when GOs are still required to provide that information to the Compliance Enforcement Authority
(CEA). Furthermore, it is unclear what non-reliability purpose such withholding serves. PCs, TPs, TOPs, and RCs are not commercial competitors of
IBR original equipment manufacturers, and, like the CEA, these functional entities routinely and necessarily handle confidential, commercially sensitive
information in the course of their day-to-day operations and are no strangers to the systems and practices necessary to manage such information.
Additionally, ERCOT is concerned that the word “replaced” in PRC-029-1 Requirement R4, Part 4.3.1 may provide a pathway to circumvent the spirit of
the Standard, as it does not clearly specify whether an exemption expires when equipment is refurbished, and an argument could be made that the
refurbished equipment was not “replaced.” ERCOT believes that an existing exemption should no longer be needed after the underlying equipment is
refurbished, and recommends using “replaced, refurbished, or updated” in Requirement R4 to clarify this point.
In the course of the development process for ERCOT’s ride-through requirements, some entities indicated that some software and firmware upgrades
may also require memory upgrades and sought clarity as to whether such memory upgrades would be considered “hardware” upgrades. In response,
ERCOT clarified that such upgrades would be considered part of the underlying software and firmware upgrades, and ERCOT encourages NERC to
include this same clarification in PRC‑029-1.
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Jens Boemer - Electric Power Research Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
2020-02_EPRI Comments on Draft 4 of NERC PRC-029 (IBR ride-through) Reliability Standard.pdf
Comment
I.
Introduction
1.
The Electric Power Research Institute (EPRI)[1] respectfully submits these comments (This Response) in response to North American
Electric Reliability Corporation (NERC)’s request for formal comment on Project 2020-02 Modifications to PRC-024 (Generator Ride-through), issued on
September 24, 2024.
2.
EPRI closely collaborates with its members inclusive of electric power utilities, Independent System Operators (ISOs), and Regional
Transmission Organizations (RTOs), as well as numerous other stakeholders, domestically and internationally. In its role, EPRI conducts independent
research and development relating to the generation, delivery, and use of electricity for public benefit by working to help make electricity more reliable,
affordable and environmentally safe. EPRI’s comments on this topic are technical in nature based upon EPRI’s research, development, and
demonstration experience over the last 50 years in planning, analyzing, and developing technologies for electric power.
3.
EPRI research and technology transfer deliverables are generally accessible on its website to the public, either for free or for purchase, and
occasionally subject to licensing, export control, and other requirements.[2] The publicly available and free-of-charge milestone reports from a U.S.
Department of Energy (DOE)- and EPRI member-funded research project, Adaptive Protection and Validated Models to Enable Deployment of High
Penetrations of Solar PV (“PV-MOD”), [3] and other research deliverables substantiate many of the comments made in This Response.
4.
While not a standards development organization (SDO), EPRI conducts research and demonstration projects in relevant areas as well as
facilitates knowledge transfer and collaboration that SDOs may, at times, use to inform technical and regulatory standards development, such as in
Institute of Electrical and Electronics Engineers (IEEE), International Electrotechnical Commission (IEC), International Council on Large Electric
Systems (CIGRE), and NERC.[4]
5.
EPRI’s comments in This Response address reliability and NERC’s draft PRC-029 Reliability Standards for IBRs ride-through requirements
developed under project 2020-02. All comments are aimed at providing independent technical information to respond to the draft published by NERC
based on EPRI’s research and development results and associated staff expertise and do not necessarily reflect the opinions of those supporting and
working with EPRI to conduct collaborative research and development. Where appropriate, EPRI’s comments do not only address the specific questions
of the NOPR but also related scope that may help to inform a final order. Some of EPRI’s comments presented in This Response have also been
submitted in response to the previous Federal Energy Regulatory Commission’s (FERC) Notice of Proposed Rulemaking (NOPR) to direct North
American Electric Reliability Corporation (NERC) to develop Reliability Standards for inverter-based resources (IBRs) that cover data sharing, model
validation, planning and operational studies, and performance requirements (RM22-12), issued on November 17, 2022.
6.
EPRI also submitted comments on the initial draft of PRC-029 which was issued on March 27, 2024, on Draft 2 which was issued June 18,
2024, and on Draft 3 which was issued on July 22, 2024. This 4th set of EPRI comments supports the same direction as the previously submitted
comments and offers a technical analysis based on the latest “Draft 4”.[5]
II.
Conclusion
7.
EPRI appreciates the opportunity to provide NERC with its technical recommendations and comments on these important topics related to
Reliability Standards for IBRs. EPRI looks forward to working with its members, NERC, and other stakeholders on providing further independent
technical information on these important questions.
III.
Contact Information
Jens C. Boemer, Technical Executive
Manish Patel, Technical Executive
Anish Gaikwad, Deputy Director
Aidan Tuohy, Director, R&D
EPRI
3420 Hillview Ave
Palo Alto, CA 94304
Email: JBoemer@epri.com, ManPatel@epri.com, AGaikwad@epri.com, ATuohy@epri.com
Robert Chapman, Senior Vice President, Corporate Affairs
EPRI
3420 Hillview Ave
Palo Alto, CA 94304
Email: RChapman@epri.com
[1] EPRI is a nonprofit corporation organized under the laws of the District of Columbia Nonprofit Corporation Act and recognized as a tax-exempt
organization under Section 501(c)(3) of the U.S. Internal Revenue Code of 1996, as amended, and acts in furtherance of its public benefit mission.
EPRI was established in 1972 and has principal offices and laboratories located in Palo Alto, Calif.; Charlotte, N.C.; Knoxville, Tenn.; and Lenox, Mass.
EPRI conducts research and development relating to the generation, delivery, and use of electricity for the benefit of the public. An independent,
nonprofit organization, EPRI brings together its scientists and engineers as well as experts from academia and industry to help address challenges in
electricity, including reliability, efficiency, health, safety, and the environment. EPRI also provides technology, policy and economic analyses to inform
long-range research and development planning, as well as supports research in emerging technologies.
[2] https://www.epri.com (last accessed, August 6, 2024)
[3] PV-MOD Project Website. EPRI. Palo Alto, CA: 2024. [Online] https://www.epri.com/pvmod (last accessed, August 6, 2024)
[4] For transparency, we would like to disclose that EPRI collaborates with other organizations such as IEEE, IEC, CIGRE, and NERC; however, EPRI
is not a regulatory- or standard-setting organization. EPRI research is often considered in the development of recommendations, guidelines, and best
practices that are not determinative.
[5] https://www.nerc.com/pa/Stand/Pages/Project_2020-02_Transmission-connected_Resources.aspx
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Scott Thompson - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Document Name
Comment
•
The exemptions are only for equipment that is in-service by the effective date of PRC-029-1. The concern remains that facilities under
construction at the effective date might not meet the requirements. The time needed to perform studies of the ongoing projects would be
limited. Without an exemption for new equipment, we may be at risk of having to sacrifice protection to meet requirements of the standard.
If an exemption is used, the standard requires “Identification of the specific piece(s) of hardware causing the limitation” and “Technical documentation
verifying the limitation is due to hardware that would need to be physically replaced to meet all Ride-through criteria”. Our existing limitation memo from
one of our suppliers is vague. We are not sure how successful we would be in obtaining the required detailed information. Further, the standard
requires that we “Provide a copy of the acceptance of a hardware limitation by the CEA…”. I think this means we would need the Compliance
Enforcement Authority to accept our statement that there is a hardware limitation, likely making a vague response from a manufacturer unacceptable.
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Constantin Chitescu - Ontario Power Generation Inc. - 5
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Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
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Kyle Thomas - Elevate Energy Consulting - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Elevate appreciates the opportunity to comment on the draft NERC standards, particularly those pertaining to future IBR NERC Reliability Standards,
and FERC Order No. 901 directives. Elevate also appreciates the revisions in the latest draft of PRC-029-01 that include the hardware limitation
exemptions for frequency ride-through requirements for existing resources, and the alignment of the frequency ride-through requirements in Attachment
2 with the IEEE 2800 standard that properly balances the capabilities of IBRs today with grid reliability.
Elevate continues to strongly encourage NERC to reconsider adoption of IEEE 2800-2022. The unwillingness to adopt IEEE 2800-2022 by NERC
is leading to entirely duplicative efforts that are not serving any additional value as compared to the work conducted in the IEEE 2800-2022
developments. It does not appear that a holistic approach and strategy is being taken to meet the FERC Order No. 901 directives, which is leading to
very low ballot scores, significant rework, and misalignment with industry recommended practices.
The draft NERC PRC-029 is duplicative with IEEE 2800-2022 Clause 7 yet only covers a small fraction of the IBR-specific capability and performance
requirements and necessary equipment limitation details that are outlined in that clause. Therefore, there is no clear reliability benefit versus the cost of
implementation PRC-029 as compared with IEEE 2800-2022 and the recommendations set forth in the NERC disturbance reports and guidelines.
Concerns with Draft PRC-029
If the draft PRC-029 standard is to be pursued as currently structured, Elevate would like to highlight the following concerns listed below. These should
be addressed in a future version of the standard.
· Inconsistencies with PRC-029 and IEEE 2800-2022: There are numerous inconsistencies in the draft standard language and attachment 1 and 2
when compared to IEEE 2800-2022. These should be considered and reviewed for clarity and completeness in the standard.
o IEEE 2800 identifies the following items, but the standard does not support. Clarification/review should occur for each of these items:
*IEEE 2800 recognizes limitations with VSC-HVDC equipment in meeting consecutive votlage deviation ride-through capabilite, the PRC-029 standard
does not.
*IEEE 2800 allows for an exception for “self-protection” when negative-sequence voltage is greater than specified duration and threshold. This may be
required for Type III WTG based plants, and this exception does not exist in PRC-029
*IEEE 2800 recognizes 500kV system voltages are actually operated in the range of 525kV and therefore has equipment rated to 550kV. These 500kV
operating conditions and corresponding updated voltage ride-through curves should be considered in the standard.
*IEEE 2800 allows for an exception for “self-protection” when negative-sequence voltage is greater than specified duration and threshold. This may be
required for Type III WTG based plants, and this exception does not exist in PRC-029
*IEEE 2800 7.2.2.1 has an exception on IBR post-disturbance current limitations for voltage disturbances that reduce RPA voltage to less than 50% of
nominal. PRC-029 does not have this exception.
*For V > 1.05 and ≤ 1.10, a ride-through duration of 1800 seconds is specified in both IEEE 2800 and draft PRC-029. The IEEE 2800-2022 specifies
that this ride-through duration is cumulative over a 3600 second time period. Draft PRC-029 remains silent regarding applicable cumulative time-period.
*The standard should be updated to explicitly state that the voltage ride-through curves are to be interpreted as voltage vs time duration as is stated in
IEEE 2800. This is to ensure that there is no incorrect interpretation that these curves are “envelope” curves. This could be done by adding a new note
to explicitly call out the voltage vs time duration interpretation of the curves.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment
Attachment 1 to PRC-029-1 is a set of performance-based criteria for voltage ride-through. Footnote 10 to Tables 1 and 2 in Attachment 1 is a design
consideration that does not belong in a set of performance requirements. It should be removed.
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Nazra Gladu - Manitoba Hydro - 1
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Document Name
Comment
(1) The wording in Section 2.1.3 is unclear. MH recommends it be changed to “Prioritize Real Power or Reactive Power delivery when the voltage is
less than 0.95 per unit, the voltage is within the continuous operating region, and the IBR cannot deliver both Real Power and Reactive Power due to a
current limit or Reactive Power limit unless otherwise specified through other mechanisms by an associated Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator.”
(2) Facilities section 4.2.1. The Elements associated with (1) Bulk Electric System (BES) IBRs. What is the IBR aggregate nameplate capacity rating
(greater than or equal to 20 MVA or 75MVA)? The IBR aggregate nameplate capacity rating need to be added to 4.2.1.
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Rhonda Jones - Invenergy LLC - 5
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Comment
None
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Nick Leathers - Ameren - Ameren Services - 1,3,5,6 - MRO,SERC
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Comment
N/A
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Colin Chilcoat - Invenergy LLC - 6
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Comment
None
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
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Document Name
Comment
NIPSCO supports the following additional comments provided by the NAGF:
a. Revise the language to include exemptions for software limits and balance of plant issues. Alternatively, clarify that a hardware limitation includes
software and balance of plant equipment limitations.
b. Requirement R4 and R4.1– current draft language only applies to IBRs that are in service before the effective date of PRC-029-1. Need to
consider revising to address IBRs that will be in-service 2-3 years from now and are currently in design/procurement that potentially will not be able to
meet PRC-029-1 requirements. Recommend that the R4.1 12-month exemption documentation reporting criteria be extended to 36 months to address
this issue.
c.
Requirement R4.2.2 – the NAGF is unclear as to what the Compliance Enforcement Authority (CEA) acceptance for an IBR hardware limitation
exemption will consist of. Will the CEA provide an email response confirming acceptance to the Generator Owner submitting the exemption? How are
such exemptions to be submitted and to whom within the CEA organization? The CEA process needs to be defined, otherwise this requirement is not
enforceable.
d. Requirement R4.3 could be interpreted such that any Ride-through capability limiting component that is replaced with a like and kind component to
fully meet R1-R3 is without the ability to obtain exemption from Ride-through criteria (i.e. the exemption no longer applies). This could force the
retirement of IBRs which are in-service prior to the effective date of PRC-029-1 and that have hardware failures for which a replacement component that
fully meets all Ride-through criteria is not available. The NAGF provides the following revised language for consideration:
4.3.1 When existing hardware causing the limitation(s) is replaced with hardware that changes the Ride-through capability of the IBR, the exemption for
that Ride-through criteria no longer applies.
4.3.1.1 If the limitations requiring exemption from R1-R3 are still present, documentation must be updated and resubmitted as required.
The proposed modifications ensure that it is clearly understood that a Generator Owner can use like-in-kind replacements for hardware components
that may fail on IBRs which are in-service prior to the effective date of PRC-029-1.
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Robert Blackney - Edison International - Southern California Edison Company - 1
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Document Name
Comment
See comments submitted by EEI.
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and the Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 2
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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI is concerned that the language in R3 exceeds what a GO can provide. GO’s do not design their resources. They develop specifications for
procurement and operate those resources within their design capabilities, as specified by the OEM. In the case of legacy resources, they have not
been designed to meet the requirements contained in PRC-029 or IEEE 2800-2020. Therefore, they cannot ensure, even if they conduct an EMT
analysis of that resource that it will in all cases operate in a manner that meets or exceeds these standards. To address this concern, we ask that the
language in R3 be changed to better align with what GOs can meet. To address our concern, we offer the following (in boldface):
R3. Each Generator Owner shall provide documentation that each IBR is configured to meet or exceed Ride-through requirements during a
frequency excursion event whereby the System frequency remains within the “must Ride-through zone” according to Attachment 2 and the absolute rate
of change of frequency (RoCoF) magnitude is less than or equal to 5 Hz/second, unless a documented hardware limitation exists in accordance with
Requirement R4. [Violation Risk Factor: High] [Time Horizon: Operations Assessment]
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Lindsay Wickizer - Berkshire Hathaway - PacifiCorp - 6
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Document Name
Comment
PacifiCorp supports EEI and MRO NSRF comments on this Standard.
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Romel Aquino - Edison International - Southern California Edison Company - 3
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Comment
see EEI comments
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer
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Comment
see EEI comments
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Patricia Lynch - NRG - NRG Energy, Inc. - 5
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Document Name
Comment
NRG is in support of the additional comments for consideration provided by NAGF regarding the PRC_029 draft 4.
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Martin Sidor - NRG - NRG Energy, Inc. - 6
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Document Name
Comment
NRG Provides the following comments that mirror those of the NAGF.
a.
Revise the language to include exemptions for software limits and balance of plant issues. Alternatively, clarify that a hardware limitation includes
software and balance of plant equipment limitations.
b.
Requirement R4 and R4.1– current draft language only applies to IBRs that are in service before the effective date of PRC-029-1. Need to
consider revising to address IBRs that will be in-service 2-3 years from now and are currently in design/procurement that potentially will not be able to
meet PRC-029-1 requirements. Recommend that the R4.1 12-month exemption documentation reporting criteria be extended to 36 months to address
this issue.
c.
Requirement R4.2.2 – NRG is unclear as to what the Compliance Enforcement Authority (CEA) acceptance for an IBR hardware limitation
exemption will consist of. Will the CEA provide an email response confirming acceptance to the Generator Owner submitting the exemption? How are
such exemptions to be submitted and to whom within the CEA organization? The CEA process needs to be defined, otherwise this requirement is not
enforceable.
d.
Requirement R4.3 could be interpreted such that any Ride-through capability limiting component that is replaced with a like and kind component to
fully meet R1-R3 is without the ability to obtain exemption from Ride-through criteria (i.e. the exemption no longer applies). This could force the
retirement of IBRs which are in-service prior to the effective date of PRC-029-1 and that have hardware failures for which a replacement component that
fully meets all Ride-through criteria is not available. NRG agrees with the proposed NAGF revised language for consideration:
4.3.1 When existing hardware causing the limitation(s) is replaced with hardware that changes the Ride-through capability of the IBR, the exemption for
that Ride-through criteria no longer applies.
4.3.1.1 If the limitations requiring exemption from R1-R3 are still present, documentation must be updated and resubmitted as required.
The proposed modifications ensure that it is clearly understood that a Generator Owner can use like-in-kind replacements for hardware components
that may fail on IBRs which are in-service prior to the effective date of PRC-029-1.
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI comments
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
NV Energy is concerned that the language in R3 exceeds what a GO can provide. GO’s do not design their resources. They develop specifications for
procurement and operate those resources within their design capabilities, as specified by the OEM. In the case of legacy resources, they have not
been designed to meet the requirements contained in PRC-029 or IEEE 2800-2020. Therefore, they cannot ensure, even if they conduct an EMT
analysis of that resource that it will in all cases operate in a manner that meets or exceeds these standards. To address this concern, we ask that the
language in R3 be changed to better align with what GOs can meet. To address our concern, we offer the following (in boldface):
R3. Each Generator Owner shall provide documentation ensure the design and operation is such that each IBR is configured to meets or
exceeds Ride-through requirements during a frequency excursion event whereby the System frequency remains within the “must Ride-through zone”
according to Attachment 2 and the absolute rate of change of frequency (RoCoF) magnitude is less than or equal to 5 Hz/second, unless a documented
hardware limitation exists in accordance with Requirement R4. [Violation Risk Factor: High] [Time Horizon: Operations Assessment]
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Brian Lindsey - Entergy - 1
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Document Name
Comment
It is unclear why the CEA needs to be included in the notification of limitations. What is the CEA’s role, other than a reviewer/approver and why the does
the CEA need to approve or accept these limitations. Without a defined process it is unclear how this requirement can be enforced.
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Christine Kane - WEC Energy Group, Inc. - 3, Group Name WEC Energy Group
Answer
Document Name
Comment
Sections 4.1 and 4.2 call for documenting hardware limitations and reporting the same within 12 months following the effective date of PRC-029-1. As
the equipment manufacturer panelists stated, they will have to evaluate each site individually. Given the number of legacy units in service and the
number of units that will connect to the grid before the effective date of the standard, evaluating all the data and providing necessary attestations within
a 12 month period is not practical. The equipment manufacturer panelists also stated that resources will be an issue. More time is needed to document
all this.
WEC Energy Group suggests that the SDT create and add graphs to support Tables 1 and 2 and the respective notes. Graphs should highlight “must
Ride‐through zone” and “may Ride‐through zone” terms that are listed in note 11. One of the early revisions had a graph. Why was it removed?
WEC Energy Group requests that an Implementation Guidance document be created and published to help industry better understand this convoluted
and unclear standard and how to implement it.
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
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Document Name
Comment
MP supports the MRO NSRF comments regarding Requirement 4.3. MP also supports EEI’s comments regarding Requirement 3
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Wayne Sipperly - North American Generator Forum - 5 - MRO,WECC,Texas RE,NPCC,SERC,RF
Answer
Document Name
Comment
The NAGF provides the following comments for consideration:
a. Revise the language to include exemptions for software limits and balance of plant issues. Alternatively, clarify that a hardware limitation includes
software and balance of plant equipment limitations.
b. Requirement R4 and R4.1– current draft language only applies to IBRs that are in service before the effective date of PRC-029-1. Need to
consider revising to address IBRs that will be in-service 2-3 years from now and are currently in design/procurement that potentially will not be able to
meet PRC-029-1 requirements. Recommend that the R4.1 12-month exemption documentation reporting criteria be extended to 36 months to address
this issue.
c.
Requirement R4.2.2 – the NAGF is unclear as to what the Compliance Enforcement Authority (CEA) acceptance for an IBR hardware limitation
exemption will consist of. Will the CEA provide an email response confirming acceptance to the Generator Owner submitting the exemption? How are
such exemptions to be submitted and to whom within the CEA organization? The CEA process needs to be defined, otherwise this requirement is not
enforceable.
d. Requirement R4.3 could be interpreted such that any Ride-through capability limiting component that is replaced with a like and kind component to
fully meet R1-R3 is without the ability to obtain exemption from Ride-through criteria (i.e. the exemption no longer applies). This could force the
retirement of IBRs which are in-service prior to the effective date of PRC-029-1 and that have hardware failures for which a replacement component that
fully meets all Ride-through criteria is not available. The NAGF provides the following revised language for consideration:
4.3.1 When existing hardware causing the limitation(s) is replaced with hardware that changes the Ride-through capability of the IBR, the exemption for
that Ride-through criteria no longer applies.
4.3.1.1 If the limitations requiring exemption from R1-R3 are still present, documentation must be updated and resubmitted as required.
The proposed modifications ensure that it is clearly understood that a Generator Owner can use like-in-kind replacements for hardware components
that may fail on IBRs which are in-service prior to the effective date of PRC-029-1.
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Maozhong Gong - GE - GE Wind - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
Since the first wind turbine was installed in the U.S., product development across the industry has continued to evolve and advance. This evolution is a
benefit for the industry because we have been able to install advanced technologies. However, this also means we have varying degrees of assets
installed. For this reason, we strongly believe NERC needs to implement policies that recognize the distinctions between the operational fleet/assets
and newly deployed units and establish different/distinct regulations for each. During the Technical Conference, several participants, including
individuals participating in the pool process, highlighted the need for this distinguishment. It was suggested the applicability of PRC-024-3 ride-through
requirements for installed assets, while applicability of PRC-029-1, aligned with IEEE 2800-2020, for newly deployed assets. While we understand
NERC’s rationale to not “leave capability on the table”, there will be significant administrative challenges to apply for exemptions putting asset owners
and OEMs at risk of not being able to fulfill the request. As stated by Arne Koerber, Executive for GE Vernova’s Wind Product Management, during the
Technical Conference, proving that a capability is not possible is significantly more difficult than proving specific capability. A detailed system study for
multiple product variants with multiple components configurations would be required to determine hardware limitations, which is unpractical and in
certain cases unfeasible for older units. Some of the challenges with this effort could include: components’ vendors may no longer be in business
and/or, lab setups or prototypes may no longer be in service.
There are other items that were discussed in the Technical Conference which we would like to highlight:
• IEEE 2800-2022 standard was not developed with the intent to impact existing assets, but with the intent to standardize requirements applicable
tonew IBRs installations to support the grid of the future.
• Retroactive requirements diverge the focus of OEMs from developing new and modern products to fulfill the most challenging grid needs of the
future.
• OEMs stated the need of ~5 years cycle to develop new products with the advanced capabilities stated. Yet, the implementation plan schedule
hasn’t changed to allow the entire window suggested by FERC, which is by 2030.
We strongly recommend:
1. Proposing PRC-024-3 requirements to installed assets, while keeping PRC-029-1 aligned to IEEE 2800-2022 for new assets.
2. Developing an exemption process that is based on “product capabilities” and not focusing on “hardware limitations”. This will better demonstrate what
the industry can do to comply with the provision.
3. Timing for compliance to be extended to the maximum allowed period given by FERC, which is by 2030.
Furthermore, we are concerned that policies are becoming too complex that the much-needed focus on zero emitting technologies are being put at risk.
We included the number of GE Vernova assets impacted in two sections below; however, we strongly urge NERC to conduct a thorough analysis
across the industry of all generation assets that would have to comply, including timing of compliance, units that may be unable to comply, and most
importantly impact to the system if certain units cannot comply.
Proposed requirements for new installations:
Requirements which we are concerned for new installations after PRC-029 compliance date:
o Multiple fault ride-through from Attachment 1, item 9:
PRC-029-1 Draft 4 Proposal: While IEEE 2800-2022 allows IBRs to trip for more than two deviations for voltage levels below 0.25pu, PRC-029-1
requires more than 4 deviations for any voltage level. Also, IEEE 2800 allows wind turbines to trip on multiple faults to self-protect against mechanical
resonance that exceed equipment limits.
GE Vernova’s ONW concerns: Riding-through multiple subsequent voltage excursions have significant mechanical and electrical stress on assets,
specially at lower voltage levels (i.e. <0.25pu). It can significantly increase mechanical loads when multiple faults are spaced too close to the drive train
frequency. Since the release and start of adoption of IEEE 2800-2022 requirements across North America, GE Vernova ONW is working on updating
current products’ design to meet or exceed proposed requirements. As an OEM, consistent requirements allow us to plan and execute product
development cycles efficiently and supports offering products with a wide applicability.
GE Vernova’s ONW recommendations: Align with IEEE 2800-2022, section 7.2.2.4, for consistency to IEEE 2800- 2022 efforts to harmonize
requirements across North America.
o Instantaneous trip settings from Attachment 1, item 10:
PRC-029-1 Draft 4 Proposal: Instantaneous trip settings based on instantaneously calculated voltage measurements with less than filtering lengths of
one cycle (16.6 millisecond) are not permissible.
GE Vernova’s ONW concerns: The power electronics in individual inverter-based resources require sub-cycle overvoltage protection with fast filtering.
It is infeasible to filter for a cycle to trip on extreme sub-cycle overvoltages that would cause equipment damage. The choice here is to protect
generation by tripping followed by an auto-restart in a few minutes vs equipment damage followed by a trip (caused by equipment damage).
GE Vernova’s ONW recommendations: Align with IEEE 2800-2022 which requires one cycle filtering for plant level disconnection and specify subcycle transient overvoltage requirements that IBRs have to ride through.
Proposed requirements for legacy installations:
Requirements which we are concerned for legacy installations prior PRC-029 compliance date:
o Frequency ride-through from Attachment 2, Table 3:
PRC-029-1 Draft Proposal: PRC-029-1 proposes frequency ride-through curve similar to IEEE 2800-2022, Section 7.3.2.1, retroactive for installed
assets. GE Vernova’s ONW concerns: While meeting this curve is not a concern for current products and legacy products since PRC-024-1
implementation, it is a concern however that a substantial number of turbines installed prior to 2014 do not fully meet the curve. These products
represent over 20GW of units installed in North America. For type 3 wind turbines, grid frequency determines the synchronous speed which in turn
determines the slip. Larger frequency deviations result in higher slip which results in higher voltages on the rotor side converter. Additionally auxiliary
devices such as motors are impacted. Evaluation of potential design impact is ongoing; however, at this point GE Vernova’s ONW cannot confirm
whether such changes will impact hardware. These turbines meet or exceed the grid requirements that were in place at the time of installation.
GE Vernova’s ONW recommendations: Apply PRC-024-3 requirements to installed assets. If frequency ride through capability of the product is higher
than requirements, these assets are set to the maximum product capability. GE Vernova does not commission wind turbines to operate at the frequency
ride-through requirement capability, but rather at the product capability, which meets or exceeds requirements that were enforced at the time assets
were installed.
o Voltage ride-through from Attachment 1, Table 1:
PRC-029 proposal: PRC-029-1 proposes voltage ride-through curve similar to IEEE 2800-2022, Section 7.2.2.1.
GE Vernova’s ONW concerns: For all installed GE Vernova ONW wind turbine variants with enabled Zero Voltage Ride-Through capability (ZVRT),
voltage ride-through curve may potentially be met at POI due to the voltage drops across the wind plant collector system and the substation
transformer, but only project specific evaluation can confirm it. Note that ZVRT is an available parametrization-only upgrade to GE Vernova’s ONW
legacy wind turbines. These products represent the entirety of the installed base in North America. Changes to the wind turbine voltage ride-through
capability to meet the proposed curve, require the rotor to withstand additional mechanical loads during voltage excursions. Power path, critical auxiliary
devices, rotor side converter and dynamic braking circuit might require re-design to handle energy dump from the generator. Evaluation of potential
design impact is ongoing; however, at this point GE Vernova’s ONW cannot confirm whether such changes will impact hardware. While a full
assessment on a per product variant will take time, potential turbine modifications include replacement of auxiliaries (i.e. motors), changes to operating
rotor RPM curves reducing turbine energy production, and full (in the case of the oldest turbines) or partial replacement of converters. These turbines
meet or exceed the grid requirements that were in place at the time of installation.
GE Vernova’s ONW Recommendations: Apply PRC-024-3 requirements to installed assets. GE Vernova offers ZVRT which helps legacy plants in
meeting or exceeding voltage ride-through requirements of PRC-024-3.
o Multiple fault ride-through from Attachment 1, item 9:
PRC-029-1 Draft 4 proposal: While IEEE 2800-2022 allows IBR to trip for more than two deviations for voltage levels below 0.25pu, PRC-029-1 states
more than 4 deviations for any voltage level. Also, IEEE 2800 allows wind turbines to trip on multiple faults to self-protect against mechanical resonance
that exceed equipment limits.
GE Vernova’s ONW concerns: Riding-through multiple subsequent voltage excursions have significant mechanical and electrical stress on assets,
specially at lower voltage levels (i.e. <0.25pu). It can significantly increase mechanical loads when multiple faults are spaced too close to the drive train
frequency, and in the worst case require significant upgrades to the mechanical drive train.
GE Vernova’s ONW recommendations: We recommend turbines to be required to attempt to ride through multiple voltage events and not trip on
number of subsequent voltage deviations alone but allowed to trip to protect the integrity of the mechanical system e.g. if using devices such as slip
couplings.
o Instantaneous trip settings from Attachment 1, item 10:
PRC-029-1 Draft 4 Proposal: Instantaneous trip settings based on instantaneously calculated voltage measurements with less than filtering lengths of
one cycle (16.6 millisecond) are not permissible.
GE Vernova’s ONW concerns: The power electronics in individual inverter-based resources require sub-cycle overvoltage protection with fast filtering.
It is infeasible to filter for a cycle to trip on extreme sub-cycle overvoltages that would cause equipment damage. The choice here is to protect
generation by tripping followed by an auto-restart in a few minutes vs equipment damage followed by a trip (caused by equipment damage).
GE Vernova’s ONW recommendations: Align with IEEE 2800-2022 which requires one cycle filtering for plant level disconnection and specify subcycle transient overvoltage requirements that IBRs have to ride through.
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John Pearson - ISO New England, Inc. - 2
Answer
Document Name
Comment
ISO New England supports the IBR requirements in this PRC-029-1 draft. R4 of this PRC-029-1 draft provides an exemption for IBRs in-service by the
effective date of the standard that have hardware limitations that prevent them from meeting Ride-through criteria as detailed in Requirements R1-R3.
ISO New England supports this exemption since the new requirements in PRC-029-1 were not applicable when developers procured and constructed
such IBRs. ISO New England is concerned that this exemption is insufficient in scope. Specifically, R4 will become effective before projects that, at this
time, have a) completed the required interconnection studies according to applicable standards at that time, and b) have procured equipment and are
under construction, but c) will not yet be in-service at the time the standard becomes effective within approximately the next three years. Permitting,
procurement and construction often take years after a project completes its interconnection studies (where the project is studied to ensure reliability per
the standards in effect at the time), especially considering today’s development timelines and supply chain issues. Imposing new requirements at later
development stages can cause delays and introduce compliance burdens that were not possible to anticipate during the project analysis and equipment
procurement phases to planned projects that are well on their way to completing their interconnection.
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Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Collaborators
Answer
Document Name
Comment
It is the opinion of ACES that the language surrounding the applicability of the exemption criteria specified in Requirement R4 should be consistent in
Requirements R1-R3. As written, both Requirements R2 and R3 contain the phrase “unless a documented hardware limitation exists in accordance with
Requirement R4” whereas Requirement R1 only allows for an “accepted hardware limitation” for voltage at the “high-side of the main power
transformer”.
Furthermore, we believe that the phrase “and is initiated by a non-fault switching event on the transmission system” should be struck from the 3rd bullet
point of Requirement R1. We contend that, as written, Requirement R1 requires the IBR to meet or exceed Ride-through requirements during a fault
event for any value of the instantaneous positive sequence voltage phase angle while simultaneously allowing the IBR to trip (or initiate current
blocking) during a non-fault switching event. It is our opinion that the GO will likely be unable to differentiate between an event initiated by a fault or an
event initiated by a “non-fault switching event” on the Transmission system. In short, Transmission switching events are outside the purview of the GO.
We recommend the following language for Requirement R1.
R1. Each Generator Owner shall ensure the design and operation is such that each IBR meets or exceeds Ride-through requirements, in accordance
with the “must Ride-through zone” as specified in Attachment 1, except in the following conditions: [Violation Risk Factor: High] [Time Horizon:
Operations Assessment]
• Unless a documented hardware limitation exists in accordance with Requirement R4;
• The IBR needed to electrically disconnect in order to clear a fault;
• The instantaneous positive sequence voltage phase angle change is more than 25 electrical degrees at the high-side of the main power
transformer; or
• The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed 1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for
longer than 2 seconds.
We at ACES appreciate the work put forth by the SDT and the SC to listen and respond to Industry comments, particularly with respect to the exemption
process. However, we continue to have concerns surrounding the language or Requirement R4, specifically part 4.3. It is our opinion that, as written, R4
part 4.3 does not allow for “like in kind” replacement of failed hardware. We recommend using the following language for Requirement R4 part 4.3:
4.3. Except as specified in Requirement R4, Part 4.3.2 below, each Generator Owner with a previously accepted limitation that replaces the hardware
causing the limitation shall document and communicate such a hardware change to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s) within 90 days of the hardware change.
4.3.1. Except as specified in Requirement R4, Part 4.3.2 below, when existing hardware causing the limitation is replaced, the exemption for that Ridethrough criteria no longer applies.
4.3.2. Replacement hardware with the same capabilities and limitations of the existing hardware (commonly referred to as a “like-in-kind” replacement)
shall be exempt from Requirement R4, Part 4.3.
Thank you for the opportunity to comment.
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Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name
Comment
Black Hills Corporation agrees with what EEI has stated: “…EEI is concerned that the language in R3 exceeds what a GO can provide. GO’s do not
design their resources. They develop specifications for procurement and operate those resources within their design capabilities, as specified by the
OEM. In the case of legacy resources, they have not been designed to meet the requirements contained in PRC-029 or IEEE 2800-2020. Therefore,
they cannot ensure, even if they conduct an EMT analysis of that resource, that it will in all cases operate in a manner that meets or exceeds these
standards.”
Additionally, the NAGF in their additional comments made some great comments and modified change suggestions that Black Hills Corporation
supports to help ensure clarity to this standard.
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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
2020-02_Unoffical_Comment_Form_09172024 - NSRF.docx
Comment
MRO NSRF would recommend the following modifications to Requirement 4.3.
4.3. Each Generator Owner with a previously accepted limitation that replaces the hardware causing the limitation shall document and communicate
such a hardware change to the associated Planning Coordinator(s), Transmission Planner(s), Transmission Operator(s), and Reliability Coordinator(s)
within 90 days of the hardware change.
4.3.1 When existing hardware causing the limitation(s) is replaced with hardware that changes the Ride-through capability of the IBR, the exemption for
that Ride-through criteria no longer applies.
4.3.1.1 If the limitations requiring exemption from R1-R3 are still present, documentation must be updated and resubmitted as required.
These modifications ensure that it is clearly understood that a Generator Owner can use like-in-kind replacements for hardware components that may
fail on IBRs which are in-service prior to the effective date of PRC-029-1.
As currently written, R4.3 could be interpreted such that if any Ride-through capability limiting component is replaced, the IBR would be required to fully
meet R1-R3 without the ability to obtain exemption from Ride-through criteria. This could force the retirement of IBRs which are in-service prior to the
effective date of PRC-029-1 and that have hardware failures for which only like-in-kind replacements or replacement components that fully meets all
Ride-through criteria are not available.
Additional MRO NSRF concerns include:
Frequency exemptions are currently limited to “hardware” only, MRO NSRF suggests that clarifying language be added to indicate that if “upgraded”
software is not available the issue then then hardware exemption is acceptable.
Multiple manufacturers have indicated their inverters are capable, but they could not obtain specifications from supporting equipment manufacturers and
that it would be extremely difficult to determine if the entire plant could ride through an excursion event and that facilities may trip due to ancillary
equipment.
This issue with obtaining information for balance-of-plant equipment paired with the fact that all vendors at the NERC Technical conference agreed EMT
studies would be required to verify facility level ride through capability leads to a great deal of concern regarding the ability to determine ride through
capability for facilities in their entirety.
Additionally, the time required to develop EMT studies for the number of impacted facilities could be extremely challenging for GOs due to the limited
resources available.
MRO NSRF is also concerned that the timeline for implementation could be extremely problematic if the effective date set forth by FERC is too soon.
This could impact projects that are already under development and were not designed to IEEE 2800 requirements, providing many facilities that are
coming online with no viable path to compliance.
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Ruchi Shah - AES - AES Corporation - 5
Answer
Document Name
Comment
AES Clean Energy strongly supports the revisions that have been made and we greatly appreciate the efforts of the Standard Drafting Team and
Standards Committee. Throughout the NERC Ride-through Technical Conference and in formal comments we raised concerns that R4 exemptions do
not consider out of business OEMs and the possibility that limitations may not be hardware-based. AES Clean Energy offers the following suggestions
to address these concerns:
1.
Update the following language that has recently been added to the PRC-028 Technical Rationale and include in the PRC-029 Technical Rationale:
PRC-028 Technical Rationale Excerpt
“It is recognized that the manufacturer of an IBR unit in commercial operation before the effective date of this standard may be out of business, acquired
by, or merged with another manufacturer. In such cases, if the entity is not able to determine capability of IBR unit to record the required SER data, the
SER data is not required. Documentation should be retained to demonstrate that entity is unable to determine IBR unit recording capability from
available manufacturer data either from an original manufacturer or from an acquiring manufacturer.”
Suggested PRC-029 Technical Rationale Addition
“It is recognized that the manufacturer of an IBR unit in commercial operation before the effective date of this standard may be out of business, acquired
by, or merged with another manufacturer. In such cases, if the entity is not able to determine capability of IBR to meet Ride-through criteria as detailed
in Requirements R1-R3, the IBR will be exempt from PRC-029. Documentation should be retained to demonstrate that entity is unable to determine IBR
performance capability from available manufacturer data either from an original manufacturer or from an acquiring manufacturer.”
2.
Update the language in R4 to allow exemptions that are not hardware-based.
R4. Each Generator Owner identifying an IBR that is in‐service by the effective date of PRC‐029‐1, has known hardware limitations that prevent the IBR
from meeting Ride‐through criteria as detailed in Requirements R1-R3, and requires an exemption from specific Ride‐through criteria shall:10 [Violation
Risk Factor:Lower] [Time Horizon: Long‐term Planning]
4.1. Document information supporting the identified hardware limitation no later than 12 months following the effective date of PRC‐029‐1. This
documentation shall include:
4.1.1 Identifying information of the IBR (name and facility number);
4.1.2 Which aspects of Ride‐through requirements that the IBR would be unable to meet and the capability of the hardware IBR due to the limitation;
4.1.3 Identify the specific cause of piece(s) of hardware causing the limitation;
4.1.4 For hardware-based limitations, Ttechnical documentation verifying the limitation is due to hardware that would need to be physically replaced to
meet all Ride-through criteria, and that the limitation cannot be removed by software updates or setting changes, and;
4.1.5 Information regarding any plans to remedy the hardware limitation (such as an estimated date).
3.
Some consideration should be given that projects being placed in-service shortly after the Standard effective date will have been designed and
procured several years prior and may require exemptions under R4. The first sentence of the requirement can be revised as follows:
“R4. Each Generator Owner identifying an IBR that reaches commercial operation is in‐service before or within 24 months of by the effective date of
PRC‐029‐1,…”
The following footnote from PRC-028 on commercial operation should be included for consistency:
“Commercial operation means achievement of this designation indicating that the facility has received all approvals necessary for operation after
completion of initial start-up testing.”
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Marcus Bortman - APS - Arizona Public Service Co. - 6
Answer
Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of their members:
EEI is concerned that the language in R3 exceeds what a GO can provide. GO’s do not design their resources. They develop specifications for
procurement and operate those resources within their design capabilities, as specified by the OEM. In the case of legacy resources, they have not
been designed to meet the requirements contained in PRC-029 or IEEE 2800-2020. Therefore, they cannot ensure, even if they conduct an EMT
analysis of that resource that it will in all cases operate in a manner that meets or exceeds these standards. To address this concern, we ask that the
language in R3 be changed to better align with what GOs can meet. To address our concern, we offer the following (in boldface):
R3. Each Generator Owner shall provide documentation that each IBR is configured to meet or exceed Ride-through requirements during a frequency
excursion event whereby the System frequency remains within the “must Ride-through zone” according to Attachment 2 and the absolute rate of change
of frequency (RoCoF) magnitude is less than or equal to 5 Hz/second, unless a documented hardware limitation exists in accordance with Requirement
R4. [Violation Risk Factor: High] [Time Horizon: Operations Assessment]
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Joshua London - Eversource Energy - 1, Group Name Eversource
Answer
Document Name
Comment
Eversource supports the comments of EEI.
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Dane Rogers - Dane Rogers On Behalf of: Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 1, 5, 6; - Dane Rogers, Group
Name OG&E
Answer
Document Name
Comment
OG&E Supports comments submitted by MRO NSRF.
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Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Document Name
Comment
SMUD appreciates the actions taken by the Standard Drafting Team and the Steering Committee to revise the language in Section 4, Applicability so
that it matches the Applicability language in PRC-028-1 and PRC-030-1. This was a minor but important change to ensure uniformity among this first
set of IBR Standards.
SMUD is voting Affirmative on this draft #4 but believes that the term “in-service” in Requirement R4 is too vague and needs to be defined in either a
future version of PRC-029, Implementation Guidance, or a CMEP Practice Guide. Entities who are planning, designing and constructing IBRs today
with slightly older equipment could be caught in a Catch-22 if their project is delayed and the exemption from specific Ride-through criteria in
Requirement R4 is dependent upon whether the project is “in-service” or not. The term in-service could be confused with the project’s energization
date, commercial operation date, or other operational condition during construction and commissioning. For reference, Requirement R4 is listed here:
R4. Each Generator Owner identifying an IBR that is in-service [emphasis added] by the effective date of PRC-029-1, has known hardware limitations
that prevent the IBR from meeting Ride-through criteria as detailed in Requirements R1-R3, and requires an exemption from specific Ride-through
criteria shall: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
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Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
1. The standard does not include exemption for instances when a transformer differential protection trip during a fault beyond our control. As written,
IBR unit will be out of compliance.
2. The standard language in R4 mentions exception regarding hardware limitation but no mentions of software limitation. It should be added to avoid
confusion.
3. Legacy sites may not be able to meet the new proposed FRT and VRT curves. Language in the standard needs to capture that and allow them to
operate with max. capability without compliance repercussions.
4. Damage curve may not be an easy evidence document to get from OEM. It’s considered intellectual proprietary documentation.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
1. The standard does not include exemption for instances when a transformer differential protection trip during a fault beyond our control. As written,
IBR unit will be out of compliance.
2. The standard language in R4 mentions exception regarding hardware limitation but no mentions of software limitation. It should be added to avoid
confusion.
3. Legacy sites may not be able to meet the new proposed FRT and VRT curves. Language in the standard needs to capture that and allow them to
operate with max. capability without compliance repercussions.
4. Damage curve may not be an easy evidence document to get from OEM. It’s considered intellectual proprietary documentation.
Kimberly Turco on behalf of Constellation Segments 5 and 6.
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Natalie Johnson - Enel Green Power - 5
Answer
Document Name
Comment
The Implementation Plan mandates compliance within 12 months of the effective date. This timeframe is insufficient to complete necessary studies,
acquire additional documentation from IBR manufacturers if required, and submit the data to the Planning Coordinator, Transmission Planner,
Transmission Operator, Reliability Coordinator, and Compliance Enforcement Authority (CEA).
Moreover, the standard does not clearly specify a procedure nor a timeframe for the CEA to accept or deny a hardware limitation. Consequently, 12
months is insufficient for both the GO to collect the data required in Requirement R4.1 and for the CEA to evaluate and determine acceptance or denial
of any hardware limitations needing an exemption from specific Ride-through criteria.
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
Althought WECC voted affirmative, WECC suggests the following for clarity, and believes these are all non-substantive changes and would not require
reposting. WECC suggests adding (IBR) after "Inverter-Based Resource" in the title or identifying IBR in the "Purpose" (or in Requirement R1). Part 4.2
should say “manufacturer” for OEM not “manufacture”. Requirement R4 Part 4.2.1 needs rewritten for clarity (remove “shall be provided”) The word
"Provide" was added at the beginning. In Requirement R4 Part 4.3, the CEA will not know if the limitation has been mitigated as there is no obligation to
inform the CEA yet the VSLs include the CEA (last of the “Or” statements for each level.) Should Table 2 for 1.10 pu be shown as ”≥ 1.10” (as in
Table 1) and not simply “> 1.10”?
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
FirstEnergy requests DT consider adding a range of return to pre-disturbance real power output. To satisfy R2.5 as written, IBR sites would need to
operation in static VAR control rather than desired automatic voltage control (system actively adjusting VARs to control voltage). This would maintain a
static power factor on the sties that would fail to provide effective voltage support due to manual intervention required to adjust VAR setpoint, not
allowing for immediate response to voltage changes. This weakened response to voltage changes could result less stable grid voltage and increased
potential for voltage trips, which does not align with the intent of the Standard. Changing this to provide a range from the pre-disturbance real power
output would allow for change in setpoint for IBR operation during a transient such that this automatic voltage control could be utilized, improving
voltage support from IBR generators and enhancing IBR stability and reliability.
In addition, the Standard uses the term “available power” in R2.5 for an acceptable return limit. This term is not defined and cannot be numerically
determined at this time. FirstEnergy requests for DT to provide a definition for this term and a specific numerical methodology for determining “available
power” at a solar site for given conditions.
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Jeffrey Streifling - NB Power Corporation - 1
Answer
Document Name
Comment
Attachment 1 to PRC-029-1 Draft 4 is a set of performance-based criteria for voltage ride-through. Footnote 10 to Tables 1 and 2 in said Attachment 1
is a design consideration that does not belong in the set of performance requirements. It should be removed.
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Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Document Name
Comment
AEPC signed on to ACES comments, please see their commments.
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
NA
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Karl Blaszkowski - CMS Energy - Consumers Energy Company - 3
Answer
Document Name
Comment
The exemptions are only for equipment that is in-service by the effective date of PRC-029-1. The concern remains that facilities under construction at
the effective date might not meet the requirements. The time needed to perform studies of the ongoing projects would be limited. Without an
exemption for new equipment, we may be at risk of having to sacrifice protection to meet requirements of the standard.
If an exemption is used, the standard requires “Identification of the specific piece(s) of hardware causing the limitation” and “Technical documentation
verifying the limitation is due to hardware that would need to be physically replaced to meet all Ride-through criteria”. Our existing limitation memo from
one of our suppliers is vague. We are not sure how successful we would be in obtaining the required detailed information. Further, the standard
requires that we “Provide a copy of the acceptance of a hardware limitation by the CEA…”. I think this means we would need the Compliance
Enforcement Authority to accept our statement that there is a hardware limitation, likely making a vague response from a manufacturer unacceptable.
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Thomas Foltz - AEP - 5
Answer
Document Name
Comment
While AEP appreciates the revisions to R4.2 which limits the sharing of material deemed proprietary by the manufacturer, the obligations (including
footnote 11) nonetheless assume that the GO will still be able to obtain that material. If a manufacturer considers such information to be proprietary, it
would be unlikely they would be willing to share it with the GO, even if the GO is obligated to obtain it in the standard. AEP recommends the removal of
footnote 11 or that exclusions be included to accommodate situations where the manufacturer refuses to provide proprietary information to the GO.
AEP recommends removing the phrase “demonstrate the design of each IBR” from the proposed standard and returning to the original event-based
requirements. The phrase may prove difficult to fully comply with, as a Functional Entity would have to know the design of the collector system and
parameters and run the models correctly to demonstrate this. Much of this needed information would need to be provided by the manufacturer, which
may require non-disclosure agreements.
If the design aspect is retained, then AEP offers the following: R1, R2 and R3 state, “Each Generator Owner shall ensure the design and operation is
such…” Operation of the equipment is the GOP’s responsibility, not the GO’s. If the SDT’s intention was regarding the design of the system, AEP
recommends revising the language to instead state, “Each Generator Owner shall ensure the *operational design* is such…”.
AEP is concerned by the inclusion of the phrase “through other mechanisms” in this standard, and recommend it be removed from Requirements 2.1.3,
2.2, and 2.5 as we believe it could be misinterpreted or misunderstood. It is not clear how the obligations are or are-not met when “through other
mechanisms” is introduced. For example, if the TOP would need the GO to do “X” instead of “Y”, and if the GO fails to do “X”, has the GO failed to
comply with the obligation or does this put the requirement *outside* of the standard? AEP instead recommends using the language from the Technical
Rationale which references “or according to requirements specified.”
AEP believes the text “Provide any response to additional information requested” in R 4.2.1 is confusing and should be clarified, as it is not clear what
the intended meaning or purpose is of “any response.” AEP suggests it instead state “Provide any additional information requested by the
associated…”.
There needs to be an exemption for system-related causes of ride-through failure. IBRs should be exempt from ride-through requirements in R1 through
R3 if tripping or failure to ride through is attributable to any of the following:
1. Sub-synchronous control interaction or ferro-resonance involving series compensation confirmed by the TOP, RC, TP, or PC
2. Unstable behavior of other nearby IBRs or dynamic devices such as FACTS or HVDC confirmed by the TOP, RC, TP, or PC
3. System short circuit levels during contingencies below the level of IBR stable operation confirmed by the TOP, RC, TP, or PC
4. System-level transient or oscillatory instabilities confirmed by the TOP, RC, TP, or PC
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name
Comment
The exemptions are only for equipment that is in-service by the effective date of PRC-029-1. The concern remains that facilities under construction at
the effective date might not meet the requirements. The time needed to perform studies of the ongoing projects would be limited. Without an
exemption for new equipment, we may be at risk of having to sacrifice protection to meet requirements of the standard.
If an exemption is used, the standard requires “Identification of the specific piece(s) of hardware causing the limitation” and “Technical documentation
verifying the limitation is due to hardware that would need to be physically replaced to meet all Ride-through criteria”. Our existing limitation memo from
one of our suppliers is vague. We are not sure how successful we would be in obtaining the required detailed information. Further, the standard
requires that we “Provide a copy of the acceptance of a hardware limitation by the CEA…”. I think this means we would need the Compliance
Enforcement Authority to accept our statement that there is a hardware limitation, likely making a vague response from a manufacturer unacceptable.
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Revise Standard Section A. Introduction, 4. Applicability, 4.2 Facilities, 4.2.2, for the phrase “connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.”. Most GO’s do not have the ability to assess the
“common point of connection”. Either an action to ensure TO notifies GO of applicability or change to the “point of interconnect” is required.
Revise Technical Rationale to define the mechanism and associated parameters of an “event trigger” for the GO since it is not defined, and guidance is
required.
Revise Standard R4.2 to include a time limitation for the CEA to accept or reject a hardware limitation. Failure to define the time limitation leaves the
GO subject to compliance risks and a possible noncompliance. Additionally, define process actions for a potential CEA denial, appeal process, etc.
For Standard R4.1, define if month is “calendar” month, otherwise, define time-period for “Document information supporting the identified hardware
limitation no later than 12 months following the effective date of PRC-029-1…”.
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Updated Reminder
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough)
Additional Ballot and Non-binding Poll Open through September 30, 2024
Now Available
An additional ballot for PRC-029-1 - Frequency and Voltage Ride-through Requirements for
Inverter-based Resources and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels are open through 8 p.m. Eastern, Monday, September 30, 2024.
NOTE: This will be the last opportunity to vote on PRC-029-1. The proposed Standard will not be
posted for final ballot.
The Standards Committee approved waivers to the Standard Processes Manual at their December
2023 meeting. These waivers were sought by NERC Standards staff for reduced formal comment
and ballot periods. This will assist the drafting teams in expediting the standards development
process due to firm timeline expectations set by FERC Order 901. FERC Order 901 was issued under
Docket No. RM22-12-000 on October 19, 2023.
The standard drafting team’s considerations of the responses received from the last comment
period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot
pool. Contact ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
Balloting
Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here.
Note: Votes cast in previous ballots, will not carry over to additional ballots. It is the responsibility of
the registered voter in the ballot pools to place votes again. To ensure a quorum is reached, if you do
not want to vote affirmative or negative, cast an abstention.
RELIABILITY | RESILIENCE | SECURITY
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Director of Standards Development, Jamie Calderon (via
email) or at 404-960-0568. Subscribe to this project's observer mailing list by selecting "NERC Email
Distribution Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to
PRC-024 (Generator Ride-through) observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Ballot Open Reminder
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)| September 24, 2024
2
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough)
Formal Comment Period Open through September 30, 2024
Now Available
A formal comment period for PRC-029-1 - Frequency and Voltage Ride-through Requirements for
Inverter-based Resources, is open through 8 p.m. Eastern, Monday, September 30, 2024.
On August 15, 2024, the NERC Board of Trustees (Board) invoked Section 321 of the NERC Rules of
Procedure (ROP) to address critical and rapidly growing risk to the reliability of the Bulk Power
System associated with inverter-based resources (IBR) in response to FERC Order No. 901 directives.
PRC-029-1 (Frequency and Voltage Ride-through Requirements for Inverter-based Resources) is a
draft standard designed to establish capability-based and performance-based Ride-through
requirements for IBRs during grid disturbances. The draft standard failed to achieve consensus from
the Registered Ballot Body over multiple ballots, calling into question whether development would
be completed by FERC’s filing deadline of November 4, 2024, which resulted in the Board acting
under Section 321 of the ROP. Under this special authority, the Board directed the Standards
Committee to work with NERC to host a technical conference and to ballot an additional ballot of
PRC-029-1 within 45-days of the August 15 Board action.
The Standards Committee approved waivers to the Standard Processes Manual at their December
2023 meeting. These waivers were sought by NERC Standards staff for reduced formal comment and
ballot periods. This will assist the drafting teams in expediting the standards development process
due to firm timeline expectations set by FERC Order 901. FERC Order 901 was issued under Docket
No. RM22-12-000 on October 19, 2023.
Note: PRC-024-4 passed the recent additional ballot (conducted June 28 – July 8, 2024). This
standard will move to a final ballot when the PRC-029-1 ballots open (September 24-30, 2024) as
only non-substantive revision(s) were made.
Reminder Regarding Corporate RBB Memberships
Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
ballotadmin@nerc.net to assist with the removal of any duplicate registrations.
RELIABILITY | RESILIENCE | SECURITY
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
Additional ballots for the standard and implementation plan, as well as the non-binding polls of the
associated Violation Risk Factors and Violation Severity Levels will be conducted September 24-30,
2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Director of Standards Development, Jamie Calderon (via email)
or at 404-960-0568. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution
Lists" from the "Service" drop-down menu and specify “Project 2020-02 Modifications to PRC-024
(Generator Ride-through) observer list” in the Description Box.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 17, 2024
2
NERC Balloting Tool (/)
Dashboard (/)
Users
Ballots
Comment Forms
Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/350)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 AB 4 ST
Voting Start Date: 9/24/2024 12:01:00 AM
Voting End Date: 10/4/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 4
Total # Votes: 239
Total Ballot Pool: 267
Quorum: 89.51
Quorum Established Date: 10/4/2024 9:14:18 AM
Weighted Segment Value: 77.88
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
74
1
46
0.821
10
0.179
0
11
7
Segment:
2
8
0.7
6
0.6
1
0.1
0
0
1
Segment:
3
54
1
36
0.8
9
0.2
0
5
4
Segment:
4
14
1
9
0.75
3
0.25
0
1
1
Segment:
5
67
1
33
0.66
17
0.34
0
8
9
Segment:
6
45
1
23
0.697
10
0.303
0
6
6
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.5
5
0.5
0
0
0
0
0
Totals:
267
6.2
158
4.828
50
1.372
0
31
28
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Abstain
N/A
1
Ameren - Ameren
Services
Tamara Evey
Affirmative
N/A
1
American Transmission
Company, LLC
Amy Wilke
Affirmative
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Affirmative
N/A
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Affirmative
N/A
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Affirmative
N/A
1
Austin Energy
Thomas
Standifur
Abstain
N/A
Affirmative
N/A
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
NERC
Memo
Affirmative
N/A
Adrian Andreoiu
Abstain
N/A
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Travis
Grablander
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
Affirmative
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Affirmative
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Third-Party
Comments
1
Colorado Springs Utilities
Corey Walker
Negative
Third-Party
Comments
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Affirmative
N/A
1
Duke Energy
Katherine Street
Affirmative
N/A
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Affirmative
N/A
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Affirmative
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Negative
Comments
Submitted
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
Affirmative
N/A
1 - NERC Ver 4.2.1.0
Glencoe
Light and
Power
Terry Volkmann
© 2024
Machine
Name:
ATLVPEROWEB02
Commission
Tim Kelley
Ballot
Hayden Maples
Tricia Bynum
Segment
Organization
Voter
1
Great River Energy
Gordon Pietsch
1
Hydro One Networks, Inc.
Emma Halilovic
1
IDACORP - Idaho Power
Company
Sean Steffensen
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
1
International
Transmission Company
Holdings Corporation
Michael Moltane
1
JEA
1
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Abstain
N/A
None
N/A
Denise Sanchez
Affirmative
N/A
Gail Elliott
Affirmative
N/A
Joseph McClung
Affirmative
N/A
KAMO Electric
Cooperative
Micah Breedlove
Affirmative
N/A
1
Lakeland Electric
Larry Watt
Affirmative
N/A
1
Lincoln Electric System
Josh Johnson
None
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Matt Lewis
Abstain
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Nazra Gladu
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Abstain
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Negative
Third-Party
Comments
Negative
Comments
Submitted
1
NB Power Corporation
Jeffrey Streifling
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ijad Dewan
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Affirmative
N/A
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Affirmative
N/A
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug Peterchuck
Affirmative
N/A
1
Oncor Electric Delivery
Byron Booker
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Affirmative
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Affirmative
N/A
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
None
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
None
N/A
None
N/A
1
Seminole Electric
Kristine Ward
Cooperative, Inc.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Broc Bruton
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Affirmative
N/A
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Abstain
N/A
1
Western Area Power
Administration
Ben Hammer
Negative
Third-Party
Comments
1
Xcel Energy, Inc.
Eric Barry
Affirmative
N/A
2
California ISO
Darcy O'Connell
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Affirmative
N/A
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Affirmative
N/A
Affirmative
N/A
2
New York Independent
Gregory Campoli
System
Operator
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB02
Jennie Wike
Segment
Organization
Voter
2
PJM Interconnection,
L.L.C.
Thomas Foster
2
Southwest Power Pool,
Inc. (RTO)
3
Designated
Proxy
NERC
Memo
Affirmative
N/A
Joshua Phillips
None
N/A
APS - Arizona Public
Service Co.
Jessica Lopez
Affirmative
N/A
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Lovita Griffin
Abstain
N/A
3
Avista - Avista
Corporation
Robert Follini
Affirmative
N/A
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Negative
Comments
Submitted
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Lincoln Burton
Affirmative
N/A
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
None
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo
Pesantez
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Elizabeth Davis
Ballot
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Entergy
James Keele
Negative
Comments
Submitted
3
Evergy
Marcus Moor
Affirmative
N/A
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
3
Exelon
Kinte Whitehead
Affirmative
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Negative
Comments
Submitted
3
Great River Energy
Michael
Brytowski
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
Affirmative
N/A
3
Lincoln Electric System
Sam Christensen
Affirmative
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
Abstain
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Affirmative
N/A
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Abstain
N/A
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
3
Nebraska Public Power
District
Tony Eddleman
Affirmative
N/A
Negative
Comments
Submitted
3
NiSource - Northern
Steven
Indiana Public Service
Taddeucci
Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
3
North Carolina Electric
Membership Corporation
Chris Dimisa
3
NW Electric Power
Cooperative, Inc.
Heath Henry
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
3
Omaha Public Power
District
3
Designated
Proxy
NERC
Memo
Affirmative
N/A
Affirmative
N/A
Affirmative
N/A
David Heins
Affirmative
N/A
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
3
Pacific Gas and Electric
Company
Sandra Ellis
Affirmative
N/A
3
Platte River Power
Authority
Richard Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Negative
Comments
Submitted
3
PPL - Louisville Gas and
Electric Co.
James Frank
Affirmative
N/A
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
None
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Usama Tahir
None
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Affirmative
N/A
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
Affirmative
N/A
3
Southern Company Joel Dembowski
Alabama
PowerName:
Company
© 2024 - NERC Ver 4.2.1.0
Machine
ATLVPEROWEB02
Scott Brame
Ballot
Dane Rogers
Bob Cardle
Segment
Designated
Proxy
Voter
3
Tennessee Valley
Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Ryan Walter
None
N/A
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Nicholas Friebel
Affirmative
N/A
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Affirmative
N/A
4
Austin Energy
Tony Hua
Abstain
N/A
4
Buckeye Power, Inc.
Jason Procuniar
Negative
Third-Party
Comments
4
CMS Energy Consumers Energy
Company
Aric Root
Negative
Comments
Submitted
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Negative
Comments
Submitted
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Affirmative
N/A
4
Oklahoma Municipal
Power Authority
Michael Watt
Affirmative
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Affirmative
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
George Pino
None
N/A
4
Utility Services, Inc.
Carver Powers
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
4
Western Power Pool
Kevin Conway
Affirmative
N/A
Ryan Strom
Scott Brame
Tim Kelley
Ballot
NERC
Memo
Organization
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
AEP
Thomas Foltz
Abstain
N/A
5
AES - AES Corporation
Ruchi Shah
Negative
Comments
Submitted
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
American Municipal
Power
Amy Ritts
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Affirmative
N/A
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Affirmative
N/A
5
Austin Energy
Michael Dillard
Abstain
N/A
5
Avista - Avista
Corporation
Glen Farmer
Affirmative
N/A
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Negative
Comments
Submitted
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
5
Bonneville Power
Administration
Milli Chennell
Affirmative
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
Affirmative
N/A
5
CMS Energy Consumers Energy
Company
David
Greyerbiehl
Negative
Comments
Submitted
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Affirmative
N/A
Negative
Comments
Submitted
5 - NERC Ver 4.2.1.0
Constellation
Alison MacKellar
© 2024
Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Negative
Third-Party
Comments
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
None
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
Abstain
N/A
5
Entergy - Entergy
Services, Inc.
Gail Golden
Negative
Comments
Submitted
5
Evergy
Jeremy Harris
Affirmative
N/A
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Negative
Comments
Submitted
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
Negative
Third-Party
Comments
5
Grid Strategies LLC
Michael Goggin
Affirmative
N/A
5
Imperial Irrigation District
Tino Zaragoza
Affirmative
N/A
5
Invenergy LLC
Rhonda Jones
Negative
Comments
Submitted
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Affirmative
N/A
5
Los Angeles Department
of Water and Power
Robert Kerrigan
None
N/A
5
Lower Colorado River
Authority
Teresa Krabe
Abstain
N/A
5
LS Power Development,
LLC
C. A. Campbell
None
N/A
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
5
Manitoba Hydro
Kristy-Lee Young
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Muscatine Power and
Water
Chance Back
Abstain
N/A
5
National Grid USA
Robin Berry
Negative
Third-Party
Comments
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
None
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
Negative
Comments
Submitted
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
Affirmative
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
Affirmative
N/A
5
Ontario Power Generation
Inc.
Constantin
Chitescu
Negative
Comments
Submitted
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Affirmative
N/A
5
Pacific Gas and Electric
Company
Tyler Brun
Affirmative
N/A
5
Pattern Operators LP
George E Brown
Negative
Third-Party
Comments
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Affirmative
N/A
5
PSEG Nuclear LLC
Tim Kucey
None
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
None
N/A
Affirmative
N/A
5
Sacramento Municipal
Ryder Couch
Utility District
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Scott Brame
Bob Cardle
Tim Kelley
Segment
Organization
Voter
5
Salt River Project
Thomas Johnson
5
Seminole Electric
Cooperative, Inc.
5
Designated
Proxy
NERC
Memo
Affirmative
N/A
Melanie Wong
None
N/A
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Affirmative
N/A
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Affirmative
N/A
5
Tennessee Valley
Authority
Darren Boehm
Abstain
N/A
5
TransAlta Corporation
Ashley Scheelar
None
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
Affirmative
N/A
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Abstain
N/A
5
Vistra Energy
Daniel
Roethemeyer
Negative
Comments
Submitted
5
WEC Energy Group, Inc.
Michelle Hribar
Negative
Comments
Submitted
5
Xcel Energy, Inc.
Gerry Huitt
Affirmative
N/A
6
AEP
Mathew Miller
Abstain
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Marcus Bortman
Affirmative
N/A
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Affirmative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Imane Mrini
Abstain
N/A
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Israel Perez
Ballot
Adam Burlock
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
Negative
Comments
Submitted
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Affirmative
N/A
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
6
Duke Energy
John Sturgeon
Affirmative
N/A
6
Edison International Southern California
Edison Company
Stephanie Kenny
Affirmative
N/A
6
Entergy
Julie Hall
None
N/A
6
Evergy
Tiffany Lake
Affirmative
N/A
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Negative
Comments
Submitted
6
Great River Energy
Brian Meloy
None
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Invenergy LLC
Colin Chilcoat
Negative
Comments
Submitted
6
Lakeland Electric
Paul Shipps
Affirmative
N/A
6
Lincoln Electric System
Eric Ruskamp
Affirmative
N/A
6
Los Angeles Department
of Water and Power
Anton Vu
Abstain
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
None
N/A
Affirmative
N/A
© 2024
Machine
6 - NERC Ver 4.2.1.0
Manitoba
HydroName: ATLVPEROWEB02
Brandin Stoesz
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Muscatine Power and
Water
Nicholas Burns
Abstain
N/A
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Affirmative
N/A
6
NiSource - Northern
Indiana Public Service
Co.
Rebecca Blair
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Negative
Comments
Submitted
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Affirmative
N/A
6
Omaha Public Power
District
Shonda McCain
Affirmative
N/A
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Affirmative
N/A
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
None
N/A
6
Sacramento Municipal
Utility District
Charles Norton
Tim Kelley
Affirmative
N/A
6
Salt River Project
Timothy Singh
Israel Perez
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Bret Galbraith
None
N/A
6
Snohomish County PUD
No. 1
John Liang
Affirmative
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Tennessee Valley
Authority
Armando
Rodriguez
Abstain
N/A
6
WEC Energy Group, Inc.
David Boeshaar
Negative
Comments
Submitted
6
Xcel Energy, Inc.
Steve Szablya
Affirmative
N/A
10
Northeast Power
Coordinating Council
Gerry Dunbar
Affirmative
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Affirmative
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
Greg Sorenson
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/350)
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) Implementation Plan AB 4 OT
Voting Start Date: 9/24/2024 12:01:00 AM
Voting End Date: 10/4/2024 8:00:00 PM
Ballot Type: OT
Ballot Activity: AB
Ballot Series: 4
Total # Votes: 240
Total Ballot Pool: 271
Quorum: 88.56
Quorum Established Date: 10/4/2024 9:19:35 AM
Weighted Segment Value: 77.89
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
75
1
45
0.833
9
0.167
1
12
8
Segment:
2
8
0.7
6
0.6
1
0.1
0
0
1
Segment:
3
55
1
37
0.804
9
0.196
0
5
4
Segment:
4
14
1
9
0.75
3
0.25
0
1
1
Segment:
5
68
1
34
0.667
17
0.333
0
7
10
Segment:
6
46
1
23
0.697
10
0.303
0
6
7
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
9
0
0
0
0
0
0
0
0
0
Segment:
10
5
0.4
4
0.4
0
0
0
1
0
Totals:
271
6.1
158
4.751
49
1.349
1
32
31
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Abstain
N/A
1
Ameren - Ameren
Services
Tamara Evey
Affirmative
N/A
1
American Transmission
Company, LLC
Amy Wilke
Affirmative
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Affirmative
N/A
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Affirmative
N/A
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Affirmative
N/A
1
Austin Energy
Thomas
Standifur
Abstain
N/A
Affirmative
N/A
1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Corporation
Segment
Organization
Voter
1
Balancing Authority of
Northern California
Kevin Smith
1
BC Hydro and Power
Authority
1
Designated
Proxy
NERC
Memo
Affirmative
N/A
Adrian Andreoiu
Abstain
N/A
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Travis
Grablander
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
None
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Affirmative
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Third-Party
Comments
1
Colorado Springs Utilities
Corey Walker
Negative
Third-Party
Comments
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Affirmative
N/A
1
Duke Energy
Katherine Street
Affirmative
N/A
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Affirmative
N/A
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Affirmative
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Negative
Comments
Submitted
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
Negative
No Comment
Submitted
1 - NERC Ver 4.2.1.0
Glencoe
Light and
Power
Terry Volkmann
© 2024
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Name:
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Commission
Tim Kelley
Ballot
Hayden Maples
Tricia Bynum
Segment
Organization
Voter
1
Great River Energy
Gordon Pietsch
1
Hydro One Networks, Inc.
Emma Halilovic
1
IDACORP - Idaho Power
Company
Sean Steffensen
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
1
International
Transmission Company
Holdings Corporation
Michael Moltane
1
JEA
1
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Abstain
N/A
None
N/A
Denise Sanchez
Affirmative
N/A
Gail Elliott
Affirmative
N/A
Joseph McClung
Affirmative
N/A
KAMO Electric
Cooperative
Micah Breedlove
Affirmative
N/A
1
Lakeland Electric
Larry Watt
Affirmative
N/A
1
Lincoln Electric System
Josh Johnson
None
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Matt Lewis
Abstain
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Nazra Gladu
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Abstain
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Negative
Third-Party
Comments
Abstain
N/A
1
NB Power Corporation
Jeffrey Streifling
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Ijad Dewan
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Affirmative
N/A
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Affirmative
N/A
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug Peterchuck
Affirmative
N/A
1
Oncor Electric Delivery
Byron Booker
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Affirmative
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
Affirmative
N/A
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
None
N/A
1
Public Utility District No. 1
of Chelan County
Diane E Landry
Affirmative
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
None
N/A
Wayne
Guttormson
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Broc Bruton
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
None
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Affirmative
N/A
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Abstain
N/A
1
Western Area Power
Administration
Ben Hammer
Negative
Third-Party
Comments
1
Xcel Energy, Inc.
Eric Barry
Affirmative
N/A
2
California ISO
Darcy O'Connell
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Affirmative
N/A
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
Affirmative
N/A
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Midcontinent
ISO,
Inc. ATLVPEROWEB02
Bobbi Welch
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Name:
Jennie Wike
Segment
Organization
Voter
2
New York Independent
System Operator
Gregory Campoli
2
PJM Interconnection,
L.L.C.
Thomas Foster
2
Southwest Power Pool,
Inc. (RTO)
3
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Affirmative
N/A
Joshua Phillips
None
N/A
APS - Arizona Public
Service Co.
Jessica Lopez
Affirmative
N/A
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Lovita Griffin
Abstain
N/A
3
Avista - Avista
Corporation
Robert Follini
Affirmative
N/A
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Negative
Comments
Submitted
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Lincoln Burton
Affirmative
N/A
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
None
N/A
Affirmative
N/A
3
Duke Energy - Florida
Marcelo
PowerMachine
Corporation
Pesantez
© 2024 - NERC Ver 4.2.1.0
Name: ATLVPEROWEB02
Elizabeth Davis
Carly Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Entergy
James Keele
Negative
Comments
Submitted
3
Evergy
Marcus Moor
Affirmative
N/A
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
3
Exelon
Kinte Whitehead
Affirmative
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Negative
Comments
Submitted
3
Great River Energy
Michael
Brytowski
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
Affirmative
N/A
3
Lincoln Electric System
Sam Christensen
Affirmative
N/A
3
Los Angeles Department
of Water and Power
Fausto Serratos
Abstain
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Affirmative
N/A
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Abstain
N/A
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
3
Nebraska Public Power
District
Tony Eddleman
Affirmative
N/A
Negative
Comments
Submitted
3
NiSource - Northern
Steven
Indiana Public Service
Taddeucci
Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
3
North Carolina Electric
Membership Corporation
Chris Dimisa
3
NW Electric Power
Cooperative, Inc.
Heath Henry
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
3
Omaha Public Power
District
3
Designated
Proxy
NERC
Memo
Affirmative
N/A
Affirmative
N/A
Affirmative
N/A
David Heins
Affirmative
N/A
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
3
Pacific Gas and Electric
Company
Sandra Ellis
Affirmative
N/A
3
Platte River Power
Authority
Richard Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Negative
Comments
Submitted
3
PPL - Louisville Gas and
Electric Co.
James Frank
Affirmative
N/A
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
None
N/A
3
Public Utility District No. 1
of Chelan County
Joyce Gundry
Affirmative
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Usama Tahir
None
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Affirmative
N/A
Affirmative
N/A
3
Snohomish County PUD
Holly Chaney
No. 1 Machine Name: ATLVPEROWEB02
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Scott Brame
Ballot
Dane Rogers
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Southern Company Alabama Power
Company
Joel Dembowski
Affirmative
N/A
3
Tennessee Valley
Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Ryan Walter
None
N/A
3
WEC Energy Group, Inc.
Christine Kane
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Nicholas Friebel
Affirmative
N/A
4
Alliant Energy
Corporation Services, Inc.
Larry Heckert
Affirmative
N/A
4
Austin Energy
Tony Hua
Abstain
N/A
4
Buckeye Power, Inc.
Jason Procuniar
Negative
Third-Party
Comments
4
CMS Energy Consumers Energy
Company
Aric Root
Negative
Comments
Submitted
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Negative
Comments
Submitted
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Affirmative
N/A
4
Oklahoma Municipal
Power Authority
Michael Watt
Affirmative
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Affirmative
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ryan Strom
Scott Brame
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Seminole Electric
Cooperative, Inc.
George Pino
None
N/A
4
Utility Services, Inc.
Carver Powers
Affirmative
N/A
4
Western Power Pool
Kevin Conway
Affirmative
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
AES - AES Corporation
Ruchi Shah
Affirmative
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
American Municipal
Power
Amy Ritts
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Affirmative
N/A
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Affirmative
N/A
5
Austin Energy
Michael Dillard
Abstain
N/A
5
Avista - Avista
Corporation
Glen Farmer
Affirmative
N/A
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Negative
Comments
Submitted
5
Black Hills Corporation
Sheila Suurmeier
Negative
Comments
Submitted
5
Bonneville Power
Administration
Milli Chennell
Affirmative
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
Affirmative
N/A
5
CMS Energy Consumers Energy
Company
David
Greyerbiehl
Negative
Comments
Submitted
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
5
Colorado Springs Utilities
Jeffrey Icke
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Affirmative
N/A
5
Constellation
Alison MacKellar
Negative
Comments
Submitted
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Affirmative
N/A
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
None
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
Negative
Comments
Submitted
5
Entergy - Entergy
Services, Inc.
Gail Golden
Negative
Comments
Submitted
5
Evergy
Jeremy Harris
Affirmative
N/A
5
FirstEnergy - FirstEnergy
Corporation
Matthew
Augustin
Negative
Comments
Submitted
5
Great River Energy
Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
Negative
Third-Party
Comments
5
Grid Strategies LLC
Michael Goggin
Negative
Comments
Submitted
5
Imperial Irrigation District
Tino Zaragoza
Affirmative
N/A
5
Invenergy LLC
Rhonda Jones
Negative
Comments
Submitted
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Affirmative
N/A
None
N/A
5
Los Angeles Department
Robert Kerrigan
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of Water and Power
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Lower Colorado River
Authority
Teresa Krabe
Abstain
N/A
5
LS Power Development,
LLC
C. A. Campbell
None
N/A
5
Manitoba Hydro
Kristy-Lee Young
Affirmative
N/A
5
Muscatine Power and
Water
Chance Back
Abstain
N/A
5
National Grid USA
Robin Berry
Negative
Third-Party
Comments
5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
None
N/A
5
New York Power Authority
Zahid Qayyum
Negative
Third-Party
Comments
5
North Carolina Electric
Membership Corporation
Reid Cashion
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
Negative
Comments
Submitted
5
OGE Energy - Oklahoma
Gas and Electric Co.
Patrick Wells
None
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power
District
Kayleigh
Wilkerson
Affirmative
N/A
5
Ontario Power
Generation Inc.
Constantin
Chitescu
Negative
Comments
Submitted
5
OTP - Otter Tail Power
Company
Stacy Wahlund
Affirmative
N/A
5
Pacific Gas and Electric
Company
Tyler Brun
Affirmative
N/A
5
Pattern Operators LP
George E Brown
Negative
Third-Party
Comments
Affirmative
N/A
5
PPL - Louisville Gas and
Julie Hostrander
ElectricMachine
Co.
© 2024 - NERC Ver 4.2.1.0
Name: ATLVPEROWEB02
Scott Brame
Bob Cardle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
PSEG Nuclear LLC
Tim Kucey
None
N/A
5
Public Utility District No. 1
of Chelan County
Rebecca Zahler
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
None
N/A
5
Sacramento Municipal
Utility District
Ryder Couch
Tim Kelley
Affirmative
N/A
5
Salt River Project
Thomas Johnson
Israel Perez
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Melanie Wong
None
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Affirmative
N/A
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Affirmative
N/A
5
Tennessee Valley
Authority
Darren Boehm
Abstain
N/A
5
TransAlta Corporation
Ashley Scheelar
None
N/A
5
Tri-State G and T
Association, Inc.
Sergio Banuelos
Affirmative
N/A
5
U.S. Bureau of
Reclamation
Wendy Kalidass
Abstain
N/A
5
Vistra Energy
Daniel
Roethemeyer
Negative
Comments
Submitted
5
WEC Energy Group, Inc.
Michelle Hribar
Negative
Comments
Submitted
5
Xcel Energy, Inc.
Gerry Huitt
Affirmative
N/A
6
AEP
Mathew Miller
Abstain
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
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Adam Burlock
David Vickers
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
APS - Arizona Public
Service Co.
Marcus Bortman
Affirmative
N/A
6
Arkansas Electric
Cooperative Corporation
Bruce Walkup
Affirmative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Imane Mrini
Abstain
N/A
6
Berkshire Hathaway PacifiCorp
Lindsay Wickizer
Negative
Comments
Submitted
6
Black Hills Corporation
Rachel Schuldt
Negative
Comments
Submitted
6
Bonneville Power
Administration
Tanner Brier
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Jason Chandler
Affirmative
N/A
6
Constellation
Kimberly Turco
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Negative
Comments
Submitted
6
Duke Energy
John Sturgeon
Affirmative
N/A
6
Edison International Southern California
Edison Company
Stephanie Kenny
Affirmative
N/A
6
Entergy
Julie Hall
None
N/A
6
Evergy
Tiffany Lake
Affirmative
N/A
6
FirstEnergy - FirstEnergy
Corporation
Stacey Sheehan
Negative
Comments
Submitted
6
Great River Energy
Brian Meloy
None
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Invenergy LLC
Colin Chilcoat
Negative
Comments
Submitted
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Hayden Maples
Denise Sanchez
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Lakeland Electric
Paul Shipps
Affirmative
N/A
6
Lincoln Electric System
Eric Ruskamp
Affirmative
N/A
6
Los Angeles Department
of Water and Power
Anton Vu
Abstain
N/A
6
Luminant - Luminant
Energy
Russell Ferrell
None
N/A
6
Manitoba Hydro
Brandin Stoesz
Affirmative
N/A
6
Muscatine Power and
Water
Nicholas Burns
Abstain
N/A
6
New York Power Authority
Shelly Dineen
Negative
Third-Party
Comments
6
NextEra Energy - Florida
Power and Light Co.
Justin Welty
Affirmative
N/A
6
NiSource - Northern
Indiana Public Service
Co.
Rebecca Blair
Negative
Comments
Submitted
6
NRG - NRG Energy, Inc.
Martin Sidor
Negative
Comments
Submitted
6
OGE Energy - Oklahoma
Gas and Electric Co.
Ashley F Stringer
Affirmative
N/A
6
Omaha Public Power
District
Shonda McCain
Affirmative
N/A
6
Portland General Electric
Co.
Stefanie Burke
None
N/A
6
Powerex Corporation
Raj Hundal
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Affirmative
N/A
6
PSEG - PSEG Energy
Resources and Trade
LLC
Laura Wu
None
N/A
6
Public Utility District No. 1
of Chelan County
Tamarra Hardie
None
N/A
Affirmative
N/A
6
Sacramento Municipal
Charles Norton
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Utility District
Tim Kelley
Segment
Organization
Voter
6
Salt River Project
Timothy Singh
6
Seminole Electric
Cooperative, Inc.
6
Designated
Proxy
Israel Perez
Ballot
NERC
Memo
Affirmative
N/A
Bret Galbraith
None
N/A
Snohomish County PUD
No. 1
John Liang
Affirmative
N/A
6
Southern Company Southern Company
Generation
Ron Carlsen
Affirmative
N/A
6
Tennessee Valley
Authority
Armando
Rodriguez
Abstain
N/A
6
WEC Energy Group, Inc.
David Boeshaar
Negative
Comments
Submitted
6
Xcel Energy, Inc.
Steve Szablya
Affirmative
N/A
10
Northeast Power
Coordinating Council
Gerry Dunbar
Affirmative
N/A
10
ReliabilityFirst
Tyler
Schwendiman
Affirmative
N/A
10
SERC Reliability
Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Abstain
N/A
Greg Sorenson
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BALLOT RESULTS
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-029-1 | Non-binding Poll AB 4 NB
Voting Start Date: 9/24/2024 12:01:00 AM
Voting End Date: 10/4/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 4
Total # Votes: 218
Total Ballot Pool: 251
Quorum: 86.85
Quorum Established Date: 10/4/2024 9:20:15 AM
Weighted Segment Value: 73.6
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
1
71
1
41
0.82
9
0.18
13
8
Segment:
2
7
0.3
2
0.2
1
0.1
3
1
Segment:
3
51
1
30
0.769
9
0.231
7
5
Segment:
4
14
1
9
0.75
3
0.25
1
1
Segment:
5
62
1
28
0.636
16
0.364
8
10
Segment:
6
41
1
17
0.654
9
0.346
7
8
Segment:
7
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
Segment:
9
0
0
0
0
0
0
0
0
Segment
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
10
5
0.4
4
0.4
0
0
1
0
Totals:
251
5.7
131
4.229
47
1.471
40
33
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Abstain
N/A
1
Ameren - Ameren
Services
Tamara Evey
Abstain
N/A
1
American Transmission
Company, LLC
Amy Wilke
Affirmative
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Affirmative
N/A
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Affirmative
N/A
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Affirmative
N/A
1
Austin Energy
Thomas
Standifur
Abstain
N/A
1
Avista - Avista
Corporation
Mike Magruder
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
BC Hydro and Power
Authority
Adrian Andreoiu
Abstain
N/A
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Black Hills Corporation
Travis
Grablander
Negative
Comments
Submitted
1
Bonneville Power
Administration
Kamala RogersHolliday
Affirmative
N/A
1
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
Affirmative
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Negative
Comments
Submitted
1
Colorado Springs Utilities
Corey Walker
Negative
Comments
Submitted
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Affirmative
N/A
1
Duke Energy
Katherine Street
Affirmative
N/A
1
Edison International Southern California
Edison Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Negative
Comments
Submitted
1
Evergy
Kevin Frick
Affirmative
N/A
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Affirmative
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Negative
Comments
Submitted
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
1
Glencoe Light and Power
Commission
Terry Volkmann
Affirmative
N/A
1 - NERC Ver 4.2.1.0
Great River
Energy
Gordon Pietsch
© 2024
Machine
Name: ATLVPEROWEB02
Affirmative
N/A
Hayden Maples
Tricia Bynum
Segment
Organization
Voter
1
Hydro One Networks, Inc.
Emma Halilovic
1
IDACORP - Idaho Power
Company
Sean Steffensen
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
1
International Transmission
Company Holdings
Corporation
Michael Moltane
1
JEA
1
Designated
Proxy
NERC
Memo
Abstain
N/A
None
N/A
Denise Sanchez
Affirmative
N/A
Gail Elliott
Affirmative
N/A
Joseph McClung
Affirmative
N/A
KAMO Electric
Cooperative
Micah Breedlove
Affirmative
N/A
1
Lakeland Electric
Larry Watt
Affirmative
N/A
1
Lincoln Electric System
Josh Johnson
None
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department
of Water and Power
faranak sarbaz
Abstain
N/A
1
Lower Colorado River
Authority
Matt Lewis
Abstain
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Abstain
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Negative
Comments
Submitted
1
NB Power Corporation
Jeffrey Streifling
Affirmative
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
None
N/A
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Ijad Dewan
Ballot
Andy Fuhrman
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Northeast Missouri
Electric Power
Cooperative
Brett Douglas
Affirmative
N/A
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug Peterchuck
Affirmative
N/A
1
Oncor Electric Delivery
Byron Booker
Broc Bruton
Affirmative
N/A
1
Pacific Gas and Electric
Company
Marco Rios
Bob Cardle
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
Negative
Comments
Submitted
1
PPL Electric Utilities
Corporation
Michelle
McCartney
Longo
None
N/A
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
None
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
None
N/A
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
None
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed
Derbas
Affirmative
N/A
Affirmative
N/A
1
Sho-Me Power Electric
Olivia Olson
Cooperative
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Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Affirmative
N/A
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Abstain
N/A
1
Unisource - Tucson
Electric Power Co.
Jessica Cordero
Abstain
N/A
1
Western Area Power
Administration
Ben Hammer
Negative
Comments
Submitted
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Helen Lainis
Abstain
N/A
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Abstain
N/A
2
New York Independent
System Operator
Gregory Campoli
Abstain
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Joshua Phillips
None
N/A
3
APS - Arizona Public
Service Co.
Jessica Lopez
Affirmative
N/A
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Elizabeth Davis
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3
Arkansas Electric
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Affirmative
N/A
3
Associated Electric
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Todd Bennett
Affirmative
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3
Austin Energy
Lovita Griffin
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3
Avista - Avista
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Affirmative
N/A
3
BC Hydro and Power
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Ming Jiang
Abstain
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3
Berkshire Hathaway
Energy - MidAmerican
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Negative
Comments
Submitted
3
Black Hills Corporation
Josh Combs
Negative
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Submitted
3
Central Electric Power
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Adam Weber
Affirmative
N/A
3
CMS Energy - Consumers
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Negative
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Affirmative
N/A
3
Con Ed - Consolidated
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Lincoln Burton
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3
DTE Energy - Detroit
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Marvin Johnson
None
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3
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Affirmative
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Heath Henry
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Affirmative
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Company
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None
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Larry Heckert
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Jason Procuniar
Negative
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Negative
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Katrina Lyons
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George Pino
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Utility Services, Inc.
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Western Power Pool
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5
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AES - AES Corporation
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Affirmative
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Associated Electric
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Chuck Booth
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Negative
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Milli Chennell
Affirmative
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California Department of
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ASM Mostafa
None
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CMS Energy - Consumers
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Negative
Comments
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Colorado Springs Utilities
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Affirmative
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Con Ed - Consolidated
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Michelle Pagano
Affirmative
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5
Constellation
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Negative
Comments
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Dairyland Power
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Affirmative
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Decatur Energy Center
LLC
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Negative
Comments
Submitted
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DTE Energy - Detroit
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Mohamad
Elhusseini
None
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5
Duke Energy
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Affirmative
N/A
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Edison International Southern California
Edison Company
Selene Willis
Affirmative
N/A
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Enel Green Power
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Negative
Comments
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Entergy - Entergy
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Gail Golden
Negative
Comments
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Evergy
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FirstEnergy - FirstEnergy
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Affirmative
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Greybeard Compliance
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Mike Gabriel
Negative
Comments
Submitted
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Grid Strategies LLC
Michael Goggin
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5
Imperial Irrigation District
Tino Zaragoza
Affirmative
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5
JEA
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Affirmative
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Lincoln Electric System
Brittany Millard
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Los Angeles Department
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National Grid USA
Robin Berry
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NB Power Corporation New Brunswick Power
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Fon Hiew
None
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5
New York Power Authority
Zahid Qayyum
Negative
Comments
Submitted
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Reid Cashion
Affirmative
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NRG - NRG Energy, Inc.
Patricia Lynch
Negative
Comments
Submitted
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Patrick Wells
Affirmative
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
Affirmative
N/A
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Constantin
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Affirmative
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5
OTP - Otter Tail Power
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Stacy Wahlund
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Pacific Gas and Electric
Company
Tyler Brun
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George E Brown
Negative
Comments
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PPL - Louisville Gas and
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None
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5
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Tim Kucey
None
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5
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Salt River Project
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Melanie Wong
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and Electric
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Affirmative
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Southern Company Southern Company
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Affirmative
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5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
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Authority
Darren Boehm
None
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Tri-State G and T
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Sergio Banuelos
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5
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Con Ed - Consolidated
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Jason Chandler
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Constellation
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Rebecca Blair
Negative
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Martin Sidor
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Ashley F Stringer
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Linn Oelker
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Southern Company Southern Company
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PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 3 of PRC-024-4 is posted for final ballot. Non-substantive corrections were identified
during the last additional ballot. This draft includes those corrections.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process Manual
December 13, 2023
25-day formal comment period with initial ballot
March 27 - April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
Anticipated Actions
Date
Final ballot
September 25 –
September 30, 2024
Board Adoption
October 8, 2024
Final Draft of PRC-024-4
September 2024
Page 1 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Final Draft of PRC-024-4
September 2024
Page 2 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
A. Introduction
1.
Title:
Frequency and Voltage Protection Settings for Synchronous Generators,
Type 1 and Type 2 Wind Resources, and Synchronous Condensers
2.
Number:
PRC-024-4
3.
Purpose:
To assure that protection of synchronous generators, type 1 and type 2
wind resources, and synchronous condensers do not cause tripping
during defined frequency and voltage excursions in support of the Bulk
Power System (BPS).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Generator Owners that apply protection listed in Sections 4.2.1 or 4.2.2.
4.1.2. Transmission Owners that apply protection listed in Section 4.2.2.
4.1.3. Transmission Owners (in the Quebec Interconnection only) that own a
BES generator step-up (GSU) transformer or main power transformer
(MPT) 1 and apply protection listed in Section 4.2.1.
4.1.4. Planning Coordinators (in the Quebec Interconnection only)
4.2. Facilities 2:
4.2.1 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the generating resource(s); or (ii)
provide signals to the generating resource(s) to trip; and are applied to
the following:
4.2.1.1
Bulk Electric System (BES) synchronous generators.
4.2.1.2
BES GSU transformer(s) for synchronous generators.
4.2.1.3
High-side of the synchronous generator-connected unit
auxiliary transformer 3 (UAT) installed on BES generating
resource(s).
4.2.1.4
Individual dispersed power producing type 1 or type 2 wind
resource(s) identified in the BES Definition, Inclusion I4.
For the purpose of this standard, the MPT is the power transformer that steps up voltage from multiple small synchronous
generators (e.g. multiple small hydro generators connecting to a common bus) or from a type 1 or type 2 wind resource
collector station to transmission voltage .
2 It is not required to install or activate the protections described in Facilities Section 4.2.
3 These transformers are variously referred to as station power UAT, or station service transformer(s) used to provide overall
auxiliary power to the synchronous generators. This UAT is the transformer connected on the generator bus between the low
side of the GSU and the generator terminal.
1
Final Draft of PRC-024-4
September 2024
Page 3 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
4.2.1.5
Elements that are designed primarily for the delivery of
capacity from multiple synchronous generators connecting to
a common bus or individual dispersed power producing type 1
or type 2 wind resources identified in the BES Definition,
Inclusion I4, to the point where those resources aggregate to
greater than 75 MVA.
4.2.1.6
MPT of multiple synchronous generators connecting to a
common bus or MPT of individual dispersed power producing
type 1 or type 2 wind resources as identified in the BES
Definition, Inclusion I4.
4.2.2 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip transmission connected synchronous
condensers; or (ii) provide signals to trip transmission connected
synchronous condenser and are applied to the following:
4.2.2.1
BES synchronous condensers
4.2.2.2
BES step-up transformer(s) for synchronous condensers.
4.2.2.3
High-side of the synchronous condenser-connected unit
auxiliary transformer (UAT).
4.2.3 Exemptions: Protection on all auxiliary equipment within the
synchronous generator, type 1 or type 2 wind resource, or synchronous
condenser Facility.
5.
Effective Date: See Implementation Plan for PRC-024-4
Final Draft of PRC-024-4
September 2024
Page 4 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
B. Requirements and Measures
R1.
Each Generator Owner and Transmission Owner shall set applicable frequency
protection 4 in accordance with PRC-024-4 Attachment 1 such that the applicable
protection does not cause the Facility to which it is applied to trip within the “no trip
zone” during a frequency excursion with the following exceptions: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•
Applicable frequency protection may be set to trip within a portion of the “no
trip zone” for documented and communicated regulatory or equipment
limitations in accordance with Requirement R3.
M1. Each Generator Owner and Transmission Owner shall have evidence that the
applicable frequency protection has been set in accordance with Requirement R1,
such as dated setting sheets, calibration sheets, calculations, or other documentation.
R2.
Each Generator Owner and Transmission Owner shall set applicable voltage
protection 5 in accordance with PRC-024-4 Attachment 2, such that the applicable
protection does not cause the Facility to which it is applied to trip within the “no trip
zone” during a voltage excursion at the high-side of the GSU or MPT, subject to the
following exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
•
If the Transmission Planner allows less stringent voltage protection settings than
those required to meet PRC-024-4 Attachment 2, then the Generator Owner or
Transmission Owner may set its protection within the voltage recovery
characteristics of a location-specific Transmission Planner’s study.
•
Applicable voltage protection may be set to trip during a voltage excursion
within a portion of the “no trip zone” for documented and communicated
regulatory or equipment limitations in accordance with Requirement R3.
M2. Each Generator Owner and Transmission Owner shall have evidence that applicable
voltage protection has been set in accordance with Requirement R2, such as dated
setting sheets, voltage-time boundaries, calibration sheets, coordination plots,
dynamic simulation studies, calculations, or other documentation.
R3.
Each Generator Owner and Transmission Owner shall document each known
regulatory or equipment limitation 6 that prevents its Facility, with applicable
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. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to trip the same Facilities.
5 Ibid.
6 Excludes limitations caused by the setting capability of the frequency, voltage, and volts per hertz protective relays applied to
the synchronous generator(s), type 1 and type 2 wind resource(s), and synchronous condenser(s). This does not exclude
limitations originating in the equipment protected by the relay(s).
4
Final Draft of PRC-024-4
September 2024
Page 5 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
3.1. The Generator Owner and Transmission Owner shall communicate the
documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and
Transmission Planner within 30 calendar days of any of the following:
•
Identification of a regulatory or equipment limitation.
•
Repair of the equipment causing the limitation that removes the limitation.
•
Replacement of the equipment causing the limitation with equipment that
removes the limitation.
•
Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life-time frequency excursion allowance.
M3. Each Generator Owner and Transmission Owner shall have evidence that it has
documented and communicated any known regulatory or equipment limitations that
resulted in an exception to Requirements R1 or R2 in accordance with Requirement
R3, such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
R4.
Each Generator Owner and Transmission Owner shall provide its applicable protection
settings associated with Requirements R1 and R2 to the Planning Coordinator or
Transmission Planner that models the associated Facility within 60 calendar days of
receipt of a written request for the data and within 60 calendar days of any change to
those previously requested settings unless directed by the requesting Planning
Coordinator or Transmission Planner that the reporting of protection setting changes
is not required. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M4. Each Generator Owner and Transmission Owner shall have evidence that it
communicated applicable protection settings in accordance with Requirement R4,
such as dated emails, correspondence or other evidence and copies of any requests it
has received for that information.
Final Draft of PRC-024-4
September 2024
Page 6 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
The Generator Owner and Transmission Owner shall keep data or evidence
of Requirements R1 through R4 for five years or until the next audit,
whichever is longer.
•
If a Generator Owner or Transmission Owner is found non-compliant, the
Generator Owner or Transmission Owner shall keep information related to
the non-compliance until mitigation is complete and approved for the time
period specified above, whichever is longer.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Final Draft of PRC-024-4
September 2024
Page 7 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
R1.
N/A
N/A
N/A
R2.
N/A
N/A
N/A
R3.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 30 calendar days but less
than or equal to 60 calendar
days of identifying the
limitation.
Final Draft of PRC-024-4
September 2024
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 60 calendar days but less
than or equal to 90 calendar
days of identifying the
limitation.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 90 calendar days but less
than or equal to 120 calendar
days of identifying the
limitation.
Severe VSL
The Generator Owner or
Transmission Owner failed to
set its applicable frequency
protection so that it does not
trip according to Requirement
R1.
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does not
trip according to Requirement
R2.
The Generator Owner or
Transmission Owner failed to
document any known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar
Page 8 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
days of identifying the
limitation.
R4.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 60 calendar days but less
than or equal to 90 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 90 calendar days but less
than or equal to 120 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 120 calendar days but less
than or equal to 150 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner failed to
provide its protection settings
within 150 calendar days of any
change to those settings.
OR
OR
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
60 calendar days but less than
or equal to 90 calendar days of
a written request.
The Generator Owner or
Transmission Owner provided
protection settings more than
90 calendar days but less than
or equal to 120 calendar days
of a written request.
The Generator Owner or
Transmission Owner or
provided protection settings
more than 120 calendar days
but less than or equal to 150
calendar days of a written
request.
The Generator Owner or
Transmission Owner failed to
provide protection settings
within 150 calendar days of a
written request.
Final Draft of PRC-024-4
September 2024
OR
Page 9 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
D. Regional Variances
D.A.
Variance for the Quebec Interconnection
This Variance replaces Requirement R2 of the continent-wide standard in its entirety
and adds a new requirement, Requirement D.A.5., applicable to Planning
Coordinators in the Quebec Interconnection.
This Variance replaces continent-wide Requirement R2 in its entirety with the
following:
D.A.2.
Each Generator Owner and Transmission Owner shall set applicable
voltage protection 7 in accordance with PRC-024 Attachment 2A, such
that the applicable protection does not cause the Facility to which it is
applied to trip within the “no trip zone” during a voltage excursion at the
high-side of the GSU or MPT, subject to the following exceptions:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
•
For newly designated strategic power plants, applicable protections
must comply with the high voltage durations for such plants within 48
calendar months of the notification made pursuant to Requirement
D.A.5. During this transition period, voltage protections must at least
comply with the high voltage durations for “all power plants”.
•
Applicable voltage protection may be set to trip during a voltage
excursion within a portion of the “no trip zone” of PRC-024
Attachment 2A for documented and communicated regulatory or
equipment limitations in accordance with Requirement R3.
•
If the Transmission Planner allows less stringent voltage protection
settings than those required to meet PRC-024 Attachment 2A, then
the Generator Owner or Transmission Owner may set its protection
within the voltage recovery characteristics of a location-specific
Transmission Planner’s study.
M.D.A.2. Each Generator Owner and Transmission Owner shall have evidence that
applicable voltage protection has been set in accordance with
Requirement R2, such as dated setting sheets, voltage-time boundaries,
calibration sheets, coordination plots, dynamic simulation studies,
calculations, or other documentation.
This Variance adds the following Requirement:
D.A.5
Each Planning Coordinator shall designate, at least once every five
calendar years, the strategic power plants that must comply with
Attachment 2A and notify, within 30 calendar days of its designation,
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to trip the same Facilities.
7
Final Draft of PRC-024-4
September 2024
Page 10 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
each Generator Owner or Transmission Owner that owns facilities 8 in the
strategic power plants. [Violation Risk Factor: Medium] [Time Horizon:
Long-term planning]
M.D.A.5
Each Planning Coordinator shall have evidence that it designated, at least
once every five calendar years, strategic power plants in accordance with
Requirement D.A.5, Part 5 and shall have dated evidence that each
Generator Owner or Transmission Owner has been notified in accordance
with Requirement D.A.5, part 5.2. Evidence may include, but is not
limited to letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
Facilities in the strategic power plants include facilities with synchronous generator(s) from the generator up to and including
the MPT or GSU.
8
Final Draft of PRC-024-4
September 2024
Page 11 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
This Variance adds a VSL for D.A.5 and modifies the VSL for R2 as follows:
R#
D.A.2.
Violation Severity Levels
Lower
VSL
N/A
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Generator Owner or Transmission
Owner failed to set its applicable
voltage protection so that it does not
trip in accordance with Requirement
D.A.2.
OR
D.A.5.
N/A
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or Transmission
Owner that owns facilities in the
strategic power plants between 31
days and 45 days after its designation.
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or Transmission
Owner that owns facilities in the
strategic power plants between 46
days and 60 days after its designation.
The Generator Owner or Transmission
Owner set its applicable voltage
protection in accordance with
Requirement D.A.2 but, for strategic
power plants, failed to do so within 48
months of notification.
The Planning Coordinator failed to
designate, at least once every five
years, the strategic power plants that
must comply with Attachment 2A.
OR
The Planning Coordinator failed to
notify, each Generator Owner or
Transmission Owner that owns
facilities in the strategic power plants
or notified them more than 60 days
after its designation.
E.Associated Documents
Implementation Plan
Final Draft of PRC-024-4
September 2024
Page 12 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Version History
Version
Date
Action
Change Tracking
1
May 9, 2013
Adopted by the NERC Board of
Trustees
1
March 20, 2014
FERC Order issued approving PRC024-1. (Order becomes effective on
7/1/16.)
2
February 12, 2015
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2014-01:
Applicability revised to
clarify application of
requirements to BES
dispersed power
producing resources
2
May 29, 2015
FERC Letter Order in Docket No.
RD15-3-000 approving PRC-024-2
Modifications to adjust
the applicability to
owners of dispersed
generation resources.
3
February 6, 2020
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2018-04
3
July 9, 2020
FERC Letter Order approved PRC0243. Docket No. RD20-7-000
3
July 17, 2020
Effective Date
10/1/2022
4
August 2, 2024
Revisions made by the 2020-02
Drafting Team
Revision accounts for
changes with PRC-029-1
as part of Milestone 2 of
NERC’s work plan to
address FERC Order No.
901.
Final Draft of PRC-024-4
September 2024
Page 13 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 1
(Frequency No Trip Boundaries by Interconnection 9)
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1: Eastern Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 1: Frequency Boundary Data Points - Eastern Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥60.5
Instantaneous 10
10(90.935-1.45713*f)
≤57.8
≤59.5
Instantaneous11
10(1.7373*f-100.116)
<60.5
Continuous operation
> 59.5
Continuous operation
The figures do not visually represent the “no trip zone” boundaries before 0.1 seconds and after 10,000 seconds. The
Frequency Boundary Data Points Table defines the entirety of the “no trip zone” boundaries.
10 Frequency is calculated over a window of time. While the frequency boundaries include the option to trip instantaneously for
frequencies outside the specified range, this calculation should occur over a time window. Typical window/filtering lengths are
three to six cycles (50 – 100 milliseconds). Instantaneous trip settings based on instantaneously calculated frequency
measurement is not permissible.
9
Final Draft of PRC-024-4
September 2024
Page 14 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
63
Frequency (Hz)
62
61
60
59
No Trip Zone*
58
57
56
0.1
1
10
100
1000
10000
Time (Sec)
Figure 2: Western Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 2: Frequency Boundary Data Points – Western Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.7
≥61.6
≥60.6
<60.6
Instantaneous11
30
180
Continuous operation
≤57.0
≤57.3
≤57.8
≤58.4
≤59.4
Instantaneous11
0.75
7.5
30
180
>59.4
Continuous operation
Final Draft of PRC-024-4
September 2024
Page 15 of 22
Frequency (Hz)
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
67
66
65
64
63
62
61
60
59
58
57
56
55
No Trip Zone*
0.1
1
10
100
1000
10000
Time (Sec)
Figure 3: Quebec Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 3: Frequency Boundary Data Points – Quebec Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (Sec)
>66.0
≥63.0
Instantaneous11
5
<55.5
≤56.5
Instantaneous11
0.35
≥61.5
90
≤57.0
2
≥60.6
660
≤57.5
10
<60.6
Continuous operation
≤58.5
90
≤59.4
660
>59.4
Continuous operation
Final Draft of PRC-024-4
September 2024
Page 16 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 4: ERCOT Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 4: Frequency Boundary Data Points – ERCOT Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥61.6
≥60.6
<60.6
Instantaneous11
30
540
Continuous operation
≤57.5
≤58.0
≤58.4
≤59.4
Instantaneous11
2
30
540
>59.4
Continuous operation
Final Draft of PRC-024-4
September 2024
Page 17 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
PRC-024 — Attachment 2
Voltage (per unit)8
(Voltage No-Trip Boundaries – Eastern, Western, and ERCOT Interconnections)
1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
The Voltage No Trip Zone ends at 4
seconds for applicability to PRC-024
No Trip Zone*
0
0.5
1
1.5
2
2.5
Time (sec)
High Voltage Duration
3
3.5
4
Low Voltage Duration
Figure 5: Voltage No-Trip Boundaries – Eastern, Western, and ERCOT
Interconnections
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 5: Voltage Boundary Data Points
High Voltage Duration
Low Voltage Duration
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
≥1.200
≥1.175
≥1.15
≥1.10
<1.10
0.00
0.20
0.50
1.00
4.00
<0.45
<0.65
<0.75
<0.90
≥ 0.90
0.15
0.30
2.00
3.00
4.00
Final Draft of PRC-024-4
September 2024
Page 18 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 2: Voltage Boundary Clarifications – Eastern, Western,
and ERCOT Interconnections
Boundary Details:
1. Unless otherwise specified by the Transmission Planner, the per unit voltage base for
these boundaries is the nominal transmission system voltage (e.g., 100 kV, 115 kV, 138
kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the boundaries assume RMS fundamental frequency phase-to-ground or
phase-to-phase per unit voltage.
5. For applicability to PRC-024, the “no trip zone” ends at 4 seconds.
Evaluating Protection Settings:
The voltage values in the Attachment 2 voltage boundaries are voltages at the high-side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high-side of the transformer with a low side below 100kV and a high-side 100kV or above.
When evaluating protection settings, consider the voltage differences between where the
protection is measuring voltage and the high-side of the GSU/MPT. A steady state calculation or
dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the synchronous generator,
type 1 or 2 wind resources, or synchronous condenser under study.
b. All installed wind resource reactive support (e.g., static VAR compensators, synchronous
condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals or
the collector station and the high-side of the GSU/MPT.
d. For dynamic simulations, the synchronous generator or condenser automatic voltage
regulator is in automatic voltage control mode with associated limiters in service.
Final Draft of PRC-024-4
September 2024
Page 19 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
PRC-024— Attachment 2A
(Voltage No-Trip Boundaries – Quebec Interconnection)
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
0 0.1
0.033
0.15
2.5
0.5
1
2
3
4
5
30
300
Time (sec)
Low Voltage/High Voltage Duration – Synchronous Generators and Condensers
High Voltage Duration - Strategic Power Plants
Figure 6: Voltage No-Trip Boundaries – Quebec Interconnection
* The area outside the “No Trip Zone” is not a “Must Trip Zone.”
Final Draft of PRC-024-4
September 2024
Page 20 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Table 6: High Voltage Boundary Data Points – Quebec Interconnection
High Voltage Duration for all
Synchronous Generators and
Condensers
High Voltage Duration for strategic
Power Plants
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
-->1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
--0.033
0.10
2.00
30
300
continuous
>1.50
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
0.033
0.10
2.50
5.00
30
300
continuous
Table 7: Low Voltage Boundary Data Points – Quebec Interconnection
Low Voltage Duration for all
Synchronous Generators and
Condensers
Final Draft of PRC-024-4
September 2024
Voltage (per unit)
Minimum Time (sec)
<0.25
<0.75
<0.85
<0.90
≥0.90
0.15
1.00
2.00
30
continuous
Page 21 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 2A: Voltage Boundary Clarifications – Quebec
Interconnection
Boundary Details:
1. The per unit voltage base for these boundaries is the nominal operating voltage (e.g.,
120 kV, 161 kV, 230 kV, 315 kV, 735 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the Quebec Interconnection boundaries assume positive-sequence values.
Evaluating Protection Settings:
The voltage values in the Attachment 2A voltage boundaries are voltages at the high-side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high-side of the transformer that connects to the interconnecting voltage. When evaluating
protection settings, consider the voltage differences between where the protection is
measuring voltage and the high-side of the GSU/MPT. A steady state calculation or dynamic
simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high-side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Final Draft of PRC-024-4
September 2024
Page 22 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 3 of PRC-024-4 is posted for final ballot. Non-substantive corrections were identified
during the last additional ballot. This draft includes those corrections.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process Manual
December 13, 2023
25-day formal comment period with initial ballot
March 27 - April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
Anticipated Actions
Date
Final ballot
September 25 –
September 30, 2024
Board Adoption
October 8, 2024
Final Draft of PRC-024-4
September 2024
Page 1 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Final Draft of PRC-024-4
September 2024
Page 2 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
A. Introduction
1.
Title:
Frequency and Voltage Protection Settings for Synchronous Generators,
Type 1 and Type 2 Wind Resources, and Synchronous Condensers
2.
Number:
PRC-024-4
3.
Purpose:
To assure that protection of synchronous generators, type 1 and type 2
wind resources, and synchronous condensers do not cause tripping
during defined frequency and voltage excursions in support of the Bulk
Power System (BPS).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Generator Owners that apply protection listed in Sections 4.2.1 or 4.2.2.
4.1.2. Transmission Owners that apply protection listed in Section 4.2.2.
4.1.3. Transmission Owners (in the Quebec Interconnection only) that own a
BES generator step-up (GSU) transformer or main power transformer
(MPT) 1 and apply protection listed in Section 4.2.1.
4.1.4. Planning Coordinators (in the Quebec Interconnection only)
4.2. Facilities 2:
4.2.1 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the generating resource(s); or (ii)
provide signals to the generating resource(s) to trip; and are applied to
the following:
4.2.1.1
Bulk Electric System (BES) synchronous generators.
4.2.1.2
BES GSU transformer(s) for synchronous generators.
4.2.1.3
High-side of the synchronous generator-connected unit
auxiliary transformer 3 (UAT) installed on BES generating
resource(s).
4.2.1.4
Individual dispersed power producing type 1 or type 2 wind
resource(s) identified in the BES Definition, Inclusion I4.
1
For the purpose of this standard, the MPT is the power transformer that steps up voltage from multiple small synchronous
generators (e.g. multiple small hydro generators connecting to a common bus) or from a type 1 or type 2 wind resource
collector station to transmission voltage .
2 It is not required to install or activate the protections described in Facilities Section 4.2.
3 These transformers are variously referred to as station power UAT, or station service transformer(s) used to provide overall
auxiliary power to the synchronous generators. This UAT is the transformer connected on the generator bus between the low
side of the GSU and the generator terminal.
Final Draft of PRC-024-4
September 2024
Page 3 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
4.2.1.5
Elements that are designed primarily for the delivery of
capacity from multiple synchronous generators connecting to
a common bus or individual dispersed power producing type 1
or type 2 wind resources identified in the BES Definition,
Inclusion I4, to the point where those resources aggregate to
greater than 75 MVA.
4.2.1.6
MPT of multiple synchronous generators connecting to a
common bus or MPT of individual dispersed power producing
type 1 or type 2 wind resources as identified in the BES
Definition, Inclusion I4.
4.2.2 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip transmission connected synchronous
condensers; or (ii) provide signals to trip transmission connected
synchronous condenser and are applied to the following:
4.2.2.1
BES synchronous condensers
4.2.2.2
BES step-up transformer(s) for synchronous condensers.
4.2.2.3
High-side of the synchronous condenser-connected unit
auxiliary transformer (UAT).
4.2.3 Exemptions: Protection on all auxiliary equipment within the
synchronous generator, type 1 or type 2 wind resource, or synchronous
condenser Facility.
5.
Effective Date: See Implementation Plan for PRC-024-4
Final Draft of PRC-024-4
September 2024
Page 4 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
B. Requirements and Measures
R1.
Each Generator Owner and Transmission Owner shall set applicable frequency
protection 4 in accordance with PRC-024-4 Attachment 1 such that the applicable
protection does not cause the Facility to which it is applied to trip within the “no trip
zone” during a frequency excursion with the following exceptions: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•
Applicable frequency protection may be set to trip within a portion of the “no
trip zone” for documented and communicated regulatory or equipment
limitations in accordance with Requirement R3.
M1. Each Generator Owner and Transmission Owner shall have evidence that the
applicable frequency protection has been set in accordance with Requirement R1,
such as dated setting sheets, calibration sheets, calculations, or other documentation.
R2.
Each Generator Owner and Transmission Owner shall set applicable voltage
protection 5 in accordance with PRC-024-4 Attachment 2, such that the applicable
protection does not cause the Facility to which it is applied to trip within the “no trip
zone” during a voltage excursion at the high-side of the GSU or MPT, subject to the
following exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
•
If the Transmission Planner allows less stringent voltage protection settings than
those required to meet PRC-024-4 Attachment 2, then the Generator Owner or
Transmission Owner may set its protection within the voltage recovery
characteristics of a location-specific Transmission Planner’s study.
•
Applicable voltage protection may be set to trip during a voltage excursion
within a portion of the “no trip zone” for documented and communicated
regulatory or equipment limitations in accordance with Requirement R3.
M2. Each Generator Owner and Transmission Owner shall have evidence that applicable
voltage protection has been set in accordance with Requirement R2, such as dated
setting sheets, voltage-time boundaries, calibration sheets, coordination plots,
dynamic simulation studies, calculations, or other documentation.
R3.
Each Generator Owner and Transmission Owner shall document each known
regulatory or equipment limitation 6 that prevents an its synchronous generator, type
1 or type 2 wind resource, or synchronous condenser,Facility with applicable
frequency or voltage protection from meeting the protection setting criteria in
Requirements R1 or R2, including (but not limited to) study results, experience from
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to same to trip the same Facilities.
5 Ibid.
6 Excludes limitations caused by the setting capability of the frequency, voltage, and volts per hertz protective relays applied to
the synchronous generator(s), type 1 and type 2 wind resource(s), and synchronous condenser(s). This does not exclude
limitations originating in the equipment protected by the relay(s).
4
Final Draft of PRC-024-4
September 2024
Page 5 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
an actual event, or manufacturer’s advice. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
3.1. The Generator Owner and Transmission Owner shall communicate the
documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and
Transmission Planner within 30 calendar days of any of the following:
•
Identification of a regulatory or equipment limitation.
•
Repair of the equipment causing the limitation that removes the limitation.
•
Replacement of the equipment causing the limitation with equipment that
removes the limitation.
•
Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life-time frequency excursion allowance.
M3. Each Generator Owner and Transmission Owner shall have evidence that it has
documented and communicated any known regulatory or equipment limitations that
resulted in an exception to Requirements R1 or R2 in accordance with Requirement
R3, such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
R4.
Each Generator Owner and Transmission Owner shall provide its applicable protection
settings associated with Requirements R1 and R2 to the Planning Coordinator or
Transmission Planner that models the associated Facility within 60 calendar days of
receipt of a written request for the data and within 60 calendar days of any change to
those previously requested settings unless directed by the requesting Planning
Coordinator or Transmission Planner that the reporting of protection setting changes
is not required. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M4. Each Generator Owner and Transmission Owner shall have evidence that it
communicated applicable protection settings in accordance with Requirement R4,
such as dated e-mails, correspondence or other evidence and copies of any requests it
has received for that information.
Final Draft of PRC-024-4
September 2024
Page 6 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
The Generator Owner and Transmission Owner shall keep data or evidence
of Requirements R1 through R4 for five years or until the next audit,
whichever is longer.
•
If a Generator Owner or Transmission Owner is found non-compliant, the
Generator Owner or Transmission Owner shall keep information related to
the non-compliance until mitigation is complete and approved for the time
period specified above, whichever is longer.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Final Draft of PRC-024-4
September 2024
Page 7 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
R1.
N/A
N/A
N/A
R2.
N/A
N/A
N/A
R3.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 30 calendar days but less
than or equal to 60 calendar
days of identifying the
limitation.
Final Draft of PRC-024-4
September 2024
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 60 calendar days but less
than or equal to 90 calendar
days of identifying the
limitation.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more
than 90 calendar days but less
than or equal to 120 calendar
days of identifying the
limitation.
Severe VSL
The Generator Owner or
Transmission Owner failed to
set its applicable frequency
protection so that it does not
trip according to Requirement
R1.
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does not
trip according to Requirement
R2.
The Generator Owner or
Transmission Owner failed to
document any known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar
Page 8 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
days of identifying the
limitation.
R4.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 60 calendar days but less
than or equal to 90 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 90 calendar days but less
than or equal to 120 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner provided
its protection settings more
than 120 calendar days but less
than or equal to 150 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner failed to
provide its protection settings
within 150 calendar days of any
change to those settings.
OR
OR
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
60 calendar days but less than
or equal to 90 calendar days of
a written request.
The Generator Owner or
Transmission Owner provided
protection settings more than
90 calendar days but less than
or equal to 120 calendar days
of a written request.
The Generator Owner or
Transmission Owner or
provided protection settings
more than 120 calendar days
but less than or equal to 150
calendar days of a written
request.
The Generator Owner or
Transmission Owner failed to
provide protection settings
within 150 calendar days of a
written request.
Final Draft of PRC-024-4
September 2024
OR
Page 9 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
D. Regional Variances
D.A.
Variance for the Quebec Interconnection
This Variance replaces Requirement R2 of the continent-wide standard in its entirety
and adds a new requirement, Requirement D.A.5., applicable to Planning
Coordinators in the Quebec Interconnection.
This Variance replaces continent-wide Requirement R2 in its entirety with the
following:
D.A.2.
Each Generator Owner and Transmission Owner shall set applicable
voltage protection 7 in accordance with PRC-024 Attachment 2AB, such
that the applicable protection does not cause the Facility to which it is
applied to trip within the “no trip zone” during a voltage excursion at the
high-side of the GSU or MPT, subject to the following exceptions:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
•
For newly designated strategic power plants, applicable protections
must comply with the high voltage durations for such plants within 48
calendar months of the notification made pursuant to Requirement
D.A.5. During this transition period, voltage protections must at least
comply with the high voltage durations for “all power plants”.
•
Applicable voltage protection may be set to trip during a voltage
excursion within a portion of the “no trip zone” of PRC-024
Attachment 2AB for documented and communicated regulatory or
equipment limitations in accordance with Requirement R3.
•
If the Transmission Planner allows less stringent voltage protection
settings than those required to meet PRC-024 Attachment 2AB, then
the Generator Owner or Transmission Owner may set its protection
within the voltage recovery characteristics of a location-specific
Transmission Planner’s study.
M.D.A.2. Each Generator Owner and Transmission Owner shall have evidence that
applicable voltage protection has been set in accordance with
Requirement R2, such as dated setting sheets, voltage-time boundaries,
calibration sheets, coordination plots, dynamic simulation studies,
calculations, or other documentation.
This Variance adds the following Requirement:
D.A.5
Each Planning Coordinator shall designate, at least once every five
calendar years, the strategic power plants that must comply with
Attachment 2AB and notify, within 30 calendar days of its designation,
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated control
systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type 2 wind resource(s),
or synchronous condenser(s); or (ii) provide signals to same to trip the same Facilities.
7
Final Draft of PRC-024-4
September 2024
Page 10 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
each Generator Owner or Transmission Owner that owns facilities 8 in the
strategic power plants. [Violation Risk Factor: Medium] [Time Horizon:
Long-term planning]
M.D.A.5
Each Planning Coordinator shall have evidence that it designated, at least
once every five calendar years, strategic power plants in accordance with
Requirement D.A.5, Part 5 and shall have dated evidence that each
Generator Owner or Transmission Owner has been notified in accordance
with Requirement D.A.5, part 5.2. Evidence may include, but is not
limited to letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
Facilities in the strategic power plants include facilities with synchronous generator(s) from the generator up to and including
the MPT or GSU.
8
Final Draft of PRC-024-4
September 2024
Page 11 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous
Condensers
Violation Severity Levels
This Variance adds a VSL for D.A.5 and modifies the VSL for R2 as follows:
R#
D.A.2.
Violation Severity Levels
Lower
VSL
N/A
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Generator Owner or Transmission
Owner failed to set its applicable
voltage protection so that it does not
trip in accordance with Requirement
D.A.2.
OR
D.A.5.
N/A
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or Transmission
Owner that owns facilities in the
strategic power plants between 31
days and 45 days after its designation.
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or Transmission
Owner that owns facilities in the
strategic power plants between 46
days and 60 days after its designation.
The Generator Owner or Transmission
Owner set its applicable voltage
protection in accordance with
Requirement D.A.2 but, for strategic
power plants, failed to do so within 48
months of notification.
The Planning Coordinator failed to
designate, at least once every five
years, the strategic power plants that
must comply with Attachment 2B.
OR
The Planning Coordinator failed to
notify, each Generator Owner or
Transmission Owner that owns
facilities in the strategic power plants
or notified them more than 60 days
after its designation.
E.Associated Documents
Implementation Plan
Final Draft of PRC-024-4
September 2024
Page 12 of 22
PRC-024-4 —Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type
2 Wind Resources, and Synchronous Condensers
Version History
Version
Date
Action
Change Tracking
1
May 9, 2013
Adopted by the NERC Board of
Trustees
1
March 20, 2014
FERC Order issued approving PRC024-1. (Order becomes effective on
7/1/16.)
2
February 12, 2015
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2014-01:
Applicability revised to
clarify application of
requirements to BES
dispersed power
producing resources
2
May 29, 2015
FERC Letter Order in Docket No.
RD15-3-000 approving PRC-024-2
Modifications to adjust
the applicability to
owners of dispersed
generation resources.
3
February 6, 2020
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2018-04
3
July 9, 2020
FERC Letter Order approved PRC0243. Docket No. RD20-7-000
3
July 17, 2020
Effective Date
10/1/2022
4
August 2, 2024
Revisions made by the 2020-02
Drafting Team
Revision accounts for
changes with PRC-029-1
as part of Milestone 2 of
NERC’s work plan to
address FERC Order No.
901.
Final Draft of PRC-024-4
September 2024
Page 13 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 1
(Frequency No Trip Boundaries by Interconnection 9)
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1: Eastern Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 1: Frequency Boundary Data Points - Eastern Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥60.5
Instantaneous 10
10(90.935-1.45713*f)
≤57.8
≤59.5
Instantaneous11
10(1.7373*f-100.116)
<60.5
Continuous operation
> 59.5
Continuous operation
The figures do not visually represent the “no trip zone” boundaries before 0.1 seconds and after 10,000 seconds. The
Frequency Boundary Data Points Table defines the entirety of the “no trip zone” boundaries.
10 Frequency is calculated over a window of time. While the frequency boundaries include the option to trip instantaneously for
frequencies outside the specified range, this calculation should occur over a time window. Typical window/filtering lengths are
three to six cycles (50 – 100 milliseconds). Instantaneous trip settings based on instantaneously calculated frequency
measurement is not permissible.
9
Final Draft of PRC-024-4
September 2024
Page 14 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
63
Frequency (Hz)
62
61
60
59
No Trip Zone*
58
57
56
0.1
1
10
100
1000
10000
Time (Sec)
Figure 2: Western Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 2: Frequency Boundary Data Points – Western Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.7
≥61.6
≥60.6
<60.6
Instantaneous11
30
180
Continuous operation
≤57.0
≤57.3
≤57.8
≤58.4
≤59.4
Instantaneous11
0.75
7.5
30
180
>59.4
Continuous operation
Final Draft of PRC-024-4
September 2024
Page 15 of 22
Frequency (Hz)
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
67
66
65
64
63
62
61
60
59
58
57
56
55
No Trip Zone*
0.1
1
10
100
1000
10000
Time (Sec)
Figure 3: Quebec Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 3: Frequency Boundary Data Points – Quebec Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (Sec)
>66.0
≥63.0
Instantaneous11
5
<55.5
≤56.5
Instantaneous11
0.35
≥61.5
90
≤57.0
2
≥60.6
660
≤57.5
10
<60.6
Continuous operation
≤58.5
90
≤59.4
660
>59.4
Continuous operation
Final Draft of PRC-024-4
September 2024
Page 16 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 4: ERCOT Interconnection Boundaries
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 4: Frequency Boundary Data Points – ERCOT Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
≥61.6
≥60.6
<60.6
Instantaneous11
30
540
Continuous operation
≤57.5
≤58.0
≤58.4
≤59.4
Instantaneous11
2
30
540
>59.4
Continuous operation
Final Draft of PRC-024-4
September 2024
Page 17 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
PRC-024 — Attachment 2
Voltage (per unit)8
(Voltage No-Trip Boundaries – Eastern, Western, and ERCOT Interconnections)
1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
The Voltage No Trip Zone ends at 4
seconds for applicability to PRC-024
No Trip Zone*
0
0.5
1
1.5
2
2.5
Time (sec)
High Voltage Duration
3
3.5
4
Low Voltage Duration
Figure 5: Voltage No-Trip Boundaries – Eastern, Western, and ERCOT
Interconnections
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 5: Voltage Boundary Data Points
High Voltage Duration
Low Voltage Duration
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
≥1.200
≥1.175
≥1.15
≥1.10
<1.10
0.00
0.20
0.50
1.00
4.00
<0.45
<0.65
<0.75
<0.90
≥ 0.90
0.15
0.30
2.00
3.00
4.00
Final Draft of PRC-024-4
September 2024
Page 18 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 2A: Voltage Boundary Clarifications – Eastern, Western,
and ERCOT Interconnections
Boundary Details:
1. Unless otherwise specified by the Transmission Planner, the per unit voltage base for
these boundaries is the nominal transmission system voltage (e.g., 100 kV, 115 kV, 138
kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the boundaries assume RMS fundamental frequency phase-to-ground or
phase-to-phase per unit voltage.
5. For applicability to PRC-024, the “no trip zone” ends at 4 seconds.
Evaluating Protection Settings:
The voltage values in the Attachment 2 voltage boundaries are voltages at the high-side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high-side of the transformer with a low side below 100kV and a high-side 100kV or above.
When evaluating protection settings, consider the voltage differences between where the
protection is measuring voltage and the high-side of the GSU/MPT. A steady state calculation or
dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the synchronous generator,
type 1 or 2 wind resources, or synchronous condenser unit under study.
b. All installed wind resourcegenerating plant reactive support (e.g., static VAR
compensators, synchronous condensers, capacitors) equipment is available and
operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high-side of the GSU/MPT.
d. For dynamic simulations, the synchronous generator or condenser automatic voltage
regulator is in automatic voltage control mode with associated limiters in service.
Final Draft of PRC-024-4
September 2024
Page 19 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
PRC-024— Attachment 2AB
(Voltage No-Trip Boundaries – Quebec Interconnection)
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
0 0.1
0.033
0.15
2.5
0.5
1
2
3
4
5
30
300
Time (sec)
Low Voltage/High Voltage Duration – Synchronous Generators and Condensers
High Voltage Duration - Strategic Power Plants
Figure 6: Voltage No-Trip Boundaries – Quebec Interconnection
* The area outside the “No Trip Zone” is not a “Must Trip Zone.”
Final Draft of PRC-024-4
September 2024
Page 20 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Table 6: High Voltage Boundary Data Points – Quebec Interconnection
High Voltage Duration for all
Synchronous Generators and
Condensers
High Voltage Duration for strategic
Power Plants
Voltage (per unit)
Minimum Time (sec)
Voltage (per unit)
Minimum Time (sec)
-->1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
--0.033
0.10
2.00
30
300
continuous
>1.50
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
0.033
0.10
2.50
5.00
30
300
continuous
Table 7: Low Voltage Boundary Data Points – Quebec Interconnection
Low Voltage Duration for all
Synchronous Generators and
Condensers
Final Draft of PRC-024-4
September 2024
Voltage (per unit)
Minimum Time (sec)
<0.25
<0.75
<0.85
<0.90
≥0.90
0.15
1.00
2.00
30
continuous
Page 21 of 22
PRC-024-4 Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and 2 Wind,
and Synchronous Condensers
Attachment 2AC: Voltage Boundary Clarifications – Quebec
Interconnection
Boundary Details:
1. The per unit voltage base for these boundaries is the nominal operating voltage (e.g.,
120 kV, 161 kV, 230 kV, 315 kV, 735 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the Quebec Interconnection boundaries assume positive-sequence values.
Evaluating Protection Settings:
The voltage values in the Attachment 2B voltage boundaries are voltages at the high-side of the
GSU/MPT. For resources with multiple stages of step up to reach interconnecting voltage, this is
the high-side of the transformer that connects to the interconnecting voltage. When evaluating
protection settings, consider the voltage differences between where the protection is
measuring voltage and the high-side of the GSU/MPT. A steady state calculation or dynamic
simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators,
synchronous condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals
and the high-side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Final Draft of PRC-024-4
September 2024
Page 22 of 22
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 3 of PRC-024-4 is posted for final ballot. Non-substantive corrections were identified during
the last additional ballot. This draft includes those corrections.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process Manual
December 13, 2023
25-day formal comment period with initial ballot
March 27 - April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
Anticipated Actions
Date
Final ballot
September 25 –
September 30, 2024
Board Adoption
October 8, 2024
Page 1 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Page 2 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
A. Introduction
1.
Title:
Frequency and Voltage Protection Settings for Synchronous
Generatorsing, Type 1 and Type 2 Wind Resources, and Synchronous Condensers
2.
Number:
PRC-024-43
3.
Purpose:
To assureset that protection of such that synchronous generatorsing, type 1
and type 2 wind resource(s), and synchronous condensers do not cause
tripping remain connected during defined frequency and voltage
excursions in support of the Bulk Electric Power System (BPES).
4.
Applicability:
4.1. Functional Entities:
4.1.1 Generator Owners that apply protection listed in Section 4.2.1 or 4.2.2.
4.1.2 Transmission Owners that apply protection listed in Section 4.2.2.
4.1.24.1.3
Transmission Owners (in the Quebec Interconnection only) that own
a BES generator step-up (GSU) transformer or main power transformer
(MPT) 1 and apply protection listed in Section 4.2.1.
4.1.34.1.4
Planning Coordinators (in the Quebec Interconnection only)
4.2. Facilities 2:
4.2.1 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip the generating resource(s); or (ii)
provide signals to the generating resource(s) to either trip or cease injecting
current; and are applied to the following:
4.2.1.1 Bulk Electric (BES) synchronous generatorsing resource(s).
4.2.1.2 BES GSU transformer(s) for synchronous generators.
4.2.1.3 High -side of the synchronous generator-connected unit auxiliary
transformer 3 (UAT) installed on BES generating resource(s).
4.2.1.4 Individual dispersed power producing type 1 or type 2 wind
resource(s) identified in the BES Definition, Inclusion I4.
For the purpose of this standard, the MPT is the power transformer that steps up voltage from the collection system
voltage to the nominal transmission/interconnecting system voltage for dispersed power producing resources.
1
2
It is not required to install or activate the protections described in Facilities Section 4.2.
These transformers are variably referred to as station power UAT, or station service transformer(s) used to provide
overall auxiliary power to the generating resource(s). This UAT is the transformer connected on the generator bus
between the low side of the GSU and the generator terminal.
3
Page 3 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
4.2.1.5 Elements that are designed primarily for the delivery of capacity
from multiple synchronous generators connecting to a common
bus orthe individual dispersed power producing type 1 or type 2
wind resources identified in the BES Definition, Inclusion I4, to the
point where those resources aggregate to greater than 75 MVA.
4.2.1.6 MPT 4 of multiple synchronous generators connecting to a
common bus or MPT of individual dispersed power producting
type 1 or type 2 wind resource(s) as identified in the BES
Definition, Inclusion I4.
4.2.2 Frequency, voltage, and volts per hertz protection (whether provided by
relaying or functions within associated control systems) that respond to
electrical signals and: (i) directly trip transmission connected synchronous
condensers; or (ii) provide signals to trip transmission connected
synchronous condenser and are applied to the following:
5.
4.2.2.1
BES synchronous condensers
4.2.2.2
BES step-up transformer(s) for synchronous condensers.
4.2.2.3
High-side of the synchronous condenser-connected unit auxiliary
transformer (UAT).
4.2.24.2.3
Exemptions: Protection on all auxiliary equipment within the
synchronous generatoring, type 1 or type 2 wind resource, or synchronous
condenser Facility.
Effective Date: See the Implementation Plan for PRC-024-43.
For the purpose of this standard, the MPT is the power transformer that steps up voltage from the collection system
voltage to the nominal transmission/interconnecting system voltage for dispersed power producing resources
4
Page 4 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
B. Requirements and Measures
R1.
Each Generator Owner and Transmission Owner shall set its applicable frequency
protection 5 in accordance with PRC-024-4 Attachment 1 such that the applicable
protection does not cause the generating resourceFacility to which it is applied to trip or
cease injecting current within the “no trip zone” during a frequency excursion with the
following exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
•
Applicable frequency protection may be set to trip or cease injecting current within
a portion of the “no trip zone” for documented and communicated regulatory or
equipment limitations in accordance with Requirement R3.
M1. Each Generator Owner and Transmission Owner shall have evidence that the applicable
frequency protection has been set in accordance with Requirement R1, such as dated
setting sheets, calibration sheets, calculations, or other documentation.
R2.
Each Generator Owner and Transmission Owner shall set its applicable voltage
protection 65 in accordance with PRC-024-4 Attachment 2, such that the applicable
protection does not cause the generating resourceFacility to which it is applied to trip or
cease injecting current within the “no trip zone” during a voltage excursion at the
high- side of the GSU or MPT, subject to the following exceptions: [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning]
•
If the Transmission Planner allows less stringent voltage protection settings than
those required to meet PRC-024-4 Attachment 2, then the Generator Owner may
set its protection within the voltage recovery characteristics of a location-specific
Transmission Planner’s study.
•
Applicable voltage protection may be set to trip or cease injecting current during a
voltage excursion within a portion of the “no trip zone” for documented and
communicated regulatory or equipment limitations in accordance with
Requirement R3.
M2. Each Generator Owner and Transmission Owner shall have evidence that applicable
voltage protection has been set in accordance with Requirement R2, such as dated
setting sheets, voltage-time boundaries, calibration sheets, coordination plots, dynamic
simulation studies, calculations, or other documentation.
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated
control systems) that respond to electrical signals and: (i) directly trip the synchronous generatorsing, type 1 or type 2
wind resource(s), or synchronous condenser(s); or (ii) provide signals to the generating resource(s) to either trip or
cease injecting currentthe same Facilties.
5
6
Ibid
Page 5 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
R3.
Each Generator Owner and Transmission Owner shall document each known regulatory
or equipment limitation 7 that prevents an applicable generating resource(s)its Facility,
with applicable 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. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
3.1. The Generator Owner and Transmission Owner shall communicate the
documented regulatory or equipment limitation, or the removal of a previously
documented regulatory or equipment limitation, to its Planning Coordinator and
Transmission Planner within 30 calendar days of any of the following:
•
Identification of a regulatory or equipment limitation.
•
Repair of the equipment causing the limitation that removes the limitation.
•
Replacement of the equipment causing the limitation with equipment that
removes the limitation.
•
Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life-time frequency excursion allowance.
M3. Each Generator Owner and Transmission Owner shall have evidence that it has
documented and communicated any known regulatory or equipment limitations that
resulted in an exception to Requirements R1 or R2 in accordance with Requirement R3,
such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
R4.
Each Generator Owner and Transmission Owner shall provide its applicable protection
settings associated with Requirements R1 and R2 to the Planning Coordinator or
Transmission Planner that models the associated Facility generating resource(s) within
60 calendar days of receipt of a written request for the data and within 60 calendar days
of any change to those previously requested settings unless directed by the requesting
Planning Coordinator or Transmission Planner that the reporting of protection setting
changes is not required. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
M4. Each Generator Owner and Transmission Owner shall have evidence that it
communicated applicable protection settings in accordance with Requirement R4, such
as dated e-mails, correspondence or other evidence and copies of any requests it has
received for that information.
Excludes limitations caused by the setting capability of the frequency, voltage, and volts per hertz protective relays
applied to the synchronous for the generatorsing, type 1 or type 2 wind resource(s), and synchronous condenser(s).
This does not exclude limitations originating in the equipment protected by the relay. This also does not exclude
limitations of frequency, voltage, and volts per hertz protection embedded in control systems.
7
Page 6 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means
NERC or the Regional Entity, or any entity as otherwise designated by an Applicable
Governmental Authority, in their respective roles of monitoring and/or enforcing
compliance with mandatory and enforceable Reliability Standards in their
respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the period
of time an entity is required to retain specific evidence to demonstrate compliance.
For instances where the evidence retention period specified below is shorter than
the time since the last audit, the Compliance Enforcement Authority may ask an
entity to provide other evidence to show that it was compliant for the full-time
period since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
•
The Generator Owner and Transmission Owner shall keep data or evidence
Requirement R1 through R4; for five3 years or until the next audit,
whichever is longer.
•
If a Generator Owner or Transmission Owner is found non-compliant, the
Generator Owner or Transmission Owner shall keep information related to
the non-compliance until mitigation is complete and approved for the time
period specified above, whichever is longer.
1.3. Compliance Monitoring and Assessment Program: As defined in the NERC Rules of
Procedure, “Compliance Monitoring and Enforcement Program” refers to the
identification of the processes that will be used to evaluate data or information for
the purpose of assessing performance or outcomes with the associated Reliability
Standard.
Page 7 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and Type 2 Wind Resources, and
Synchronous Condensers
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed
to set its applicable
frequency protection so
that it does not trip or
cease injecting current
according to Requirement
R1.
R2.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed
to set its applicable voltage
protection so that it does
not trip or cease injecting
current according to
Requirement R2.
R3.
The Generator Owner or
Transmission Owner
documented the known nonprotection system equipment
limitation that prevented it
from meeting the criteria in
Requirement R1 or R2 and
communicated the
documented limitation to its
Planning Coordinator and
The Generator Owner or
Transmission Owner
documented the known
non-protection system
equipment limitation that
prevented it from meeting
the criteria in Requirement
R1 or R2 and
communicated the
documented limitation to
The Generator Owner
or Transmission Owner
documented the known
non-protection system
equipment limitation
that prevented it from
meeting the criteria in
Requirement R1 or R2
and communicated the
documented limitation
The Generator Owner or
Transmission Owner failed
to document any known
non-protection system
equipment limitation that
prevented it from meeting
the criteria in Requirement
R1 or R2.
Page 8 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and Type 2 Wind Resources, and
Synchronous Condensers
Violation Severity Levels
R#
R4.
Lower VSL
Moderate VSL
Transmission Planner more
than 30 calendar days but less
than or equal to 60 calendar
days of identifying the
limitation.
its Planning Coordinator
and Transmission Planner
more than 60 calendar
days but less than or equal
to 90 calendar days of
identifying the limitation.
to its Planning
Coordinator and
Transmission Planner
more than 90 calendar
days but less than or
equal to 120 calendar
days of identifying the
limitation.
OR
The Generator Owner or
Transmission Owner provided
its protection settings more
than 60 calendar days but less
than or equal to 90 calendar
days of any change to those
settings.
The Generator Owner or
Transmission Owner
provided its protection
settings more than 90
calendar days but less than
or equal to 120 calendar
days of any change to
those settings.
The Generator Owner
or Transmission Owner
provided its protection
settings more than 120
calendar days but less
than or equal to 150
calendar days of any
change to those
settings.
The Generator Owner or
Transmission Owner failed
to provide its protection
settings within 150 calendar
days of any change to those
settings.
OR
The Generator Owner or
Transmission Owner provided
protection settings more than
60 calendar days but less than
or equal to 90 calendar days of
a written request.
OR
The Generator Owner or
Transmission Owner
provided protection
settings more than 90
calendar days but less than
High VSL
OR
The Generator Owner
or Transmission Owner
provided protection
settings more than 120
calendar days but less
than or equal to 150
Severe VSL
The Generator Owner or
Transmission Owner failed
to communicate the
documented limitation to
its Planning Coordinator
and Transmission Planner
within 120 calendar days of
identifying the limitation.
OR
The Generator Owner or
Transmission Owner failed
to provide protection
settings within 150 calendar
days of a written request.
Page 9 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and Type 2 Wind Resources, and
Synchronous Condensers
Violation Severity Levels
R#
Lower VSL
Moderate VSL
or equal to 120 calendar
days of a written request.
High VSL
Severe VSL
calendar days of a
written request.
Page 10 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
D. Regional Variances
D.A.
Variance for the Quebec Interconnection
This Variance extends the applicability of Requirements R1, R3, and R4 to
Transmission Owners in the Quebec Interconnection that own a BES GSU or MPT
and apply protection listed in Section 4.2.1, Facilities. This Variance also replaces
Requirement R2 of the continent-wide standard in its entirety and adds a new
requirement, Requirement D.A.5., applicable to Planning Coordinators in the
Quebec Interconnection.
In Requirements R1, R3, and R4, all references to “Generator Owner” are replaced
with “Generator Owner and Transmission Owner.”
This Variance replaces continent-wide Requirement R2 in its entirety with the
following:
D.A.2.
Each Generator Owner and Transmission Owner shall set its applicable
voltage protection 85 in accordance with PRC-024 Attachment 2Aa, such
that the applicable protection does not cause the generating
resourceFacility to which it is applied to trip within the “no trip zone” or
cease injecting current during a voltage excursion within the “no trip
zone” at the high- side of the GSU or MPT, subject to the following
exceptions: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
•
For newly designated strategic power plants, applicable protections
must comply with the high voltage durations for such plants within 48
calendar months of the notification made pursuant to Requirement
D.A.5. During this transition period, voltage protections must at least
comply with the high voltage durations for “all power plants”.
•
Applicable voltage protection may The generating resource(s) are
permitted to be set to trip or to cease injecting current during a
voltage excursion within a portion of bounded by the “no trip zone”
of PRC-024 Attachment 2Aa for documented and communicated
regulatory or equipment limitations in accordance with Requirement
R3.
•
If the Transmission Planner allows less stringent voltage protection
settings than those required to meet PRC-024 Attachment 2Aa, then
the Generator Owner or Transmission Owner may set its protection
Frequency, voltage, and volts per hertz protection (whether provided by relaying or functions within associated
control systems) that respond to electrical signals and: (i) directly trip the synchronous generator(s), type 1 or type
2 wind resource(s), or synchronous condenser(s); or (ii) provide signals to trip the same Facilities.
8
Page 11 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and
Type 2 Wind Resources, and Synchronous Condensers
within the voltage recovery characteristics of a location-specific
Transmission Planner’s study.
•
Inverter-based resources voltage protection settings may be set to
cease injecting current momentarily during a voltage excursion at the
high side of the MPT, bounded by the “no trip zone” of PRC-024
Attachment 2a, under the following conditions:
o After a minimum delay of 0.022 s, when the positive-sequence
voltage exceeds 1.25 per unit (p.u.) Normal operation must
resume once the voltage drops back below 1.25 p.u at the high
side of the MPT.
o After a minimum delay of 0.022 s, when the phase-to-ground
root mean square (RMS) voltages exceeds 1.4 p.u., as measured
at generator terminals, on one or multiple phases. Normal
operation must resume once the positive-sequence voltage
drops back below the 1.25 p.u. at the high side of the MPT.
M.D.A.2. Each Generator Owner and Transmission Owner shall have evidence that
applicable voltage protection has been set in accordance with
Requirement R2, such as dated setting sheets, voltage-time boundaries,
calibration sheets, coordination plots, dynamic simulation studies,
calculations, or other documentation.
This Variance adds the following Requirement:
D.A.5
Each Planning Coordinator shall designate, at least once every five
calendar years, the strategic power plants that must comply with
Attachment 2Aa and notify, within 30 calendar days of its designation,
each Generator Owner or Transmission Owner that owns facilities 9 in the
strategic power plants. [Violation Risk Factor: Medium] [Time Horizon:
Long-term planning]
M.D.A.5
Each Planning Coordinator shall have evidence that it designated, at least
once every five calendar years, strategic power plants in accordance with
Requirement D.A.5, Part 5 and shall have dated evidence that each
Generator Owner or Transmission Owner has been notified in accordance
with Requirement D.A.5, part 5.2. Evidence may include, but is not
limited to: letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
Facilities in the strategic power plants include facilities with synchronous generator(s) from the generator up to
and including the MPT or GSU.
9
Page 12 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2 Wind and Synchronous Condensers
Resources
Violation Severity Levels
This Variance adds a VSL for D.A.5 and modifies the VSL for R2 as follows:
Violation Severity Levels
R#
Lower
VSL
Moderate VSL
High VSL
Severe VSL
D.A.2.
N/A
N/A
N/A
The Generator Owner or
Transmission Owner failed to
set its applicable voltage
protection so that it does not
trip or cease injecting current in
accordance with Requirement
D.A.2.
OR
D.A.5.
N/A
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or
Transmission Owner that owns
The Planning Coordinator designated
strategic power plants at least once
every five calendar years but notified
each Generator Owner or
Transmission Owner that owns
The Generator Owner or
Transmission Owner set its
applicable voltage protection in
accordance with Requirement
D.A.2 but, for strategic power
plants, failed to do so within 48
months of notification.
The Planning Coordinator failed
to designate, at least once
every five years, the strategic
power plants that must comply
with Attachment 2Aa.
Page 13 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2 Wind and Synchronous Condensers
Resources
Violation Severity Levels
R#
Lower
VSL
Moderate VSL
High VSL
Severe VSL
facilities in the strategic power plants facilities in the strategic power plants
between 31 days and 45 days after its between 46 days and 60 days after its OR
designation.
designation.
The Planning Coordinator failed
to notify, each Generator
Owner or Transmission Owner
that owns facilities in the
strategic power plants or
notified them more than 60
days after the its designation.
E. Associated Documents
Implementation Plan
Page 14 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
E.A.
Associated Documents
Implementation Plan
Page 15 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Version History
Version
Date
Action
Change Tracking
1
May 9, 2013
Adopted by the NERC Board of
Trustees
1
March 20, 2014
FERC Order issued approving PRC024-1. (Order becomes effective
on 7/1/16.)
2
February 12, 2015
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2014-01:
Applicability revised to
clarify application of
requirements to BES
dispersed power
producing resources
2
May 29, 2015
FERC Letter Order in Docket No.
RD15-3-000 approving PRC-024-2
Modifications to adjust
the applicability to
owners of dispersed
generation resources.
3
February 6, 2020
Adopted by the NERC Board of
Trustees
Standard revised in
Project 2018-04
3
July 9, 2020
FERC Letter Order approved PRC024-3. Docket No. RD20-7-000
3
July 17,2020
October 1, 2022
Effective Date
4
August 2, 2024
Revisions made by the 2020-02
Drafting Team
Revision accounts for
changes with PRC-029-1
as part of Milestone 2 of
NERC’s work plan to
address FERC Order No.
901.
Page 16 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Attachment 1
(Frequency No Trip Boundaries by Interconnection 10)
Eastern Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 1: Eastern Interconnection Boundaries
Figure 1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 1: Frequency Boundary Data Points - Eastern Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
Instantaneous11
≤57.8
Instantaneous11
≥60.5
10(90.935-1.45713*f)
≤59.5
10(1.7373*f-100.116)
The figures do not visually represent the “no trip zone” boundaries before 0.1 seconds and after 10,000 seconds. The
Frequency Boundary Data Points Table defines the entirety of the “no trip zone” boundaries.
10
Frequency is calculated over a window of time. While the frequency boundaries include the option to trip instantaneously for
frequencies outside the specified range, this calculation should occur over a time window. Typical window/filtering lengths are
three to six cycles (50 – 100 milliseconds). Instantaneous trip settings based on instantaneously calculated frequency
measurement is not permissible.
11
Page 17 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
<60.5
Continuous operation
> 59.5
Continuous operation
Table 1
Western Interconnection Boundaries
Frequency (Hz)
63
62
61
60
No Trip Zone*
59
58
57
56
0.1
1
10
100
1000
10000
Time (Sec)
Figure 2: Western Interconnection Boundaries
Figure 2
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 2: Frequency Boundary Data Points – Western Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.7
Instantaneous11
≤57.0
Instantaneous11
≥61.6
30
≤57.3
0.75
≥60.6
180
≤57.8
7.5
<60.6
Continuous operation
≤58.4
30
≤59.4
180
>59.4
Continuous operation
Table 2
Page 18 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Frequency (Hz)
Quebec Interconnection Boundaries
67
66
65
64
63
62
61
60
59
58
57
56
55
No Trip Zone*
0.1
1
10
100
1000
10000
Time (Sec)
Figure 3: Quebec Interconnection Boundaries
Figure 3
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 3: Frequency Boundary Data Points – Quebec Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (Sec)
>66.0
Instantaneous11
<55.5
Instantaneous11
≥63.0
5
≤56.5
0.35
≥61.5
90
≤57.0
2
≥60.6
660
≤57.5
10
<60.6
Continuous operation
≤58.5
90
≤59.4
660
>59.4
Continuous operation
Table 3
Page 19 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
ERCOT Interconnection Boundaries
63
Frequency (Hz)
62
61
60
No Trip Zone*
59
58
57
0.1
1
10
100
1000
10000
Time (Sec)
Figure 4: ERCOT Interconnection Boundaries
Figure 4
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 4: Frequency Boundary Data Points – ERCOT Interconnection
High Frequency Duration
Low Frequency Duration
Frequency (Hz)
Minimum Time (Sec)
Frequency (Hz)
Minimum Time (sec)
≥61.8
Instantaneous11
≤57.5
Instantaneous11
≥61.6
30
≤58.0
2
≥60.6
540
≤58.4
30
<60.6
Continuous
operation
≤59.4
540
>59.4
Continuous operation
Table 4
Page 20 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
PRC-024 — Attachment 2
Voltage (per unit)10
(Voltage No-Trip Boundaries – Eastern, Western, and ERCOT Interconnections)
1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
The Voltage No Trip Zone ends at 4
seconds for applicability to PRC-024
No Trip Zone*
0
0.5
1
1.5
2
2.5
Time (sec)
High Voltage Duration
3
3.5
4
Low Voltage Duration
Figure 5: Voltage No-Trip Boundaries – Eastern, Western, and ERCOT
Interconnections
12Figure
1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Table 5: Voltage Boundary Data Points
High Voltage Duration
Low Voltage Duration
Voltage (pu)
Minimum Time (sec)
Voltage (pu)
Minimum Time (sec)
≥1.200
≥1.175
≥1.15
≥1.10
<1.10
0.00
0.20
0.50
1.00
4.00
<0.45
<0.65
<0.75
<0.90
≥ 0.90
0.15
0.30
2.00
3.00
4.00
Voltage at the high-side of the GSU or MPT.
10
Page 21 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Table 1
Page 22 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
Attachment 2: Voltage Boundary Clarifications – Eastern,
Western, and ERCOT Interconnections
Boundary Details:
1. Unless otherwise specified by the Transmission Planner, the per unit voltage base for
these boundaries is the nominal transmission system voltage (e.g., 100 kV, 115 kV, 138
kV, 161 kV, 230 kV, 345 kV, 400 kV, 500 kV, 765 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60
Hertz or the magnitude of the high voltage boundary can be adjusted in proportion to
deviations of frequency below 60 Hertz.
4. Voltages in the boundaries assume RMS fundamental frequency phase-to-ground or
phase-to-phase per unit voltage.
5. For applicability to PRC-024, the “no trip zone” ends at 4 seconds.
Evaluating Protection Settings:
The voltage values in the Attachment 2 voltage boundaries are voltages at the high side of the
GSU/MPT. For generating resources with multiple stages of step up to reach interconnecting
voltage, this is the high side of the transformer with a low side below 100kV and a high side
100kV or above. When evaluating protection settings, consider the voltage differences between
where the protection is measuring voltage and the high side of the GSU/MPT. A steady state
calculation or dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the synchronous generator,
type 1 or 2 wind resources, or synchronous condenser unit under study.
b. All installed wind resource generating plant reactive support (e.g., static VAR
compensators, synchronous condensers, capacitors) equipment is available and
operating normally.
c. Account for the actual tap settings of transformers between the generator terminals or
the collector station and the high side of the GSU/MPT.
d. For dynamic simulations, the synchronous generator or condenser automatic voltage
regulator is in automatic voltage control mode with associated limiters in service.
Page 23 of 26
PRC-024-34 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind and Synchronous Condensers Resources
PRC-024— Attachment 2a
(Voltage No-Trip Boundaries – Quebec Interconnection)
May cease current injection momentarily
under specified conditions
1.5
Positive-sequence Voltage (per unit)
1.4
1.25
1.20
1.15
1.10
1.0
"No Trip Zone" *
0.90
0.85
0.75
0.25
0
0 0.1
0.033
0.15
2.5
0.5
1
2
3
4
5
30
300
Time (sec)
Low Voltage/High Voltage Duration - All Power Plants
Low Voltage Duration – Inverter-Based Resources
High Voltage Duration - Strategic Power Plants
Figure 6: Voltage No-Trip Boundaries – Quebec Interconnection
Figure 1
* The area outside the "No Trip Zone" is not a "Must Trip Zone."
Page 24 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind, and Synchronous Condensers Resources
V Table 6: High Voltage Boundary Data Points – Quebec Interconnection
High Voltage Duration for all Power
Plants
High Voltage Duration for strategic
Power Plants
Voltage (pu)
Minimum Time (sec)
Voltage (pu)
Minimum Time (sec)
-->1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
--0.033
0.10
2.00
30
300
continuous
>1.50
>1.40
>1.25
>1.20
>1.15
>1.10
≤1.10
0.033
0.10
2.50
5.00
30
300
continuous
Table 1
Table 7: Low Voltage Boundary Data Points – Quebec Interconnection
Low Voltage Duration for all Power
Plants
Low Voltage Duration for InverterBased Resources
Voltage (pu)
Minimum Time (sec)
Voltage (pu)
Minimum Time (sec)
<0.25
<0.75
<0.85
<0.90
≥0.90
0.15
1.00
2.00
30
continuous
<0.25
<0.75
<0.85
<0.90
≥0.90
3.4*V(pu)+0.15
1.00
2.00
30
continuous
Table 2
Page 25 of 26
PRC-024-43 —Frequency and Voltage Protection Settings for Synchronous Generatorsing, Type 1 and 2
Wind, and Synchronous Condensers Resources
Attachment 2Aa: Voltage Boundary Clarifications – Quebec
Interconnection
Boundary Details:
1. The per unit voltage base for these boundaries is the nominal operating voltage (e.g., 120
kV, 161 kV, 230 kV, 315 kV, 735 kV, etc.).
2. The values in the table represent the minimum time durations allowed for specified
voltage excursion thresholds.
3. When evaluating volts per hertz protection, either assume a system frequency of 60 Hertz
or the magnitude of the high voltage boundary can be adjusted in proportion to deviations
of frequency below 60 Hertz.
4. Voltages in the Quebec Interconnection boundaries assume positive-sequence values.
Evaluating Protection Settings:
The voltage values in the Attachment 2a voltage boundaries are voltages at the high side of the
GSU/MPT. For generating resources with multiple stages of step up to reach interconnecting
voltage, this is the high side of the transformer that connects to the interconnecting voltage.
When evaluating protection settings, consider the voltage differences between where the
protection is measuring voltage and the high side of the GSU/MPT. A steady state calculation or
dynamic simulation may be used.
If using a steady state calculation or dynamic simulation, use the following conditions when
evaluating protection settings:
a. The most probable real and reactive loading conditions for the unit under study.
b. All installed generating plant reactive support (e.g., static VAR compensators, synchronous
condensers, capacitors) equipment is available and operating normally.
c. Account for the actual tap settings of transformers between the generator terminals and
the high side of the GSU/MPT.
d. For dynamic simulations, the automatic voltage regulator is in automatic voltage control
mode with associated limiters in service.
Page 26 of 26
Technical Rationale
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-024-4 – Frequency and Voltage Protection Settings for Synchronous
Generators, Type 1 and 2 Wind Plants, and Synchronous Condensers
General Rationale
The drafting team proposes to modify PRC-024-3 to retain the Reliability Standard as a protection-based
standard with applicability to only synchronous generators, synchronous condensers, and type 1 and 2
wind plants. This proposal is a consequence of both the different natures of synchronous and inverterbased generation resources and several recent events exhibiting significant IBR ride-through deficiencies.
The behavior of rotating synchronous generators during faults and other disturbances on the transmission
system is well established and understood in comparison to IBR generation. The disturbance ride-through
vulnerabilities of synchronous generators are pole slipping instability and undervoltage dropout of critical
plant auxiliary equipment, leading to tripping of a generator. Pole slipping (or loss of synchronism) can be
managed by active power dispatch constraints or stability System Operating Limits, and is outside the
scope of Project 2020-02. Undervoltage dropout of critical auxiliary equipment is also outside the scope of
Project 2020-02 because of complexities associated with auxiliary systems and how such equipment
behaves under low voltage conditions. The Project 2020-02 Standard Authorization Request (SAR) notes
that auxiliary equipment has not posed a ride-through risk and the SAR specifically excludes modifications
in PRC-024-3 for auxiliary equipment.
Over-frequency protection, under-frequency protection, over-voltage protection, and under-voltage
protection may or may not be applied to synchronous generating units. If applied, settings should be
coordinated between the needs of generating unit protection and the no-trip zones within PRC-024-4
attachments. Coordination of generating unit capabilities, voltage regulating controls, and protection is
addressed within PRC-019-2. Excitation and governing controls affect synchronous generator ride-through
behavior to some degree but because of progressive improvement, standardization, and level of maturity
of these controls, they are rarely a cause of unnecessary tripping during disturbances. In addition, there
are other existing NERC standards to prevent unnecessary tripping of the generators during a system
disturbance such as PRC-025-2 “Generator Relay Loadability” and PRC-026-2 “Relay Performance During
Stable Power Swings”. For these reasons, there is no need to impose actual disturbance ride-through
requirements on synchronous units but only to include restrictions for frequency and voltage protection
setting ranges as maintained in PRC-024-4.
Rationale for Applicability Section (4.0)
Functional Entities (4.1)
The functional entity responsible for setting frequency, voltage, and volts per hertz protection for
synchronous generators, type 1 and 2 wind plants, and synchronous condensers is either the Generator
Owner (GO) or Transmission Owner (TO). Planning Coordinators (PC) are retained as applicable entities
only in the Quebec Interconnection. Modifications are proposed in PRC-024-4 to expand functional entity
RELIABILITY | RESILIENCE | SECURITY
applicability to include “Transmission Owners that apply protection” because of the inclusion of
synchronous condenser applicability in section 4.2.2.
Facilities (4.2)
Applicability Facilities subparts in Section 4.1.1 were modified to restrict PRC-024-4 to synchronous
generators and type 1 and 2 wind plants. Section 4.2.2 was added to cover synchronous condensers and
associated equipment.
Rationale for Requirements R1 through R4
Modifications were made to Requirements R1, R2, R3, and R4 to include the Transmission Owner as a
functional entity applicable to each requirement because of the addition of synchronous condensers.
Modifications were made to Requirements R1, R2, R3, and R4 to include language for type 1 and 2 wind
plants and synchronous condensers and to remove language that relates to inverter-based resource (IBR)
functionality since IBRs will be addressed in a new standard PRC-029-1.
Technical Rationale for Reliability Standard PRC-024-4
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | September 2024
2
Violation Risk Factor and Violation Severity Level
Justifications
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
PRC-024-4
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC-024-4. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to BulkPower System instability, separation, or a cascading sequence of
failures, or could place the Bulk-Power System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to BulkPower System instability, separation, or a cascading sequence of failures, or could place the Bulk-Power System at
an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk-Power System, or the ability to effectively
monitor and control the Bulk-Power System. However, violation of a medium risk requirement is unlikely to lead to Bulk- Power System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the BulkPower
System, or the ability to effectively monitor, control, or restore the BulkPower System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Power System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk-Power System, or the ability to effectively monitor and control the Bulk-Power System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk-Power
System, or the ability to effectively monitor, control, or restore the Bulk-Power System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
2
Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
3
NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
The performance or product
measured meets the majority of the
intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet some
of the intent.
Severe VSL
The performance or product
measured does not substantively
meet the intent of the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
4
Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
5
The VRF did not change from the previously FERC approved PRC-024-3 Reliability Standard.
VSLs for PRC-024-4, Requirement R1
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to set its
applicable frequency protection so
that it does not trip according to
Requirement R1.
VSL Justifications for PRC-024-4, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
consequence of lowering the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
6
VSL Justifications for PRC-024-4, Requirement R1
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
7
The VRF did not change from the previously FERC approved PRC-024-3 Reliability Standard.
VSLs for PRC-024-4, Requirement R2
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Generator Owner or
Transmission Owner failed to set its
applicable voltage protection so that
it does not trip according to
Requirement R2.
VSL Justifications for PRC-024-4, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
consequence of lowering the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
8
VSL Justifications for PRC-024-4, Requirement R2
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
9
The VRF did not change from the previously FERC approved PRC-024-3 Reliability Standard.
VSLs for PRC-024-4, Requirement R3
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner documented
the known non-protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 30
calendar days but less than or
equal to 60 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner documented
the known non-protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 60
calendar days but less than or
equal to 90 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner documented
the known non-protection system
equipment limitation that
prevented it from meeting the
criteria in Requirement R1 or R2
and communicated the
documented limitation to its
Planning Coordinator and
Transmission Planner more than 90
calendar days but less than or
equal to 120 calendar days of
identifying the limitation.
The Generator Owner or
Transmission Owner failed to
document any known nonprotection system equipment
limitation that prevented it from
meeting the criteria in Requirement
R1 or R2.
OR
The Generator Owner or
Transmission Owner failed to
communicate the documented
limitation to its Planning
Coordinator and Transmission
Planner within 120 calendar days of
identifying the limitation.
VSL Justifications for PRC-024-4, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
consequence of lowering the level of compliance.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
10
VSL Justifications for PRC-024-4, Requirement R3
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
11
The VRF did not change from the previously FERC approved PRC-024-3 Reliability Standard.
VSLs for PRC-024-4, Requirement R4
Lower
Moderate
High
The Generator Owner or
Transmission Owner provided its
protection settings more than 60
calendar days but less than or
equal to 90 calendar days of any
change to those settings.
The Generator Owner or
Transmission Owner provided its
protection settings more than 90
calendar days but less than or
equal to 120 calendar days of any
change to those settings.
The Generator Owner or
Transmission Owner provided its
protection settings more than 120
calendar days but less than or
equal to 150 calendar days of any
change to those settings.
OR
OR
OR
The Generator Owner or
Transmission Owner provided
protection settings more than 60
calendar days but less than or
equal to 90 calendar days of a
written request.
The Generator Owner or
Transmission Owner provided
protection settings more than 90
calendar days but less than or
equal to 120 calendar days of a
written request.
The Generator Owner or
Transmission Owner or provided
protection settings more than 120
calendar days but less than or
equal to 150 calendar days of a
written request.
Severe
The Generator Owner or
Transmission Owner failed to
provide its protection settings within
150 calendar days of any change to
those settings.
OR
The Generator Owner or
Transmission Owner failed to
provide protection settings within
150 calendar days of a written
request.
VSL Justifications for PRC-024-4, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The requirement adds a functional entity. Therefore, the proposed VSLs do not have the unintended
consequence of lowering the level of compliance.
FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
The proposed VSLs are binary and do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
12
VSL Justifications for PRC-024-4, Requirement R4
Penalties
Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations
Each VSL is based on a single violation and not cumulative violations.
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | PRC-024-4
VRF and VSL Justifications | September 2024
13
Standards Announcement
Project 2020-02 Modifications to PRC-024 (Generator Ridethrough)
Final Ballot Open through September 30, 2024
Now Available
A final ballot for PRC-024-4 - Frequency and Voltage Protection Settings for Synchronous Generators,
Type 1 and Type 2 Wind Resources, and Synchronous Condensers is open through 8 p.m. Eastern,
Monday, September 30, 2024.
The Implementation Plan for Project 2020-02 Modifications to PRC-024 (Generator Ride-through) applies
to both PRC-024-4 and PRC-029-1. The Implementation Plan was posted on September 17 with the reballot of PRC-029-1 and is open for final ballot through 8 p.m. Eastern, Monday, September 30, 2024.
Balloting
In the final ballot, votes are counted by exception. Votes from the previous ballot are automatically
carried over in the final ballot. Only members of the applicable ballot pools can cast a vote. Ballot pool
members who previously voted have the option to change their vote in the final ballot. Ballot pool
members who did not cast a vote during the previous ballot can vote in the final ballot.
Members of the ballot pool(s) associated with this project can log into the Standards Balloting and
Commenting System (SBS) and submit votes here.
•
Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours
for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The voting results will be posted and announced after the ballots close. If approved, the standard will be
submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory
authorities.
For information on the Standards Development Process, refer to the Standard Processes Manual.
RELIABILITY | RESILIENCE | SECURITY
For more information or assistance, contact Director of Standards Development, Jamie Calderon (via email)
or at 404-960-0568.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | PRC-024-4 - Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2
Wind Resources, and Synchronous Condensers
Final Ballot | September 2024
2
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Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Ballot Name: 2020-02 Modifications to PRC-024 (Generator Ride-through) PRC-024-4 FN 3 ST
Voting Start Date: 9/25/2024 11:12:13 AM
Voting End Date: 9/30/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 3
Total # Votes: 246
Total Ballot Pool: 271
Quorum: 90.77
Quorum Established Date: 9/25/2024 12:01:49 PM
Weighted Segment Value: 86.41
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
75
1
47
0.855
8
0.145
0
11
9
Segment:
2
8
0.8
7
0.7
1
0.1
0
0
0
Segment:
3
55
1
41
0.837
8
0.163
0
3
3
Segment:
4
14
1
11
0.917
1
0.083
0
0
2
Segment:
5
68
1
44
0.83
9
0.17
0
8
7
Segment:
6
46
1
29
0.806
7
0.194
0
6
4
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Segment
Segment: 0
0
0
0
9 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
© 2024
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
10
5
0.5
5
0.5
0
0
0
0
0
Totals:
271
6.3
184
5.444
34
0.856
0
28
25
Segment
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Affirmative
N/A
1
Ameren - Ameren Services
Tamara Evey
None
N/A
1
American Transmission
Company, LLC
Amy Wilke
None
N/A
1
APS - Arizona Public
Service Co.
Daniela
Atanasovski
Affirmative
N/A
1
Arizona Electric Power
Cooperative, Inc.
Jennifer Bray
Affirmative
N/A
1
Arkansas Electric
Cooperative Corporation
Emily Corley
None
N/A
1
Associated Electric
Cooperative, Inc.
Mark Riley
Negative
N/A
1
Austin Energy
Thomas Standifur
Affirmative
N/A
1
Avista - Avista Corporation
Mike Magruder
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Affirmative
N/A
Abstain
N/A
1
BC Hydro and Power
Adrian Andreoiu
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Authority
Tim Kelley
Segment
Organization
Voter
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
1
Black Hills Corporation
Micah Runner
1
Bonneville Power
Administration
1
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Affirmative
N/A
Kamala RogersHolliday
Abstain
N/A
CenterPoint Energy
Houston Electric, LLC
Daniela
Hammons
None
N/A
1
Central Iowa Power
Cooperative
Kevin Lyons
Affirmative
N/A
1
Colorado Springs Utilities
Corey Walker
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Affirmative
N/A
1
Duke Energy
Katherine Street
Affirmative
N/A
1
Edison International Southern California Edison
Company
Robert Blackney
Affirmative
N/A
1
Entergy
Brian Lindsey
Affirmative
N/A
1
Evergy
Kevin Frick
Affirmative
N/A
1
Eversource Energy
Joshua London
Affirmative
N/A
1
Exelon
Daniel Gacek
Affirmative
N/A
1
FirstEnergy - FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
1
Glencoe Light and Power
Commission
Terry Volkmann
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Emma Halilovic
Abstain
N/A
1
IDACORP - Idaho Power
Company
Sean Steffensen
None
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Carly Miller
Hayden Maples
Stephen Stafford
Ijad Dewan
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Denise Sanchez
Affirmative
N/A
1
International Transmission
Company Holdings
Corporation
Michael Moltane
Gail Elliott
Affirmative
N/A
1
JEA
Joseph McClung
Affirmative
N/A
1
KAMO Electric Cooperative
Micah Breedlove
Negative
N/A
1
Lakeland Electric
Larry Watt
None
N/A
1
Lincoln Electric System
Josh Johnson
None
N/A
1
Long Island Power
Authority
Isidoro Behar
Abstain
N/A
1
Los Angeles Department of
Water and Power
faranak sarbaz
Abstain
N/A
1
Lower Colorado River
Authority
Matt Lewis
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Negative
N/A
1
Manitoba Hydro
Nazra Gladu
Affirmative
N/A
1
Minnkota Power
Cooperative Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and
Water
Andrew Kurriger
Abstain
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Negative
N/A
1
National Grid USA
Michael Jones
Affirmative
N/A
1
NB Power Corporation
Jeffrey Streifling
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Affirmative
N/A
1
Northeast Missouri Electric
Power Cooperative
Brett Douglas
Negative
N/A
Affirmative
N/A
1
OGE Energy - Oklahoma
Terri Pyle
Gas and Electric Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Andy Fuhrman
Segment
Organization
Voter
1
Omaha Public Power
District
Doug Peterchuck
1
Oncor Electric Delivery
Byron Booker
1
OTP - Otter Tail Power
Company
Charles Wicklund
1
Pacific Gas and Electric
Company
Marco Rios
1
PNM Resources - Public
Service Company of New
Mexico
1
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Affirmative
N/A
Affirmative
N/A
Affirmative
N/A
Lynn Goldstein
Affirmative
N/A
PPL Electric Utilities
Corporation
Michelle
McCartney Longo
Negative
N/A
1
PSEG - Public Service
Electric and Gas Co.
Karen Arnold
Affirmative
N/A
1
Public Utility District No. 1
of Chelan County
Diane E Landry
Affirmative
N/A
1
Public Utility District No. 1
of Snohomish County
Alyssia Rhoads
Affirmative
N/A
1
Public Utility District No. 2
of Grant County,
Washington
Joanne Anderson
Affirmative
N/A
1
Sacramento Municipal
Utility District
Wei Shao
Tim Kelley
Affirmative
N/A
1
Salt River Project
Laura Somak
Israel Perez
Affirmative
N/A
1
SaskPower
Wayne
Guttormson
Abstain
N/A
1
Seminole Electric
Cooperative, Inc.
Kristine Ward
None
N/A
1
Sempra - San Diego Gas
and Electric
Mohamed Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Olivia Olson
Negative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Broc Bruton
Bob Cardle
Jennifer Lapaix
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Southern Company Southern Company
Services, Inc.
Matt Carden
Negative
N/A
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
None
N/A
1
Tallahassee Electric (City
of Tallahassee, FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley Authority
David Plumb
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Donna Wood
Affirmative
N/A
1
U.S. Bureau of
Reclamation
Richard Jackson
Affirmative
N/A
1
Unisource - Tucson Electric
Power Co.
Jessica Cordero
Abstain
N/A
1
Western Area Power
Administration
Ben Hammer
Affirmative
N/A
1
Xcel Energy, Inc.
Eric Barry
Affirmative
N/A
2
California ISO
Darcy O'Connell
Affirmative
N/A
2
Electric Reliability Council
of Texas, Inc.
Kennedy Meier
Negative
N/A
2
Independent Electricity
System Operator
Helen Lainis
Affirmative
N/A
2
ISO New England, Inc.
John Pearson
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
Affirmative
N/A
2
New York Independent
System Operator
Gregory Campoli
Affirmative
N/A
2
PJM Interconnection,
L.L.C.
Thomas Foster
Affirmative
N/A
2
Southwest Power Pool, Inc.
(RTO)
Joshua Phillips
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Jennie Wike
Elizabeth Davis
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
APS - Arizona Public
Service Co.
Jessica Lopez
Affirmative
N/A
3
Arkansas Electric
Cooperative Corporation
Ayslynn Mcavoy
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Negative
N/A
3
Austin Energy
Lovita Griffin
Affirmative
N/A
3
Avista - Avista Corporation
Robert Follini
Affirmative
N/A
3
BC Hydro and Power
Authority
Ming Jiang
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Joseph Amato
Affirmative
N/A
3
Black Hills Corporation
Josh Combs
Affirmative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Negative
N/A
3
CMS Energy - Consumers
Energy Company
Karl Blaszkowski
None
N/A
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Lincoln Burton
Affirmative
N/A
3
DTE Energy - Detroit
Edison Company
Marvin Johnson
Affirmative
N/A
3
Duke Energy - Florida
Power Corporation
Marcelo Pesantez
Affirmative
N/A
3
Edison International Southern California Edison
Company
Romel Aquino
None
N/A
3
Entergy
James Keele
Affirmative
N/A
3
Evergy
Marcus Moor
Affirmative
N/A
3
Eversource Energy
Vicki O'Leary
Affirmative
N/A
Affirmative
N/A
3
Exelon
Kinte Whitehead
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Carly Miller
Hayden Maples
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Affirmative
N/A
3
Great River Energy
Michael Brytowski
Affirmative
N/A
3
Imperial Irrigation District
George Kirschner
Affirmative
N/A
3
JEA
Marilyn Williams
Affirmative
N/A
3
Lakeland Electric
Steven Marshall
Affirmative
N/A
3
Lincoln Electric System
Sam Christensen
Affirmative
N/A
3
Los Angeles Department of
Water and Power
Fausto Serratos
Abstain
N/A
3
M and A Electric Power
Cooperative
Gary Dollins
Negative
N/A
3
Manitoba Hydro
Mike Smith
Affirmative
N/A
3
MGE Energy - Madison
Gas and Electric Co.
Benjamin Widder
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
Affirmative
N/A
3
Nebraska Public Power
District
Tony Eddleman
Affirmative
N/A
3
NiSource - Northern
Indiana Public Service Co.
Steven Taddeucci
Negative
N/A
3
North Carolina Electric
Membership Corporation
Chris Dimisa
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
Heath Henry
Negative
N/A
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Omaha Public Power
District
David Heins
Affirmative
N/A
3
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB02
Denise Sanchez
Scott Brame
Segment
Organization
Voter
3
Pacific Gas and Electric
Company
Sandra Ellis
3
Platte River Power
Authority
3
Designated
Proxy
NERC
Memo
Affirmative
N/A
Richard Kiess
Affirmative
N/A
PNM Resources - Public
Service Company of New
Mexico
Amy
Wesselkamper
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
James Frank
Negative
N/A
3
PSEG - Public Service
Electric and Gas Co.
Christopher
Murphy
Affirmative
N/A
3
Public Utility District No. 1
of Chelan County
Joyce Gundry
Affirmative
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Tim Kelley
Affirmative
N/A
3
Salt River Project
Mathew Weber
Israel Perez
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
Usama Tahir
None
N/A
3
Sempra - San Diego Gas
and Electric
Bryan Bennett
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Negative
N/A
3
Snohomish County PUD
No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Negative
N/A
3
Tennessee Valley Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Ryan Walter
Affirmative
N/A
3
WEC Energy Group, Inc.
Christine Kane
Affirmative
N/A
3
Xcel Energy, Inc.
Nicholas Friebel
Affirmative
N/A
Affirmative
N/A
4
Alliant Energy Corporation
Larry Heckert
Services,
Inc. Name: ATLVPEROWEB02
© 2024 - NERC Ver 4.2.1.0
Machine
Bob Cardle
Ballot
Segment
Organization
Voter
4
Austin Energy
Tony Hua
4
Buckeye Power, Inc.
Jason Procuniar
4
CMS Energy - Consumers
Energy Company
4
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Negative
N/A
Aric Root
Affirmative
N/A
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Affirmative
N/A
4
Georgia System
Operations Corporation
Katrina Lyons
Affirmative
N/A
4
North Carolina Electric
Membership Corporation
Richard McCall
Affirmative
N/A
4
Oklahoma Municipal Power
Authority
Michael Watt
None
N/A
4
Public Utility District No. 1
of Snohomish County
John D.
Martinsen
Affirmative
N/A
4
Public Utility District No. 2
of Grant County,
Washington
Karla Weaver
Affirmative
N/A
4
Sacramento Municipal
Utility District
Foung Mua
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
George Pino
None
N/A
4
Utility Services, Inc.
Carver Powers
Affirmative
N/A
4
Western Power Pool
Kevin Conway
Affirmative
N/A
5
AEP
Thomas Foltz
Affirmative
N/A
5
AES - AES Corporation
Ruchi Shah
Negative
N/A
5
Ameren - Ameren Missouri
Sam Dwyer
Affirmative
N/A
5
American Municipal Power
Amy Ritts
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Andrew Smith
Affirmative
N/A
5
Associated Electric
Cooperative, Inc.
Chuck Booth
Negative
N/A
Affirmative
N/A
© 2024
5 - NERC Ver 4.2.1.0
AustinMachine
Energy Name: ATLVPEROWEB02
Michael Dillard
Ryan Strom
Scott Brame
Tim Kelley
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Avista - Avista Corporation
Glen Farmer
Affirmative
N/A
5
BC Hydro and Power
Authority
Quincy Wang
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Dwanique Spiller
Affirmative
N/A
5
Black Hills Corporation
Sheila Suurmeier
Affirmative
N/A
5
Bonneville Power
Administration
Milli Chennell
Abstain
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
None
N/A
5
CMS Energy - Consumers
Energy Company
David Greyerbiehl
Affirmative
N/A
5
Colorado Springs Utilities
Jeffrey Icke
Affirmative
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Michelle Pagano
Affirmative
N/A
5
Constellation
Alison MacKellar
Negative
N/A
5
Dairyland Power
Cooperative
Tommy Drea
Affirmative
N/A
5
Decatur Energy Center
LLC
Megan Melham
Affirmative
N/A
5
DTE Energy - Detroit
Edison Company
Mohamad
Elhusseini
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California Edison
Company
Selene Willis
Affirmative
N/A
5
Enel Green Power
Natalie Johnson
Abstain
N/A
5
Entergy - Entergy Services,
Inc.
Gail Golden
None
N/A
Affirmative
N/A
5
Evergy
Jeremy Harris
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Hayden Maples
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Corporation
Matthew Augustin
Affirmative
N/A
5
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Jacalynn Bentz
Affirmative
N/A
5
Greybeard Compliance
Services, LLC
Mike Gabriel
Negative
N/A
5
Grid Strategies LLC
Michael Goggin
Negative
N/A
5
Imperial Irrigation District
Tino Zaragoza
Affirmative
N/A
5
Invenergy LLC
Rhonda Jones
Negative
N/A
5
JEA
John Babik
Affirmative
N/A
5
Lincoln Electric System
Brittany Millard
Affirmative
N/A
5
Los Angeles Department of
Water and Power
Robert Kerrigan
Abstain
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Lower Colorado River
Authority
Teresa Krabe
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N/A
5
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LLC
C. A. Campbell
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Chance Back
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5
National Grid USA
Robin Berry
Affirmative
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5
NB Power Corporation New Brunswick Power
Transmission Corporation
Fon Hiew
Abstain
N/A
5
New York Power Authority
Zahid Qayyum
Negative
N/A
5
North Carolina Electric
Membership Corporation
Reid Cashion
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
None
N/A
5
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Gas and Electric Co.
Patrick Wells
Affirmative
N/A
Affirmative
N/A
5
Oglethorpe Power
Donna Johnson
Corporation
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Wilkerson
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5
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Inc.
Constantin
Chitescu
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N/A
5
OTP - Otter Tail Power
Company
Stacy Wahlund
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5
Pacific Gas and Electric
Company
Tyler Brun
Affirmative
N/A
5
Pattern Operators LP
George E Brown
Affirmative
N/A
5
PPL - Louisville Gas and
Electric Co.
Julie Hostrander
Negative
N/A
5
PSEG Nuclear LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District No. 1
of Chelan County
Rebecca Zahler
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Becky Burden
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N/A
5
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Utility District
Ryder Couch
Tim Kelley
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N/A
5
Salt River Project
Thomas Johnson
Israel Perez
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5
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Cooperative, Inc.
Melanie Wong
None
N/A
5
Sempra - San Diego Gas
and Electric
Jennifer Wright
Affirmative
N/A
5
Southern Company Southern Company
Generation
Leslie Burke
Negative
N/A
5
Tallahassee Electric (City
of Tallahassee, FL)
Karen Weaver
Affirmative
N/A
5
Tennessee Valley Authority
Darren Boehm
Abstain
N/A
5
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Ashley Scheelar
None
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5
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Association, Inc.
Sergio Banuelos
Affirmative
N/A
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Adam Burlock
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U.S. Bureau of
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Wendy Kalidass
5
Vistra Energy
Daniel
Roethemeyer
5
WEC Energy Group, Inc.
5
Designated
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Memo
Affirmative
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Affirmative
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Gerry Huitt
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N/A
6
AEP
Mathew Miller
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6
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Robert Quinlivan
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6
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Marcus Bortman
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Bruce Walkup
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6
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Brian Ackermann
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Imane Mrini
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6
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Rachel Schuldt
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6
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Robert Hirchak
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N/A
6
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Edison Co. of New York
Jason Chandler
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N/A
6
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Kimberly Turco
Negative
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6
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Resources, Inc.
Sean Bodkin
Affirmative
N/A
6
Duke Energy
John Sturgeon
Negative
N/A
6
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Company
Stephanie Kenny
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Affirmative
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6
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Julie Hall
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Evergy
Tiffany Lake
6
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NERC
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Great River Energy
Brian Meloy
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Affirmative
N/A
6
Invenergy LLC
Colin Chilcoat
Negative
N/A
6
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Paul Shipps
Affirmative
N/A
6
Lincoln Electric System
Eric Ruskamp
Affirmative
N/A
6
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Anton Vu
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Russell Ferrell
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6
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Brandin Stoesz
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6
Muscatine Power and
Water
Nicholas Burns
Abstain
N/A
6
New York Power Authority
Shelly Dineen
Negative
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6
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Justin Welty
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Dmitriy Bazylyuk
Negative
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Martin Sidor
Abstain
N/A
6
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Gas and Electric Co.
Ashley F Stringer
Affirmative
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6
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District
Shonda McCain
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6
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Co.
Stefanie Burke
None
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6
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Raj Hundal
Abstain
N/A
6
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Electric Co.
Linn Oelker
Negative
N/A
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Bret Galbraith
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No. 1
John Liang
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6
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Ron Carlsen
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David Boeshaar
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Gerry Dunbar
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PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Final Draft of PRC-029-1 is posted for a formal comment and additional ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
25-day formal comment period and initial ballot
March 27 – April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
15-day formal comment period and additional ballot
July 22 – August 12, 2024
14-day formal comment period and additional ballot
September 17 –
September 30, 2024
Final Ballot
None Required
Board adoption
October 8, 2024
Final Draft of PRC-029-1
October 2024
Page 1 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Ride-through: The plant/facility remains connected and continues to operate through voltage
or frequency system disturbances.
Final Draft of PRC-029-1
October 2024
Page 2 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
A. Introduction
1. Title:
Frequency and Voltage Ride-through Requirements for Inverter-based
Resources
2. Number:
PRC-029-1
3. Purpose:
To ensure that IBRs Ride-through to support the Bulk Power System (BPS)
during and after defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.2
Facilities:
4.2.1. Bulk Electric System (BES) IBRs
4.2.2. Non-BES IBRs that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system
designed primarily for delivering such capacity to a common point of
connection at a voltage greater than or equal to 60 kV.
Effective Date: See Implementation Plan for Project 2020-02 – PRC-029-1
Standard-only Definition: None
Final Draft of PRC-029-1
October 2024
Page 3 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
B. Requirements and Measures
R1.
Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements, in accordance with the “must Ridethrough 1 zone” as specified in Attachment 1, except in the following conditions:
[Violation Risk Factor: High] [Time Horizon: Operations Assessment]
•
The IBR needed to electrically disconnect in order to clear a fault;
•
The voltage at the high-side of the main power transformer 2 went outside an
accepted hardware limitation, in accordance with Requirement R4;
•
The instantaneous positive sequence voltage phase angle change is more than
25 electrical degrees at the high-side of the main power transformer and is
initiated by a non-fault switching event on the transmission system 3; or
•
The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than
2 seconds.
M1. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R1. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner shall
retain evidence of actual disturbance monitoring (i.e., sequence of event recorder,
dynamic disturbance recorder, and fault recorder) to demonstrate that the operation
of each IBR did adhere to Ride-through requirements, as specified in Requirement R1.
If the Generator Owner choose to utilize Ride-through exemptions that occur within
the “must Ride-through zone” and are caused by non-fault initiated phase jumps of
greater than 25 electrical degrees, then each Generator Owner shall also retain
evidence of actual disturbance monitoring (i.e., sequence of event recorder, dynamic
disturbance recorder, and fault recorder) data to demonstrate that the IBR failed to
Ride-through during a phase jump of greater than or equal to 25 electrical degrees, and
documentation from their Transmission Planner, Reliability Coordinator, Planning
Coordinator, or Transmission Operator that a non-fault initiated switching event
occurred.
R2. Each Generator Owner shall ensure the design and operation is such that the voltage
performance for each IBR adheres to the following during a voltage excursion, unless a
documented hardware limitation exists in accordance with Requirement R4. [Violation
Risk Factor: High] [Time Horizon: Operations Assessment]
2.1.
While the voltage at the high-side of the main power transformer remains within
the continuous operation region as specified in Attachment 1, each IBR shall:
Includes no tripping associated with phase lock loop loss of synchronism.
For the purpose of this standard, the main power transformer is the power transformer that steps up voltage from the
collection system voltage to the nominal transmission/interconnecting system voltage for IBRs. In case of IBR connecting via a
dedicated Voltage Source Converter High Voltage Direct Current (VSC-HVDC), the main power transformer is the main power
transformer on the receiving end.
3 Current blocking mode may be used for non-fault initiated phase jumps greater than 25 degrees in order to prevent tripping.
1
2
Final Draft of PRC-029-1
October 2024
Page 4 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
2.1.1 Continue to deliver the pre-disturbance level of Real Power or available
Real Power 4, whichever is less. 5
2.1.2 Continue to deliver Reactive Rower up to its Reactive Power limit and
according to its controller settings.
2.1.3 Prioritize Real Power or Reactive Power when the voltage is less than
0.95 per unit, the voltage is within the continuous operating region, and
the IBR cannot deliver both Real Power and Reactive Power due to a
current limit or Reactive Power limit, unless otherwise specified through
other mechanisms by an associated Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator.
2.2.
2.3.
While voltage at the high-side of the main power transformer is within the
mandatory operation region as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support, on
the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under 6:
•
Reactive Power priority by default; or
•
Real Power priority if required through other mechanisms by an associated
Transmission Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator.
While voltage at the high-side of the main power transformer is within the
permissive operation region, as specified in Attachment 1, each IBR may operate
in current blocking mode if necessary to avoid tripping. Otherwise, each IBR shall
follow the requirements for the mandatory operation region in Requirement
R2.2.
2.3.1 If an IBR enters current blocking mode, it shall restart current exchange
in less than or equal to five cycles of positive sequence voltage returning
to a continuous operation region or mandatory operation region.
2.4.
Each IBR shall not itself cause voltage at the high-side of the main power
transformer to exceed the applicable high voltage thresholds and time durations
in its response as voltage recovers from the mandatory or permissive operation
regions to the continuous operation region.
2.5.
Each IBR shall restore Real Power output to the pre-disturbance or available
level 7 (whichever is lesser) within 1.0 second when the voltage at the high-side
of the main power transformer returns from the mandatory operation region or
“Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
5 Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
6 In either case and if required, the magnitude of Real Power and reactive current shall be as specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
7 “Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
4
Final Draft of PRC-029-1
October 2024
Page 5 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
permissive operation region (including operating in current blocking mode) to
the continuous operation region, as specified in Attachment 1, unless an
associated Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator requires a lower post-disturbance Real Power level
requirement or requires a different post-disturbance Real Power restoration
time through other mechanisms. 8
M2. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to requirements, as specified in Requirement R2. Examples of evidence may
include, but are not limited to dynamic simulations, studies, plant protection settings,
and control settings design evaluation. Each Generator Owner shall also retain evidence
of actual disturbance monitoring (i.e., sequence of event recorder, dynamic disturbance
recorder, and fault recorder) data to demonstrate that the operation of each IBR did
adhere to performance requirements, as specified in Requirement R2, during each
voltage excursion measured at the high-side of the main power transformer. Regarding
R2.1.3, R2.2, and R2.5, the Generator Owner shall retain evidence of receiving such
performance requirements, (e.g., email exchange, contract information) if the
Transmission Planner, Transmission Operator, Reliability Coordinator, or Planning
Coordinator has required the Generator Owner through other mechanisms to follow
performance requirements other than those in Requirement R2 (e.g., ramp rates,
Reactive Power prioritization).
R3. Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements during a frequency excursion event
whereby the System frequency remains within the “must Ride-through zone” according
to Attachment 2 and the absolute rate of change of frequency (RoCoF) 9 magnitude is
less than or equal to 5 Hz/second, unless a documented hardware limitation exists in
accordance with Requirement R4. [Violation Risk Factor: High] [Time Horizon:
Operations Assessment]
M3. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R3. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner shall
also retain evidence of actual disturbance monitoring (i.e., sequence of event recorder,
dynamic disturbance recorder, and fault recorder) data to demonstrate the operation
of each IBR did adhere to Ride-through requirements, as specified in Requirement R3,
during each frequency excursion event measured at the high-side of the main power
transformer.
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of PRC029-1, has known hardware limitations that prevent the IBR from meeting Ride-through
criteria as detailed in Requirements R1-R3, and requires an exemption from specific
Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
9 Rate of change of frequency (RoCoF) is calculated as the average rate of change for multiple calculated system frequencies for
a time period of greater than or equal to 0.1 second. RoCoF is not calculated during the fault occurrence and clearance.
8
Final Draft of PRC-029-1
October 2024
Page 6 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Ride-through criteria shall: 10 [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
4.1.
Document information supporting the identified hardware limitation no later
than 12 months following the effective date of PRC-029-1. This documentation
shall include:
4.1.1 Identifying information of the IBR (name and facility number);
4.1.2 Which aspects of Ride-through requirements that the IBR would be
unable to meet and the capability of the hardware due to the limitation;
4.1.3 Identification of the specific piece(s) of hardware causing the limitation;
4.1.4 Technical documentation verifying the limitation is due to hardware that
would need to be physically replaced to meet all Ride-through criteria,
and that the limitation cannot be remedied by software updates or
setting changes; and
4.1.5 Information regarding any plans to remedy the hardware limitation (such
as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1, except for any
material considered by the original equipment manufacturer to be proprietary
information, to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the Compliance
Enforcement Authority (CEA) no later than 12 months following the effective
date of PRC-029-1. 11
4.2.1 Provide any response for additional information requested by the
associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA to the
requestor within 90 days of the request.
4.2.2 Provide a copy of the acceptance of a hardware limitation by the CEA to
the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s) within 90 days
of receiving the acceptance. 12
4.3.
Each Generator Owner with a previously accepted limitation that replaces the
hardware causing the limitation shall document and communicate such a
hardware change to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s) within 90
days of the hardware change.
10 The exemption requests for a non-US Registered Entity should be implemented in a manner that is consistent with, or under
the direction of, the applicable governmental authority or its agency in the non-US jurisdiction.
11 To the extent the original equipment manufacturer considers any material to be proprietary, the Generator Owner is
required to share this proprietary material only with the CEA.
12 Acceptance by the CEA is verification that the information provided includes all information listed in Requirement R4.1.
Final Draft of PRC-029-1
October 2024
Page 7 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
4.3.1 When existing hardware causing the limitation is replaced, the
exemption for that Ride-through criteria no longer applies.
M4. Each Generator Owner submitting for an exemption for an IBR that is in-service by the
effective date of PRC-029-1, shall have evidence of submission to the CEA consistent
with the information listed in Requirement R4.1. Each Generator Owner shall have
evidence of communicated copies of each submission in accordance with Requirement
R4.2 and to the associated entities described in Requirement R4.2. Acceptable types of
evidence for submittals include, but are not limited to, meeting minutes, agreements,
copies of procedures or protocols in effect, or email correspondence. Acceptable types
of evidence for a hardware limitation may include, but is not limited to damage curves
provided by the original equipment manufacturer. Each Generator Owner that receives
a request for additional information under Requirement R4.2.1 shall have evidence of
providing that information within 90 days. Each Generator Owner that replaces
hardware at an IBR that is directly associated with an accepted exemption and that
hardware is the cause for the limitation, shall have evidence of communicating the
hardware change to the associated entities described in Requirement R4.3 within 90
days of the hardware replacement.
Final Draft of PRC-029-1
October 2024
Page 8 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means
NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring and/or
enforcing compliance with mandatory and enforceable Reliability Standards in
their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below is
shorter than the time since the last audit, the Compliance Enforcement Authority
may ask an entity to provide other evidence to show that it was compliant for the
full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
•
Each Generator Owner shall retain evidence with Requirements R1, R2, and
R3 in this standard for 36 calendar months or the date of the last audit,
whichever is greater.
•
Each Generator Owner shall retain evidence with Requirement R4 in this
standard for five calendar years or the date of the last audit, whichever is
greater.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC Rules
of Procedure, “Compliance Monitoring and Enforcement Program” refers to the
identification of the processes that will be used to evaluate data or information
for the purpose of assessing performance or outcomes with the associated
Reliability Standard.
Final Draft of PRC-029-1
October 2024
Page 9 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to
Ride-through in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to Ride-through
requirements in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
R2.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to adhere
to performance requirements
during voltage excursions, as
specified in Requirement R2,
unless a documented
hardware limitation exists in
accordance with Requirement
R4.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to performance
requirements during voltage
excursions, as specified in
Requirement R2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
R3.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to
Ride-through in accordance
with Attachment 2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to Ride-through
requirements in accordance
with Attachment 2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
Final Draft of PRC-029-1
October 2024
Page 10 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
R#
R4.
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 12 months, but less than
or equal to 15 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 15 months, but less than
or equal to 18 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 18 months, but less than
or equal to 24 months after
the effective date of
Requirement R4.
The Generator Owner failed to
document complete
information for IBR identified
with known hardware
limitations that prevent the
IBR from meeting Ridethrough criteria as detailed in
Requirements R1, R2, or R3.
OR
OR
OR
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
90 days but less than or equal
to 120 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
120 days, but less than or
equal to 150 days after
receiving a request for
additional information by an
entity listed in Requirement
R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
150 days but less than or equal
to 180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
provide a copy to the
applicable entities as detailed
in Requirement R4.2 within 24
months after the effective
date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
90 days but less than or equal
to 120 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
Final Draft of PRC-029-1
October 2024
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
120 days but less than or equal
to 150 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
150 days but less than or equal
to 180 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
OR
The Generator Owner failed to
respond to the applicable
Page 11 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
R#
Lower VSL
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), Reliability
Coordinator(s), and CEA more
than 90 calendar days but less
than or equal to 120 calendar
days after the change to the
hardware.
Moderate VSL
OR
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 120 calendar days but
less than or equal to 150
calendar days after the change
to the hardware.
High VSL
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 150 calendar days but
less than or equal to 180
calendar days after the change
to the hardware.
Severe VSL
entities as detailed in
Requirement R4.2.2 more than
180 days after receiving the
acceptance of a hardware
limitation by the CEA.
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s),Reliability
Coordinator(s), and CEA more
than 180 days after the change
to the hardware.
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
Final Draft of PRC-029-1
October 2024
Page 12 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Version History
Version
Date
1
10/8/24
Draft 4 approved by the NERC Board of
Trustees
1
10/16/24
Draft4_Errata approved by the Standards
Committee
Final Draft of PRC-029-1
October 2024
Action
Change
Tracking
Page 13 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-through Requirements for AC-Connected Wind IBR
13
Voltage
(per unit) 14
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 15
N/A
≥ 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
3.00
< 0.70
Mandatory Operation Region
2.50
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.16
< 0.10
Permissive Operation Region
0.16
Table 2: Voltage Ride-through Requirements for All Other IBR
Voltage
(per unit) 16
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 17
N/A
> 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
6.00
< 0.70
Mandatory Operation Region
3.00
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.32
< 0.10
Permissive Operation Region
0.32
Type 3 and type 4 wind resources directly connected to the AC Transmission System.
Refer to bullet #4 below.
15 These conditions are referred to as the “may Ride-through zone”.
16 Refer to bullet #4 below.
17 These conditions are referred to as the “may Ride-through zone”.
13
14
Final Draft of PRC-029-1
October 2024
Page 14 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
1. Table 1 applies to type 3 and type 4 wind IBR or hybrid IBR that include wind, unless
connected via a dedicated Voltage Source Converter - High Voltage Direct Current
(VSC-HVDC) transmission facility.
2. Table 2 applies to all other IBR types not covered in Table 1; including, but not
limited to, the following facilities:
a. IBR, regardless of their energy resource, interconnecting via a dedicated VSCHVDC transmission facility.
b. Other IBR or hybrid IBR consisting of photovoltaic (PV) and BESS.
3. The applicable voltage for VSC-HVDC system with a dedicated connection to an IBR
is on the AC side of the transformer(s) that is (are) used to connect the VSC-HVDC
system to the interconnected transmission system.
4. The voltage base for per unit calculation is the nominal phase-to-ground or
phase-to-phase transmission system voltage unless otherwise defined by the
Planning Coordinator, Transmission Planner, or Transmission Owner.
5. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase-to-neutral or phase-to-phase fundamental root mean square (RMS) voltage at
the high-side of the main power transformer.
6. Tables 1 and 2 are only applicable when the frequency is within the “must
Ride-through zone” as specified in Figure 1 of Attachment 2.
7. At any given voltage value, each IBR shall Ride-through unless the time duration at
that voltage has exceeded the specified minimum Ride-through time duration. If the
voltage is continuously varying over time, it is necessary to add the duration within
each band of Tables 1 and 2 over any 10 second time period.
8. The specified duration of the mandatory operation regions and the permissive
operation regions in Tables 1 and 2 is cumulative over one or more disturbances
within any 10 second time period.
9. The IBR may trip for more than four deviations of the applicable voltage at the highside of the main power transformer outside of the continuous operation region
within any 10 second time period.
10. Instantaneous trip settings based on instantaneously calculated voltage
measurements with less than filtering lengths of one cycle (16.6 millisecond) are not
permissible.
11. The “must Ride-through zone” is the combined area of the mandatory operating
regions, the continuous operating regions, and the permissive operating region. All
area outside of these operating regions is referred to as the “may Ride-through
zone”.
Final Draft of PRC-029-1
October 2024
Page 15 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 2: Frequency Ride-Through Criteria
Table 3: Frequency Ride-through Capability Requirements
System Frequency (Hz)
Minimum Ride-Through
Time (sec)
> 61.8
May trip
> 61.2
299
≤ 61.2 and ≥ 58.8
Continuous
< 58.8
299
< 57.0
May trip
1. Frequency measurements are taken at the high-side of the main power transformer.
2. Frequency is measured over a period of time (typically 3-6 cycles) to calculate system
frequency at the high-side of the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency value, each IBR shall Ride-through unless the time duration at
that frequency has exceeded the specified minimum ride-through time duration.
5. The specified durations of Table 3 are cumulative over one or more disturbances within
a 10-minute time period.
Final Draft of PRC-029-1
October 2024
Page 16 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
63
May Ride-through Zone
62
Frequency (Hz)
61
Must Ride-through Zone
60
59
58
May Ride-through Zone
57
56
0
100
200
300
299
400
500
600
700
800
900
∞
1000
Time (seconds)
Figure 1: PRC-029 Frequency Ride-through Requirements
Final Draft of PRC-029-1
October 2024
Page 17 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
Draft 4 of PRC-029-1 is posted for a formal comment and additional ballot.
Completed Actions
Date
Standards Committee accepted revised Standard Authorization Request
(SAR) for posting
April 19, 2023
Standards Committee approved waivers to the Standards Process
Manual
December 13, 2023
25-day formal comment period and initial ballot
March 27 – April 22, 2024
15-day formal comment period and additional ballot
June 18 – July 8, 2024
15-day formal comment period and additional ballot
July 22 – August 12, 2024
Anticipated Actions
Date
14-day formal comment period and additional ballot
September 17 –
September 30, 2024
Final Ballot
None Required
Board adoption
October 8, 2024
Draft 4_errata of PRC-029-1
October 2024
Page 1 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
Ride-through: The plant/facility remains connected and continues to operate through voltage
or frequency system disturbances.
Draft 4_errata of PRC-029-1
October 2024
Page 2 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
A. Introduction
1. Title:
Frequency and Voltage Ride-through Requirements for Inverter-based
Resources
2. Number:
PRC-029-1
3. Purpose:
To ensure that IBRs Ride-through to support the Bulk Power System (BPS)
during and after defined frequency and voltage excursions.
4. Applicability:
4.1
Functional Entities:
4.1.1. Generator Owner
4.2
Facilities:
4.2.1. Bulk Electric System (BES) IBRs
4.2.2. Non-BES IBRs that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system
designed primarily for delivering such capacity to a common point of
connection at a voltage greater than or equal to 60 kV.
Effective Date: See Implementation Plan for Project 2020-02 – PRC-029-1
Standard-only Definition: None
Draft 4_errata of PRC-029-1
October 2024
Page 3 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
B. Requirements and Measures
R1.
Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements, in accordance with the “must Ridethrough 1 zone” as specified in Attachment 1, except in the following conditions:
[Violation Risk Factor: High] [Time Horizon: Operations Assessment]
•
The IBR needed to electrically disconnect in order to clear a fault;
•
The voltage at the high-side of the main power transformer 2 went outside an
accepted hardware limitation, in accordance with Requirement R4;
•
The instantaneous positive sequence voltage phase angle change is more than
25 electrical degrees at the high-side of the main power transformer and is
initiated by a non-fault switching event on the transmission system 3; or
•
The Volts per Hz (V/Hz) at the high-side of the main power transformer exceed
1.1 per unit for longer than 45 seconds or exceed 1.18 per unit for longer than
2 seconds.
M1. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R1. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner shall
retain evidence of actual disturbance monitoring (i.e., sequence of event recorder,
dynamic disturbance recorder, and fault recorder) to demonstrate that the operation
of each IBR did adhere to Ride-through requirements, as specified in Requirement R1.
If the Generator Owner choose to utilize Ride-through exemptions that occur within
the “must Ride-through zone” and are caused by non-fault initiated phase jumps of
greater than 25 electrical degrees, then each Generator Owner shall also retain
evidence of actual disturbance monitoring (i.e., sequence of event recorder, dynamic
disturbance recorder, and fault recorder) data to demonstrate that the IBR failed to
Ride-through during a phase jump of greater than or equal to 25 electrical degrees, and
documentation from their Transmission Planner, Reliability Coordinator, Planning
Coordinator, or Transmission Operator that a non-fault initiated switching event
occurred.
R2. Each Generator Owner shall ensure the design and operation is such that the voltage
performance for each IBR adheres to the following during a voltage excursion, unless a
documented hardware limitation exists in accordance with Requirement R4. [Violation
Risk Factor: High] [Time Horizon: Operations Assessment]
2.1.
While the voltage at the high-side of the main power transformer remains within
the continuous operation region as specified in Attachment 1, each IBR shall:
Includes no tripping associated with phase lock loop loss of synchronism.
For the purpose of this standard, the main power transformer is the power transformer that steps up voltage from the
collection system voltage to the nominal transmission/interconnecting system voltage for IBRs. In case of IBR connecting via a
dedicated Voltage Source Converter High Voltage Direct Current (VSC-HVDC), the main power transformer is the main power
transformer on the receiving end.
3 Current blocking mode may be used for non-fault initiated phase jumps greater than 25 degrees in order to prevent tripping.
1
2
Draft 4_errata of PRC-029-1
October 2024
Page 4 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
2.1.1 Continue to deliver the pre-disturbance level of Real Power or available
Real Power 4, whichever is less. 5
2.1.2 Continue to deliver Reactive Rower up to its Reactive Power limit and
according to its controller settings.
2.1.3 Prioritize Real Power or Reactive Power when the voltage is less than
0.95 per unit, the voltage is within the continuous operating region, and
the IBR cannot deliver both Real Power and Reactive Power due to a
current limit or Reactive Power limit, unless otherwise specified through
other mechanisms by an associated Transmission Planner, Planning
Coordinator, Reliability Coordinator, or Transmission Operator.
2.2.
2.3.
While voltage at the high-side of the main power transformer is within the
mandatory operation region as specified in Attachment 1, each IBR shall
exchange current, up to the maximum capability to provide voltage support, on
the affected phases during both symmetrical and asymmetrical voltage
disturbances, either under 6:
•
Reactive Power priority by default; or
•
Real Power priority if required through other mechanisms by an associated
Transmission Planner, Planning Coordinator, Reliability Coordinator, or
Transmission Operator.
While voltage at the high-side of the main power transformer is within the
permissive operation region, as specified in Attachment 1, each IBR may operate
in current blocking mode if necessary to avoid tripping. Otherwise, each IBR shall
follow the requirements for the mandatory operation region in Requirement
R2.2.
2.3.1 If an IBR enters current blocking mode, it shall restart current exchange
in less than or equal to five cycles of positive sequence voltage returning
to a continuous operation region or mandatory operation region.
2.4.
Each IBR shall not itself cause voltage at the high-side of the main power
transformer to exceed the applicable high voltage thresholds and time durations
in its response as voltage recovers from the mandatory or permissive operation
regions to the continuous operation region.
2.5.
Each IBR shall restore Real Power output to the pre-disturbance or available
level 7 (whichever is lesser) within 1.0 second when the voltage at the high-side
of the main power transformer returns from the mandatory operation region or
“Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
5 Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
6 In either case and if required, the magnitude of Real Power and reactive current shall be as specified by the Transmission
Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator.
7 “Available Real Power" refers to changes of facility Real Power output attributed to factors such as weather patterns, change
of wind, and change in irradiance, but not changes of facility Real Power attributed to IBR tripping in whole or part.
4
Draft 4_errata of PRC-029-1
October 2024
Page 5 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
permissive operation region (including operating in current blocking mode) to
the continuous operation region, as specified in Attachment 1, unless an
associated Transmission Planner, Planning Coordinator, Reliability Coordinator,
or Transmission Operator requires a lower post-disturbance Real Power level
requirement or requires a different post-disturbance Real Power restoration
time through other mechanisms. 8
M2. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to requirements, as specified in Requirement R2. Examples of evidence may
include, but are not limited to dynamic simulations, studies, plant protection settings,
and control settings design evaluation. Each Generator Owner shall also retain evidence
of actual disturbance monitoring (i.e., sequence of event recorder, dynamic disturbance
recorder, and fault recorder) data to demonstrate that the operation of each IBR did
adhere to performance requirements, as specified in Requirement R2, during each
voltage excursion measured at the high-side of the main power transformer. Regarding
R2.1.3, R2.2, and R2.5, the Generator Owner shall retain evidence of receiving such
performance requirements, (e.g., email exchange, contract information) if the
Transmission Planner, Transmission Operator, Reliability Coordinator, or Planning
Coordinator has required the Generator Owner through other mechanisms to follow
performance requirements other than those in Requirement R2 (e.g., ramp rates,
Reactive Power prioritization).
R3. Each Generator Owner shall ensure the design and operation is such that each IBR
meets or exceeds Ride-through requirements during a frequency excursion event
whereby the System frequency remains within the “must Ride-through zone” according
to Attachment 2 and the absolute rate of change of frequency (RoCoF) 9 magnitude is
less than or equal to 5 Hz/second, unless a documented hardware limitation exists in
accordance with Requirement R4. [Violation Risk Factor: High] [Time Horizon:
Operations Assessment]
M3. Each Generator Owner shall have evidence to demonstrate the design of each IBR will
adhere to Ride-through requirements, as specified in Requirement R3. Examples of
evidence may include, but are not limited to dynamic simulations, studies, plant
protection settings, and control settings design evaluation. Each Generator Owner shall
also retain evidence of actual disturbance monitoring (i.e., sequence of event recorder,
dynamic disturbance recorder, and fault recorder) data to demonstrate the operation
of each IBR did adhere to Ride-through requirements, as specified in Requirement R3,
during each frequency excursion event measured at the high-side of the main power
transformer.
R4. Each Generator Owner identifying an IBR that is in-service by the effective date of PRC029-1, has known hardware limitations that prevent the IBR from meeting Ride-through
criteria as detailed in Requirements R1-R3, and requires an exemption from specific
Except if this would occur during a frequency excursion. The Real Power response should recover in accordance with the
primary frequency controller.
9 Rate of change of frequency (RoCoF) is calculated as the average rate of change for multiple calculated system frequencies for
a time period of greater than or equal to 0.1 second. RoCoF is not calculated during the fault occurrence and clearance.
8
Draft 4_errata of PRC-029-1
October 2024
Page 6 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Ride-through criteria shall: 10 [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
4.1.
Document information supporting the identified hardware limitation no later
than 12 months following the effective date of PRC-029-1. This documentation
shall include:
4.1.1 Identifying information of the IBR (name and facility number);
4.1.2 Which aspects of Ride-through requirements that the IBR would be
unable to meet and the capability of the hardware due to the limitation;
4.1.3 Identification of the specific piece(s) of hardware causing the limitation;
4.1.4 Technical documentation verifying the limitation is due to hardware that
would need to be physically replaced to meet all Ride-through criteria,
and that the limitation cannot be remedied by software updates or
setting changes; and
4.1.5 Information regarding any plans to remedy the hardware limitation (such
as an estimated date).
4.2.
Provide a copy of the information detailed in Requirement R4.1, except for any
material considered by the original equipment manufacturer to be proprietary
information, to the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the Compliance
Enforcement Authority (CEA) no later than 12 months following the effective
date of PRC-029-1. 11
4.2.1 Provide any response for additional information requested by the
associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), Reliability Coordinator(s), and the CEA to the
requestor within 90 days of the request.
4.2.2 Provide a copy of the acceptance of a hardware limitation by the CEA to
the associated Planning Coordinator(s), Transmission Planner(s),
Transmission Operator(s), and Reliability Coordinator(s) within 90 days
of receiving the acceptance. 12
4.3.
Each Generator Owner with a previously accepted limitation that replaces the
hardware causing the limitation shall document and communicate such a
hardware change to the associated Planning Coordinator(s), Transmission
Planner(s), Transmission Operator(s), and Reliability Coordinator(s) within 90
days of the hardware change.
10 The exemption requests for a non-US Registered Entity should be implemented in a manner that is consistent with, or under
the direction of, the applicable governmental authority or its agency in the non-US jurisdiction.
11 To the extent the original equipment manufacturer considers any material to be proprietary, the Generator Owner is
required to share this proprietary material only with the CEA.
12 Acceptance by the CEA is verification that the information provided includes all information listed in Requirement R4.1.
Draft 4_errata of PRC-029-1
October 2024
Page 7 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
4.3.1 When existing hardware causing the limitation is replaced, the
exemption for that Ride-through criteria no longer applies.
M4. Each Generator Owner submitting for an exemption for an IBR that is in-service by the
effective date of PRC-029-1, shall have evidence of submission to the CEA consistent
with the information listed in Requirement R4.1. Each Generator Owner shall have
evidence of communicated copies of each submission in accordance with Requirement
R4.2 and to the associated entities described in Requirement R4.2. Acceptable types of
evidence for submittals include, but are not limited to, meeting minutes, agreements,
copies of procedures or protocols in effect, or email correspondence. Acceptable types
of evidence for a hardware limitation may include, but is not limited to damage curves
provided by the original equipment manufacturer. Each Generator Owner that receives
a request for additional information under Requirement R4.2.1 shall have evidence of
providing that information within 90 days. Each Generator Owner that replaces
hardware at an IBR that is directly associated with an accepted exemption and that
hardware is the cause for the limitation, shall have evidence of communicating the
hardware change to the associated entities described in Requirement R4.3 within 90
days of the hardware replacement.
Draft 4_errata of PRC-029-1
October 2024
Page 8 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means
NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring and/or
enforcing compliance with mandatory and enforceable Reliability Standards in
their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below is
shorter than the time since the last audit, the Compliance Enforcement Authority
may ask an entity to provide other evidence to show that it was compliant for the
full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
•
Each Generator Owner shall retain evidence with Requirements R1, R2, and
R3 in this standard for 36 calendar months or the date of the last audit,
whichever is greater.
•
Each Generator Owner shall retain evidence with Requirement R4 in this
standard for five calendar years or the date of the last audit, whichever is
greater.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC Rules
of Procedure, “Compliance Monitoring and Enforcement Program” refers to the
identification of the processes that will be used to evaluate data or information
for the purpose of assessing performance or outcomes with the associated
Reliability Standard.
Draft 4_errata of PRC-029-1
October 2024
Page 9 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to
Ride-through in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to Ride-through
requirements in accordance
with Attachment 1, except for
those conditions identified in
Requirement R1.
R2.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to adhere
to performance requirements
during voltage excursions, as
specified in Requirement R2,
unless a documented
hardware limitation exists in
accordance with Requirement
R4.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to performance
requirements during voltage
excursions, as specified in
Requirement R2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
R3.
The Generator Owner failed to
ensure the design capability of
each applicable IBR to
Ride-through in accordance
with Attachment 2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
N/A
N/A
The Generator Owner failed to
ensure each applicable IBR
adhered to Ride-through
requirements in accordance
with Attachment 2, unless a
documented hardware
limitation exists in accordance
with Requirement R4.
Draft 4_errata of PRC-029-1
October 2024
Page 10 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Violation Severity Levels
R#
R4.
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 12 months, but less than
or equal to 15 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 15 months, but less than
or equal to 18 months after
the effective date of
Requirement R4.
The Generator Owner
provided a copy to the
applicable entities as detailed
in Requirement R4.2 more
than 18 months, but less than
or equal to 24 months after
the effective date of
Requirement R4.
The Generator Owner failed to
document complete
information for IBR identified
with known hardware
limitations that prevent the
IBR from meeting Ridethrough criteria as detailed in
Requirements R1, R2, or R3.
OR
OR
OR
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
90 days but less than or equal
to 120 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
120 days, but less than or
equal to 150 days after
receiving a request for
additional information by an
entity listed in Requirement
R4.2.1.
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
150 days but less than or equal
to 180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
The Generator Owner failed to
provide a copy to the
applicable entities as detailed
in Requirement R4.2 within 24
months after the effective
date of Requirement R4.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
90 days but less than or equal
to 120 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
Draft 4_errata of PRC-029-1
October 2024
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
120 days but less than or equal
to 150 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.2 more than
150 days but less than or equal
to 180 days after receiving the
acceptance of a hardware
limitation by the CEA.
OR
OR
The Generator Owner failed to
respond to the applicable
entities as detailed in
Requirement R4.2.1 more than
180 days after receiving a
request for additional
information by an entity listed
in Requirement R4.2.1.
OR
The Generator Owner failed to
respond to the applicable
Page 11 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
R#
Violation Severity Levels
Lower VSL
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s), Reliability
Coordinator(s), and CEA more
than 90 calendar days but less
than or equal to 120 calendar
days after the change to the
hardware.
Moderate VSL
OR
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 120 calendar days but
less than or equal to 150
calendar days after the change
to the hardware.
High VSL
The Generator Owner with a
previously communicated
hardware limitation that
replaces the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Reliability
Coordinator(s), Transmission
Operator(s), and CEA more
than 150 calendar days but
less than or equal to 180
calendar days after the change
to the hardware.
Severe VSL
entities as detailed in
Requirement R4.2.2 more than
180 days after receiving the
acceptance of a hardware
limitation by the CEA.
The Generator Owner with a
previously communicated
hardware limitation that
replace the documented
limiting hardware but failed to
document and communicate
the change to its Planning
Coordinator(s), Transmission
Planner(s), Transmission
Operator(s),Reliability
Coordinator(s), and CEA more
than 180 days after the change
to the hardware.
D. Regional Variances
None.
E. Associated Documents
Implementation Plan .
Draft 4_errata of PRC-029-1
October 2024
Page 12 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Version History
Version
Date
Initial Draft
3/27/24
Draft
Draft 2
6/4/24
Revised following initial comment review
Draft 3
7/22/24
Revised following additional comment review
Draft 4
9/12/24
Revised following additional comment review
Draft 4_errata of PRC-029-1
October 2024
Action
Change
Tracking
Page 13 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 1: Voltage Ride-Through Criteria
Table 1: Voltage Ride-through Requirements for AC-Connected Wind IBR
13
Voltage
(per unit) 14
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 15
N/A
≥ 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
3.00
< 0.70
Mandatory Operation Region
2.50
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.16
< 0.10
Permissive Operation Region
0.16
Table 2: Voltage Ride-through Requirements for All Other IBR
Voltage
(per unit) 16
Operation Region
Minimum RideThrough Time (sec)
> 1.20
N/A 17
N/A
> 1.10
Mandatory Operation Region
1.0
> 1.05
Continuous Operation Region
1800
≤ 1.05 and ≥ 0.90
Continuous Operation Region
Continuous
< 0.90
Mandatory Operation Region
6.00
< 0.70
Mandatory Operation Region
3.00
< 0.50
Mandatory Operation Region
1.20
< 0.25
Mandatory Operation Region
0.32
< 0.10
Permissive Operation Region
0.32
Type 3 and type 4 wind resources directly connected to the AC Transmission System.
Refer to bullet #4 below.
15 These conditions are referred to as the “may Ride-through zone”.
16 Refer to bullet #4 below.
17 These conditions are referred to as the “may Ride-through zone”.
13
14
Draft 4_errata of PRC-029-1
October 2024
Page 14 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
1. Table 1 applies to type 3 and type 4 wind IBR or hybrid IBR that include wind, unless
connected via a dedicated Voltage Source Converter - High Voltage Direct Current
(VSC-HVDC) transmission facility.
2. Table 2 applies to all other IBR types not covered in Table 1; including, but not
limited to, the following facilities:
a. IBR, regardless of their energy resource, interconnecting via a dedicated VSCHVDC transmission facility.
b. Other IBR or hybrid IBR consisting of photovoltaic (PV) and BESS.
3. The applicable voltage for VSC-HVDC system with a dedicated connection to an IBR
is on the AC side of the transformer(s) that is (are) used to connect the VSC-HVDC
system to the interconnected transmission system.
4. The voltage base for per unit calculation is the nominal phase-to-ground or
phase-to-phase transmission system voltage unless otherwise defined by the
Planning Coordinator, Transmission Planner, or Transmission Owner.
5. The applicable voltage for Tables 1 and 2 is identified as the voltage max/min of
phase-to-neutral or phase-to-phase fundamental root mean square (RMS) voltage at
the high-side of the main power transformer.
6. Tables 1 and 2 are only applicable when the frequency is within the “must
Ride-through zone” as specified in Figure 1 of Attachment 2.
7. At any given voltage value, each IBR shall Ride-through unless the time duration at
that voltage has exceeded the specified minimum Ride-through time duration. If the
voltage is continuously varying over time, it is necessary to add the duration within
each band of Tables 1 and 2 over any 10 second time period.
8. The specified duration of the mandatory operation regions and the permissive
operation regions in Tables 1 and 2 is cumulative over one or more disturbances
within any 10 second time period.
9. The IBR may trip for more than four deviations of the applicable voltage at the highside of the main power transformer outside of the continuous operation region
within any 10 second time period.
10. Instantaneous trip settings based on instantaneously calculated voltage
measurements with less than filtering lengths of one cycle (16.6 millisecond) are not
permissible.
11. The “must Ride-through zone” is the combined area of the mandatory operating
regions, the continuous operating regions, and the permissive operating region. All
area outside of these operating regions is referred to as the “may Ride-through
zone”.
Draft 4_errata of PRC-029-1
October 2024
Page 15 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
Attachment 2: Frequency Ride-Through Criteria
Table 3: Frequency Ride-through Capability Requirements
System Frequency (Hz)
Minimum Ride-Through
Time (sec)
> 61.8
May trip
> 61.2
299
≤ 61.2 and ≥ 58.8
Continuous
< 58.8
299
< 57.0
May trip
1. Frequency measurements are taken at the high-side of the main power transformer.
2. Frequency is measured over a period of time (typically 3-6 cycles) to calculate system
frequency at the high-side of the main power transformer.
3. Instantaneous or single points of measurement may not be used in the determination of
control settings.
4. At any given frequency value, each IBR shall Ride-through unless the time duration at
that frequency has exceeded the specified minimum ride-through time duration.
5. The specified durations of Table 3 are cumulative over one or more disturbances within
a 10-minute time period.
Draft 4_errata of PRC-029-1
October 2024
Page 16 of 17
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based Resources
63
May Ride-through Zone
62
Frequency (Hz)
61
Must Ride-through Zone
60
59
58
May Ride-through Zone
57
56
0
100
200
300
299
400
500
600
700
800
900
∞
1000
Time (seconds)
Figure 1: PRC-029 Frequency Ride-through Requirements
Draft 4_errata of PRC-029-1
October 2024
Page 17 of 17
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Reliability Standards PRC-024-4 and PRC-029-1
Applicable Standard(s)
•
PRC-024-4 – Frequency and Voltage Protection Settings for Synchronous Generators, Type 1
and Type 2 Wind Resources, and Synchronous Condensers
•
PRC-029-1 – Frequency and Voltage Ride-through Requirements for Inverter-based
Generating Resources
Requested Retirement(s)
•
PRC-024-3 Frequency and Voltage Protection Settings for Generating Resources
Prerequisite Standard(s)
•
None
Applicable Entities
•
See subject Reliability Standards.
New Terms in the NERC Glossary of Terms
This section includes all newly defined, revised, or retired terms used or eliminated in the NERC
Reliability Standard. New or revised definitions listed below become approved when the proposed
standard is approved. When the standard becomes effective, these defined terms will be removed
from the individual standard and added to the Glossary.
Proposed New Definition(s):
Ride-through: The plant/facility remains connected and continues to operate through voltage or
frequency system disturbances.
Background
The purpose of Project 2020-02 is to modify Reliability Standard PRC-024-3 or replace it with a
performance-based Ride-through standard that ensures generators remain connected to the
Bulk Power System (BPS) during system disturbances. Specifically, the project focuses on using
disturbance monitoring data to substantiate inverter-based resource (IBR) ride-through performance
during grid disturbances. The project also ensures associated generators that fail to Ride-through
system events are addressed with a corrective action plan (if possible) and reported to necessary
entities for situational awareness.
RELIABILITY | RESILIENCE | SECURITY
The purpose for this project is based on the culmination of multiple analyses conducted by the ERO
Enterprise regarding widespread IBR tripping events. Furthermore, the NERC Inverter-Based Resource
Performance Subcommittee 1 has developed comprehensive recommendations for improved
performance of IBRs, including the recommendation to develop comprehensive ride-through
requirements.
In October 2023, FERC issued Order No. 901 2 which directs the development of new or modified
Reliability Standards that include new requirements for disturbance monitoring, data sharing, postevent performance validation, and correction of IBR performance. In January 2024, NERC submitted a
filing to FERC outlining a comprehensive work plan to address the directives within Order No. 901. 3
Within the work plan, NERC identified three active Standards Development projects that would need to
be filed for regulatory approval with FERC by November 4, 2024. These projects include 2020-02
Modifications to PRC-024 (Generator Ride-through) 4, 2021-04 Modifications to PRC-002-2 5, and 202302 Analysis and Mitigation of BES Inverter-based Resource Performance Issues 6.
Project 2020-02
Proposed Reliability Standard PRC-029-1 is a new Reliability Standard that includes Ride-through
requirements and performance requirements for IBRs. The scope of this project was adjusted to align
with associated regulatory directives from FERC Order No. 901 and the scope of the other projects
related to “Milestone 2” of the NERC work plan. The components of this project’s Standard
Authorization Request (SAR) that related to the inclusions of new data recording requirements are
covered in Project 2021-04 and the proposed new PRC-028-1 Reliability Standard. Components of this
project’s SAR that relate to analytics and corrective actions plans are covered in Project 2023-02 and the
proposed new PRC-030-1 Reliability Standard.
PRC-029-1 includes requirements for Generator Owner IBR to continue to inject current and perform
voltage support during a BPS disturbance. The standard also specifically requires Generator Owner IBR
to prohibit momentary cessation in the no-trip zone during disturbances.
PRC-024-4 includes modifications to revise applicable facility types to remove IBR, retain type 1 and
type 2 wind, and to include synchronous condensers.
See documents at the NERC IRPS website: https://www.nerc.com/comm/RSTC/Pages/IRPS.aspx and the previous Inverter-Based
Resource Performance Working Group website https://www.nerc.com/comm/RSTC/Pages/IRPWG.aspx
2 See FERC Order 901, Docket No. RM22-12-000; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=202310193157&optimized=false; October 19, 2023
3 See INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF
RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%2
0901%20Work%20Plan_packaged%20-%20public%20label.pdf; January 17, 2024
4 See NERC Standards Development Project page for Project 2002-02; https://www.nerc.com/pa/Stand/Pages/Project_202002_Transmission-connected_Resources.aspx
5 See NERC Standards Development Project page for Project 2021-04; https://www.nerc.com/pa/Stand/Pages/Project-2021-04Modifications-to-PRC-002-2.aspx
6 See NERC Standards Development Project page for Project 2023-02; https://www.nerc.com/pa/Stand/Pages/Project-2023-02Performance-of-IBRs.aspx
1
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | October 2024
2
General Considerations
This implementation plan recognizes the urgent need for Reliability Standards to address IBR ride
through performance, as demonstrated by multiple event reports of the last decade, while providing a
reasonable period of time for entities to develop the necessary procedures and change their protection
and control settings to meet the new requirements. The ERO Enterprise acknowledges that there are
IBRs currently in operation and unable to meet voltage Ride-through requirements due to their inability
to modify their coordinated protection and control settings. Consistent with FERC Order No. 901, a
limited and documented exemption process for those IBR is appropriate and included within this
Implementation Plan. Other NERC Standards Development projects will be pursued to address ongoing
identification and mitigation of any potential reliability impacts to the BPS for such exemptions.
This implementation plan also recognizes that certain requirements (Requirements R1, R2, and R3) call
for entities to “ensure the design and operation” of their IBR units meets certain criteria. Design
elements may be implemented more expeditiously than operation requirements; the latter of which
will require entities to show compliance through use of actual disturbance monitoring data. Therefore,
this implementation plan provides staggered timeframes by which entities shall first ensure the design
of their IBR units meets the criteria (12 months following regulatory approval). Subsequent compliance
with the “operation” elements of these requirements shall become due as entities install disturbance
monitoring equipment on each applicable IBR in accordance with the implementation plan for proposed
Reliability Standard PRC-028-1 Disturbance Monitoring and Reporting Requirements for Inverter-based
Resources.
The ERO Enterprise acknowledges that Generator Owners and Generator Operators owning or
operating Bulk Power System connected IBRs that do not meet NERC’s current definition of Bulk Electric
System (“BES”) will be registered no later than May 2026 in accordance with the IBR Registration
proceeding in FERC Docket No. RR24-2. To ensure an orderly registration and compliance process for
these entities, as well as fairness and consistency in the standard’s application among similar asset
types, this implementation plan provides additional time for both new and existing registered entities to
come into compliance with Reliability Standard PRC-029-1’s requirements for their applicable IBRs not
meeting the BES definition. In so doing, this implementation plan advances an orderly process for new
registrants while allowing existing entities to focus their immediate efforts on their assets posing the
highest risk to the reliable operation of the Bulk Power System.
Effective Date and Phased-in Compliance Dates
The effective dates for the proposed Reliability Standards are provided below. Where the standard
drafting team identified the need for a longer implementation period for compliance with a particular
section of a proposed Reliability Standard (i.e., an entire Requirement or a portion thereof), the
additional time for compliance with that section is specified below. The phased-in compliance dates for
those particular sections represent the date that entities must begin to comply with that particular
section of the Reliability Standard, even where the Reliability Standard goes into effect at an earlier
date.
PRC-024-4
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | October 2024
3
Where approval by an applicable governmental authority is required, Reliability Standard PRC-024-4
shall become effective on the first day of the first calendar quarter that is twelve months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC024-4 shall become effective on the first day of the first calendar quarter that is twelve months after the
date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1 and definition of Ride-through
Where approval by an applicable governmental authority is required, Reliability Standard PRC-029-1
and the definition of Ride-through shall become effective on the first day of the first calendar quarter
that is twelve months after the effective date of the applicable governmental authority’s order
approving the standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC029-1 and the definition of Ride-through shall become effective on the first day of the first calendar
quarter that is twelve months after the date the standard is adopted by the NERC Board of Trustees, or
as otherwise provided for in that jurisdiction.
PRC-029-1 Phased-in Compliance Dates
Requirements R1, R2, and R3
Capability-Based Elements
Bulk Electric System IBRs
Entities shall comply with the portion of Requirements R1, R2, and R3 relating to the design of their
BES IBRs to meet the requirements by the effective date of the standard.
Applicable Non-BES IBRs 7
Entities shall not be required to comply with Requirements R1, R2, and R3 relating to the design of
their applicable non-BES IBRs until the later of: (1) January 1, 2027; or (2) the effective date of the
standard.
Performance-Based Elements (all applicable IBRs)
Entities shall not be required to comply with the portion of Requirements R1, R2, and R3 relating to
the operation of IBRs to meet the requirements until the entity has established the required
The standard defines such as IBRs as “Non-BES Inverter-Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.”
7
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | October 2024
4
disturbance monitoring equipment capabilities for those IBRs in accordance with the
implementation plan for Reliability Standard PRC-028-1.
Requirement R4
Bulk Electric System IBRs
Entities shall comply with Requirement R4 for their BES IBRs by the effective date of the standard.
Applicable Non-BES IBRs
Entities shall not be required to comply with Requirement R4 or their non-BES IBRs until the later of:
(1) January 1, 2027; or (2) the effective date of the standard.
Retirement Date
PRC-024-3
Reliability Standard PRC-024-3 shall be retired immediately prior to the effective date of Reliability
Standards PRC-024-4 and PRC-029-1 in the particular jurisdiction in which the revised standard is
becoming effective.
Equipment Limitations and Process for Requirement R4
Consistent with FERC Order No. 901, a limited and documented exemption for some legacy IBR with
certain documented equipment limitations are acceptable. Per the Order, these IBRs are
“…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.” 8
To ensure compliance with Requirement R4 and alignment with FERC Order No. 901, only those IBR that
are in operation as of the effective date of PRC-029-1 may be considered for potential exemption.
Further, only those IBR that are unable to meet ride-through requirements due to their inability to
modify their coordinated protection and control settings may be considered for potential exemption.
8
Order No. 901 at p. 193.
Implementation Plan | PRC-024-4 and PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | October 2024
5
Implementation Plan
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Reliability Standards PRC-024-4 and PRC-029-1
Applicable Standard(s)
PRC‐024‐4 – Frequency and Voltage Protection Settings for Synchronous Generators, Type 1
and Type 2 Wind Resources, and Synchronous Condensers
PRC‐029‐1 – Frequency and Voltage Ride‐through Requirements for Inverter‐based
Generating Resources
Requested Retirement(s)
PRC‐024‐3 Frequency and Voltage Protection Settings for Generating Resources
Prerequisite Standard(s)
None
Applicable Entities
See subject Reliability Standards.
New Terms in the NERC Glossary of Terms
This section includes all newly defined, revised, or retired terms used or eliminated in the NERC
Reliability Standard. New or revised definitions listed below become approved when the proposed
standard is approved. When the standard becomes effective, these defined terms will be removed
from the individual standard and added to the Glossary.
Proposed New Definition(s):
Ride‐through: The plant/facility remains connected and continues to operate through voltage or
frequency system disturbances.
Background
The purpose of Project 2020‐02 is to modify Reliability Standard PRC‐024‐3 or replace it with a
performance‐based Ride‐through standard that ensures generators remain connected to the
Bulk Power System (BPS) during system disturbances. Specifically, the project focuses on using
disturbance monitoring data to substantiate inverter‐based resource (IBR) ride‐through performance
during grid disturbances. The project also ensures associated generators that fail to Ride‐through
system events are addressed with a corrective action plan (if possible) and reported to necessary
entities for situational awareness.
RELIABILITY | RESILIENCE | SECURITY
The purpose for this project is based on the culmination of multiple analyses conducted by the ERO
Enterprise regarding widespread IBR tripping events. Furthermore, the NERC Inverter‐Based Resource
Performance Subcommittee1 has developed comprehensive recommendations for improved
performance of IBRs, including the recommendation to develop comprehensive ride‐through
requirements.
In October 2023, FERC issued Order No. 9012 which directs the development of new or modified
Reliability Standards that include new requirements for disturbance monitoring, data sharing, post‐
event performance validation, and correction of IBR performance. In January 2024, NERC submitted a
filing to FERC outlining a comprehensive work plan to address the directives within Order No. 901.3
Within the work plan, NERC identified three active Standards Development projects that would need to
be filed for regulatory approval with FERC by November 4, 2024. These projects include 2020‐02
Modifications to PRC‐024 (Generator Ride‐through)4, 2021‐04 Modifications to PRC‐002‐25, and 2023‐
02 Analysis and Mitigation of BES Inverter‐based Resource Performance Issues6.
Project 2020‐02
Proposed Reliability Standard PRC‐029‐1 is a new Reliability Standard that includes Ride‐through
requirements and performance requirements for IBRs. The scope of this project was adjusted to align
with associated regulatory directives from FERC Order No. 901 and the scope of the other projects
related to “Milestone 2” of the NERC work plan. The components of this project’s Standard
Authorization Request (SAR) that related to the inclusions of new data recording requirements are
covered in Project 2021‐04 and the proposed new PRC‐028‐1 Reliability Standard. Components of this
project’s SAR that relate to analytics and corrective actions plans are covered in Project 2023‐02 and the
proposed new PRC‐030‐1 Reliability Standard.
PRC‐029‐1 includes requirements for Generator Owner IBR to continue to inject current and perform
voltage support during a BPS disturbance. The standard also specifically requires Generator Owner IBR
to prohibit momentary cessation in the no‐trip zone during disturbances.
PRC‐024‐4 includes modifications to revise applicable facility types to remove IBR, retain type 1 and
type 2 wind, and to include synchronous condensers.
1 See documents at the NERC IRPS website: https://www.nerc.com/comm/RSTC/Pages/IRPS.aspx and the previous Inverter‐Based
Resource Performance Working Group website https://www.nerc.com/comm/RSTC/Pages/IRPWG.aspx
2 See FERC Order 901, Docket No. RM22‐12‐000; https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231019‐
3157&optimized=false; October 19, 2023
3 See INFORMATIONAL FILING OF THE NORTH AMERICAN RELIABILITY CORPORATION REGARDING THE DEVELOPMENT OF
RELIABILITY STANDARDS RESPONSIVE TO ORDER NO. 901
https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/NERC%20Compliance%20Filing%20Order%20No%2
0901%20Work%20Plan_packaged%20‐%20public%20label.pdf; January 17, 2024
4 See NERC Standards Development Project page for Project 2002‐02; https://www.nerc.com/pa/Stand/Pages/Project_2020‐
02_Transmission‐connected_Resources.aspx
5 See NERC Standards Development Project page for Project 2021‐04; https://www.nerc.com/pa/Stand/Pages/Project‐2021‐04‐
Modifications‐to‐PRC‐002‐2.aspx
6 See NERC Standards Development Project page for Project 2023‐02; https://www.nerc.com/pa/Stand/Pages/Project‐2023‐02‐
Performance‐of‐IBRs.aspx
Implementation Plan | PRC‐024‐4 and PRC‐029‐1 _ Errata
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | October 2024
2
General Considerations
This implementation plan recognizes the urgent need for Reliability Standards to address IBR ride
through performance, as demonstrated by multiple event reports of the last decade, while providing a
reasonable period of time for entities to develop the necessary procedures and change their protection
and control settings to meet the new requirements. The ERO Enterprise acknowledges that there are
IBRs currently in operation and unable to meet voltage Ride‐through requirements due to their inability
to modify their coordinated protection and control settings. Consistent with FERC Order No. 901, a
limited and documented exemption process for those IBR is appropriate and included within this
Implementation Plan. Other NERC Standards Development projects will be pursued to address ongoing
identification and mitigation of any potential reliability impacts to the BPS for such exemptions.
This implementation plan also recognizes that certain requirements (Requirements R1, R2, and R3) call
for entities to “ensure the design and operation” of their IBR units meets certain criteria. Design
elements may be implemented more expeditiously than operation requirements; the latter of which
will require entities to show compliance through use of actual disturbance monitoring data. Therefore,
this implementation plan provides staggered timeframes by which entities shall first ensure the design
of their IBR units meets the criteria (12 months following regulatory approval). Subsequent compliance
with the “operation” elements of these requirements shall become due as entities install disturbance
monitoring equipment on each applicable IBR in accordance with the implementation plan for proposed
Reliability Standard PRC‐028‐1 Disturbance Monitoring and Reporting Requirements for Inverter‐based
Resources.
The ERO Enterprise acknowledges that Generator Owners and Generator Operators owning or
operating Bulk Power System connected IBRs that do not meet NERC’s current definition of Bulk Electric
System (“BES”) will be registered no later than May 2026 in accordance with the IBR Registration
proceeding in FERC Docket No. RR24‐2. To ensure an orderly registration and compliance process for
these entities, as well as fairness and consistency in the standard’s application among similar asset
types, this implementation plan provides additional time for both new and existing registered entities to
come into compliance with Reliability Standard PRC‐029‐1’s requirements for their applicable IBRs not
meeting the BES definition. In so doing, this implementation plan advances an orderly process for new
registrants while allowing existing entities to focus their immediate efforts on their assets posing the
highest risk to the reliable operation of the Bulk Power System.
Effective Date and Phased-in Compliance Dates
The effective dates for the proposed Reliability Standards are provided below. Where the standard
drafting team identified the need for a longer implementation period for compliance with a particular
section of a proposed Reliability Standard (i.e., an entire Requirement or a portion thereof), the
additional time for compliance with that section is specified below. The phased‐in compliance dates for
those particular sections represent the date that entities must begin to comply with that particular
section of the Reliability Standard, even where the Reliability Standard goes into effect at an earlier
date.
Implementation Plan | PRC‐024‐4 and PRC‐029‐1 _ Errata
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | October 2024
3
PRC-024-4
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐024‐4
shall become effective on the first day of the first calendar quarter that is twelve months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC‐
024‐4 shall become effective on the first day of the first calendar quarter that is twelve months after the
date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.
PRC-029-1 and definition of Ride-through
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐029‐1
and the definition of Ride‐through shall become effective on the first day of the first calendar quarter
that is twelve months after the effective date of the applicable governmental authority’s order
approving the standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the Reliability Standard PRC‐
029‐1 and the definition of Ride‐through shall become effective on the first day of the first calendar
quarter that is twelve months after the date the standard is adopted by the NERC Board of Trustees, or
as otherwise provided for in that jurisdiction.
PRC-029-1 Phased-in Compliance Dates
Requirements R1, R2, and R3
Capability‐Based Elements
Bulk Electric System IBRs
Entities shall comply with the portion of Requirements R1, R2, and R3 relating to the design of their
BES IBRs to meet the requirements by the effective date of the standard.
Applicable Non‐BES IBRs7
Entities shall not be required to comply with Requirements R1, R2, and R3 relating to the design of
their applicable non‐BES IBRs until the later of: (1) January 1, 2027; or (2) the effective date of the
standard.
Performance‐Based Elements (all applicable IBRs)
Entities shall not be required to comply with the portion of Requirements R1, R2, and R3 relating to
the operation of IBRs to meet the requirements until the entity has established the required
7 The standard defines such as IBRs as “Non‐BES Inverter‐Based Resources that either have or contribute to an aggregate nameplate
capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage greater than or equal to 60 kV.”
Implementation Plan | PRC‐024‐4 and PRC‐029‐1 _ Errata
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | October 2024
4
disturbance monitoring equipment capabilities for those IBRs in accordance with the
implementation plan for Reliability Standard PRC‐028‐1.
Requirement R4
Bulk Electric System IBRs
Entities shall comply with Requirement R4 for their BES IBRs by the effective date of the standard.
Applicable Non‐BES IBRs
Entities shall not be required to comply with Requirement R4 or their non‐BES IBRs until the later of:
(1) January 1, 2027; or (2) the effective date of the standard.
Retirement Date
PRC-024-3
Reliability Standard PRC‐024‐3 shall be retired immediately prior to the effective date of Reliability
Standards PRC‐024‐4 and PRC‐029‐1 in the particular jurisdiction in which the revised standard is
becoming effective.
Equipment Limitations and Process for Requirement R4
Consistent with FERC Order No. 901, a limited and documented exemption for some legacy IBR with
certain documented equipment limitations are acceptable. Per the Order, these IBRs are
“…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.”8
To ensure compliance with Requirement R4 and alignment with FERC Order No. 901, only those IBR that
are in operation as of the effective date of PRC‐029‐1 may be considered for potential exemption.
Further, only those IBR that are unable to meet voltage ride‐through requirements due to their inability
to modify their coordinated protection and control settings may be considered for potential exemption.
8 Order No. 901 at p. 193.
Implementation Plan | PRC‐024‐4 and PRC‐029‐1 _ Errata
Project 2020‐02 Modifications to PRC‐024 (Generator Ride‐through) | October 2024
5
Standards Committee and NERC Ride-through
Technical Conference
Conference Details
September 4-5, 2024 | 9:00 a.m. – 4:00 p.m. Eastern
Location: The Westin Washington, DC Downtown
999 9th St NW, Washington, DC 20001
Click here for: Virtual Registration Only
Click here for: Agenda
Click here for: Panel Questions
Background
On August 15, 2024, the NERC Board of Trustees (Board) invoked Section 321 of the NERC Rules of
Procedure (ROP) to address critical and rapidly growing risk to the reliability of the Bulk Power System
associated with inverter-based resources (IBR) in response to FERC Order No. 901 directives. PRC-029-1
(Frequency and Voltage Ride-through Requirements for Inverter-based Resources) is a draft standard
designed to establish capability-based and performance-based Ride-through requirements for IBRs
during grid disturbances. The draft standard failed to achieve consensus from the Registered Ballot Body
over multiple ballots, calling into question whether development would be completed by FERC’s filing
deadline of November 4, 2024, which resulted in the Board acting under Section 321 of the ROP. Under
this special authority, the Board directed the Standards Committee to work with NERC to host a technical
conference. This technical conference will address the remaining issues for the proposed Ride-through
standard (PRC-029-1). Using input from the technical conference, the proposed Reliability Standard will be
revised as appropriate, then put to one more stakeholder ballot. If the standard achieves at least 60%
stakeholder approval, the Board may consider it for adoption under this special process. There is a 45-day
deadline to complete the process.
Meeting Format
This technical conference will be in-person near the NERC Washington, DC office – location to be
announced - with a virtual option available. The technical conference will be recorded and transcribed.
Recordings will be made available following the technical conference. Breakfast and lunch will be
provided.
RELIABILITY | RESILIENCE | SECURITY
Registration
In-person registration has reached capacity. Only virtual registrations are being accepted at this time.
Agenda
A detailed agenda will be provided. Some of the topics to be covered include:
1. the definition of Ride-through,
2. newly proposed criteria for frequency Ride-through performance, and
3. allowable hardware-based exemptions under FERC Order No. 901.
Submittal of Comments
As part of the preparation for the technical conference and to support the decisions by the Standards
Committee and NERC, the public is encouraged to provide comments for consideration on the topics
identified on the agenda. In particular, any information on hardware-based limitations that would prevent
IBR from meeting the proposed frequency criteria within PRC-029-1 is requested. Commenters are
advised this information will be used as part of the record of development and should not include
information that would be considered Critical Energy/Electric Infrastructure Information (CEII) or
proprietary information. Summarized, aggregated, or otherwise non identifying information that can be
substantiated with verifiable data, is requested for these submittals. NERC may request follow-ups with
individual commenters to review this data through separate and non-public mechanisms.
Include in Comments
1. Indicate if you are representing a NERC registered entity and, if so, which functional registrations.
2. Indicate if you are representing an original equipment manufacturer of IBR.
3. Indicate if your company provided comments through the Standards Development process for
Project 2020-02 Modifications to PRC-024 (Generator Ride-through), to allow the team to cross
reference previous information. If your entity is part of the Registered Ballot Body, also provide
what segment(s) your company is in.
4. Provide comments specific to the proposed frequency Ride-through criteria.
5. Provide comments specific to the proposed Ride-through definition.
6. Provide comments specific to hardware-based limitations that would prevent IBR from meeting
the proposed frequency criteria within PRC-029-1.
Instructions for Submittal
Please submit comments via email and include any attachments in PDF to the parties listed below:
• Jamie Calderon, Manager of Standard Development (jamie.calderon@nerc.net)
• Alison Oswald, Manager of Standard Development (alison.oswald@nerc.net)
• Lauren Perotti, Assistant General Counsel (lauren.perotti@nerc.net)
• Todd Bennett, Standards Committee Chair (tbennett@aeci.org)
• Troy Brumfield, Standards Committee Vice-Chair (lbrumfield@atcllc.com)
Comments received after August 27, 2024 will be accepted but may not be reviewed prior to completing
the Board directed actions.
Standards Committee and NERC Ride-through Technical Conference – Conference Details | August 2024
2
Agenda
Standards Committee and NERC Ride-through
Technical Conference
September 4 - 5, 2024 | 9:00 a.m.- 4:00 p.m. Eastern
Location: The Westin Washington, DC Downtown
999 9th St NW, Washington, DC 20001
Wednesday, September 4, 2024
8:55 AM - 9:00 AM
Safety Briefing
Event Space Staff
9:00 AM - 9:05 AM
NERC Antitrust Compliance Guidelines and Commission Staff Disclaimer
NERC Staff
9:05 AM - 9:15 AM
Welcome and Opening Remarks – NERC Board of Trustees
Speaker: Rob Manning
9:15 AM - 9:25 AM
Opening Remarks – NERC
Speaker: Mark Lauby
9:25 AM - 9:35 AM
Opening Remarks – FERC
Speaker: David Ortiz
9:35 AM – 9:50 AM
Technical Conference Overview - Standards Committee
Speaker: Todd Bennett (AEC)
Introduction to the conference objectives. Walk through the agenda and expectations for next steps and
interactions through any usage of Slido.
9:50 AM – 10:15 AM
Presentation: Summary Review of 901 and Milestone 2
Speaker: Jamie Calderon (NERC)
Summary overview of FERC Order 901, the associated Milestone 2 Reliability Standard projects and details
of how those projects interrelate. Includes Q&A.
10:15 AM - 10:30 AM
Morning Break
10:30 AM - 11:15 AM
Presentation: Review of Voltage and Frequency Ride-through Criteria in PRC-029-1
Speakers: Husam Al-Hadidi and Shawn Wang (2020-02 Drafting Team Members)
Drafting Team members will review their approach to drafting PRC-029-1 along with key decisions made
throughout the project development. Includes Q&A.
11:15 AM - 12:00 PM
Presentation: Review of Voltage and Frequency Ride-through Criteria
Speaker: Alex Shattuck (NERC)
A detailed review of proposed voltage and frequency criteria in used in the industry. This includes proposed
criteria in PRC-024, PRC-029-1, and other criteria options such as IEEE 2800-2022. The presentation will
explore the challenges associated with this requirement, particularly for existing generators, and will
discuss known issues regarding quality of model data, issues obtaining capability information, and other
issues that have been identified in recent NERC disturbance reports and NERC Alert reports. Includes Q&A.
12:00 PM - 1:00 PM
Lunch Break
1:00 PM - 2:00 PM
Panel Discussion: Original Equipment Manufacturer Perspectives on Voltage and Frequency Ridethrough Criteria
Moderators: Alex Shattuck (NERC) and Charlie Cook (Duke Energy)
Panelists:
•
Thomas Schmidt Grau (Vestas)
•
Thierry Ngassa (Power Electronics)
•
Scott Karpiel (SMA)
•
Dinesh Pattabiraman (TMEIC)
•
Samir Dahal (Siemens Energy)
•
Arne Koerber (GE Vernova)
This session will focus on the challenges with meeting the proposed voltage and frequency criteria. This
session is informed by original equipment manufacturer (OEM) concerns pertaining to the usage of different
criteria values for both voltage and frequency, particularly in relation to older generators and FERC Order
901 directives. Panelists will discuss challenges and potential solutions aimed at maximizing Ride-through
capability while balancing reliability needs and implementation practicality.
2:00 PM - 2:15 PM
Afternoon Break
Agenda – Standards Committee and NERC Ride-through Technical Conference – September 4 - 5, 2024
2
2:15 PM – 3:00 PM
Panel Discussion with Q&A: Addressing the Challenges of Voltage and Frequency Ride-through Criteria
Moderators: Howard Gugel (NERC) and Charlie Cook (Duke Energy)
Panelists:
•
Mark Lauby (NERC)
•
Manish Patel (EPRI)
•
Todd Chwialkowski (EDF)
•
Andy Hoke (NREL)
•
Michael Goggin (Grid Strategies LLC)
During this session, we will talk about the differences in the recommended voltage and frequency Ridethrough Reliability Standards compared to other potential criteria. This discussion has been initiated due to
concerns raised by stakeholders about using different standard values for voltage and frequency, especially
with regards to older generators and FERC Order 901 directives. The panelists will examine possible
solutions to find a middle ground between reliability needs and the feasibility of making adjustments to
current protection and controller settings.
3:00 PM - 3:30 PM
Slido Polling: Voltage and Frequency Ride-through Criteria
Moderator: Amy Casuscelli (Xcel energy) and NERC Staff
Conference participants will be presented various options through Slido live polling to provide immediate
feedback on proposed revisions to PRC-029-1 voltage and frequency Ride-through criteria. The session is
intended to collect industry feedback to gauge consensus on definition revisions. The Standards Committee
members assigned to revise PRC-029-1 will leverage these polling results as determined by the Standards
Committee.
3:30 PM – 3:45 PM | Parking Lot
3:45 PM - 4:00 PM
Day 1 Wrap-Up
Board Member – Sue Kelly
Agenda – Standards Committee and NERC Ride-through Technical Conference – September 4 - 5, 2024
3
Thursday, September 5th
9:00 AM - 9:15 AM
Recap of Day 1 and Introduction to Day 2
Todd Bennett (AEC) and Soo Jin Kim (NERC)
9:15 AM - 10:15 PM
Panel Discussion: Discussion on Frequency Ride-Through Exemptions in PRC-029-1
Moderators: Charles Yeung (SPP) and Alex Shattuck (NERC)
Panelists:
•
Howard Gugel (NERC)
•
Dane Rogers (OGE)
•
Jason MacDowell (ESIG)
•
Mark Ahlstrom (NextEra)
This session will focus on the differences posed by the proposed draft which does not include exemptions
for hardware-based limitations in meeting frequency criteria. This session is informed by submitted
stakeholder concerns pertaining to proposed PRC-029-1 providing no hardware-based limitations for
frequency criteria. Panelists will discuss known limitations and what options are available to balance
reliability needs with the practicality of implementation for older type IBR.
10:15 AM - 10:30 AM
Morning Break
10:30 AM - 11:00 AM
Presentation: Outlining Objectives of a Ride-through Definition
Speaker(s): Joel Anthes (2020-02 Drafting Team Member)
A thorough examination of the usage of the term “Ride-through” within NERC reports, IEEE, currently active
Ride-through Reliability Standards, and other industry usage of this term. This presentation(s) will also
review the proposed definition in the current draft of PRC-029-1 and a comparative analysis of other
proposed definitions evaluated by the drafting team during development. Special attention will be given to
stakeholder comments during the last draft ballot regarding the clarity and scope of terms such as "entire"
and "in its entirety." The discussion will also emphasize the critical nature of finalizing a single definition for
usage in NERC’s Glossary of Terms and associated Reliability Standards.
11:00 AM - 12:00 PM
Slido Polling: Gathering Stakeholder Input on Revised Definitions
Moderator: Amy Casuscelli (Xcel Energy)
Conference participants will be presented various options through Slido live polling to provide immediate
feedback on proposed revisions to the Ride-through definition regarding this topic. The session is intended
to collect industry feedback to gauge consensus on definition revisions. The Standards Committee members
assigned to revise PRC-029-1 will leverage these polling results as determined by the Standards Committee.
Agenda – Standards Committee and NERC Ride-through Technical Conference – September 4 - 5, 2024
4
12:00 PM - 1:00 PM
Lunch Break
1:00 PM – 1:15 PM
Presentation: Detailed Review of Milestone 2 Implementation Plans
Speaker: Jamie Calderon (NERC)
A comprehensive presentation, on the alignment of implementation plans and effective dates between
PRC-028-1 and PRC-030-1, as related to PRC-029-1. The discussion will cover the importance of coordinating
timelines to avoid gaps or overlaps that could compromise reliability or complicate compliance efforts.
1:15 PM - 2:00 PM
Panel Discussion: Strategizing Implementation Plans and Effective Dates
Moderator: Charles Yeung (SPP) and Jamie Calderon (NERC)
Panelists:
•
Howard Gugel (NERC)
•
Sam Hake (AES)
•
Manish Patel (EPRI)
•
Rhonda Jones (Invenergy)
This panel will discuss additional facts and circumstances to consider when developing strategies to
effectively implement Milestone 2 Reliability Standards and aligning Implementation Plans and effective
dates between PRC-028-1, PRC-029-1, and PRC-030-1. The discussion will explore the potential challenges
and proposed solutions that assist industry in ensuring a smooth transition to these new standards,
maintaining compliance, and minimizing the risk of any operational disruptions.
2:00 PM - 2:15 PM
Afternoon Break
2:15 PM - 2:45 PM
Slido Polling: Consensus on Implementation Plans
Moderator: Amy Casuscelli (Xcel Energy)
Conference participants will be presented various options through Slido live polling to provide immediate
feedback on proposed revisions to PRC-029-1’s Implementation Plan. The session is intended to collect
industry feedback to gauge consensus on definition revisions. The Standards Committee members assigned
to revise PRC-029-1 will leverage these polling results as determined by the Standards Committee.
2:45 PM - 3:15 PM:
Final Slido Polling: The Proposed Path Forward
Moderator: Amy Casuscelli (Xcel Energy)
A final set of polls will be conducted to gauge participant support for specific solutions discussed throughout
the conference and any other recommendations identified. Th The Standards Committee members
assigned to revise PRC-029-1 will leverage these polling results as determined by the Standards Committee.
Agenda – Standards Committee and NERC Ride-through Technical Conference – September 4 - 5, 2024
5
3:15 PM – 3:45 PM
Parking Lot
3:45 PM - 4:00 PM:
Closing Remarks and Next Steps
Speakers: Sue Kelly (NERC) and Todd Bennett (AEC)
Agenda – Standards Committee and NERC Ride-through Technical Conference – September 4 - 5, 2024
6
Standards Committee (SC) and NERC Ridethrough Technical Conference Bio’s
Standards Committee and NERC Leadership
Todd Bennett
Managing Director, Reliability Compliance & Audit Services Associated Electric
Cooperative, Inc. and SC Chair
I have been active in the power industry for 23 years and directly involved
with ERO initiatives since 2009. My industry background includes 7 years at
Sho-Me Power Electric Cooperative which included roles as a transmission
facility design engineer and director of power grid operations; and 15 years
at AECI working in NERC compliance. My focus while at AECI has been
operations, planning, and critical infrastructure protection issues. AECI is
registered as a Jointly Registered Organization (JRO) for the following
functions on behalf of a diverse set of organizations: BA, DP, GO, GOP, PC, RP,
TO, TOP, TP, and TSP. Resolving issues based on these functional registrations has made me deeply aware
of the current reliability issues and challenges that NERC and the industry are facing.
I have participated in multiple NERC & SERC industry groups and was a past chair of the SERC registered
entity forum, the current chair of the NERC Standards Committee, and previous co-chair of the NERC
Standing Committees Coordinating Group. My current role at AECI is the Managing Director of Reliability
Compliance and Audit Services. My professional focus is management of the AECI NERC compliance
program, participation in NERC standards development, participation in industry initiatives, monitoring
compliance with effective standards, and implementation of an AECI Board approved internal audit work
plan.
I obtained a BS in Engineering from the University of Missouri and an MS of Engineering Management from
the Missouri Institute of Science & Technology. I am a registered Professional Engineer (PE) and have
obtained Certified Internal Auditor (CIA) and Certification in Risk Management Assurance (CRMA)
credentials as well.
RELIABILITY | RESILIENCE | SECURITY
Troy Brumfield
Regulatory Compliance Manager American Transmission Company and SC
Vice Chair
Troy is an employee at American Transmission Company LLC (ATC) his
current position is Manager Reliability Standards Compliance. In this role,
Mr. Brumfield is responsible for leading the overall development, and
directing the activities and execution of ATC’s regulatory strategy (2)
monitoring ATC’s regulatory environment (3) representing ATC at
industry committees and trade organization meetings; and (4) working
with ATC legal staff to develop regulatory strategies and resolve
compliance and enforcement related issues.
Mr. Brumfield is the Vice-Chair of the NERC Standards Committee (SC),
Chair of the Standards Committee Process Subcommittee (SCPS) and serves as a member of the Standards
Committee Executive Committee (SCEC).
Mr. Brumfield is also a member of the MRO Compliance Monitoring and Enforcement Program Advisory
Council (CMEPAC). The CMEPAC provides advice and counsel to MRO’s Board of Directors, staff, members
and registered entities on topics like the development, retirement, and application of NERC Reliability
Standards, risk assessment, compliance monitoring, and the enforcement of applicable standards.
He has served as a chair and contributing member of several NERC Standards Drafting Teams and NERC
Initiative Teams. These include NERC Project 2017-07 Standards Alignment with Registration, Guidelines
and Technical Basis (GTB) Review Team, Standards Efficiency Review-Phase 1 Team (sub-team chair),
Member of NERC Compliance and Certification Committee-ERO Monitoring Subcommittee, Observer and
Active participant in the 2018-03 Standards Efficiency Review Retirements project, and Member of MRO
NERC Standards Review Forum.
Prior to joining ATC Mr. Brumfield was employed at Wisconsin Energy Corporation (WEC). While at WEC
Mr. Brumfield held various leadership roles in the Operations and Engineering-Major Projects work group
and the Operations Support group where he was responsible for managing regulatory obligations,
standards development, compliance, and asset management. During his time at WEC Mr. Brumfield served
as Chair of several generation and distribution regional committees and councils that were tasked with
promoting and strengthening governmental and industry partnerships. Mr. Brumfield utilized these
committees and councils as a forum to facilitate discussions related to standards interpretation and
standards execution by utility and governmental employees focused on the reliable design, construction,
operation, and maintenance of electric and gas facilities.
Mr. Brumfield earned a Bachelor of Applied Science in Electronics Engineering Technology. He also earned
a Master of Science in Engineering Management from the Milwaukee School of Engineering University
SC and NERC Ride-through Technical Conference Bios | September 4 - 5, 2024
2
Robin Manning
Board of Trustees Member, NERC
Robin E. Manning was elected to the NERC Board of Trustees in February
2018. Mr. Manning is the chair of the Compliance Committee and serves on
the Enterprise-wide Risk and Technology and Security Committees and as the
Reliability and Security Technical Committee observer. Prior to joining the
Board, Mr. Manning served as vice president of Transmission and
Distribution Infrastructure for the Power Delivery and Utilization research
sector at the Electric Power Research Institute (EPRI). He had overall
management and technical responsibility for the annual research activities
conducted by EPRI’s transmission and distribution programs in collaboration
with its global membership. Prior to joining EPRI, Mr. Manning served as an
executive vice president with the Tennessee Valley Authority (TVA) from 2008 to 2014, where he was
responsible at different times during his tenure for external relations, shared services, and power systems
operations, and served as Chief Energy Delivery Officer. Previously, he served as vice president at Duke
Energy, with responsibility for power delivery and gas transmission. Mr. Manning served on the University
of Houston Engineering Leadership Board and serves as immediate past president of the North Carolina
State Engineering Foundation Board. He is also the president of One Heart Global Ministries, a non-profit
ministry organization. Mr. Manning received a bachelor’s degree in Electrical Engineering from North
Carolina State University where he was recently named to the NC State Electrical and Computer Engineering
Hall of Fame. He also holds a master’s degree in Business Administration from Queens College in Charlotte,
North Carolina.
SC and NERC Ride-through Technical Conference Bios
3
Sue Kelly
Board of Trustees Member, NERC
Susan (Sue) Kelly was elected to the NERC Board of Trustees in February 2021
and serves on the Finance and Audit, Nominating, Regulatory Oversight, and
Technology and Security Committees. Ms. Kelly also serves as the observer
for the Reliability and Security Technical Committee and Standards
Committee. Ms. Kelly previously served as president and CEO of the American
Public Power Association (APPA) from 2014 to 2019, where she led the
national trade association serving public power utilities. She came to APPA in
2004 as its senior vice president of Policy Analysis and General Counsel and
was responsible for APPA’s energy policy formulation and policy advocacy
before FERC, the federal courts, and other governmental and industry policy
forums. Ms. Kelly has served on a number of committees, including the Steering Committee of the
Electricity Subsector Coordinating Council (2014 to 2019), the Commodity Futures Trading Commission’s
Energy and Environmental Markets Advisory Committee (2015 to 2019), the U.S. Department of Energy’s
Electricity Advisory Committee (2008 to 2009 under the Bush Administration; 2012 to 2014 under the
Obama Administration), and as the president of the Energy Bar Association (2010 to 2011). She was also a
member of the Board of Directors of the Center for Energy Workforce Development. She currently serves
on the Energy Bar Association’s Masters Council and helped start a virtual mentoring program for Energy
Bar Association members. She also serves on the E Source Advisory Board. Ms. Kelly was named one of
Washington’s “Most Powerful Women” in the November 2015 issue of Washingtonian magazine in the
“Business, Labor, and Lobbying” category. In March 2017, she was honored as Woman of the Year by the
Women’s Council on Energy and the Environment. In January 2020, she received Public Utility Fortnightly’s
Owen Young Award to honor her exceptional contributions to the electric utility industry. Ms. Kelly earned
her bachelor’s degree in Honors Interdisciplinary Studies and Economics from the University of Missouri
and her juris doctorate from George Washington University, both with high honors.
SC and NERC Ride-through Technical Conference Bios
4
Mark Lauby
Senior Vice President and Chief Engineer, NERC
Mark G. Lauby is senior vice president and chief engineer at NERC. Mr.
Lauby joined NERC in January 2007 and has held several positions,
including vice president and director of Standards and vice president
and director of Reliability Assessments and Performance Analysis. In
2012, Mr. Lauby was elected to the North American Energy Standards
Board and was appointed to the Department of Energy’s Electric
Advisory Committee by the Secretary of Energy in 2014. Mr. Lauby has
served as chair and is a life member of the International Electricity
Research Exchange and served as chair of several Institute of Electrical
and Electronics Engineers (IEEE) working groups. From 1999 to 2007,
Mr. Lauby was an appointed member of the Board of Excellent Energy International Co., Ltd., an energy
service company based in Thailand. He has been recognized for his technical achievements in many
technical associations, including the 1992 IEEE Walter Fee Young Engineer of the Year Award. He was named
a Fellow by IEEE in November 2011 for “leadership in the development and application of techniques for
bulk power system reliability.” In 2014, Mr. Lauby was awarded the IEEE Power and Energy Society’s Roy
Billinton Power System Reliability Award. In 2020, the National Academy of Engineering elected Mr. Lauby
as a member, citing his development and application of techniques for electric grid reliability analysis. He is
also a member of the IEEE Power & Energy Society (PES) Executive Advisory Committee, focused on
providing strategic support to the PES Board of Directors. Prior to joining NERC, Mr. Lauby worked for the
Electric Power Research Institute (EPRI) for 20 years, holding several senior positions, including: director,
Power Delivery and Markets; managing director, Asia, EPRI International; and manager, Power System
Engineering in the Power System Planning and Operations Program. Mr. Lauby began his electric industry
career in 1979 at the Mid-Continent Area Power Pool in Minneapolis, Minnesota. His responsibilities
included transmission planning, power system reliability assessment, and probabilistic evaluation. Mr.
Lauby is the author of more than 100 technical papers on the subjects of power system reliability, expert
systems, transmission system planning, and power system numerical analysis techniques. He earned his
bachelor’s and master’s degrees in electrical engineering from the University of Minnesota. In addition, Mr.
Lauby attended the London Business School Accelerated Development Program as well as the Executive
Leadership Program at Harvard Business School.
SC and NERC Ride-through Technical Conference Bios
5
Soo Jin Kim
Vice President of Engineering and Standards, NERC
Soo Jin Kim is the vice president of Engineering and Standards. In this
role, she is responsible for providing engineering analysis and support for
NERC activities and directing all aspects of NERC’s continent-wide
standards development process by providing oversight, guidance,
coordination, and industry education around the development of
Reliability Standards. Throughout her time at NERC, Ms. Kim has worked
on numerous initiatives involving Standards, Compliance, and
coordination across the ERO Enterprise. She joined NERC in 2012 as a
standards developer and has since served as reliability manager and
senior manager of Standards. From 2020 to 2023, she served as director
of Power Risk Issues and Strategic Management (PRISM) where she transformed the group into a crosscutting department that serves as technical advisors to other NERC functions. Under her leadership, PRISM
initiated several projects to tackle energy assurance risks, particularly those addressing extreme weather
challenges. Most notably, her team was instrumental in the formation of the Energy Reliability Assessment
Task Force and the efforts to provide the technical support for registering new inverter-based resources.
She also works with the Reliability Issues Steering Committee, and she was an integral leader in planning
and executing the 2023 NERC Leadership Summit. Prior to joining NERC, Ms. Kim was an associate at
Troutman Sanders LLP in Washington, D.C. in their Energy Practice. At Troutman Sanders, she worked on a
variety of Federal Energy Regulatory Commission compliance matters. Prior to attending law school, she
was a consultant/business analyst with various consulting firms focused on energy and commodity trading.
Ms. Kim has a bachelor’s degree in Economics and English from the University of Georgia and her juris
doctor degree from American University, Washington College of Law. She is licensed to practice law in
Georgia and Washington, D.C. She also served for five years on the board of the Women’s Energy Network
and as co-president for two of those years.
SC and NERC Ride-through Technical Conference Bios
6
David Ortiz
Director of the Office of Electric Reliability, FERC
David is the Director of the Office of Electric Reliability (OER) at the Federal
Energy Regulatory Commission. OER helps the Commission to oversee the
reliability and security of the electric grid. OER’s responsibilities include
oversight of the North American Electric Reliability Corporation in its
development and enforcement of mandatory reliability and cybersecurity
standards. David leads over 90 staff, including electrical engineers,
statisticians, attorneys and analysts. OER’s recent accomplishments
include: a standard ensuring that the grid can operate through extreme
cold weather; standards for securing the supply chain for grid-related cyber
systems and protecting the integrity and availability of grid
communications; a standard requiring increased grid cybersecurity
incident reporting; a rule requiring new generators to be able to provide frequency response, ensuring
reliability of the grid as it incorporates more renewable resources; a standard protecting the grid from solar
storms; a series of reports documenting utility best practices in grid restoration and recovery; and a series
of best practice reports in utility cybersecurity.
From 2013 to 2016, David was a Deputy Assistant Secretary for Energy Infrastructure Modeling and Analysis
(EIMA) in the Office of Electricity Delivery and Energy Reliability at the Department of Energy. From 1998
through 2013, David worked at the RAND Corporation, where he built a program of energy policy research
and analysis.
David earned his doctorate in Electrical Engineering from the University of Michigan. He graduated from
Princeton University.
David lives in Falls Church, Virginia with his wife, Nicole, and two children. He is an avid tennis player, cyclist,
home cook, and musician.
SC and NERC Ride-through Technical Conference Bios
7
Panelists – Original Equipment Manufacturer Perspectives on Voltage and Frequency
Ride-through Criteria
Thomas Schmidt Grau
Global Lead for RMS and EMT Development and Strategies for Vestas
Thomas has 15 years of experience in the industry in power plant
systems. Started my career in Vestas working on system impact
studies. Moved into modeling and became the global lead for all RMS
and EMT development and strategies, supporting all markets Vestas is
represented in. Nearly 5 years in the US being the Director for our
Power Plant Solutions group, having grid accountability across
Development, Sales, Construction, and Service. My focus is on
supporting renewable growth and ensuring Vestas takes
accountability in the renewable transition, especially around models
and ensuring the right quality is provided for utilities to carry out
reliable studies and ensure grid reliability for a green energy transition.
Scott Karpiel
Principal Application Engineer, SMA America
Scott Karpiel is a Principal Application Engineer at SMA America, the
U.S.-based subsidiary of solar and storage inverter leader SMA Solar
Technology AG, headquartered in Germany.
In this role, he provides design and consultation services, as well as
technical support, for North American photovoltaic (PV) and storage
customers, engineers, developers, owners and utilities. He also is
responsible for identifying market requirements with his involvement
in inverter-based resources working groups and standards drafting
teams to drive product enhancements and bridge any technical gaps
in the product offering. He is a subject-matter expert on utility scale renewable energy generation.
Karpiel, who joined SMA as an application engineer, has more than 30 years of experience in various
engineering disciplines, including architectural engineering, quality engineering, compliance engineering,
research and development, hardware engineering and technical support. Previous rolls in the renewable
sector include commissioning, field engineering, product management and Director of Applications
Engineering for various inverter manufacturers.
Karpiel earned a Bachelor of Science degree in electrical engineering, with a focus on energy conversion
and power electronics from the University of Colorado, Boulder.
SC and NERC Ride-through Technical Conference Bios
8
Dinesh Pattabiraman
Development Engineer in the Product Development Group at TMEIC
Corporation Americas
Dinesh is currently working as a Development Engineer in the Product
Development group at TMEIC Corporation Americas. He is experienced in
power electronics hardware, control, modeling and power system
dynamic performance studies. In his current role, he supports EMT
modeling of TMEIC inverters, helping clients through interconnection
studies and compliance with interconnection requirements and resolving
inverter performance issues during grid events. Dinesh completed his PhD
and M.S. in Electrical Engineering from the University of WisconsinMadison and his bachelor’s in electrical & Electronics Engineering from
the National Institute of Technology – Trichy, India.
Samir Dahal
Manager of Grid Interconnection and Modeling for Siemens Gamesa
Renewable Energy
Samir Dahal is a seasoned electrical engineer who manages grid
interconnection and modeling efforts at Siemens Gamesa Renewable
Energy, overseeing over 10 GW of onshore projects across the Americas.
He has extensive experience leading generator interconnection studies,
managing engineering teams, and developing inverter models, previously
serving as a Principal Consulting Engineer at Mitsubishi Electric Power
Products Inc.
Samir holds a Ph.D. in Electrical Engineering from the University of North Dakota and a Bachelor’s degree
from NYU Tandon School of Engineering. His expertise spans renewable energy, power systems, and grid
integration, supported by a strong research background and multiple academic honors.
SC and NERC Ride-through Technical Conference Bios
9
Arne Koerber
Product Line Leader for GE Vernova
Dr. Arne Koerber is the Product Line Leader, Controls & Software for GE
Vernova’s wind business. In this role, he leads product strategy for control
and software systems including turbine and plant-level controls, SCADA, farm
optimization, grid integration, and condition monitoring systems.
Arne joined GE in 2008 and has held a number of roles focused on system
simulation and controls engineering both in Europe and the US including
leading Controls & Operability Engineering for GE’s Onshore Wind business.
Arne graduated from TU Berlin, Germany with a degree in Engineering
Science and holds a PhD in Control Systems from the same University.
Moderator(s)
Alex Shattuck
Senior Engineer, Engineering & Security Integration, NERC
Alex Shattuck is a Senior Engineer in the Engineering and Security
Integration department at the North American Electric Reliability
Corporation. He contributes heavily on a number of NERC’s efforts related
to grid transformation including initiatives focused on inverter-based
resources, distributed energy resources, integrating security with
conventional engineering practices, and emerging technologies. In addition
to helping to lead NERC’s IBR activities, Alex currently coordinates NERC’s
Inverter-based Resource Performance Subcommittee and has experience
throughout the industry through work as a modeling subject matter expert
at an IBR equipment manufacturer, modeling lead at a power engineering
consultancy, and as a planning engineer at an Independent System Operator.
SC and NERC Ride-through Technical Conference Bios
10
Charlie Cook
Lead Compliance Analyst for Duke Energy and SC Member
Charlie Cook is a seasoned Regulator Compliance Specialist with over 25
years of experience in the industry. With a strong background in Internal
Controls and Audits, he has participated in numerous assessments of several
companies’ adherence to regulatory requirements. As a driven and detailoriented professional, Charlie is dedicated to ensuring that every project
achieves the highest level of quality and meets the needs of clients. When
not working, Charlie enjoys boating and off-roading and participates in
volunteer and charitable fund-raising events as a member of his local
Masonic Lodge.
Panelists – Panel Discussion with Q&A: Addressing the Challenges of Voltage and
Frequency
Mark Lauby – Senior Vice President and Chief Engineer, NERC Bio located with the
Executive Team
Manish Patel
Technical Executive for Electric Power Research Institute (EPRI)
Manish Patel, PhD, PE is a Technical Executive at Electric Power Research
Institute (EPRI) since April 2024. Before EPRI, he was with Southern
Company for 17.5 years in various roles, with experience in Protection &
Control and Transmission Planning. He is an active member of the IEEE
Power System Relaying Committee. He is a registered Professional
Engineer in the state of Alabama.
SC and NERC Ride-through Technical Conference Bios
11
Todd Chwialkowski
Director, Transmission Regulatory and Compliance for EDF Renewables
Todd Chwialkowski is a Director of Regulatory and Compliance for EDF
Renewables. He is currently based out of Denver, CO. Prior to this
position at EDFR, Todd worked as a Manager of NERC Business
Development and NERC Compliance Subject Matter Expert, and Senior
Project Manager, Cyber Security, contracting at the Department of
Interior, Bureau of Reclamation in their Power Resources Office. He
earned an engineering degree from the University of Minnesota, and
his MBA from the American Military University. He is a current
Certified Information Systems Security Professional (CISSP) and a
Certified Information Systems Auditor (CISA).
Andy Hoke
Principal Engineer in the Power Systems Engineering Center at the
National Renewable Energy Laboratory (NREL)
Andy Hoke is a principal engineer in the Power Systems Engineering
Center at the National Renewable Energy Laboratory (NREL), where he
has worked for the past 14 years. He received the Ph.D. and M.S.
degrees in Electrical, Computer, and Energy Engineering from the
University of Colorado, Boulder, in 2016 and 2013, respectively. Dr.
Hoke’s expertise is in grid integration of power electronics and
inverter-based renewable and distributed energy. His work includes
power systems modeling and simulation, advanced inverter controls
design, hardware-in-the-loop testing and model development, and
standards development. He has served as Chair of IEEE 1547.1-2020 and P2800.2, which contain the test
and verification procedures to ensure DERs and inverter-based resources conform to the grid
interconnection requirements of IEEE Standards 1547 and 2800, respectively. He is a registered professional
engineer in the State of Colorado.
SC and NERC Ride-through Technical Conference Bios
12
Michael Goggin
Consultant for Grid Strategies LLC
Michael Goggin has worked on renewable energy, transmission, and
reliability issues for 20 years. He has testified in dozens of state regulatory
and FERC proceedings on those topics. At Grid Strategies he serves as a
consultant for a range of clean energy industry clients. For the preceding 10
years he held various positions at the American Wind Energy Association,
now known as the American Clean Power Association. Michael has previously
served on the NERC Standards, Operating, and Planning Committees. He
graduated with honors from Harvard University.
Moderator(s)
Howard Gugel
Vice President of Regulatory Oversight, NERC
Howard Gugel is the vice president of Regulatory Oversight at NERC. In this
role, he is responsible for directing programs and processes to monitor,
review, and evaluate program effectiveness of the Electric Reliability
Organization (ERO) Enterprise’s implementation of risk-based compliance
monitoring and enforcement. This includes adherence to the NERC Rules of
Procedure, the Compliance Monitoring and Enforcement Program, and
approved delegation agreements. He is also responsible for overseeing the
ERO’s Organization Registration and Certification process. Prior to this, he
was vice president of Engineering and Standards at NERC. In this role, he
provided engineering analysis and support for NERC activities and directed
all aspects of NERC’s continent-wide standards development process by providing oversight, guidance,
coordination, and industry education of the development of Reliability Standards. He also previously served
as the director of Performance Analysis, where he was responsible for the development, maintenance, and
analysis of reliability performance metrics, including those in NERC’s annual State of Reliability report. This
included analyzing various databases of transmission and generations outages to look for statistically
significant trends. In 2022, Mr. Gugel was appointed to the Department of Energy’s Electric Advisory
Committee by the Secretary of Energy. He also serves on the North American Energy Standards Board. Mr.
Gugel has more than 34 years of experience in the electric utility industry. Prior to joining NERC, he was a
transmission area maintenance manager for Progress Energy Florida, where he managed a staff of field
personnel who maintained transmission lines and substation equipment. Prior to that, he was a
transmission planning manager, also for Progress Energy Florida. His background includes management
experience in operations and energy marketing. He has worked for two investor-owned utilities, a rural
electric cooperative, and an energy marketing firm. Mr. Gugel earned his bachelor’s and master’s degree in
Electrical Engineering from the University of Missouri – Rolla. He is a licensed professional engineer in
Missouri.
SC and NERC Ride-through Technical Conference Bios
13
Panelists – Discussion on Frequency Ride-through Exemptions in PRC-029-1
Howard Gugel – Vice President of Regulatory Oversight, NERC Bio located above
Dane Rogers
Lead NERC Compliance Analyst for Oklahoma Gas and Electric Company
(OG&E)
Dane Rogers is a Lead NERC Compliance Analyst for Oklahoma Gas and
Electric Company (OG&E). He is responsible for ensuring compliance with
current O&P NERC Reliability Standard as well as monitoring new and
revised Standards, assessing feasibility and impact, and coordinating
Company position for balloting and commenting. He is actively engaged in
multiple industry trade groups, serving as the Chair of the Midwest
Reliability Organization’s NERC Standards Review Forum (MRO NSRF), and
serving on the Advisory Committee of the North American Generator
Forum (NAGF).
In addition to his compliance experience at OG&E, Dane has held process and plant engineering positions
at a synchronous generating facility as well as an operational reliability engineering position on the
distribution system. Dane has also worked as a Quality Manager at a high-speed manufacturing facility
owned by AB-InBev.
Prior to earning his BS in Mechanical Engineering from Oklahoma State University, Dane served in the
Oklahoma Army National Guard.
SC and NERC Ride-through Technical Conference Bios
14
Mark Ahlstrom
Vice-President, Renewable Energy Policy for NextEra Energy Resource
Mark Ahlstrom is Vice President of Renewable Energy Policy for NextEra
Energy Resources and President of the Board of Directors of the Energy
Systems Integration Group. He currently serves on NERC’s Reliability
Issues Steering Committee and chairs the SPP Future Grid Strategy
Advisory Group, and he previously served on the NERC Essential
Reliability Services Working Group and the NERC Integrating Variable
Generation Task Force. Today, Mark focuses on rapid grid
transformation pathways that are accelerated by the Inflation
Reduction Act of 2022 with emphasis on reliability, economics, and
innovation. Mark is a senior member of IEEE and a CIGRE member.
A biochemistry and biomedical engineering graduate of the University of Wisconsin-Madison, Mark initially
worked as a software engineer at Honeywell Avionics and then as an artificial intelligence researcher at the
Honeywell Computer Sciences Center before leaving to be founder of two software companies. In late 2000
he became CEO of WindLogics, a venture-funded computational weather modeling company that applied
its technologies to improved understanding of wind energy projects. WindLogics was acquired in 2006 and
is now the NextEra Analytics division of NextEra Energy Resources—America’s premier clean energy leader
and the world’s largest producer of wind and solar energy.
SC and NERC Ride-through Technical Conference Bios
15
Moderator(s)
Charles Yeung
Executive Director Interregional Affairs Southwest Power Pool
Charles H. Yeung is Executive Director of Interregional Affairs for the
Southwest Power Pool (SPP). Since 2004, he has been responsible for
leading SPP in the development of reliability and business standards
at the national and continent-wide level. He is also SPP’s primary
contact to the ISO RTO Council’s Standards Review Committee (SRC),
a multi-member ISO/RTO group who works closely with ISO/RTO
CEOs to formulate regulatory policy and to assess proposals for
reliability standards and business practices impacting ISO/RTO
reliability and markets.
Mr. Yeung has experience in the engineering and the regulatory side of electric utilities. His first professional
employment was in 1988 at Houston Lighting & Power Co, (HL&P, now Centerpoint Energy). There Mr.
Yeung worked as a relay protection engineer and engineered transmission protection systems to ensure
safe and reliable operations of transmission networks in the HL&P service territory. He also calculated
power flow information for transmission service contracts in the 1990’s prior to FERC Order 888 for Open
Access. In 1995 he began work in the HL&P Regulatory Department where he was involved in creating rules
for the formation of ERCOT, the Texas regional transmission organization.
Mr. Yeung is a 1988 graduate of Texas A&M College Station with a bachelor’s degree in electrical
engineering and is a registered Professional Engineer. He also holds a Master of Business Administration
from the University of Houston
Alex Shattuck – Senior Engineer, Engineering & Security Integration, NERC Bio located
above
SC and NERC Ride-through Technical Conference Bios
16
Panelist(s) – Strategizing Implementation Plans and Effective Dates
Howard Gugel – Vice President of Regulatory Oversight, NERC Bio located above
Sam Hake
NERC Compliance Engineer for AES Clean Energy
I have been part of the energy sector since 2015. In 9 years, I have had
several different roles including NERC Compliance support, Transmission
Planning, Asset Management, and P&C Engineering. Currently, I am
supporting the NERC Compliance Program at AES Clean Energy as a NERC
Compliance engineer. In this role I have experience working with
Operations and Planning experts, focusing on the PRC suite of Standards,
supporting integration and operation of renewable resources. Prior to
joining AES Clean Energy I spent six years at Eversource Energy. At Eversource I had the opportunity to be
part of several different departments including NERC Compliance, Asset Management, and Protection and
Controls Engineering. Before joining Eversource, I was with Burns & McDonnell for two years working as
a Transmission Planning Engineer.
Manish Patel – Technical Executive for Electric Power Research Institute (EPRI) Bio
located above
Rhonda Jones
Vice President of Reliability Compliance at Invenergy LLC
As a 14-year NERC Regulatory Compliance leader, she administers
Invenergy’s NERC Compliance Programs. Her teams are responsible for
ensuring 70+ power generation companies, across North America and
Canada, are positioned to demonstrate how its strong operational practices
adhere with regulations. The effectiveness of the programs is based on the
promotion of reliable and safe operations, continuous training and
development, interwoven internal controls, standards development
participation, and a depth of both regulatory and technical expertise.
Additionally, Rhonda leads Invenergy’s RTO/ISO Market Registration & Compliance Program.
Rhonda served as a founder and chair of Black and Brown at Invenergy, an employee affinity group
focused on increasing awareness, presence, opportunity, and participation, for people of African ancestry
in sustainable energy careers. Rhonda is also a member of Invenergy’s DEI Corporate Committee and a
contributor to North American Generator Forum efforts.
She holds a BBA in Accounting, an MBA and a Juris Doctorate.
When this change agent takes a break from promoting grid resiliency, she enjoys hosting events, teaching
Business Ethics and DEI in the Workplace, and live music.
Moderator(s)
SC and NERC Ride-through Technical Conference Bios
17
Charles Yeung – Executive Director Interregional Affairs Southwest Power Pool Bio
located above
Jamie Calderon
Manager, Standards Development, NERC
Jamie joined NERC in 2015 as an engineer developing Reliability
Assessments and transitioned in 2017 to a senior engineer role with
Compliance Assurance. Prior to joining NERC, Jamie served as a
Transmission Planning Engineer and Bulk Power dispatcher for the
Municipal Electric Authority of Georgia (MEAG). Jamie Calderon received
her bachelor's degree of science in Electrical Engineering Technology
from Southern Polytechnic State University in Marietta, Georgia.
SC and NERC Ride-through Technical Conference Bios
18
Standards Committee & NERC Ride-Through
Technical Conference
Panel Questions
September 4 – 5, 2024 | 9:00 a.m.- 4:00 p.m. Eastern
Location: The Westin Washington, DC Downtown
999 9th St NW, Washington, DC 20001
Wednesday, September 4, 2024
Panel Discussion: Original Equipment Manufacturer Perspectives on
Voltage and Frequency Ride-through Criteria
This session will focus on the challenges with meeting the proposed voltage and frequency criteria. This
session is informed by original equipment manufacturer (OEM) concerns pertaining to the usage of different
criteria values for both voltage and frequency, particularly in relation to older generators and FERC Order
901 directives. Panelists will discuss challenges and potential solutions aimed at maximizing Ride-through
capability while balancing reliability needs and implementation practicality.
Questions:
1. Do you anticipate challenges with your equipment meeting the voltage Ride-through criteria as
specified in Attachment 1 of the draft PRC-029?
a. If so, do you have an estimate for how many products would be affected?
b. How does this estimate change when considering IEEE 2800-2022 criteria?
c. How does this estimate change when considering PRC-024 boundaries?
2. Do you anticipate challenges with your equipment meeting the frequency Ride-through criteria as
specified in Attachment 2 of the draft PRC-029?
a. If so, do you have an estimate for how many products would be affected?
b. How does this estimate change when considering IEEE 2800-2022 criteria?
c. How does this estimate change when considering PRC-024 boundaries?
3. What documentation is necessary from manufacturers to prove which hardware limitations exist
that would prevent your equipment from meeting the criteria in draft PRC-029 Attachments 1 and
Attachment 2?
4. What documentation are you comfortable sharing with Generator Owners (GO), Transmission
Planners, or NERC?
5. What is the generalized length of time associated with any redesign of current products to meet
the criteria specified in PRC-029 without exception?
6. Are there any future or currently in design products able to meet the criteria in PRC-029?
Panel Discussion with Q&A: Addressing the Challenges of Voltage and
Frequency Ride-through Criteria
During this session, we will talk about the differences in the recommended voltage and frequency Ridethrough Reliability Standards compared to other potential criteria. This discussion has been initiated due to
concerns raised by stakeholders about using different standard values for voltage and frequency, especially
with regards to older generators and FERC Order 901 directives. The panelists will examine possible
solutions to find a middle ground between reliability needs and the feasibility of making adjustments to
current protection and controller settings.
Questions:
1. Approximately what percentage of GO portfolios are potentially affected by PRC-029 draft criteria.
How does this change if thresholds are lowered to 2800-2022 criteria?
2. What are reasonable solutions to ensure legacy equipment can be compliant with voltage criteria
in draft PRC-029 Attachment 1.
3. What are reasonable solutions to ensure legacy equipment can be compliant with frequency
criteria in draft PRC-029 Attachment 2.
4. Do you expect equipment to fail to meet the voltage Ride-through criteria as specified in
Attachment 1 of the draft PRC-029 due to hardware limitations?
a. If so, do you have an estimate for how many products would be affected?
b. How does this estimate change when considering IEEE 2800-2022 criteria.
c. How does this estimate change when considering PRC-024 boundaries?
5. What considerations are needed regarding software-based maximizations to optimize voltage and
frequency Ride-through capabilities?
Panel Questions - Standards Committee & NERC Ride-through Technical Conference – September 4 - 5, 2024
2
Thursday, September 5, 2024
Panel Discussion: Discussion on Frequency Ride-through Exemptions in
PRC-029-1
This session will focus on the differences posed by the proposed draft which does not include exemptions
for hardware-based limitations in meeting frequency criteria. This session is informed by submitted
stakeholder concerns pertaining to proposed PRC-029-1 providing no hardware-based limitations for
frequency criteria. Panelists will discuss known limitations and what options are available to balance
reliability needs with the practicality of implementation for older type Investor-based Resources (IBR).
Questions:
1. What are the financial and practical impacts between hardware-based and software-based
solutions?
2. What is the timeline of software-based updates necessary to meet PRC-029 draft criteria? How
does this timeline differ from hardware-based updates?
3. Do you expect equipment to fail to meet the frequency Ride-Through criteria as specified in
Attachment 2 of the draft PRC-029 due to hardware limitations.
a. If so, do you have an estimate for how many products would be affected?
b. How does this estimate change when considering IEEE 2800-2022 criteria?
c. How does this estimate change when considering PRC-024 boundaries?
4. What difficulties do GOs have when attempting to obtain hardware limitation data from OEM?
5. What difficulties do GOs have when attempting to coordinate their plant to successfully meet the
criteria specified in Attachment 2 of the draft PRC-029?
6. Many commenters have said that it would only be fair to grandfather existing facilities and inconstruction facilities from ride through requirements due to the costs of retrofitting. Other
commenters have said that their facilities have an expected shelf life of up to 30 years, meaning
there may be facilities in place in 2050 - when IBR penetration is expected to be much higher - that
are not able to comply with requirements NERC wrote in 2024. How should NERC balance the
burden on generators who may be asked to incur large retrofitting costs, with the burden on
Transmission Owners, Transmission Planners, and end-use customers from poor or unexpected IBR
performance?
Panel Questions - Standards Committee & NERC Ride-through Technical Conference – September 4 - 5, 2024
3
Panel Discussion: Strategizing Implementation Plans and Effective Dates
This panel will discuss additional facts and circumstances to consider when developing strategies to
effectively implement Milestone 2 Reliability Standards and aligning implementation plans and effective
dates between PRC-028-1, PRC-029-1, and PRC-030-1. The discussion will explore the potential challenges
and proposed solutions that assist industry in ensuring a smooth transition to these new Reliability
Standards, maintaining compliance, and minimizing the risk of any operational disruptions.
Questions:
1. Given the complexities of aligning PRC-028-1, PRC-029-1, and PRC-030-1, what strategies would
you recommend in synchronizing implementation to avoid conflicts or gaps in compliance? What
considerations are needed to prevent potential overlaps or inconsistencies between
implementation plans?
2. What do you anticipate will be the most significant challenges when retrofitting or modifying
legacy IBR to comply with these new standards? Can you share any practical solutions or best
practices that have proven effective in ensuring compatibility and minimizing operational
disruptions?
3. With NERC expanding its registration criteria for GO, how should companies approach the
integration of new assets or changes in ownership to ensure seamless compliance? What are the
key considerations to keep in mind?
4. How do supply chain issues impact the timely implementation of these new standards, particularly
in terms of retrofitting existing or new installs? What proactive measures can be taken to mitigate
potential risks?
5. What are some of the most challenging aspects of testing and verification in the context of these
new standards, especially when dealing with a mix of new and retrofitted IBR? How do you ensure
that testing protocols are robust enough to meet compliance requirements without introducing
unnecessary complexity or delays?
Panel Questions - Standards Committee & NERC Ride-through Technical Conference – September 4 - 5, 2024
4
Welcome to the Standards Committee
and NERC Ride-through
Technical Conference Day 1
RELIABILITY | RESILIENCE | SECURITY
Safety Briefing
RELIABILITY | RESILIENCE | SECURITY
NERC Antitrust Compliance Guidelines
and Commission Staff Disclaimer
RELIABILITY | RESILIENCE | SECURITY
Welcome and Opening Remarks
Rob Manning – NERC Board of Trustees
Mark Lauby – NERC
David Ortiz – FERC
RELIABILITY | RESILIENCE | SECURITY
Technical Conference Overview Standards Committee
Todd Bennett – AEC
RELIABILITY | RESILIENCE | SECURITY
Summary Review of Milestone 2 and
Order 901
Jamie Calderon - Manager, Standards Development
Standards Committee & NERC Ride-through Technical Conference
September 4, 2024
RELIABILITY | RESILIENCE | SECURITY
Order 901 Summary
• FERC Order 901
▪ October 2023
▪ 4 Milestones through November
2026
▪ IBR related performance issues
▪ Leverage existing guidance where
possible
7
RELIABILITY | RESILIENCE | SECURITY
Order 901 Summary
• IBR Data Sharing
• IBR Model Validation
• IBR Planning and Operational
Studies
• IBR Performance
Requirements
E-1-RM22-12-000 | Federal Energy Regulatory Commission (ferc.gov)
8
RELIABILITY | RESILIENCE | SECURITY
Order 901 Summary
Registered IBRs
• Bulk-Power System connected IBRs registered with NERC for compliance purposes
Unregistered IBRs
• Bulk-Power System connected IBRs not registered with NERC for compliance
purposes
“IBR-DER”
• Distribution connected IBRs that in the aggregate have a material impact on the
Bulk-Power System
9
RELIABILITY | RESILIENCE | SECURITY
FERC Order 901 Milestones
10
RELIABILITY | RESILIENCE | SECURITY
Project 2021-04
Modifications to PRC-002 - Phase II
• New Standard: PRC-028-1 Disturbance Monitoring and Reporting Requirements
for Inverter-Based Resources
• Data needed by all 901 related Standards
• Requires installation of equipment - phased-in through 2030
• Share data on request
11
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
PRC-024 (Generator Ride-through)
• New Standard: PRC-029-1 Frequency and Voltage Ride-through Requirements for
Inverter-Based Resources
• Establish capability-based ride-through criteria
• Establish performance-based ride-through criteria
12
RELIABILITY | RESILIENCE | SECURITY
Project 2023-02
Analysis and Mitigation of BES IBR Performance Issues
• New Standard: PRC-030-1 Unexpected Inverter-Based Resource Event Mitigation
• Analysis of performance during a disturbance
• Triggers what is evaluated for ride-through performance
13
RELIABILITY | RESILIENCE | SECURITY
Milestone 2 Summary
Voltage or Frequency
Excursion
Disturbance Monitoring Data
Capabilities and Data Sharing
Project 2021-04
Assure Performance Data
is Provided to Planners
for Model Validation
Milestone 3
14
IBRs Must Not Violate RideThrough Performance Criteria
Project 2020-02
Assure Performance Data
is Provided to Planners
and Operators for Studies
Milestone 4
Generator Owners Must
Perform Post-Event Analytics
Project 2023-02
Corrective Action Plans
RELIABILITY | RESILIENCE | SECURITY
Questions and Answers
15
RELIABILITY | RESILIENCE | SECURITY
Communication
16
RELIABILITY | RESILIENCE | SECURITY
Review of Voltage and Frequency
Ride-through Criteria in PRC-029-1
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Xiaoyu (Shawn) Wang, Chair (Enel North America)
Husam Al-Hadidi, Vice Chair (Manitoba Hydro
NERC Ride-through Technical Conference
September 04, 2024
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Drafting Team- SAR and Standards
Drafting Team Roster
Name
Entity
Chair
Xiaoyu (Shawn) Wang
Enel North America
Vice Chair
Husam Al-Hadidi
Manitoba Hydro
Members
Ebrahim Rahimi
California ISO
John B. Anderson
Xcel Energy
Johnny C. Carlisle
Southern Company Services, Inc.
Robert J. O’Keefe
American Electric Power
Rajat Majumder
Invenergy
Alex Pollock
RES
Ebrahim Rahimi
California ISO
Fabio Rodriguez
Duke Energy
Kenneth Silver
8minute Solar Energy
Ovidiu Vasilachi
Independent Electricity System Operator (IESO)
John Zong
Electric Power Engineers
Jamie Calderon
North American Electric Reliability Corporation
NERC Staff
18
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
SAR1
• Title: Revision of relevant Reliability Standards to include applicability of transmissionconnected dynamic reactive resources
• Date Submitted: Feb 24, 2020 (Revised on February 3, 2022)
19
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
SAR2
•
•
•
•
Title: Generator Ride-through Standard (PRC-024-03 Replacement)
Date Submitted: April 28, 2022 (revised March 31, 2023)
Industry Need:
Based on the ERO Enterprise analyzing over 10 disturbances reports highlighting key findings
and recommendations
▪ A widespread loss of generating resources – solar PV, wind, synchronous generation, and battery energy storage
systems (BESS)
▪ Multiple IBR experience abnormally tripping, ceasing current injection, or reducing power output with control
interactions.
▪ The unexpected loss of widespread generating assets poses a significant risk to BPS reliability.
• The existing PRC-024-3 is an equipment settings standard focused solely on voltage and
frequency protection and is inadequate to address the IBR performance issues
• The proposed standards project will address this known reliability risk with a more suitable
performance-based standard that ensures generating resource ride-through performance for
expected or planned BPS disturbances
20
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
SDT Approach
• Modify PRC-024-3 to retain the Reliability Standard as a protection-based standard,
applicable only to synchronous generators, synchronous condensers, and Type 1 and
Type 2 wind turbines
• Create a new Reliability Standard (PRC-029-1) to address inverter-based resource (IBR)
disturbance ride-through performance criteria
• Coincide with ride-through requirements of IEEE standards but structure to follow
language from FERC Order No. 901, which states that “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”
21
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
after 1st Comment Period
• The comment period and initial ballot for the first draft: 3/27/2024 – 4/27/2024
• The first draft failed the initial ballot and received ~200 pages of comments from different
stakeholders
• The drafting team went through a series of meetings to address all the comments in May and
early June, including an in-person meeting and dedicated meetings with specific stakeholders,
e.g., EPRI
• The second comment period on Draft 2: 6/18/2024 – 7/8/2024
• The drafting team went through a series of meetings to address all the comments in July and
issued Draft 3: 7/22/2024 – 8/12/2024
• PRC-024-4 has passed ballot
• Draft 3 of PRC-029-1 failed to pass ballot
• On August 15, the NERC Board of Trustees invoked Rule 321
22
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
23
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Project 2020-02
Draft Language PRC-029-1
24
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
25
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
26
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
27
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
28
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
29
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
30
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
31
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
32
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
33
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
Draft Language PRC-029-1
34
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
• Relevant information
▪ Project page
• Contact information
▪ Jamie Calderon: Jamie.Calderon@nerc.net
▪ Xiaoyu (Shawn) Wang: xiaoyu.wang@enel.com
▪ Husam Al-Hadidi: halhadidi@hydro.mb.ca
35
RELIABILITY | RESILIENCE | SECURITY
Questions and Answers
36
RELIABILITY | RESILIENCE | SECURITY
Review of Voltage and Frequency Ride
Through
Alex Shattuck, Senior Engineer
NERC Ride-through Technical Conference
September 04, 2024
RELIABILITY | RESILIENCE | SECURITY
Why do we need Ride-through?
• Unexpected events happen often on the bulk power system
▪ These events cause varied deviations from nominal in system voltage and frequency
o Not all unexpected events cause major deviations, but the bulk power system must be prepared to perform
reliably when major events occur
• NERC must create effective and efficient criteria to reduce reliability risks
25,000 Bus Synthetic Grid - Northeastern United States (tamu.edu)
38
10000 Bus Synthetic Grid - Western United States (tamu.edu)
2000 Bus Synthetic Grid - Texas (tamu.edu)
RELIABILITY | RESILIENCE | SECURITY
Summary of Observed Major Events
• 10 published major disturbance reports published
since 2016 with an approximate total of 15,000 MW
• Numerous wind-related events in ERCOT area that
did not trigger event reports
• Winter storms Uri and Elliot stressed system
frequency
Eastern Interconnection System Frequency | Winter Storm Elliott
Report
ERCOT System Frequency |The February 2021 Cold Weather Outages in Texas and the
South Central United States
39
RELIABILITY | RESILIENCE | SECURITY
Comparing Frequency Criteria
40
RELIABILITY | RESILIENCE | SECURITY
Comparing Frequency Criteria
41
RELIABILITY | RESILIENCE | SECURITY
Comparing Major Events to Ride-through Criteria
• All events in published major event reports saw deviations within continuous operation
bands in draft PRC-029 and IEEE 2800-2022
• Nearly all frequency-related tripping was due to the use of instantaneous measurements
42
RELIABILITY | RESILIENCE | SECURITY
Comparing Winter Storms to Ride-through Criteria
• Winter storms resulted in significantly more severe frequency deviations
• Winter storm Uri frequency deviation touches PRC-024 criteria but is far from draft
PRC-029 and IEEE 2800-2022 criteria
43
RELIABILITY | RESILIENCE | SECURITY
Summary of Disturbance Observations
• Analyzed major events and both winter
storm Uri and Elliot resulted in frequency
deviations within the continuous
operation bands detailed in the draft
PRC-029 and IEEE 2800-2022
• Currently no “benchmark event” for
frequency and voltage criteria to be based
on
• Branching Paths: Set protection settings
as wide as possible to maximize ridethrough capability – or – determine
reasonable criteria that will ensure BPS
reliability
44
RELIABILITY | RESILIENCE | SECURITY
NERC’s Published Recommendations for Ride-Through
• From the March 14, 2023 Level 2 Alert: Inverter-Based
Resource Performance Issues
▪ Expand AC voltage protection settings as widely as possible
within the inverter equipment capability. Eliminate or minimize
the use of inverter instantaneous AC voltage tripping (e.g., zero
or near-zero3 time delay using instantaneous peak
measurements)
▪ Inverter frequency protection should be set based on equipment
capability. Frequency protection should operate on a filtered
frequency measurement over a time window. Eliminate or
minimize the use of inverter instantaneous frequency tripping.
o Notes 2-3 on Table 3 of draft PRC-029 Attachment 2 address the
filtered measurement performance issue
• These recommendations have been repeated in
numerous major event reports
45
RELIABILITY | RESILIENCE | SECURITY
Balance is Needed
Bulk Power
System
Needs
46
Technical
Capabilities
• Significant lead time
necessary to design
Effective new equipment
• Maximum Rideand
through Capability
• Hardware
Efficient
Limitations at legacy
• Effective and
Criteria
IBRs
efficient reduction of
risks
• Diminishing returns
at capability
extremes
RELIABILITY | RESILIENCE | SECURITY
How Can New Equipment Meet Criteria?
• Criteria need to be reasonable when
compared to current and future
equipment capabilities
• If criteria are outside of current
equipment capabilities, sufficient lead
time is necessary for manufacturers to
make necessary design changes and come
to market
• Sufficient time is necessary for testing to
ensure equipment can meet proposed
criteria
• Manufacturer input and evidence is
crucial
47
RELIABILITY | RESILIENCE | SECURITY
What if Criteria Cannot Be Met by Legacy Equipment?
Manufacturer input and detailed documentation is
critical for determining solutions
Software-based
protection
parameter changes
48
Small hardwarebased retrofits of
equipment
Significant hardwarebased retrofit or
replacement
RELIABILITY | RESILIENCE | SECURITY
Are Exemptions Necessary?
• Some amount of legacy IBR may not be able to meet newly proposed criteria
▪ Software-based upgrades are a simple path towards compliance with newly proposed criteria
• Additional considerations are needed when software-based upgrades are not sufficient
• Exemptions can allow legacy equipment to remain connected to the BPS while maximizing
their capabilities and sharing this data with affected entities
▪ Efficacy of exemptions is dependent on:
o Sufficient documentation detailing a hardware-based limitation
o Sufficient documentation that software-based protection settings are set at the maximum capability of the equipment
o Review of the provided documentation to determine the level of risk associated with the documented maximum
▪ Blanket exemptions without detailed documentation is not a sufficient solution
49
RELIABILITY | RESILIENCE | SECURITY
Quantifying Risks for Legacy IBR
• Data from Level 2 Alert on IBR Performance includes all BPS-connected solar PV and BESS
• Reported data shows significant number of resources with possible software-based solutions
• Reported settings at maximum capability allow the risks of different criteria to be quantified
NERC_Inverter-Based_Resource_Performance_Issues_Public_Report_2023
50
RELIABILITY | RESILIENCE | SECURITY
Manufacturer Challenges
• Challenges for new IBR equipment:
▪
▪
▪
▪
Deciding which criteria to design for
Procuring testing locations to show compliance
Long lead times for design changes driven by changing requirements
Ride-through capabilities can become cost prohibitive at extremes
• Challenges for Legacy IBR Equipment:
▪ Hardware-based limitations exist
▪ Software-based solutions may still not meet new criteria
▪ Legacy equipment was tested in accordance with applicable requirements at the time of interconnection
o True capability is “unknown” and retesting legacy equipment may not be feasible
▪ Coordinating and implementing effective and efficient solutions can be difficult
51
RELIABILITY | RESILIENCE | SECURITY
Industry Challenges
• Challenges for new IBR equipment:
▪ Deciding which equipment will be needed to meet new requirements
▪ Obtaining evidence that equipment can meet new requirements
▪ Communicating technical details necessary to provide sufficient model and facility data
• Challenges for Legacy IBR Equipment:
▪
▪
▪
▪
52
How to manage facilities with hardware-based limitations
Assessing the feasibility of software-based solutions can be difficult
Sometimes challenging to obtain objective capability-based information
Coordinating and implementing effective and efficient solutions can be difficult
RELIABILITY | RESILIENCE | SECURITY
Key Takeaways
• NERC has analyzed over 15,000 MW of
unexpected disturbances with very few IBR
tripping due to frequency criteria exceedance
▪ All analyzed events caused frequency deviations within
continuous operation bands of draft PRC-029 and IEEE
2800-2022
• NERC recommends to maximize ride-through
capability
• Validated documentation on limitations is crucial
for efficient and effective criteria but has proven
difficult to obtain
• Manufacturer input on true capabilities of legacy
and new equipment is critical
53
RELIABILITY | RESILIENCE | SECURITY
Questions and Answers
54
RELIABILITY | RESILIENCE | SECURITY
Panel Discussion: Original Equipment
Manufacturer Perspectives on Voltage and
Frequency Ride-through Criteria
Thomas Schmidt Grau – Vestas
Thierry Ngassa – Power Electronics
Scott Karpiel – SMA
Dinesh Pattabiraman – TMEIC
Samir Dahal – Siemens Energy
Arne Koerber – GE Vernova
RELIABILITY | RESILIENCE | SECURITY
Panel Discussion with Q&A: Addressing the
Challenges of Voltage and Frequency Ridethrough Criteria
Mark Lauby – NERC
Manish Patel – EPRI
Todd Chwialkowski – EDF
Andy Hoke – NREL
Michael Goggin – Grid Strategies LLC
RELIABILITY | RESILIENCE | SECURITY
Slido Polling: Voltage and Frequency
Ride-through Criteria
RELIABILITY | RESILIENCE | SECURITY
Parking Lot
RELIABILITY | RESILIENCE | SECURITY
Day 1 Wrap-up
Sue Kelly – NERC Board of Trustees
RELIABILITY | RESILIENCE | SECURITY
Welcome to the Standards Committee
and NERC Ride-through
Technical Conference Day 2
RELIABILITY | RESILIENCE | SECURITY
NERC Antitrust Compliance Guidelines
and Commission Staff Disclaimer
RELIABILITY | RESILIENCE | SECURITY
Recap of Day 1 and Introduction to Day 2
Todd Bennett – AEC
Soo Jin Kim – NERC
RELIABILITY | RESILIENCE | SECURITY
Panel Discussion: Discussion on Frequency
Ride-Through Exemptions in PRC-029-1
Moderators: Charles Yeung – SPP and Alex Shattuck – NERC
Panelist: Howard Gugel – NERC, Dane Rogers – OGE, Jason MacDowell – GE
Vernova, Mark Ahlstrom – NextEra
RELIABILITY | RESILIENCE | SECURITY
Outlining Objectives of a Ride-through
Definition
Joel Anthes, P.E. – 2020-02 Drafting Team Member
NERC Ride-through Technical Conference
September 5, 2024
RELIABILITY | RESILIENCE | SECURITY
Definition Overview
Why is PRC-029-1 Including a Definition of Ride-through?
The Project 2020-02 SAR Generator Ride-through Standard (PRC-024-3 Replacement) –
submitted April 28, 2022( revised March 31, 2023), includes additions to the NERC
Glossary of Terms and directs the drafting team to “define the term ride-through, as
necessary”.
The drafting team for PRC-030-1 – “Unexpected Inverter-Based Resource Event
Mitigation”, under Project 2023-02, requested that the drafting team for PRC-029-1
include a definition for Ride-Through. This was necessary to link their requirement 2
reference to “Document the facility’s Ride-through performance…”
6
RELIABILITY | RESILIENCE | SECURITY
Definition Overview
Drafting Team’s Goals in Defining Ride-through
Were:
• Create a stand-alone definition that could be
included in the NERC Glossary that was not
tied to or limited by the PRC-029-1 standard.
• Create a definition that could be used within
other standards, namely PRC-030-1, to allow
them to reference IBR Ride-through
performance requirements.
7
RELIABILITY | RESILIENCE | SECURITY
Definition Overview
Drafting Team’s Goals in Defining Ride-through Were Not:
• To create an additional quantitative performance requirement(s) merely by defining the
term Ride-through.
• To define the IBR performance necessary to support system reliability (this is instead
defined under Requirements 1-4 of PRC-029-1).
8
RELIABILITY | RESILIENCE | SECURITY
Proposed Definition
Draft 2 Definition: Remaining connected, synchronized with the Transmission System,
and continuing to operate in response to System conditions through the time-frame of a
System Disturbance.
Draft 3 Definition: The entire plant/facility remaining connected to the Bulk Power
System and continuing in its entirety to operate through System Disturbances.
• Removed “synchronized with”, in response to System conditions”
• Added “entire” and “in its entirety”
• Replaced “Transmission System” with “Bulk Power System”
9
RELIABILITY | RESILIENCE | SECURITY
Proposed Definition
Draft 3 Definition: The entire plant/facility remaining connected to the Bulk Power System
and continuing in its entirety to operate through System Disturbances.
Uses approved NERC Glossary terms:
10
RELIABILITY | RESILIENCE | SECURITY
IEEE 2800-2022 Definition
IEEE 2800 Ride-through Definition: Ability to withstand voltage or frequency
disturbances inside defined limits and to continue operating as specified.
Drafting Team Comments:
• “Ability to withstand” may not be clearly construed to mean “remaining connected”
• “inside defined limits” is a reference to requirements in a standard, is unnecessary to
describe the essence of what it means to ride through, and results in the definition
not being stand-alone
• “as specified” is again a reference to requirements in a standard that is unnecessary
to describe the essence of what it means to ride through, and results in the definition
not being stand-alone
11
RELIABILITY | RESILIENCE | SECURITY
Other Proposed Definitions
• Other Ride-through Definition 1: Ability to withstand System disturbances inside
defined limits and to continue operating as specified.
▪ Very similar to IEEE 2800-2022 definition.
• Other Ride-through Definition 2: Ability to withstand voltage or frequency
Disturbances within defined regulatory limits remaining connected, synchronized with
the Transmission System, and continuing to operate.
▪ Merges aspects of IEEE and SDT draft 2 definitions; what is meant by “regulatory
limits” is not clear.
12
RELIABILITY | RESILIENCE | SECURITY
Other Proposed Definitions
• Other Ride-through Definition 3: Facilities, including all individual dispersed power
producing resources, remaining connected to the electric system and continuing to
operate in a manner that supports grid reliability throughout a System Disturbance,
including the period of recovery back to a normal operating condition.
▪ Seems more a system level definition than facility level; the phrase “in a manner that
supports grid reliability” makes it dependent on what a standard or a description
found elsewhere would describe; last phrase underlined is viewed as equivalent to
“operate through System Disturbances”
13
RELIABILITY | RESILIENCE | SECURITY
Other Proposed Definitions
• Other Ride-through Definition 4: Remaining connected, synchronized with the
Transmission System, and continuing to operate by delivering power in response to
System conditions through the time-frame of a System Disturbance.
▪ Very similar to Draft 2 definition adding only “by delivering power” which will not
always be the case with batteries in charging or idle modes
• Other Ride-through Definition 5: The entire plant/facility remaining connected to the Bulk
Power System and continuing to operate through System Disturbances.
▪ Similar to Draft 3 definition only removing “in its entirety”
14
RELIABILITY | RESILIENCE | SECURITY
Other Proposed Definitions
• Other Ride-through Definition 6: The plant/facility remaining connected to the Bulk
Power System and continuing to operate through System Disturbances as defined in
applicable reliability standards
▪ Removing “entirety” and “in its entirety” could make it possible to qualify partial tripping as
ride-through; adding “as defined in applicable reliability standards” makes definition
dependent on what such standards would describe
• Other Ride-through Definition 7: The entire plant/facility remaining connected to the
Bulk Power System, and continuing in its entirety to operate as specified through the
time‐frame of System Disturbances.
▪ Draft 3 definition with “as specified” which makes it dependent on a standard and inserting
“the time-frame of” which is pretty similar to “through” [System Disturbances]
15
RELIABILITY | RESILIENCE | SECURITY
Other Proposed Definitions
• Other Ride-through Definition 8: The entire plant/facility remaining connected and
continuing to operate through the duration of a frequency or voltage Disturbance in its
entirety, from its start to the return to pre-disturbance conditions.
▪ Essentially the same as SDT draft 3 with non-substantive changes and removal of “Bulk
Power System”
• Other Ride-through Definition 9: The entire plant/facility remaining connected to the
Bulk Power System and continuing in its entirety to operate as specified through System
Disturbances inside defined limits.
▪ Same as SDT draft 3 definition adding “as specified” and “inside defined limits” which
makes it dependent (not stand-alone)
16
RELIABILITY | RESILIENCE | SECURITY
Other Proposed Definitions
• Other Ride-through Definition 10: The entire plant/facility (including its dispersed power
producing inverters) remaining connected to the electric system and continuing in its
entirety to operate in a manner that supports grid reliability through a System
Disturbance, including the period of recovery back to a normal operating condition”.
▪ Adding “in a manner that supports grid reliability” makes it dependent on what a
standard or a description found elsewhere would describe; substituting “electric
system” for “Bulk Power System” counters a draft 3 revision to satisfy other
commenters that distribution is off limits to NERC; other additions viewed as nonsubstantive
17
RELIABILITY | RESILIENCE | SECURITY
Other Proposed Definitions
• Other Ride-through Definition 11: The plant/facility shall remain connected and in
service, maintaining the pre-disturbance equipment configuration in operation,
throughout the entirety of the system disturbance and recovery.
▪ Removing “entirety” and “in its entirety” could make it possible to qualify partial
tripping as ride-through; other changes viewed as non-substantive.
18
RELIABILITY | RESILIENCE | SECURITY
Questions and Answers
19
RELIABILITY | RESILIENCE | SECURITY
Slido Polling: Gathering Stakeholder
Input on Revised Definitions
Moderator: Amy Casuscelli – Xcel Energy
RELIABILITY | RESILIENCE | SECURITY
Detailed Review of Milestone 2
Implementation Plans
Jamie Calderon - Manager, Standards Development
Standards Committee & NERC Ride-through Technical Conference
September 5, 2024
RELIABILITY | RESILIENCE | SECURITY
What is an Implementation Plan?
• Created For:
▪ New/Modified Reliability Standards
▪ Retiring Reliability Standards
▪ New/Modified Definitions
• Ensures no overlap or gap in time
between versions
22
RELIABILITY | RESILIENCE | SECURITY
Key Terms and Sections of an IP
• “Effective Date”
▪ Specific Date
▪ Time Period after approval by governmental
authority
• “Retirement Date”
▪ Immediately Prior
• General Considerations
• Other Standard specific
23
RELIABILITY | RESILIENCE | SECURITY
Phased-In Implementation
• Often used to avoid everything all at once
• Milestones beginning after “Effective Date”
• Examples:
▪ Percentage of Facilities
▪ Requirement R1 and then later R2
• Assists Entities in
24
RELIABILITY | RESILIENCE | SECURITY
Project 2021-04
Modifications to PRC-002 - Phase II
• New Standard: PRC-028-1 Disturbance Monitoring and Reporting Requirements for
Inverter-Based Resources
• Shall become effective on the first day of the first calendar quarter after the effective
date of the Applicable Governmental Authority’s order approving the standard
25
RELIABILITY | RESILIENCE | SECURITY
Project 2021-04
Modifications to PRC-002 - Phase II
• Phased-In Implementation for:
▪
▪
▪
▪
26
Existing BES Inverter‐Based Resources (in commercial operation on or before the effective date),
New BES Inverter‐Based Resources
Existing Non-BES Inverter-Based Resources
New Non-BES Inverter-Based Resources
RELIABILITY | RESILIENCE | SECURITY
Project 2021-04
Modifications to PRC-002 - Phase II
• Existing BES IBR: 50% of IBR within three years of the effective date of PRC‐028‐1 and
100% of BES IBR by January 1, 2030
• New BES IBR: BES IBRs entering commercial operation after July 1, 2025, but on or
before October 1, 2026, entities shall comply with Requirements R1 through R7 by
October 1, 2026
27
RELIABILITY | RESILIENCE | SECURITY
Project 2021-04
Modifications to PRC-002 - Phase II
• Existing Non-BES IBR: 100% January 1, 2030.
• Existing Non-BES IBR: within 15 calendar months following the effective date of the
standard or the commercial operation date, whichever is later.
• Process for Compliance Extensions
28
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
PRC-024 (Generator Ride-through)
• New Standard: PRC-029-1 Frequency and Voltage Ride-through Requirements for
Inverter-Based Resources
• Shall become effective twelve months after the effective date of the applicable
governmental authority’s order approving the standard
29
RELIABILITY | RESILIENCE | SECURITY
Project 2020-02
PRC-024 (Generator Ride-through)
• Capability-based ride-through criteria
▪ BES IBR: the effective date of the standard.
▪ Non-BES IBR: later of January 1, 2027; or the effective date of the standard.
• Performance-based ride-through criteria
▪ BES IBR and Non-BES IBR: Align with PRC-028 Implementation Plan dates
30
RELIABILITY | RESILIENCE | SECURITY
Project 2023-02
Analysis and Mitigation of BES IBR Performance Issues
• New Standard: PRC-030-1 Unexpected Inverter-Based Resource Event Mitigation
• IP revised in current draft posted for formal comment. Currently under ballot and
cannot discuss during Q&A.
• Removed performance-based and capability-based language
31
RELIABILITY | RESILIENCE | SECURITY
Project 2023-02
Analysis and Mitigation of BES IBR Performance Issues
• Later of 1) the first day of the first calendar quarter that is twelve (12) months after the
effective date of the applicable governmental authority’s order approving the
standard; or 2) the first day of the first calendar quarter that is twelve (12) months
after the effective date of the applicable governmental authority’s order approving
Reliability Standard PRC-029-1,
• Aligns with PRC-029
32
RELIABILITY | RESILIENCE | SECURITY
Aligned Implementation
Voltage or Frequency
Excursion
Disturbance Monitoring Data
Capabilities and Data Sharing
Project 2021-04
Assure Performance Data
is Provided to Planners
for Model Validation
Milestone 3
33
IBRs Must Not Violate RideThrough Performance Criteria
Project 2020-02
Assure Performance Data
is Provided to Planners
and Operators for Studies
Milestone 4
Generator Owners Must
Perform Post-Event Analytics
Project 2023-02
Corrective Action Plans
RELIABILITY | RESILIENCE | SECURITY
Questions and Answers
34
RELIABILITY | RESILIENCE | SECURITY
Panel Discussion: Strategizing
Implementation Plans and Effective Dates
Moderator: Charles Yeung – SPP and Jamie Calderon – NERC
Panelist: Howard Gugel – NERC, Sam Hake – AES, Manish Patel – EPRI, Rhonda
Jones – Invenergy
RELIABILITY | RESILIENCE | SECURITY
Afternoon Break
15 Minutes
RELIABILITY | RESILIENCE | SECURITY
Slido Polling: Voltage and Frequency
Ride-through Criteria
Moderator: Amy Casuscelli – Xcel Energy and NERC Staff
RELIABILITY | RESILIENCE | SECURITY
Slido Polling: Consensus on
Implementation Plans
Moderator: Amy Casuscelli (Xcel Energy)
RELIABILITY | RESILIENCE | SECURITY
Slido Polling: The Proposed Path
Forward
Moderator: Amy Casuscelli – Xcel Energy and NERC Staff
RELIABILITY | RESILIENCE | SECURITY
Closing Remarks and Next Steps
Sue Kelly – NERC Board of Trustees and Todd Bennett – AEC
RELIABILITY | RESILIENCE | SECURITY
Transcript of Technical Conference Day 1
Wednesday, September 4, 2024
Conference for North American Electric Reliability Corporation
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NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
(NERC)
7
8
9
10
Standards Committee and NERC Ride-through
Technical Conference
11
12
13
14
Wednesday, September 4, 2024
9:06 a.m.
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PARTICIPANTS
2
SHAHIN ABDOLLAHY, MPR Associates
3
MARK AHLSTROM, NextEra Energy
4
SYED AHMAD, FERC
5
MELISSA ALFANO, Solar Energy Industries Association
6
HUSAM AL-HADIDI, Manitoba Hydro
7
JOEL ANTHES, Pacific Gas and Electric
8
ROMEL AQUINO, Southern California Edison
9
JOHN BABIK, JEA
10
REBECCA BALDWIN, Spiegel & McDiarmid/TAPS
11
CHRISTIAN BECKMANN MENIG, Siemens Gamesa Renewable
12
Energy
13
TODD BENNETT, AEC, NERC
14
KELSI BOYD, NERC
15
TROY BRUMFIELD, American Transmission Company
16
ADAM BURLOCK, TransAlta Corporation
17
JAMIE CALDERON, Invenergy, NERC
18
JOHNNY CARLISLE, Southern Company
19
AMY CASUSCELLI, Xcel Energy, NERC
20
TODD CHWIALKOWSKI, EDF Renewables
21
KEVIN CONWAY, Western Power Pool
22
CHARLIE COOK, Duke Energy
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PARTICIPANTS (continued)
2
MIGUEL COVA ACOSTA, Vestas
3
SAMIR DAHAL, Siemens Gamesa Renewable Energy
4
MIKAEL DAHLGREN, Hitachi Energy
5
JOEL DEMBOWSKI, Southern Company
6
GERARD DUNBAR, NPCC
7
NANCY E. BAGOT, Electric Power Supply Association
8
MOHAMED EL KHATIB, Invenergy
9
PAMELA FRAZIER, Southern Power Company
10
SEAN GALLAGHER, SEIA
11
ANDREW GALLO, ERCOT, Inc.
12
MICHAEL GOGGIN, Grid Strategies
13
HOWARD GUGEL, NERC
14
THOMAS SCHMIDT GRAU, Vestas
15
MARK GREY, EEI
16
SAMUEL HAKE, AES
17
JOSH HALE, Southern Power Company
18
JOE HENSEL, Minnkota Power Cooperative, Inc.
19
ANDY HOKE, NREL
20
KATIE IVERSEN, AES Clean Energy
21
RHONDA JONES, Invenergy
22
SRINIVAS KAPPAGANTULA, Arevon Energy
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PARTICIPANTS (continued)
2
SCOTT KARPIEL, SMA
3
SUE KELLY, NERC Board of Trustees
4
FRANK KENNEDY, Alliant Energy
5
ARNE KOERBER, GE Vernova
6
BHESH KRISHNAPPA, SEIA
7
MARK LAUBY, NERC
8
DOMINIQUE LOVE, NERC
9
RAJAT MAJUMDER, GE Vernova , NERC
10
ROB MANNING, NERC Board of Trustees
11
HAYDEN MAPLES, Evergy
12
DAVID MARSHALL, Southern Power Company
13
ARISTIDES MARTINEZ, NextEra Energy
14
AL MCMEEKIN, NERC
15
PATTI METRO, NRECA
16
THIERRY NGASSA, Power Electronics
17
LATIF NURANI, American Public Power Association
18
KAREN ONARAN, ELCON
19
MOHAMED OSMAN, NERC
20
MANISH PATEL, Electric Power Research Institute
21
DINESH PATTABIRAMAN, TMEIC Corporation Americas
22
LEVETRA PITTS, NERC
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PARTICIPANTS (continued)
2
RYAN QUINT, Elevate Energy Consulting
3
SAM RAMSEY, ACP
4
ROBERT REEDY, DOE Solar Technologies Office
5
FABIO RODRIGUEZ, Duke Energy Florida
6
DANE ROGERS, OG&E
7
THOMAS SCHMIDT GRAU, Vestas
8
RUCHI SHAH, AES Clean Energy
9
ALEX SHATTUCK, NERC
10
JOHN SKEATH, NERC
11
TRAVIS SMITH, EEI
12
EWGENIJ STARSCHICH, Siemens Energy, Inc.
13
JEB STENHOUSE, Invenergy
14
KYLE THOMAS, Elevate Energy
15
VAIDHYA VENKITANARAYANAN [Nath Venkit], GE Vernova
16
BORIS VOYNIK, FERC
17
QIUSHI WANG, AES Clean Energy
18
XIAOYU [SHAWN] WANG, NERC
19
TIFFANY WASHINGTON, NERC
20
CHARLES YEUNG, Southwest Power Pool
21
BILL ZURETTI, EPSA
22
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AGENDA
2
AGENDA
3
ITEM
4
E
5
Safety Briefing (Off the Record)
6
NERC Antitrust Compliance Guidelines and
7
8
9
10
11
12
13
14
PAG
Commission Staff Disclaimer (NERC Staff)
9
Opening Remarks:
Rob Manning, NERC Board of Trustees
10
Opening Remarks:
David Ortiz, NERC Board of Trustees
Technical Conference Overview:
14
Standards
Committee
Todd Bennett, AEC
15
Presentation:
16
Milestone 2
23
Summary Review of 901 and
17
Jamie Calderon, NERC
27
18
Q&A and Discussion
41
19
20
Presentation:
Review of Voltage and Frequency
Ride-Through Criteria in PRC-029-1
21
Xiaoyu (Shawn) Wang, Chair (Enel North America)
66
22
Husam Al-Hadidi, Vice Chair (Manitoba Hydro)
55
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Q&A and Discussion
66
2
3
AGENDA (continued)
4
AGENDA
5
ITEM
6
E
7
Presentation:
8
Ride-Through Criteria in PRC-029-1
9
10
11
PAG
Review of Voltage and Frequency
Alex Shattuck, NERC
96
Q&A and Discussion
127
Panel Discussion with Q&A:
Original Equipment
12
Manufacturer Perspectives on Voltage and
13
Frequency Ride-Through Criteria
14
15
16
Moderators:
Alex Shattuck, NERC, and Charlie
Cook, Duke Energy
Panelists:
Thomas Schmidt Grau, Vestas;
17
Thierry Ngassa, Power Electronics; Scott
18
Karpiel, SMA; Dinish Pattabiraman, TMEIC;
19
Samir Dahal, Siemens Energy; and
20
Arne Koerber, GE Vernova
21
138
Meeting Participants Q&A and Discussion
184
22
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2
3
4
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AGENDA (continued)
6
AGENDA
7
ITEM
8
E
9
Panel Discussion with Q&A:
PAG
Addressing the
10
Challenges of Voltage and Frequency Ride-Through
11
Criteria
12
13
14
Moderators:
205
Howard Gugel (NERC) and Charlie
Cook (Duke Energy)
Panelists:
Mark Lauby (NERC), Manish Patel
15
(EPRI), Todd Chwialkowski (EDF), Andy Hoke,
16
(NREL), and Michael Goggin (Grid Strategies
17
LLC)
18
19
20
21
Meeting Participants Q&A and Discussion
Day 1 Wrap-Up (Moderator:
244
Sue Kelly, Board
Member)
262
Adjournment
266
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P R O C E E D I N G S
MS. WASHINGTON:
All right.
Good morning.
Thank
you for attending the NERC Ride-through Technical
10
Conference.
11
webinar is public and is being recorded.
12
registration information was posted on the NERC website
13
and widely distributed.
14
keep in mind that the listening audience may include
15
members of the press and representatives of various
16
governmental authorities, in addition to the expected
17
participation by industry stakeholders.
18
wish to ask a question during today's webinar, please
19
use the Q&A feature in the bottom right corner of your
20
screen.
21
22
As a reminder to all participants, this
The
Speakers in the room should
Should you
Please note that there will also be a Slido during
today's conference.
It's NERC's policy and practice to
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obey the antitrust laws and to avoid all conduct that
2
unreasonably restrains competition.
3
requires the avoidance of any conduct that violates or
4
that might appear to violate the antitrust laws.
5
NERC participant that is uncertain about the legal
6
ramification of a particular course of conduct, or who
7
has doubts or concerns about whether or not the NERC's
8
antitrust compliance policy is implicated in any
9
situation should consult NERC's general counsel, Sonya
10
Any
Rocha.
11
12
This policy
At this time, I will turn the webinar over to NERC
Board of Trustee, Mr. Rod Manning.
13
MR. MANNING:
14
PARTICIPANTS:
15
MR. MANNING:
That's working.
Good morning.
Good morning.
Welcome, and thank you for being
16
here.
17
are here on the call.
18
describe this meeting.
19
with someone and I would say, it's going to be fun, and
20
then I'd stop and say, well, perhaps it's not going to
21
be fun.
22
not going to be exciting.
Many are here in the room.
Many more, I think,
I struggle this morning to
I was having a conversation
It's going to be exciting.
Well, perhaps it's
I think where I ended up
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with, it's going to be hard.
2
What we're doing is going to be hard.
3
evolutionary, I think, certainly evolutionary what
4
we're doing today and tomorrow.
5
Could be revolutionary.
6
I think that's fair.
Perhaps it's
Revolutionary?
Maybe.
We see the transformation of the grid -- we all
7
see the transformation of the grid.
8
around us, whether we choose to technically shape the
9
outcome or not.
It's happening all
Sometimes I think if we choose to not
10
take any action, the grid will transform itself anyway,
11
but we all know that condition causes the latter to be
12
less than the former, and I don't think any of us agree
13
that that's acceptable, at least from a reliability
14
perspective.
15
think going forward, and all of us agree that we need
16
to act with contemplative intention or you wouldn't be
17
here today.
18
with this.
19
None of us find this workable solution, I
We need to think about where we're going
I feel like today we meet head on one of our very
20
first transformative decisions.
21
book, "The Last Days of Night," written by Graham
22
Moore, and it's a story of Westinghouse versus Edison,
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a story of invention versus industrialization perhaps.
2
It's a story of AC versus D.C.
3
highly recommend it if you're part of our industry.
4
It's fascinating.
5
exciting.
6
you've got any history in our business, you would
7
really enjoy reading about the early days of the AC
8
versus DC.
9
It's a great read.
I
Not everyone would find it fun or
Some might find it hard, but I think if
And as I was thinking about what to talk about
10
this morning, I really thought about, you know, what we
11
are considering over the next couple of days is a giant
12
step towards rendering those prior AC/DC arguments,
13
perhaps not irrelevant, but maybe extraneous.
14
taking a big step forward, and it hasn't been easy to
15
get to this point, and it won't be easy to find a
16
pathway forward today and tomorrow.
17
to do is going to be difficult.
18
The good news is we do hard.
19
embracing hard things and wrestling them to the ground.
20
We're
What we are going
It's going to be hard.
We have a track record of
So as we are about to tackle this hard task, it
21
seems to me that there are three things that frame our
22
pathway forward.
First of all, the risk is sufficient.
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The need for voltage and frequency Ride-through
2
criteria has been demonstrated over and again.
3
incidents are becoming ever more complex.
4
potential impacts are becoming ever more predictable.
5
To continue without addressing this issue really causes
6
us to fail to address and remediate the appropriate
7
risk.
8
the technology is sufficient.
9
about that today and perhaps tomorrow, but it seems
The
The
The risk is sufficient to take action.
Second,
Now, we will hear more
10
clear that what we want to do can be done with
11
technology that is available.
12
we have taken so far is sufficient.
13
through the full measure of process and engagement.
14
have heard from all front, we have taken information
15
from all comers, and now the time has come for us to
16
stop arguing and do something.
17
issue, believe it or not, in 2016, eight years ago.
18
The time has come.
19
So there you have it.
Finally, the time that
We have moved
We
We began studying this
The risk is sufficient.
20
The technology is sufficient.
21
What remains is to just get it done.
22
becomes irrelevant.
The time is sufficient.
Hard or easy
All that remains relevant really
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is to chart a pathway forward, the pathway that sees us
2
confidently step into the future of reliability.
3
that's why I'm here today.
4
of you are here today, and I thank you for being here.
5
I thank you for the skills that you bring to the table.
6
I thank you for your engagement, for your knowledge.
7
thank you for your presence here in the room or on the
8
phone.
9
solution where those who've gone before us have failed
So
I suspect that's why most
I
I thank you for your willingness to seek a
10
to find a solution.
11
skills in the next 30 hours or so.
12
we're doing is evolutionary, revolutionary perhaps.
13
The next few hours will write this story for us, so I
14
thank you for being here, I thank you for your time,
15
and I thank you for getting it done.
16
MR. LAUBY:
17
(Laughter.)
18
MR. LAUBY:
We're going to need all of your
Ditto.
Certainly what
Mark.
David?
So anyway, good morning, everybody,
19
and that's a wonderful setup for the -- today's
20
meeting.
21
here.
22
in 1980 -- in 1830s, excuse me -- came up with kind of
I did want to kind of think about how we got
And so I talked to my old friend, Faraday, who,
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the first machine with a -- with a magnet and a
2
spinning disc, and, you know, we've been making
3
improvements to that from the beginning, DC machines,
4
AC machines.
5
that group, AC/DC, but let's not go there, and the
6
whole system, of course, being synchronized was a big,
7
big chore.
8
mechanical energy, you know, taking mechanical energy
9
and moving it, transporting it to where we need to use
10
11
I always want to start thinking about
And we -- it was really all about managing
it, of course, then transforming that to actual work.
And when we think about NERC and all the
12
activities that we all work on, it's all about avoiding
13
what we call the evil three, which is the instability,
14
islanding, and controlled -- uncontrolled cascading.
15
In fact, Steinmetz has been quoted saying that we
16
created the largest machine that people have ever built
17
in the -- in the world with the interconnected systems.
18
But, you know, it's kind of like when I'm listening to
19
my 1970s and 1980s tunes on the radio and my daughters
20
say, that's before the turn of the century, dad,
21
because that's not where we are today.
22
You know, we have a significantly new way of
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generating electrons or exciting electrons, let's put
2
it that way, because they don't really flow.
3
of get excited and bounce off each other.
4
of the transformation here is between mechanical energy
5
to electrical energy, but rather, we're really managing
6
the kind of the characteristics of a new type of
7
resource in this case, solar panels, but even wind,
8
though, at least wind has some mechanical energy.
9
there's no surprise that, you know, we have some kind
They kind
And not all
So
10
of disagreements on the way forward here.
11
that we haven't been before, and nd it disrupts a lot
12
of the technology.
13
the rules of thumb that we're used to using and really
14
kind of calls into question some of our fundamental
15
assumptions, so, you know, Ride-through, of course, is
16
just an important part of being able to go through the
17
system events and avoid the evil three, right?
18
it's certainly an important characteristic that the
19
system should have to maintain the reliable operation
20
of the system.
It's a place
It disrupts a lot of the -- kind of
And so
21
And we now have high-speed inverters that can
22
really do whatever we want them to do, and we're trying
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to some -- in some cases try to at least mimic the
2
characteristics that we need.
3
characteristics, too, that we can take advantage of,
4
and, in fact, they're critically important to the green
5
transformation of the system, and we see inverters
6
everywhere.
7
four months because I can't get inverters to fix it
8
because they're putting them in cars and they're
9
putting them in solar panels, and I don't have
But they have other
Heck, my refrigerator's been out for like
10
refrigeration.
11
should buy a new refrigerator, I guess.
12
it's also a part of our -- now our inverter base loads.
13
So how are we going to manage those?
14
going to sustain the reliable operation of the system?
15
All this comes into question.
16
a cutting edge, and, you know, there just -- there's a
17
lot obviously that has to be done, and we really stand
18
at the inflection point of this new system.
Well, anyway, that's another story.
We
But this --
How are they
So we are really here on
19
And I really -- to, you know, Rob's point here,
20
thank you for all the work that you've done to date,
21
how much work you're going to have to do to get us to
22
that next step, an important, I think, inflection point
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in our industry.
2
was talking about the largest machine that was ever
3
built.
4
will be one that will be fast moving and can provide
5
services that perhaps we never even dreamed of and be a
6
more reliable, more resilient, more secure, and we need
7
everybody's help to get there.
8
that, next, I'll ask David to provide opening remarks.
9
So as I mentioned before, Steinmetz
We're building the largest computer now, and it
DAVID ORTIZ:
So thank you.
Thanks, Mark.
With
Thanks, Rob.
It's
10
hard to hear yourself, right, stand right in front of
11
the speaker.
12
I had a teacher once that said that AC power was
13
invented just so people would have to learn
14
trigonometry.
So maybe I'll start with a joke, I think.
15
(Laughter.)
16
DAVID ORTIZ:
So my name is David Ortiz.
I'm the
17
director of the Office of Electric Reliability at FERC.
18
I want to thank Rob for motivating the conference, Mark
19
for his kind of technical insight.
20
just kind of a little bit of an overview on some of the
21
process concerns and what our role is here, especially
22
since a lot of what's happening is in response to a
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FERC order.
2
I'm a FERC staff member, and these are my opinions and
3
not those of the Commission or any individual
4
commissioner.
5
It's important to note, obviously, that
As you know, Section 215 of the Federal Power Act
6
describes the roles of FERC and NERC.
7
specifically, the way it works is that those who run
8
the system, those who build the system, those who plan
9
the system, the ones with the expertise are the ones
And most
10
who develop the standards, you know, with NERC's
11
assistance, and then those are submitted to the
12
Commission for approval and/or directed modification,
13
and that's an important role.
14
is in your hands fundamentally, and that's the way it's
15
been structured in the statute.
16
extraordinary action in certain cases, especially with
17
respect to a FERC directive, and that's the reason why
18
we're here because of action that the NERC Board took a
19
few weeks ago.
20
And so really, the job
NERC's rules permit
And then I want to note that, you know, I'm here
21
and several other FERC staff members are here, and our
22
role today is fundamentally as observers.
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to have a really big bite at the apple in November
2
after you complete your work here and NERC submits the
3
standards to us.
4
of brought us here was Order Number 901, which the
5
Commission issued in October 2023, and that directed
6
NERC to develop reliability standards for inverter-
7
based resources in four areas:
8
and information, model validation, and then planning
9
and operational studies.
10
But the instigating action that kind
IBR performance, data
We gave NERC a really tight timeline for this,
11
and, you know, we're not necessarily sorry about that,
12
but it definitely is really pushing the limits of the
13
processes that NERC has, and we appreciate NERC and all
14
of you working toward those.
15
we ask that you -- that in NERC, finish the standards
16
and submit those at the Commission for approval on a
17
rolling time -- on a rolling basis in three years.
18
And, you know, as you know, even a standard for which
19
there is essentially no disagreement, just some details
20
to work out, typically takes about a year to develop.
21
And so to actually solve complex technical problems and
22
submit to us a standard is a -- is a pretty high bar,
You know, specifically,
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and we understand that.
2
point, yes, this is a difficult task that we gave you,
3
and to a certain extent, it's just beginning.
4
know, perhaps this will be a great conference and this
5
will be a model for the next sets of standards, who
6
knows, but, you know, there's still a lot of work to be
7
done, and I want to thank Jamie for managing the whole
8
endeavor.
9
And so, you know, to Rob's
You
I'm surprised that she still has hair.
And I want to kind of address one thing with
10
respect to Order Number 901.
11
discussions that you've been having specifically about
12
this standard, but also about the standards which
13
passed recently, there's been a lot of discussion about
14
the order and language in the order.
15
staff member, and especially as an engineer and not as
16
an attorney, I'm not in a position here to interpret
17
the order, but one thing that I can say is that the way
18
the Commission works is that it -- the Commission makes
19
its decisions based upon a record.
20
that we -- that the Commission had in last October was
21
what it -- is what it used in order to make the
22
decisions in Order Number 901.
I know that within the
As a Commission
And that record
If there is new
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information that's brought to bear that would cause the
2
Commission to reconsider that, then that's something
3
that the Commission has done in the past, and I presume
4
it would be open to do -- to do in this case.
5
So for example, perhaps there's quantitative data
6
about the capabilities of various inverter-based
7
resources of various vintages, or perhaps there's some
8
operations and planning studies that indicate that
9
certain performance characteristics actually help to
10
maintain reliability as opposed to others that have
11
been proposed already.
12
that NERC -- that you provide and that you help NERC to
13
submit in the record, the easier it will be for the
14
Commission to make a decision regarding this standard
15
and any standard, you know.
16
the standards process works and the way that the
17
Commission works.
18
The more specific information
This is just the way that
The record, though, that we had indicates that
19
this is something that needs to be done.
20
this is something that NERC has been investigating
21
since 2016 after the Blue Cut Fire disturbance and the
22
-- and not only is this a -- an eight-year-old problem,
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at least, right?
2
that's coming that's tremendously important for us to
3
get a handle on.
4
EIA projects now, and it perhaps -- and this was last
5
year -- perhaps it's changed already -- that fully half
6
of U.S. electricity will be -- electricity will be
7
produced by inverter-based resources by the end of the
8
decade, right?
9
long time, but there isn't any time to waste.
10
It's one that is -- there's a wave
And that's the fact that, you know,
So, you know, not only has it been a
So I appreciate everybody getting together,
11
looking forward to just observing a productive
12
conversation.
13
we're happy to have that conversation, but really, this
14
is your time to do work, and we're just here to help.
15
So thank you so much, and have a good day.
Anybody wants to chat with me or staff,
16
(Applause.)
17
MR. BENNETT:
Okay.
Good morning, everybody.
18
Okay.
19
our -- from our three speakers that kind of help set
20
the tone for the meeting today.
21
Bennett.
22
I'm kind of here to walk through the objectives of the
So thank you for all the opening remarks from
So now my name's Todd
I'm chair of the NERC Standards Committee.
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agenda, but, Mark, just so you know, it looks like
2
we're going to do this through some high-voltage rock
3
and roll today, so there's your AC/DC reference.
4
So first of all, thank you to everybody that has
5
been involved in putting this together, so the
6
panelists that volunteered, the NERC staff that helped
7
coordinate a lot of the agenda, the meeting space, this
8
location, all of that, as well as the Standards
9
Committee members, so thank you to all the committee
10
members.
11
voluntary role, so this is in addition to their day job
12
at their respective companies.
13
you to each one of those and what they've done to make
14
this successful so far.
15
For those that may not know, that is a
So I want to say thank
So let's kick this off, and, you know, our agenda,
16
kind of just to review the agenda, I saw kind of three
17
main objectives that came through the agenda upon my
18
initial review.
19
on communication.
20
agenda was to communicate the technical issues and to
21
level set on those throughout industry, OEMs and any of
22
the other roles that we all play in industry.
So the first one is very specifically
So one of the objectives of this
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all come here, you know, and we're all going to learn
2
something today probably just a little bit.
3
But then secondly, another objective is
4
collaboration.
5
spoke to collaboration on the agenda have to do with
6
the panel discussions.
7
there's several panel discussions on various technical
8
issues with this project.
9
discussions, I will say that Standards Committee and
And so some of the items that really
So over the next couple days,
In support of those panel
10
NERC did receive multiple sets of very, very technical
11
comment and feedback.
12
that, that it was in great support of this Technical
13
Conference.
14
those, that those have been reviewed by NERC Standards
15
Committee, and the information contained therein has
16
been used to formulate some questions for the panel
17
sessions, so thank you for that.
18
frame the -- frame the discussion.
19
So first of all, we welcome
I do want to assure those that submitted
That really helps
So one thing you should be prepared for is there
20
is a finite amount of time for each one of these panel
21
discussions, so there's between 45 minutes or an hour
22
or so.
And there is a preset amount of questions, so
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there's about 10 minutes allotted for each question to
2
make it through.
3
opportunity to kind of build on some of the panelist
4
responses before each subsequent panelist.
5
the case.
6
your responses at all, but you may be able to make the
7
most of our time and kind of build on some of the
8
responses from before.
9
is kind of a time constraint on some of the panel
10
11
Panelists may find that there's an
That may be
If not, I don't want to, you know, frame
So just be cognizant of there
discussions.
And then lastly, consensus.
So maybe that's the
12
main objective of this Technical Conference is industry
13
consensus.
14
forward.
15
have a tool that will help with that.
16
mentioned earlier, Slido.
17
is the app or the technology or the mechanism that will
18
be implemented to issue some polling of the industry
19
after some of the panel discussions.
20
to provide feedback during some of the panel
21
discussions, so that is the chat mechanism for this
22
conference.
How do we move forward?
It's time to move
How do we take some steps forward?
So we do
I believe it was
I've used it before.
This
It's also a way
So you won't find that functionality in
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Webex.
2
come on that.
3
more instructions on how to participate and the
4
appropriate times to participate, so pay attention.
5
More to come on that.
6
It'll come through Slido.
So there's more to
There's more discussions -- or sorry --
And with that, I don't think I have anything else
7
to share.
8
Jamie is ready to review the summary of the FERC Order
9
901 and Milestone 2, so we'll let her get set up here,
10
and I believe she's going to go through a presentation
11
with us.
12
That's my agenda review.
MS. CALDERON:
All right.
And I believe
Want to do a quick
13
level set, so we're going to get really deep into the
14
technical details during this conference which is good,
15
it's why we're here, but we don't want to lose the
16
forest from the trees type conversation, so let's take
17
a step back.
18
time machine to October of 2023.
19
up for us, given us the -- kind of a little bit of the
20
background on FERC Order 901 coming out.
We're going to go all the way back in our
21
So next slide, please.
22
Quick summary for everyone.
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David Ortiz opened it
The order came out in
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October 2023.
2
through November of 2026, and they address a wide
3
spectrum of IBR performance-related issues.
4
here, I'm sure, is familiar with some of the
5
performance issues that are in question.
6
has to do with making sure we have an accurate way that
7
we represent them within models, that we're including
8
them within studies appropriately, and that we're also
9
just getting the data to begin with.
There are four milestones all the way
Everyone
A lot of it
So we want to be
10
able to leverage the existing standards.
11
always a good idea to just come in and do a tear-
12
down/rebuild when you don't have to, but we want to
13
make sure that we're being able to implement meaningful
14
changes within the standards.
15
little bit of a step-back where a new standard, as
16
we've seen with the IBR performance-related standards,
17
that's one avenue to go to, and the team felt it was
18
appropriate during this -- during these discussions
19
this last year.
It's not
So if it requires a
20
Next slide, please.
21
So as indicated, there are really four main issues
22
of this data sharing assuring that the data is
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available.
2
event recorders, fault recorder data, stuff that has
3
not been traditionally needed at conventional
4
generation.
5
needed to ensure that the requirements were in place
6
that required the sharing of that data to those who
7
needed it, either for modeling or for doing those
8
studies, or just for situational awareness, being able
9
to monitor the onsite impacts and making sure that that
10
11
We're talking about high-speed sequence
So those needed to be installed, and we
was visible.
There's model validation, ensuring that not just
12
once it gets thrown into the model, hasn't been
13
validated.
14
interconnection process has the model accurately
15
represented what was as built, if there was design
16
changes that happened during the initial
17
interconnection studies and we're moving into the post
18
commercial operation, and it's not operating the way it
19
was designed to as the way the model practices and
20
simulation, then there's an issue there.
21
make sure that we're building an effective model
22
validation throughout, planning and operational studies
We're looking at also verifying during the
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that leverage that.
2
listed last, but, of course, we get to those first.
And performance requirements were
3
So next slide, please.
4
Another thing about Order 901 was that it
5
references three different types of IBRs.
6
make sure that we're level setting on what those IBRs
7
are, registered IBRs for the purposes of FERC Order
8
901, that is any IBR that is going to be registered as
9
either, what we're referring to as Category 1 or
So just to
10
Category 2.
11
and unregistered IBR has to do with the earlier FERC
12
Order 2022 that required the expansion of requiring new
13
IBR generator owners to become registered and into the
14
NERC regulatory environment.
15
aggregated IBR of 20 MVA and up connected at 60 kV.
16
this is an expansion of the IBR and generator owners.
17
A lot more people coming on board.
18
Now, the distinction between registered
We're looking at
So
In that original Order 2022, it was focused on
19
registered and unregistered within that context.
20
FERC Order 901, "registered" encompasses both of those.
21
So to be clear, that unregistered IBR is really focused
22
on the not going to be registered, not part of the
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Category 2 GO/GOPs that would be potentially
2
interconnected at the transmission level.
3
be looking at aggregated sets of IBR that will not have
4
generator owners, but will be the responsibility of
5
transmission owners to aggregate and incorporate into
6
their models.
7
That would
IBR/DR, similar conversation only at the DR level.
8
So you're looking at the distribution level IBR,
9
potentially rooftop, not to be confused with having
10
individual model data for each of those, but the
11
aggregated impacts to the distribution provider and
12
ensuring that the distribution provider has at least
13
some estimation for capturing those within their models
14
and knowing the limits of their estimation.
15
there's particular issues with acquiring the data,
16
acquiring specific data, that that distribution-level
17
data is at least estimated and being able to continue
18
to be developed over time.
19
So if
How we get that aggregation is going to be a
20
continual conversation, but it's actually not part of
21
the performance requirements in Milestone 2.
22
ones that are identified within Milestone 2 are those
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registered IBRs that are going to be part of the
2
Category 1/Category 2 generator owners.
3
interconnected at 60 kV and up with the aggregation of
4
20 MVA and up.
5
Next slide, please.
6
Okay.
Those would be
So we are in the first stages of this.
7
Again, it hasn't even been a year since the order came
8
out.
9
go through some of the motions here.
So putting this in context, you know, we had to
Rule 321 was
10
something that we absolutely did not want to pursue if
11
not needed, and it was determined to be needed in this
12
case.
13
really frank conversation on some of these issues and
14
just an open technical conversation.
15
to lose sight of the fact that we have two additional
16
milestones that will equally be exhaustive in terms of
17
scope of work and the amount of time that it's going to
18
be taking to get this together.
19
ourselves in a similar position next year.
20
We needed to make sure that we were having a
But we don't want
We don't want to find
So this presentation and this whole conference,
21
while we're looking at -- specifically at Ride-through
22
and the very specific aspects, I know we want to get
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into exemptions and criteria discussions, but we don't
2
want to lose sight of the fact that there's still a lot
3
more that we need to be able to do and within the next
4
two years.
5
look to be on track.
6
hasn't passed, and I think we'll be able to get to a
7
solution at the end of this conference.
So the scope of work for November 4th, we
8
Next slide.
9
Okay.
We only have one standard that
So just to break up the three standards.
10
First Project 2021-04 at a new standard.
11
decided to break out the IBR versus the conventional
12
generation.
13
on, you know, capturing this information, we've created
14
a new standard.
15
forward PRC-028, looking at disturbance monitoring and
16
reporting requirements for IBR.
17
sequence event recorders, fault-recorded data, and
18
making sure all of that information is being provided
19
through those requirements.
20
trigger, such as a request from a planner or operator,
21
for that information.
22
that that data is just be -- required to be held on an
Again, we
So where we had PRC-02 that was focused
This Drafting Team decided to put
This is installing new
So there might be a
There's a small period of time
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ongoing basis, but we're talking about potentially
2
terabytes of data after just a couple weeks.
3
there's not a large period of time that that data is
4
required to be preserved unless a trigger is put
5
forward by the planner and operator to initiate that.
6
So
So we want to get into how these things
7
interrelate as part of this quick presentation, and I
8
see this as part of like the three-legged stool that
9
happens with real-time assessments.
You've got data
10
requirements, data-sharing requirements, and then the
11
analysis requirements.
12
we're initiating all three versions of this three-
13
legged stool simultaneously.
14
lessons learned for how we do joint standard project
15
development, three different projects working somewhat
16
in tandem.
17
some lessons learned, I'll say, and some improvements
18
that we'll make for the modeling aspects as well
19
because there's three projects that will go through a
20
similar type of need to coordinate and collaborate on a
21
single solution.
22
The difference here is that
So this has been a
Not everything was done completely.
We got
So PRC-028 looks at making sure that the
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installation of the equipment is done.
2
the implementation questions and discussions tomorrow,
3
so I won't go into the Phase 10 implementation through
4
2030, other than to say, for all of 901 -- that's
5
Milestones 2, 3, and 4 -- all have to be fully
6
implemented by 2030.
7
it's not.
8
project is taking a year or two, acquiring vendors,
9
getting through supply chain issues, making sure you've
We'll get into
It seems like a long time, but
As we all know, just a standards development
10
got contractors onsite for testing and validation.
11
It's going to take a lot of work, and don't start two
12
years from now or three years from now.
13
critical that we start soon and understand the issue
14
soon so we make sure that things are in the works and
15
scheduled and being able to be coordinated with
16
reliability -- or with the regional entities as well.
It's really
17
Next slide.
18
For PRC-030 -- did we skip PRC -- did we skip a
19
20
slide?
Thank you.
Yes.
So Project 2020-02, PRC-024, we're looking at
21
frequency and voltage Ride-through requirements.
22
why we're all here today.
It's
We're looking at
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establishing capability-based Ride-through criteria and
2
performance-based Ride-through criteria.
3
difference there being the design piece where you have
4
-- whether or not you've communicated what the unit is
5
capable of doing versus how it's actually performing in
6
practice.
7
what is it actually doing?
8
need both of those things in order to be able to align
9
them and make sure that they're the same.
So the
During a voltage or frequency excursion,
Does it match?
And so we
There's
10
going to be differences based off of things that are
11
as-built versus as-designed, but we've got to be able
12
to make sure that we're moving forward with
13
comprehensive solutions.
14
these, and that's what PRC-029 does for IBR.
15
That means we need both of
PRC-024 was modified slightly.
It takes Type
16
1/Type 2 wind.
17
synchronous generation.
18
with those changes to ensure that those assets are
19
covered.
20
asynchronous, you know, Type 3/Type 4 wind and PV where
21
we're looking at IBR that need to be looked at a little
22
bit differently.
It takes synchronous condensers and
So we're retaining PRC-024
So PRC-029 really focuses on those
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Next slide, please.
2
PRC-030, similar conversation here where there was
3
an IBR version of the standard created, looking at
4
assuring that analysis is being performed.
5
responsible entities, what were the trigger criteria,
6
and how these things interrelate is that PRC-030 really
7
triggers what is required to be evaluated.
8
PRC-028, we talked about how there was disturbance
9
monitoring data that had to be captured, that
Who was the
So within
10
information needed to be triggered for.
11
call -- we're going to investigate this particular
12
instance.
13
to know when a disturbance occurs.
14
at the wider area view.
15
own operations that might trigger it, but it's going to
16
be on planners and operators, primarily operators, to
17
be able to determine whether or not excursions occurred
18
that requires additional analysis to be able to
19
identify if generators either failed to meet Ride-
20
through or they were able to Ride-through with adequate
21
bandwidth.
22
We're going to
It's not going to be on the generator owner
They're not looking
They may know because of their
So PRC-030 is really what ties PRC-028 and 29
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together.
2
are all really needed in order to be that single
3
solution.
Again, that's that three-legged stool that
4
Next slide.
5
So finally, this is just a graphical
6
representation of what I just went through.
7
voltage or frequency excursion that happens on the
8
right and it -- for one, it's looking at the criteria
9
individual generators will be able to tell if they rode
There's a
10
through or not.
11
doesn't occur because the generator owners didn't know
12
that there was an excursion that occurred, then PRC-030
13
that's over there on the right-most block would be the
14
one that triggers that additional analysis to ensure
15
that it's performed.
16
And if that individual analysis
The data-sharing aspect comes from PRC-028, so
17
that left-most block.
18
thing that's going to be relied on to perform those
19
analytics, but we got two other boxes down there that
20
are critical, which is Milestone 3 and Milestone 4 are
21
going to require this information.
22
data-sharing capability, the ability to trigger sharing
It's really going to be the
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that data is essential for validating models, making
2
sure, again, as performance is being incorporated more
3
into these standards, that we have performance
4
evaluations during model validations and not maybe just
5
five-year stage testing based off of what -- or the
6
unit can do and based on the facts and circumstances at
7
the time that unit is tested.
8
So model validation performance may happen on an
9
ongoing basis, may be triggered on some other aspect
10
of, you know, the operators or planners' criteria or
11
working groups' processes.
12
developed within the modeling teams that are focused on
13
Milestone 3, but we won't go into that today because
14
that's obviously a whole other scope of work and we've
15
got a whole year to do it, so we'll put that one to
16
rest.
17
in terms of the performance data and the models, and
18
then conducting planning and operational studies after
19
that.
That's going to be
Milestone 4 is taking everything that's captured
20
So next slide.
21
At this point, we'll open it up for any questions.
22
I don't know if there's going to be questions.
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can move to the Slido slide as well.
2
that's getting ready just to go through how we're going
3
to be doing the Q&A, within the room, we've got two
4
microphones set up, which are between the two hallway
5
the two columns here.
6
ask in the room during any of the presentations or
7
panels, please line up behind the microphones.
8
alternate between questions in the room and online.
9
the online Slido is going to be available during
Well, while
If f folks have a question to
We'll
10
presentations.
11
questions locked so there won't be any questions that
12
will be able to be asked at any other time.
13
going to close that down and reopen it every time we
14
have a -- the possibility to go to a Q&A.
So
15
16
17
We're going to have the -- those
We're
We do have a code and instructions here coming up.
There we go.
Thank you.
So this is going to be the same information that
18
will show multiple times throughout today and tomorrow.
19
You're able to use the QR code if you want to scan on
20
your phone.
21
There will be a space to put in an event code.
22
using "Ride-through" because why not?
You are also able to just go to Slido.com.
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We're
So capital
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"R/hyphen/through."
2
just be able to get in.
3
moderator looking at the questions to make sure things
4
are on topic, that it's appropriate to the panel that's
5
being presented at that time.
6
shown multiple times, so if you miss this information
7
now, you want to grab a screenshot, please do, but that
8
will be how we go through the Slido Q&A.
9
There's no password.
You should
We will have moderated -- a
So this slide will be
So if there's any questions online -- not sure if
10
there's any questions online right now.
11
Excellent.
12
the next presentation then, which will be a 15-minute
13
break.
All right.
Okay.
I think we could probably go to
14
(Laughter.)
15
MS. CALDERON:
Oh yes, yes.
16
MR. MAJUMDER:
Thank you so much, everyone.
17
MS. CALDERON:
Oh, just for anyone asking a
Question in the room?
18
question, could you please provide your name and who
19
you're with, if you're in the room?
20
MR. MAJUMDER:
Absolutely.
My name is Rajat
21
Majumder.
22
renewable energy developer here in the U.S., and I'm
I work for in Invenergy, which is a
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also on the Standard Drafting Team of PRC-029.
2
great presentation, good setup of the meeting.
3
So
I heard a statement from Rob that -- he made it
4
very firmly that the risk is sufficient, technology is
5
sufficient, so let's get it done, it's not a matter of
6
easy and hard.
7
risk sufficient part should be data driven.
8
technology is sufficient.
9
is gap between what technology can offer now, and
Absolutely agree with that, but that
Yes,
Of course there are -- there
10
that's why we are here today.
11
already be having an approval on the standard.
12
missing until -- is how the sufficiency of the risk is
13
being established for what technology is shot.
14
that's what my humble request to the entire team, that
15
as we go through next two days, let's keep that in
16
mind, that whenever we are trying to establish a risk,
17
let's find out what is needed for the reliability of
18
our bulk electric system that we own.
19
20
21
22
MS. CALDERON:
online?
Okay.
All right.
Otherwise, we would
What is
So
Thank you.
Still no questions on
We'll go ahead and --
MS. CASUSCELLI:
All right, Jamie.
It looks like
we do have a couple of questions online.
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MS. CALDERON:
2
MS. CASUSCELLI:
Okay.
So first, "does the spoken word
3
during this Technical Conference become part of the
4
NERC/FERC record or only the comments provided in
5
writing?
6
MS. CALDERON:
Oh, yes.
So we are recording this
7
webinar or this conference.
8
transcript as we'll be able to have for our record of
9
developments.
It will be posted.
The
Everything here for this conference is a
10
little bit atypical because we're using it as part of
11
the -- our response to invoking Rule 321, so this is
12
going to be part of our full record of development.
13
The questions that are online that are asked, we'll
14
preserve those.
15
archive of questions, questions in the room.
16
have a court reporter in the room, and that's why --
17
one of the reasons we're asking folks to be able to
18
provide your name and who you're with prior to asking
19
questions so we'll be able to ensure that everything is
20
-- everything's captured.
21
MS. CASUSCELLI:
22
We'll be able to add those to the
We do
All right, a couple more.
David
McNeill from Certrec is wondering, "Does NERC
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anticipate the replacement of synchronous generation
2
with IBR-based generation to lessen the severity of
3
frequency events?"
4
MS. CALDERON:
5
MS. CASUSCELLI:
6
Less than the?
Less than the severity of
frequency events.
7
8
We'll probably get through that.
MS. CALDERON:
Not sure I understand that
question.
9
MS. CASUSCELLI:
It says, "Does NERC anticipate
10
the replacement of synchronous generation with IBR-
11
based generation to lessen the severity of frequency
12
events?"
13
MR. SHATTUCK:
Yeah.
I mean, I'd say probably
14
not.
15
we transition towards more IBR and higher penetration,
16
things are going to change.
17
and it's all grid following inverters, and, you know,
18
all the synchronous machines are gone, then things are
19
going to happen that we don't expect.
20
probably be worse than what we've seen.
21
this in a thoughtful way and replace those synchronous
22
machines with machines that are, you know, tuned right,
I mean, the thing we can certainly say is that as
If we do nothing, right,
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Now, if we do
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with the right parameters or the right capabilities
2
like we're going to talk about today, then we could be
3
relatively certain, you know, if we go forward, that
4
even if the events change their nature, that we're
5
capturing that with our, you know, study work, right?
6
If we do better studies and study what's actually going
7
to happen and study what will come next, then whatever
8
happens as far as the changes that happen, we'll be
9
able to mitigate those as much as we can.
10
11
12
MS. CASUSCELLI:
more.
All right.
Thanks, Alex.
I have
What is the code for Slido?
MS. CALDERON:
There is -- so the event code is
13
"Ride-through," capital R and then a hyphen.
14
no password on top of that.
15
additional information as optional, such as your name,
16
so that we're able to respond to that question in chat,
17
but the event code is "Ride-through."
18
19
20
MS. CASUSCELLI:
There's
So you're able to enter in
And are the preconference
comments going to be posted?
MS. CALDERON:
Okay.
The preconference comments
21
that were provided as part of the larger set of
22
comments that we requested from industry, we do not
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intend to publicly post those.
2
as a matter of our, again, record of development.
3
we as part of our filing have additional follow-up
4
questions, we might reach out to those individual
5
comment submitters for additional information.
6
additional information that's requested by FERC during
7
our filing, we're going to provide that as well, but we
8
have no intention to post the full comments.
9
MS. CASUSCELLI:
We are collecting those
All right.
Okay.
If
If it's
There's more
10
questions.
11
technical stuff if you want to approach this now or --
12
We're getting more into, like, the
MS. CALDERON:
Yeah, if it's starts getting into
13
the actual frequency or voltage criteria, we'll want to
14
wait for that panel to go because we'll have an OEM
15
panel today and another panel as well.
16
MS. CASUSCELLI:
17
MS. CALDERON:
Okay.
So as long as it's questions
18
related to kind of the larger Milestone 2 work.
19
of this, like, larger conference work stuff is fine as
20
well since this is --
21
22
MS. CASUSCELLI:
Okay.
Okay.
Some
So we'll just hold
a lot of these questions until the end, I think, or
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later.
2
MS. CALDERON:
All right.
Well, we'll put a pause
3
now.
4
think, is still probably down the way, coffee and water
5
outside, and we'll see you in a bit.
We'll go ahead to a 15-minute break, and food, I
6
(Break.)
7
MR. BENNETT:
Okay.
So it looks like we're
8
getting started here.
9
thank you for all the participants so far.
Again, I'd just like to say
Great
10
technical presentation by Jamie to kind of set up this
11
discussion.
12
that we have -- I believe that we are entering into our
13
first presentation which is review --
And then as far as right now, I believe
14
(Technical difficulties.)
15
UNIDENTIFIED SPEAKER:
16
MR. BENNETT:
Okay.
Lithium batteries.
This microphone works now.
17
So we're going to enter into our presentation to review
18
the voltage and frequency Ride-through criteria in the
19
PRC-029 standard.
20
speakers today, which are our Drafting Team members,
21
but Husam Al-Hadidi and Shawn Wang.
22
over to you, and thank you for your presentation today.
So helping us with that are our
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MR. WANG:
Thank you.
Thank you, everyone.
2
morning.
3
chair of the Standard Drafting Team.
4
to present the -- some background of this standard
5
development over the past, like, two years.
Good
My name is Shawn Wang from Enel.
I'm the
6
Yeah, maybe next slide, please.
7
Yeah.
Yeah, I'm happy
This slide shows the Drafting Team roster.
8
I really appreciate all the membership, yeah, during
9
the past two years.
It's really hard work for the
10
Drafting Team.
11
today just on behalf of us.
12
the membership, yeah, in this room -- in this room,
13
yeah.
Yeah, I think everyone actually here
Yeah.
Actually, some of
14
So yeah, with that, actually, next slide, please.
15
As Jamie, mentioned, the -- she just put the time
16
machine back to 2023, but I will get back even further
17
of this Drafting Team back to 2020 because the project
18
named 2022 -- 2002.
19
there's a SAR from NERC to revise the standard --
20
existing standard PRC-024 to include the dynamic
21
devices into PRC-02024.
22
That's the reason why actually this project just
Back at that time, actually,
That project start from 2020.
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grandfather that project to move forward to include --
2
associated with this standard.
3
Yeah.
4
Actually, in 2022, actually, NERC issued another
Next slide, please.
Yeah.
5
SAR to revise the PRC-0-24-03, actually revise the
6
generator Ride-through standard.
7
this SAR is like from the system events, right, several
8
system events.
9
we -- the NERC team identified there some missed
The background for
Actually, after the analysis, actually,
10
operations.
11
actually reduced the output, right, from the IBRs from
12
the wind, solar, or even the BES.
13
- the system event analysis identified there's some
14
reliability risks, yeah, from those abnormal trippings
15
from the IBR resources.
16
Actually, the widespread generation loss
Actually, the from -
From the analysis, actually, the -- one of the
17
issues is identified that the existing PRC-023 -- PRC-
18
024-3, is just equipment protection setting standard.
19
It's not sufficient to cover the IBR units.
20
SAR, it's proposed to address those reliability risks
21
to propose a more suitable performance-based
22
reliability standard.
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In that
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Next slide, please.
2
Yeah.
The Standard Drafting Team start from
3
actually combined those two SARs and start working on
4
this standard -- the standard to work on this project.
5
Actually, the project start from 2022, I think -- yeah,
6
2023.
7
discussion, I think as mentioned by David and Rob,
8
actually, the Standard Drafting Team realized that
9
there's difference between the synchronous generator or
At that time, actually, after the extensive
10
the traditional generator and the IBR units.
11
approach-wise, actually the Standard Drafting Team
12
decided to revise or modify the PRC-024-3 to retain the
13
reliability standard as the protection-based standard,
14
only applicable to the single generator and the
15
synchronic condenser Type 1 and Type 1 wind turbines,
16
and to create a new reliability-based standard, the
17
PRC-024 -- PRC-029, address the inverter-based
18
resources to Ride-through these system -- voltage and
19
the frequency excursions.
20
So
Actually, at the time of the last year, actually,
21
the FERC Order 901 came out.
22
Drafting Team decided to coincide with the Ride-through
Actually, the Standard
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standard proposed by the attribute standard -- no,
2
sorry -- the need to understand and follow the FERC
3
Order 901.
4
Yeah.
5
6
slide.
Next slide.
Previous one.
Go back one
Yeah.
This slide shows the timeline, actually, for the
7
Standard Drafting Team actually after the
8
the -- more than -- this year, right, after the 901
9
released.
-- during
Actually, the Standard Drafting Team work
10
very hard after that to meet the timeline, right?
11
Actually, it's very time constrained.
12
first draft released in March of this year, and the
13
first comment period run through March 27 to April 27.
14
Actually, the first draft didn't pass the ballot, and
15
they received almost 200 page comments from the
16
stakeholders.
17
hard, went through a series of meetings, including one
18
in-person meeting in Cleveland in May, to address all
19
the comments and release the second draft the -- of the
20
standard.
Actually, the
The Draft Team were, again, working very
21
So the second drafting -- the second comment
22
period ran through June 18th to July 8th of this year.
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Again, actually the -- it didn't pass the -- after
2
received the comments, actually, the Drafting Team set
3
up several meetings and address those comments,
4
actually make revisions to the draft, actually, within
5
very short time duration from July 22nd to August 12th.
6
Then they create the -- make the third draft, but
7
unfortunately, still didn't pass through the ballot.
8
Then on August 15th, the NERC Board of Trustee invoke
9
this Rule 321, so this technical meeting, yeah, yeah,
10
came up.
Yeah.
11
mention.
The PRC-024, the revised PRC-024 passed the
12
ballot, so we just focus on the PRC-029 now.
So the -- just one thing I want to
13
So next slide, please.
14
So with that, actually, I will pass the microphone
Yeah.
15
to Husam to describe the current or latest redline of
16
the Draft 3.
17
MR. AL-HADIDI:
Good morning.
Husam Al-Hadidi
18
from Manitoba Hydro.
19
steps where we were as part of developing this standard
20
with this Draft Number 3.
21
how we came to this stage from standard from Draft
22
Number 1 to Draft Number 3.
I'll just -- I'll go through the
Just I'll go in the progress
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First of all, we were having challenging of the
2
IBR definition, which was not there, and it gave us
3
some way -- went through different phases of it, but
4
until it was now approved by NERC, and it was passed
5
the ballot.
6
the standard itself.
7
with the transmission owner.
8
applicability or not?
9
because we -- part of IBR, which is the offshore or any
That's why it's now included in the -- in
Also, there was some struggle
Is it going to be part of
And the reason for that is
10
IBRs connected through the water source converter,
11
which was sometime it could be owned by the
12
transmission owner, but after a good discussion and
13
looking at some example here in U.S., we found there is
14
not a case exists, so -- and it was adding some
15
confusion to the stakeholders.
16
transmission owner from the applicability part of it,
17
and it's only now applicable for generator owner.
So we removed the
18
Next slide, please.
19
We started first with Draft Number 1, which was
20
six requirement, but we ended up with four requirement
21
in Standard Number 3, and I'll speak about why we have
22
moved some of this requirement or remove it from Draft
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Number 1.
2
voltage Ride-through, and in the first draft, we were
3
having only -- it wasn't -- it was only event-based
4
analysis.
5
we understood that analysis part, it requires some
6
measurement, and that measurement, it may not be
7
available at the early stage of the implementation of
8
the standard.
9
is just to make sure that the capabilities already
And the first requirement was about the
It was not a capability-based standard, but
And we thought it's the right way to go,
10
exist.
11
confirm that if that's -- if it was how it was designed
12
and it was -- performed as expected.
13
And then event-based analysis will -- can
So we included the designing -- the design and
14
operate, and it was -- that wasn't integrated in Draft
15
Number 2, moved away from Draft Number 1, which was
16
only about just operate the IBR, and R1, it just focus
17
on the Ride-through the voltage.
18
for this Ride-through, and the two -- the table is one
19
for the wind IBR and other -- and then -- and the
20
second one for other IBR technology.
21
for that, we want to have as wide as possible voltage
22
Ride-through criteria with understanding that the
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And we had two table
And the reason
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system short-circuit level and they (inaudible)
2
significantly change.
3
load will integrate it a lot on the system, and that
4
the need of Ride-through -- of a larger voltage Ride-
5
through, it'll be expected for ability to mitigate any
6
future risk.
7
the two tables and with understanding some limitation
8
could still exist for the wind technology.
9
And even the load itself -- IBR
For that reason, we were -- we went to
And here we have the -- we list some of the
10
exemption from the voltage Ride-through where it could
11
trip for a reason as listed in this fourth bullet.
12
of them is for (inaudible) protection, and second, we
13
understood there's an exemption, and that exemption may
14
give you a different criteria than what's there in the
15
table.
16
-- you may not be able to go for three second.
17
be able to go two second for legacy equipment only or
18
legacy IBR.
19
exemption there.
For example, like the 0.9 per voltage.
One
It may
You may
So that's the reason it's one of the
20
And also Bullet Number 3, it used to be as a
21
separate requirement in the standard in the first
22
draft, which is the -- which is the positive sequence
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instantaneous voltage jump.
2
thought it may -- it make it more fit to have it as an
3
exemption because really only if unit trip, then if
4
your voltage was -- if your base angle jump more than
5
25 degrees, then you could use it as exemption from the
6
compliance part, and you don't have to worry about it
7
as part of -- if you don't -- if you don't have a
8
protection, if you don't have this trip there, so you
9
don't have to be worried about the compliance and how
10
But we said it was -- we
to present it as a requirement.
11
And also, there was some question about the
12
voltage per hertz, and we said maybe it's good to have
13
some criteria to ensure just in the design because we
14
added the capability and there was a compliance
15
question how to prove that the design can work at the
16
boundaries of the voltage and the frequency at the same
17
time.
18
exemption criteria here.
19
Next slide, please.
20
This is the measurement.
That's why we included the voltage per hertz
Actually, the
21
measurement were changed somehow to reflect the -- some
22
feedback we got from multiple stakeholder, and I
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believe to the stage where now it add more clarity.
2
you have any question, we can answer it at the end of
3
the -- at the end of presentation.
4
slide, please.
5
If
But for now, next
For R2, I said R1 was still a voltage, but Ride-
6
through R2, it went now to focus on the -- focus on the
7
performance of the voltage.
8
on the table, there is three operating region, which is
9
the continuous, mandatory, and permissive region.
And here we split -- based
And
10
for each region, we presented the performance criteria
11
needed after a disturbance.
12
there is a weakness for every system, and you cannot
13
come with some criteria which can fit all.
14
However, we understood
We try to come with as much as possible adding
15
flexibility to the requirement, at the same time giving
16
some guideline for a starting point whenever is needed.
17
So we started with a lot of performance requirements as
18
included and very specified, like it is going to be
19
different how much your reactive power for every
20
voltage there.
21
power and reactive power?
22
What's the relationship between the
However, but we understood that could be
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challenging for some region, and it will not fit -- we
2
cannot come with answer fit all systems.
3
reason, we remove some of this language from the
4
standard, and we ended up with some language still
5
there, which is meet the minimum requirement in our --
6
in the Standard Drafting Team opinion, but at the same
7
time, having some added flexibility still there for the
8
TB and for reliability coordinator and planning
9
coordinator to come with their own criteria if it's --
For that
10
if it's going to be different than this, to mitigate
11
whatever reliability issue they have in their system.
12
Next slide, please.
13
For 2.2, this focus on mandatory operation region,
14
where 2.1, it was the continuous within mandatory, and
15
this one is merely saying that we understood there's a
16
reactive -- there is real and reactive power.
17
said that's always going to be the fault, is reactive
18
power, it makes sense if you are having a voltage
19
issue, you need to support the voltage system.
20
However, we understood for system -- for other system,
21
it could be real power priority is the need because
22
they may have some frequency issue, and they need to
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mitigate it or deal with it.
So we come -- we wrote it in such a way where there
3
is a flexibility there, but preference or the fault is
4
already provided.
5
Next slide, please.
6
For 2.3, it is actually focused in the -- in the
7
reaction of -- this one in permissive region where it's
8
-- here, it's looking at part of the -- part of the
9
FERC order was that you couldn't use voltage cessation
10
or the blocking of the current.
11
that below 0.1, especially positive sequence voltage,
12
if you have your three voltage phases already all below
13
point-zero or close to zero, then it's very hard for
14
the IBR to still continue to produce any power or try
15
to contribute to the system.
However, we understood
16
So for that reason, we said, instead of allowing
17
them to trip, we said, no, don't trip because really,
18
it may, it may not able to provide any support after
19
the fault recovery.
20
booster sequence voltage below .1, but at the same
21
time, if you booster sequence goes above .1 within five
22
cycle, you have to reconnect to the system, and you
So we say you could block if your
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have to start -- continue exchanging current, and you
2
have to meet the requirement as stated in the 2.1 or
3
2.22.
4
For 2.4, it's focused on the -- on the response of
5
the IBR after clearing the fault.
6
stated that sometime the -- based on the surface level
7
or the -- or the gain, or the right -- or the recovery
8
time, it may become a little bit -- or even the mode of
9
operation is reactive power, how much reactive power
It was a concern
10
was exchanged, it may cause a high-voltage response
11
after clearing the fault, and that voltage may go
12
outside of no trip zone, and that may cause itself to
13
trip.
14
the capability, and it has to be shown that it has --
15
it could be tuned to be able to maintain the response
16
within no trip zone -- voltage no zone.
So we see that it need to be designed or have
17
Next slide, please.
18
For the 2.5, this is for the recovery from the
19
event itself.
20
flexibility is added there.
21
recover, and that was part of the FERC order, within
22
one second.
And for the recovery, as I said, the
We said it needs to
At the same time, it has to recover fully
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for the pre-disturbance megawatt, and -- but we
2
understood that it may not be able to go to the full
3
megawatt because of some water or some change in the --
4
in the -- in the -- in the capability of the IBR is not
5
for tripping an individual IBR unit.
6
it can -- even if we trip some IBR unit, but it can
7
maintain its power after the disturbance, we say this
8
should be a compliance.
9
issue with that, but we understand in some cases you
It's only -- if
It shouldn't be -- have an
10
may not able to cover for 100 percent, and we give them
11
a flexibility, which is going to be provided by their
12
associated transmission planner or operator or
13
coordinator.
14
Next slide, please.
15
This is the fun part, which is R3, which is the
16
frequency Ride-through.
17
one, I must say.
18
change in the -- right now, the system is going through
19
significant change, and the IBR technology is going to
20
be -- penetration will be increased significantly in
21
the system.
22
exposed to the system to the high-frequency event or
We had to struggle with this
We understood the system is going to
And people have not enough experience or
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low-frequency event.
2
which, in our mind, how it's going -- the system going
3
to behave within the coming four, five, six, 10 years,
4
and what's the availability needs for the system.
5
So we try to write something
So FERC stated that you cannot have any exemption
6
criteria.
7
which we try to have some frequency requirement there,
8
performance requirement Ride-through, but at the same
9
time with understanding some legacy equipment may not
So we will -- we tried to write something
10
be able to meet some of these requirements.
11
wrote it in such a way where we did not have any
12
performance, only Ride-through, so we are not -- there
13
is no primary frequency controller as part of this
14
requirement.
15
to keep connecting and exchanging current, but you
16
don't need to respond to the frequency event as it is
17
because there is no required frequency performance.
18
So we
You need only Ride-through, and you need
And the challenge was for the ROCOF, which is 5
19
hertz per second, but we understood it's -- this value
20
cannot -- it's very difficult to calculate during the
21
fault.
22
during the fault event.
So we make it very clear that this is not
It should be after the fault
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and should be for really actual load and generation and
2
balance event.
3
So and we come with -- we widened the table beyond
4
even the IEEE 2008 and Ride-through, understanding that
5
the nature of the system will reduce a lot, and we --
6
and the technology are much capable of Ride-through of
7
frequency envelope.
8
some -- OAM about their experience with that.
9
widen this range of frequency larger than for the first
So and maybe today we'll hear from
But we
10
-- six second larger than IEEE just to make sure that
11
it's -- the future system will be able to have that
12
advantage of maintaining the IBR for longer or larger
13
exertion of frequency.
14
At the same time, also, the load will change
15
significantly.
16
make rate of change, interruption of power will be
17
significant, and the rate of change will be
18
significantly, even most likely, more than 5 hertz per
19
second.
IBR load will be there, and that will
20
Next slide, please.
21
The R4, it's -- is the exemption.
22
In this one, we
moved in different stages in our -- in our Drafting
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Team to come to this language where it's in the -- in
2
Draft Number 3.
3
agreed that an exemption, this is like a temporary
4
requirement because this one only valid for the first
5
year of -- after the -- after the effective days of the
6
standard.
7
for exemption for only voltage, which just mean that
8
for R1 and R2.
9
could, if -- for legacy equipment, you could do
What we have here, we came -- we
So after that, you have one year to apply
And for this, too, requirement, you
10
exemption.
11
provided in your submission request for exemption.
12
understood there is a risk and some assessment need to
13
be there, but -- that could not be explicitly provided
14
in this requirement.
15
exemption will be guaranteed not based on the risk.
16
just based on meeting this requirement itself.
We list some of the information need to be
We
But we said it's based on -- the
17
Next slide, please.
18
Here, we also provided the mechanism and to whom
It
19
this exemption needs to be submitted.
20
time, we said that how you need to deal with it in the
21
future, if you are -- if your exemption has been -- you
22
replace some of the equipment and if there is any
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request, additional information from transmission
2
planner or transmission operators or RC for additional
3
information.
4
information which may help them to assist the risk and
5
to model or to try to include this as part of their
6
study to understand their limitation within the
7
equipment.
It could be modeling, it could be other
8
Next slide, please.
9
I think here, just the tables of the voltage and
10
the frequency, so we have modified them, and there's
11
not much here.
12
Next slide.
13
The same thing.
This is the frequency, as I said.
14
For the first six second, we have increase the level up
15
to 64 hertz in the overfrequency part and to 60 56
16
hertz in the under frequency for six second.
17
that, we try to match some of the existing IBR
18
standards within the footprint of U.S.
19
Next slide.
20
MR. WANG:
Beyond
Thank you.
Yeah.
One more thing I want to mention
21
is, like, for the -- at the first draft, right?
22
also include the transformer voltage, the requirement,
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along with the attribute and 800 standard.
2
the Drafting Team, the development and also the
3
participate of the attribute Standard Team, right?
4
realized that it's very complex issue at this point,
5
and we just remove the -- remove that requirement and
6
just put the one atom in the attachment of the Table 1,
7
yeah, such that actually, we just try to avoid the
8
instantaneous overvoltage tripping, yeah.
9
allowed, yeah.
10
11
But during
We
That's not
Just one point we just mention, yeah.
Thank you.
MR. MAJUMDER:
Thank you, Shawn and Husam.
Rajat
12
Majumder from Invenergy.
13
course.
14
the entire room to consider and provide some guidance.
15
One is based on FERC Order 901.
16
FERC Order 901 does not allow weaver to frequency,
17
Ride-through, or 901 is silent on that.
18
provide explicit weaver to voltage, right?
19
understand that, but I just wanted to touch on that.
20
I'll go straight to R3, of
So two primary comments that I would like for
Is it true that the
It does
So I
The second one, which going back to my comment
21
earlier this morning, the sufficiency assessment of the
22
risk should be data driven.
And if we look at some of
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the earlier even that has happened, I fully agree that
2
there has been, even on where large amount of IBR
3
tripped off.
4
alert carefully were due to wrong settings.
5
try to solve a problem of some equipment settings being
6
wrong with a very broad stroke of making the
7
requirement much more stringent, I do not know if
8
that's the right way of doing things.
9
Majority of them, if we review the NERC
So if we
If we look at, again, on the data that's available
10
based on the Texas Uri event, the FERC report showed
11
the frequency nadir was 59.4 hertz with 50-percent
12
generation trip, then followed by 25-percent load
13
setting.
14
a four-hours long session or large disturbance all over
15
the world from both 60 hertz and 50 hertz, and many of
16
them has significantly more IBR penetration in their
17
system compared to here in the United States.
18
haven't seen any one of them, in 50 hertz, the
19
frequency ever went down below 49.4.
20
I was in Sigrid, Paris last week.
There was
I
So all I'm trying to say that asking for a
21
frequency right requirement thinking it may happen in
22
the future appear, to me, be pure speculation.
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would like the entire room to consider those fact and,
2
again, humbly request to establish the risk sufficiency
3
assessment based on data that's available to us.
4
you.
5
MS. CALDERON:
All right.
Thank
Jamie Calderon with
6
NERC.
7
advised with Legal there was no exemptions that were
8
allowed for frequency within FERC Order 901, so that
9
was routinely provided to the Drafting Team through
Just in response to the question, the team was
10
consult.
11
types of frequency exemptions.
12
more into that conversation in this afternoon's panel
13
and, of course, with the panel tomorrow morning.
14
we'll get into more details for that.
15
FERC Order 901 doesn't even speak to any
And we're going to get
So
But also, just as a reminder, we do want to keep
16
the Q&A to questions to either the presenters or the
17
panelists.
18
can ensure that we're allowing time for other people to
19
ask questions.
20
So please, please try to keep to that so we
MR. GOGGIN:
Thanks.
21
Strategies.
22
through curves in PRC-029.
Michael Goggin with Grid
A question about the frequency RideCan you talk a little bit
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more about the source of those curves and the technical
2
justification for the relatively wide frequency bands
3
in there?
4
MR. AL-HADIDI:
The idea behind that, we looked at
5
-- I come from Manitoba Hydro.
6
inertia can go very low, and we have multiple event
7
where we -- our frequency -- we have rate of change of
8
almost 8 hertz per second based on our inertia when we
9
-- when we, our tie line is broke from the system.
Our system, really, the
So
10
we understand the event can be very severely, and with
11
low inertia, you need -- you need to Ride-through
12
larger, wider range of band of frequency.
13
And we under -- also the base on this limitation
14
we have right now in BRC 24, it was based on the actual
15
physical limitation on thermal turbine, which is not
16
the case in many cases for -- other than IBR, the Type
17
3, where it have some -- it's still in the integrated
18
system.
19
inverter itself.
20
opportunity is there.
21
the inertia will go lower.
22
be going lower, and that's mean the rate itself can
The other one is already buffered by the
So we -- the thought was the
The need of the system will -Even the short sector will
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widely spread as a voltage dip where it can impact
2
significant number of load and the load IBR base load.
3
And this all can create a significant movement of the
4
frequency.
5
In addition to that, also, we also understand that
6
the IEEE say that 5 hertz per second.
7
about it, so it'll then take more than one second or
8
less even to go beyond the 65 hertz or even to go 55
9
hertz if you are close to this 5-hertz-per-second rate
If you look
10
of change.
11
for the IBR to respond for a frequency event.
12
said if the technology allowed that, why not to bring
13
it, and the idea that it's not a protection base, it
14
don't even -- in my opinion, the frequency or your
15
protection setting should be based on actual capability
16
and not based on the boundary itself as specified here.
17
So it doesn't give a time -- enough time
So we
So in many cases where we have our equipment, the
18
Ride-through frequency in in many area, like Manitoba
19
Hydro have, we have up to 82 hertz.
20
through.
21
insignificant based on the system need and the system
22
need maybe there in the future.
It has to Ride-
So this number, in my opinion, was
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MR. PATEL:
All right.
All right.
It's working.
2
So you know, everyone is going to talk about frequency
3
Ride-through and exemption for legacy.
4
to talk about it just now.
5
Patel, EPRI.
6
and questions.
7
young daughters to send to college.
I'm not going
But by the way, Manish
Whatever I say or ask are my own opinions
8
(Laughter.)
9
MR. PATEL:
Please don't sue me.
I still have two
So a couple of general comments.
10
Look, I'm supportive of the standard, but the standard
11
remains completely silent on when IBR is required to
12
Ride-through, for what system conditions.
13
be designed today, installed today, commissioned today
14
to Ride-through for a given system condition.
15
years go by, the transmission system has changed upside
16
down.
17
-- I think it's a -- it's a -- it's a gap that the
18
standard completely remains silent and simply states
19
Ride-through no matter what the transmission system
20
condition is, what the neighbors are doing, and all
21
that kind of stuff, right?
22
The IBR may
Is IBR still required to Ride-through?
Ten
I think
The second thing is the way the standard is
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written right now, if the differential protection on a
2
generator step of transformer mis-operates, then the
3
IBR is out of compliance because it tripped when it
4
shouldn't have tripped.
5
but in 2022, there were 1,200 mis-operations on the
6
bulk electric system, and it's just life happens,
7
right?
8
that are beyond control, right, water dripping from the
9
roof in a control house, mouse in a control house
I do not recall exact details,
So there has to be some exemption for things
10
chewing up cables, things like that.
11
about what IBR is expected to do in a continuous
12
operation region of the voltage.
13
probably unnecessary requirement because the whole
14
purpose of the standard is Ride-through when the
15
voltage and frequency are normal.
16
the standard is actually asking for IBR performance
17
when the voltage is almost normal, right, so things
18
like that.
19
20
21
22
We talk a lot
I think that is
Half of the page of
I had something else in my mind, but it's
slipping.
I have opportunity today and tomorrow then.
MR. AL-HADIDI:
Thank you for the questions.
Manish, we discussed some of this one before.
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in the first part, which is about the system strength,
2
where it was -- where it was designed, the idea were --
3
the team were, the Drafting Team, that we did not touch
4
the stability part of the IBR.
5
the standard itself, we did not speak about the, what
6
you call the rising time or starting time, or is going
7
-- is it going to be stable or not stable.
8
understood this can impact the stability, and there's
9
the third phase, which is the Milestone Number 3, which
So we said we are -- in
So we
10
is, you know, about the operation, and that need to be
11
caught at that stage of the analysis, and I believe
12
that will be -- could be advised to revise some of
13
these parameters or re-look at it as part of that --
14
part of investigation.
15
But if it -- if that part provide now
16
recommendation for change of that to maintain for
17
whatever short-circuit level system become because you
18
cannot say that I design today, system have changed,
19
now for reliability, I don't have to do anything about
20
a system change.
21
cannot Ride-through, and the system can collapse or
22
reliability issue.
System event happened, everyone
So I think that need to be
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addressed as part of the how the phase three or my
2
phase three of the standard need to look at it, and in
3
that case, we looked at it where it need to be looked
4
at, the stability of the IBR.
5
6
For the second part, I believe your second
question, if I remember was about --
7
MR. PATEL:
8
MR. AL-HADIDI:
9
MR. PATEL:
10
Mis-operation of protection.
Mis-operation, yes.
Just real-life things.
MR. AL-HADIDI:
Yes, I fully agree.
Where the
11
standard -- we work with the BRC/TRT.
12
that these three standard really are -- they were
13
integrated with each other to some level, what our --
14
the Standard Drafting Team at least thought.
Maybe it
15
wasn't clear.
We
16
thought that the BRC 29 provide the criteria itself.
17
However, the assessment itself is done by BRC/TRT
18
because there's even the correction plan.
19
is coming -- going there.
20
As Jamie stated,
We'll see how the thing goes.
Everything
In the PRC-030, it was very clear stated that if
21
it was for mis-operation, you don't need to investigate
22
it, and is no -- no corrective action is needed.
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was already exempt by the IBR tripping for -- mis-
2
operation protection was already included, in our
3
opinion, at least in the PRC-030, which maybe this a
4
good point for discussion, if that was really the right
5
way to do it or not, but that's where we are.
6
7
MR. PATEL:
Yeah.
So I understand that.
The
standard has to stand on its own, right?
8
MR. AL-HADIDI:
9
MR. PATEL:
Yeah.
PRC-030 only talks about the operation
10
of BES under PRC-004.
11
breaker trip because of, you know, real-world issue,
12
and that's not a BES element.
13
not part of PRC-030, but PRC-030 criteria is met and
14
PRC-029 criteria are met, right?
15
there has to be some indication of things in the
16
standard.
17
was in the mandatory operation region, frequency was in
18
the, you know, mandatory operation region plan
19
disappeared, and there that has -- it's out of
20
compliance.
21
22
You can have a collector feeder
If it's not, then it's
So I think -- anyhow,
Right now, the way it is written, voltage
Anyway, we, we can talk --
MR. AL-HADIDI:
Yeah, yeah, that's a good point.
That's a good point.
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MR. PATEL:
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Page 76
Yeah.
The last point that I just
2
recall is this whole concept of performance-based
3
standard.
4
based came along, it was not the fact that perform
5
under 24/7, 365, next 25 years, in that manner.
6
more about voltage and frequency trip setting.
7
is not working.
8
Performance-based was -- continue to work when the
9
voltage and frequency are within given bends, right?
I think when the whole idea of performance-
It was
PRC-024
We need to go for performance-based.
10
MR. AL-HADIDI:
11
MR. PATEL:
Yeah.
So this whole concept of performance-
12
based is a little bit misaligned than the original
13
thought five years ago when it came out of IRPTF at the
14
time.
15
MR. AL-HADIDI:
No, I agree.
16
MR. MAJUMDER:
Rajat Majumder.
Thank you.
So Husam, when you
17
responded to the other gentleman question, I have heard
18
many will, and you referred to Manitoba system.
19
I'm sure that you might have seen an ROCOF of eight
20
hertz per second.
21
the requirement from a very specific region and
22
generalize it, right?
Now,
That's shocking, but we cannot take
Again, referring back to my
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SIGRA session, there was a gentleman from South
2
Australia.
3
peak load of 3 gigawatt.
4
South Australian event with a peak load of 3 gigawatt
5
and apply that to Eastern Interconnect with 950
6
gigawatt?
7
standard, we need to be aware of the context of it.
8
Cherry picking and then applying blindly is not the
9
right way to do.
10
He presented a lot of experience with a
Now, are we going to take a
So when we are creating a reliability
Second of all, you mentioned that, well if the
11
design can do it, why not?
12
IBR.
13
029, and I don't want to speak for them because we have
14
enough expertise today within the room.
15
forward to the manufacturing panel this afternoon.
16
have representative from FOSDA, Siemen Gamesa, Hitachi
17
Energy.
18
from them.
19
operating in such a low frequency ban, there are going
20
to be many other issues, unintended consequence.
21
going to make the transformer for no apparent reason.
22
That's not the right thing to do, but transformer is
It's not about just the
We'll have transformer which are not under PRC-
They are the top at their field.
I'm looking
We
Please hear
If you are going to have transformer
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not covered within our PRC-029.
2
MR. AL-HADIDI:
(Inaudible) versus (inaudible)
3
hertz was addressed by R1, but as I said, let's maybe
4
-- let us leave it -- this topic for further discussion
5
within the industrial, what do you think about the
6
frequency range and if the capability's there or not,
7
and what's was really the concern.
8
too many comment from the stakeholder about the range
9
of the frequency.
But we did not get
Most of their concern was with the
10
ROCOF and the legacy equipment where it may not able to
11
ROCOF value.
12
MR. MAJUMDER:
13
MR. PATTABIRAMAN:
Yeah.
Hi.
Dinish Pattabiraman from
14
TMEIC, you know, equipment manufacturer.
15
question broadly on the standard in terms of why the
16
deviations in the standard compared to IEEE 2800
17
language, which has been widely accepted in the
18
industry with the high balloting rate.
19
also about to be a test procedures, IEEE 2800.2 that's
20
going to come for the standard.
21
language of IEEE 2800, which is widely accepted in PRC-
22
029?
Scheduling@TP.One
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So I have a
And there's
Why deviate from the
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MR. AL-HADIDI:
We did not -- our intent was not
2
to diverge or to follow IEEE 2800.
3
but there was a lot of requirement there, and some of
4
it actually to be hard to write it, or maybe to
5
moderate, or make it as part of the compliance itself.
6
So based on that, we looked at the variety of the need
7
for the system and from reliability perspective, that
8
was the intent.
9
divert from it, we did.
We started there,
And wherever we found the reason to
And it was also, as you know,
10
it was FERC order, was also constrained in the way we
11
looked at some of the requirements.
12
MR. PATTABIRAMAN:
So but in terms of compliance,
13
you know, 2800.2 also offers a variety of test
14
procedures.
15
procedure that comes for PRC-029, but the strength of
16
2800 is that it offers these kind of test procedures
17
which different people can study and comply -- and at
18
least study compliance with, whereas deviating from
19
2800 language -- for example, there is a language for
20
phase jump that says that, you know, 25 degrees but
21
initiated by a non-fault, you know, that kind of
22
language was not there in 2800.
I'm not sure if there's going to be a test
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changes like this throughout the standard, including
2
the frequency Ride-through requirements.
3
curious on what the thoughts of the Standard Drafting
4
Committee are on that.
5
MR. AL-HADIDI:
So I'm just
As I stated that, yes, there is
6
some slightly different, but I'm also part of the -- of
7
IEEE standard, and it's not -- it's not the perfect
8
standard.
9
change, and there was opportunity for us to look at
10
from a bit perspective like the frequency, why it's
11
there.
12
value was selected was not enough, always a good answer
13
from people who were involved in IEEE standard at that
14
stage.
15
And all it mean that there is always need to
And when we asked the question even why this
So it's based on the -- your experience, and this
16
is the task of the dd task of the Drafting Team to come
17
and consulted with the industrial and the feedback we
18
got, and based on that, we moved in this direction.
19
Thank you.
20
MR. PATTABIRAMAN:
21
MR. WANG:
22
I address.
Yeah.
Yeah.
Thank you.
For this one, I think two parts
For the 29th standard, right?
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believe most of the -- especially for the voltage part,
2
pretty much align with the IEEE 2800 standard, yeah.
3
think for frequency part, yes, actually there's some
4
division, right?
5
this -- even within the Standard Draft Team, that's the
6
ideal -- the approach we adopt so far.
7
I
So for this issue, I think even for
For this Technical Conference, one of the main
8
purpose for that -- for this conference is, like, we
9
discuss the frequency part, right?
I think for that
10
part, actually, we have that dedicated topic to discuss
11
that one, yeah.
12
even for wind manufacturer, right, if has any not issue
13
or concerns with that -- with that standard or the
14
requirement, yes, we -- the Standard Drafting Team
15
really want to hear the voice, yeah.
16
the main for this one.
17
If the OEM even for the for BES or
That's the one --
For the second one, for the -- for the testing
18
procedure, right?
19
is working on that testing procedure.
20
still ongoing efforts, right?
21
Team has very closely participate that -- the working
22
groups.
I know the IEEE standard, the 2800.2
I think it is
The Standard Drafting
Actually, we just adopt that approach maybe in
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the future for the -- for NERC standard, right, for 29
2
or even the future, the revisions, yeah, for sure we
3
can adopt that approach in the future.
4
point, I think even for the IEEE 2800.2 is still
5
ongoing efforts, yeah.
6
to bring the attention to the team, yeah.
7
MS. CASUSCELLI:
But at this
So that -- I think I just want
So we've got a number of
8
questions online.
9
Could you share the evidence or data that NERC has
I'm just going to interject here.
10
indicating that the bulk power system might experience
11
frequencies up to plus or minus 4 hertz per six
12
seconds?
13
MR. AL-HADIDI:
Even we don't -- we cannot present
14
information for even the current -- whatever their IEEE
15
standard, which is the 57 hertz.
16
don't have an event because once event or under -- or
17
once event is very rare event.
18
happen, you need to have a system, really, which can be
19
very robust and very reliable to deal with it because
20
when it happen, there's a blackout.
21
big system event to start with.
22
-- where we are right now in the system, based on where
So the evidence, you
When it -- when it
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So really, likely the
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we are and hopefully -- and that's where -- that's
2
where our standard is moving, at least hopefully, to
3
prevent us from being to that stage.
4
there is no event happen to support even any frequency,
5
even 57 hertz, which is there in IEEE standard.
6
-- we cannot -- we have no event to support that in
7
overall system.
8
MS. JONES:
9
So no event --
It was
Thank you.
Hello.
Rhonda Jones from Invenergy,
and just building upon then some -- like, when you look
10
at the 10 system disturbance events that were used in
11
the analysis, it never came below 59.
12
when the widened bands were established to also -- they
13
considered current-day needs and a little bit of
14
projection or forecasting for future needs.
15
things that I'm trying to work to reconcile is,
16
currently, right now, the interconnection dynamics were
17
considerations when you set -- when the bands were set
18
in the past.
19
were considered now just having one big band that
20
covers everything versus consideration for tailoring
21
the bands based on the interconnection dynamics.
22
So just curious
One of the
And I'm curious how those unique dynamics
MR. AL-HADIDI:
Let me see if what -- if I
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understand your question about the reaction of the IBR
2
or to -- how to recover from the frequency itself, and
3
that's why the six second was giving the IBR time to
4
respond to the frequency and try to -- because it has
5
some time response.
6
come with a performance requirement, so it could be
7
performed within four second, five second.
8
faster than synchronous machine to respond to the
9
frequency event, so hopefully that in the future will
And in our standard, we did not
It's much
10
be able to recover the frequency much faster.
11
why we thought the six second itself is the time where
12
it give enough time for the IBR technology to inject or
13
remove power from the system to respond to the
14
frequency event itself.
15
question.
16
That's
I'm not sure if I got your
Sorry if I did not get it.
MS. JONES:
That was part of it, but I think the
17
biggest thing I'm trying to understand is that the mix
18
of generation in a specific interconnection does impact
19
inertia and frequency performance.
20
MR. AL-HADIDI:
21
MS. JONES:
22
Yeah.
So I'm just wondering consideration
for bands that are more accustomed to the dynamics of
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an interconnect versus just a broad, no matter where
2
you are, this is what you need to do because there is
3
some benefits to having it tailored in that way.
4
know, when you look at the events in the East versus
5
the Western interconnect, the evidence is very distinct
6
on where the concentration of some of those misses
7
were, which are primarily contributed to settings,
8
which is human error versus not being able to perform
9
enough.
You
Was just kind of curious about maybe tailoring
10
the curves more to interconnection dynamics and
11
generation mix as opposed to just a one-size-fits-all.
12
MR. AL-HADIDI:
That could be an approach we could
13
-- we could use.
14
that.
15
still -- there is a lot of unknown, and we know that
16
systems going to change, and the way it change is going
17
to be more and more sensitive to the frequency event.
18
Load itself is significant.
19
too much IBR load technology, which is going to come
20
in, and some of these one actually the trip themself or
21
remove themselves at certain voltage.
22
removing significant amount of load on and off, that
Actually, there's nothing wrong with
It's the only thing which -- in my opinion, it's
It's going to -- we have
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will generate fundamentally very significant frequency
2
change.
3
So really just to be careful where -- we thought
4
we are -- a second part of discussion where the
5
industrial is heading.
6
there is no actual limitation, what's the harm of
7
getting there?
8
and it meets some reliability in the future and even
9
some into the system, we thought there is maybe no
Is it something which we --
if
There is -- if the cost is reasonable
10
harm.
11
goes with input from the OEM about if there's a concern
12
or not.
13
But if that's not case, we'll see how the thing
Thank you.
MS. CASUSCELLI:
14
from online here.
15
in the measures?
16
17
18
19
20
Thank you.
One more question
Can you discuss the data requirement
MR. AL-HADIDI:
Sorry.
We didn't get the
question.
MS. CASUSCELLI:
Can you discuss the data
requirement in the measures?
MR. AL-HADIDI:
Data requirement is already
21
established in the PRC-028, so PRC-028 established data
22
requirement for the measurement
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MR. VENKITANARAYANAN:
Morning.
My name is Nath
2
Venkit, and I'm from GE Vernova, and my question is on
3
the -- on the requirement that inverter-based-resources
4
should not trip on instantaneous overvoltage, which I
5
completely agree with.
6
individual inverter-based resource units, based on the
7
language in PRC-029 -- I believe, it's footnote -- or,
8
you know, Note Number 10 in Attachment 1 -- should have
9
a filtering for one cycle before they trip.
10
But the concern is that
Now, I was part of the Drafting Team for IEEE
11
2800, and this was discussed pretty extensively, that
12
standard.
13
kind of long duration overvoltage capability.
14
compromise that was established in IEEE 2800 was that
15
the one cycle filtering requirement was applied for any
16
protection at the plant level that would -- that would
17
disconnect the entire plant.
18
an overvoltage relay, then you would need that kind of,
19
you know, filtering.
20
IBR-powered electronics do not have that
So the
For example, if you had
However, for IBR units themselves, the standard
21
did not just give them a blanket exemption.
22
specified sub-cycle overvoltage Ride-through
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requirements that individual IBR units had to
2
withstand, right?
3
one cycle before you trip for any overvoltage, but a
4
more rational requirement for sub-cycle overvoltages.
5
For example, the IBR unit would need to Ride-through
6
and overvoltage of 1.8 per unit for one millisecond.
7
So that's one of the requirements in IEEE 2800.
8
9
So it wasn't a requirement to wait
So the way PRC-029 is written, I think we really
have only two choices, right?
If you have a very large
10
overvoltage that is imposed on power electronics, then
11
you can let the inverter trip, protect itself
12
hopefully, and come back online within a few seconds or
13
a few minutes, or if you don't allow it to trip, then
14
the choice is the inverter gets damaged, then trips and
15
will take several months or years before it can come
16
back online.
17
requirement not more specifically calling out sub-cycle
18
overvoltages for individual units to withstand?
19
So I would -- my question is, why is the
MR. AL-HADIDI:
We were there first.
We have --
20
it used to be in this Draft Number 1.
21
R4, we're dealing with the transient overvoltage.
22
However, we were -- basically even -- whatever we see
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right now in IEEE standard, they are having very
2
difficulties would -- come with some mechanism how even
3
to do the measurement and calculation for this
4
transient overvoltage, and we felt that the industrial
5
is not in the stage where it could have that -- the
6
work based the PRC-028 and how the mechanism, how to
7
calculate it.
8
difficult to come with way to try to be measuring the
9
compliance of that event.
10
And it's -- we thought it could be very
The question will come, why the system -- why the
11
IBR is going to see 1.8-per-unit voltage?
12
because of the switching within the IBR itself with
13
some things a design issue, or is it from the system
14
event?
15
there's any system event.
16
transiently to 1.8 without impacting -- overall, you'd
17
be -- you'd be with the filtering time of even one
18
second one cycle, most likely that will lead to your
19
voltage to be fundamentally above 1.2, and we could
20
trip for the overvoltage.
Is it
If it's from the system event, I don't believe
The voltage can go
21
We had a struggle on the technology itself, how to
22
do the measurement, and that's why we feel there is the
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best way, try to move away from this requirement,
2
become very specific, become challenging to meet the
3
compliance part of it.
4
and to remove it.
5
to ensure that if it's a protection -- transient
6
overprotection, then you have to protect it in this
7
way.
8
arrestors.
9
it, able to deal with the overvoltage during --
And that's why we moved away
And we compensated with a filtering
But if it was internal issue, you have the
You have different mechanism to deal with
as a
10
result of a switching within the IBR facility itself,
11
so, and that's part of your design.
12
that's part of it, but we were mainly concerned about
13
the system event, and we did not see a way where we can
14
capture system event for that reason.
15
MR. WANG:
Yeah.
As a design,
I just want to add some
16
background on the -- on that requirement, yeah.
17
the IEEE 2800, right, that's the -- that transit
18
overvoltage specify at unit level.
19
that's the -- I think that's the requirement.
20
MR. VENKITANARAYANAN:
21
MR. WANG:
22
the unit level.
Yes.
So in
That's the --
It is at the --
For PRC-029, we didn't talk about
We just look at the POI, right, or POI
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in -- along with the IEEE 2800.
2
the Standard Drafting Team deal with this.
3
actually even the IEEE 2800.2, Subgroup 2 and 3, we had
4
very, very lengthy discussions, yeah.
5
that at POI, right?
6
transformer.
7
transformer endurance, the experience of that high
8
voltage, right, transient overvoltage, based upon the
9
BOP of the plant, it's very complex.
Another issue, we -For the --
If we supply
So let's do POI, the high set of
Even the -- even the high set of
The issue
10
actually to reflect back to the terminal, yeah, right?
11
That's the reason why we -- the Standard Drafting
12
Team facing in the -- for the challenges, right?
13
if we apply the highest -- high set of transformers
14
that, say, like 1.8 per unit high voltage, it's very
15
hard to identify what high voltage experience in a
16
terminal.
17
requirement to the Note 10 now, just based upon the
18
previous event analysis, right?
19
like, the
20
points, yeah, just trip off the units.
21
that's the base -- the rationale at this point, yeah.
22
Even
That's one -- another reason we remove that
We just avoid, say,
-- just like (inaudible) suggest one, two
MR. VENKITANARAYANAN:
Right.
Scheduling@TP.One
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That's the --
I understand, but I
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hope you understand there are only two choices.
2
the IBR trips to protect itself and comes back online
3
within a few minutes or seconds, or it gets damaged and
4
still trips and is not able to come back online for
5
several months or years.
6
question.
7
One is
So with that, I'll end my
Thank you.
MR. AL-HADIDI:
The standard didn't go that far,
8
and as I said, we don't have any measurement on the
9
unit itself.
Our requirement from PRC-028 is only at
10
the high side of the transformer, so there is no
11
mechanism to come with any compliance requirements for
12
it.
13
That's the reason we're -- where we are right now.
MS. CASUSCELLI:
All right.
So I need to issue a
14
two-minute warning here, so I apologize to those in the
15
room who can't ask their questions.
16
ask one from online here.
17
Drafting Team take to ensure that IBR owners do not
18
bear a disproportionate responsibility for system
19
frequency response?
20
MR. AL-HADIDI:
So I'm going to
What measures did the
You have to Ride-through it.
21
going to say they have to Ride-through it.
22
to Ride-through it.
I'm
They need
So it always need responses, same
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event, and their equipment needs to stay online, and
2
the standard is not requiring them, as written right
3
now at least, to provide a frequency support or any
4
performance.
5
maintain -- connect to the system and Ride-through the
6
event itself.
7
MR. HAKE:
So no performance compliance is just to
Hi.
Sam Hake with a AES Clean Energy.
8
We're a renewable energy developer, and I'll try and
9
keep this quicker.
It's a little bit less of a
10
technical question.
11
language in R4 that talks about hardware-based
12
limitations.
13
sites that may have -- we may need exceptions based
14
more on modeling information, either availability or
15
quality of the models, in order to demonstrate and
16
determine if sites can be compliant.
17
is, why is there that focus on hardware-based
18
limitations in R4 that seems to exclude some, what we
19
believe, valid software limitations?
20
So I wanted to focus on the
We have some concerns that we have legacy
MR. AL-HADIDI:
So the question
It's for modeling or for the
21
voltage, Ride-through, you mean to say, because this
22
standard, it doesn't deal with modeling.
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misunderstood your question or maybe I -MR. HAKE:
So the language in R4 talks about
exceptions for voltage Ride-through --
4
MR. AL-HADIDI:
5
MR. HAKE:
6
MR. AL-HADIDI:
7
8
9
10
Yes.
-- based on hardware -Hardware limitation.
Yes, you're
right.
MR. HAKE:
Yeah.
So my question is why hardware
limitations only?
MR. AL-HADIDI:
Okay.
That also came from the
11
FERC order.
12
voltage exemption need to be based on the hardware
13
equipment, not the software.
14
are constrained with some language, so we -- and we
15
understood some -- and you're right.
16
could be very challenging to deal with, but we
17
understood by "software," if something could be dealt
18
with, if it's not really something which you couldn't
19
update different or upgrade your software, it become
20
really hardware limitation at that case.
21
22
FERC order stated very clearly that any
So we tried to -- when we
Some software
So we left it open, what do you -- what you guys
can come with the hardware limitation.
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In my opinion,
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if you cannot do anything about your software because
2
it's become hardware limitation where the version of it
3
or the -- is not enough or it's not in capability to
4
upgrade, it could become a hardware limitation, but
5
this is my interpretation.
6
That's my opinion.
7
MR. HAKE:
It's not NERC or FERC.
Thank you.
Right.
I appreciate that, and I think
8
that's exactly the concern, right, is that it's open to
9
interpretation.
10
MR. AL-HADIDI:
11
MR. HAKE:
12
MR. BENNETT:
Yes, you're absolutely right.
Thank you.
All right.
Thank you, everybody,
13
for the wonderful questions, both in the room and
14
online, but I think it's time -- we need to transition
15
to our next presentation here, but before we do, let's
16
-- our two friends here in the hot seat from the --
17
from the Drafting Team, why don't we just give them a
18
round of applause real quick?
19
job.
20
(Applause.)
21
MR. BENNETT:
22
They've done a great
So as they exit the stage, let me
just tee this up for Alex.
Our next presentation is a
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very similar subject, another review of voltage and
2
frequency Ride-through criteria.
3
this, this is Alex Shattuck from NERC, and yes, I did
4
pronounce his last name correctly.
5
help us out with this.
6
(Brief pause.)
7
MR. SHATTUCK:
So to walk us through
So, Alex, please
Do you need a microphone?
Thank you very much.
My plan today
8
was to present a bunch of objective facts.
9
like a bunch of y'all did your homework, and a lot of
It seems
10
what I'm presenting, we've talked about through the
11
questions and that kind of thing.
12
to just present some information and some data and some
13
observations without giving any opinions.
14
opinion by accident, sorry.
So the goal here is
If I give an
It's mine only.
15
I will read one recommendation.
16
to give a recommendation, but I'll read a
17
recommendation we've given to tell the story.
18
going to try to tell a little story here.
19
to keep this high level.
20
a little bit.
21
So with that, let's just start with the first slide.
22
So I'm not going
So I'm
I was told
We might beep into the weeds
It's a Technical Conference after all.
I figured since we're getting it started here,
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something to look at would be fun.
2
start with why do we need Ride-through.
3
the story quickly, the GIFs here are from Texas A&M's
4
kind of synthetic grid system.
5
voltage and frequency Ride-through.
6
with their kind of synthetic grid that they use at
7
their facility or at their university.
8
to kind of show, when there is a disturbance when
9
something happens, it propagates around.
So we're going to
Just to tell
They do heat maps for
They present them
So this is just
If you look
10
at the heat maps for frequency, it's not just one
11
disturbance.
12
-- you can see the differences in what's happening,
13
what deviations are happening based on location, based
14
on the system they're at.
15
It's moving all around, and it's really
And this is just kind of the world we live with,
16
right?
17
to happen.
18
job as an industry is to make sure that when they
19
happen, we are -- we've done our homework, right?
20
We've done it, we've done our planning, we've done our
21
interconnection studies, we've done our modeling
22
correctly.
Unexpected events, they happen.
They're going
They're going to continue to happen.
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Not every unexpected event is a major disturbance.
2
You know, someone hitting a telephone pole -- or sorry
3
-- utility pole and dropping a transformer is not going
4
to cause a massive frequency deviation, but something
5
like a -- an DESO-1 or DESO-2, we've seen, or a Uri,
6
right?
7
deviations to the point that we have literal processes
8
for tracking these things and reading these things and,
9
again, reports out our disturbance reports.
10
We've seen unexpected events cause significant
So what do we do?
We have to make sure that we
11
reduce risk by making effective and efficient criteria.
12
Efficient is kind of the -- I took this from our little
13
circle.
14
could probably make a system that is perfectly
15
reliable, but that's going to be a tank when we might
16
need a Toyota Camry, right?
17
there's always that kind of how much can you do with
18
something that's reasonable or something that's
19
efficient, and how do you hit your reliability with a
20
certain level of risk averseness, which probably isn't
21
a word, while still making sure that we're not making
22
everyone pay thousands of dollars a month for their
Efficient is the key thing here, right?
We
We can -- you know,
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power bill.
2
So next slide, please, Levetra.
3
We'll start with just -- or I guess we'll continue
4
with talking about what we've seen so far.
5
we have 10 published major disturbance reports since
6
2016.
7
years have been about 10,000 of those megawatts, so --
8
and about twice as many events.
9
windows of time, we've doubled both size, total size,
Right now
That's about 15,000 megawatts, and the last four
So if you look at two
10
and we've doubled the frequency of these events, which
11
means they're probably -- they're linked a little bit.
12
The observations point to the fact that they're linked
13
to penetration of IBR, right?
14
little graph on the bottom left, you can see the
15
events, right?
16
now have some of the highest penetration of IBR.
17
disturbances, those reports, those are -- those 10
18
reports are IBR related.
19
those since those last ones are out.
20
kind of data collection stage for those.
21
22
If you look at the
They're happening in areas that right
Major
There's been a few more of
We're in the RFI
But that's not the whole story, right?
also different technology.
There's
So the major events so far
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that we've given major event reports for have been
2
solar PV and BES.
3
only folks that have problems, right?
4
technology's relatively similar outside of the hardware
5
piece, right?
6
a lot of if I do something wrong parameterizing a PV, I
7
probably make that same mistake, parameterizing a wind
8
turbine in the software parameter sense, and we do have
9
some data to back that up.
That's not to say that they're the
Most IBR
There's software based, software driven,
NERC is working with Texas
10
RE and ERCOT to make a wind report that shows and links
11
to the causes of reduction of those previous
12
disturbances.
13
hasn't been a major disturbance that was a wind -- I
14
guess there was a panhandle disturbance, but there --
15
other than that, there haven't been that many wind-
16
related disturbances.
17
So that's to say that just because there
It's not to say that the wind has no risk
18
associated with it.
19
top of my head numbers for that, it was something about
20
80 percent of the multiple thousands of megawatts
21
unexpectedly tripping off wind in Texas, about 80
22
percent of those or 90 percent of those were for the
Just preliminary, kind of off the
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exact same reasons that we presented in all of the
2
solar PV and BES reports.
3
up?
4
night, right?
5
wind isn't operating at full capacity like PV is.
6
have a hundred-megawatt PV plant and a hundred-megawatt
7
wind plant in the middle of the day, the wind plant's
8
probably half-ish and the PV plant's at max.
So why are they not showing
Well, they're kind of, you know, it could be at
The faults happen during the day.
Maybe
If I
9
So the same disturbance trips both of those off,
10
same size plant, but the event for the PV is twice as
11
big, right, because it's actually operating at max.
12
outside of those, we also have Winter Storms Uri and
13
Elliot as far as, like, firm data we can pull from, and
14
just those are the Uri and Elliot on the right side
15
here.
16
So
So if you go to the next slide, please.
All right.
We'll orient ourselves with what I
17
realized -- it's actually pretty clear.
18
orient ourselves with what is out there right now, so,
19
and what we're discussing today.
20
it to PRC-024, PRC-029, the draft criteria right now,
21
and IEEE 2800, and they're all in the same graph here,
22
and it's kind of a mess, right?
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someone brought it up -- PRC-024 four has regional
2
variances for -- different requirements for different
3
areas, right?
4
029 and, you know Quebec's PRC-024 curve, they're
5
pretty similar, but again, that's for a specific system
6
with specific needs.
7
If you look at, you know, the draft PRC-
And also the mess of this, it's confusing, right?
8
It's hard to look at that -- you know, if I'm -- if I'm
9
interconnecting a facility, and I want to do it across
10
the United States, and I want to be a developer, it's
11
kind of confusing to know, you know, exactly where to
12
find each criteria, exactly how to do each plant in
13
each area and how we talk to each other.
14
alert data, what we saw a lot of in ERCOT specifically
15
was ERCOT machines have Western interconnection
16
parameters, right, because they're similar developers,
17
and they just put them on that one, right, because
18
they're not the same.
19
there will always very likely need to be some sort of,
20
you know, small variance or something to make sure that
21
everything's reliable for everybody.
22
isn't any one-size-fits-all anything for everybody, but
Reviewing the
Unifying them can help, but
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if you have a good starting point, we can adapt that to
2
what we need for reliability.
3
of help with the rest of the slides and the
4
comparison --
And what I did to kind
5
If you go to the next slide, Levetra --
6
I realize that's a typo.
I wrote "most
7
stringent," but it's least stringent.
8
inside of every curve to basically say if you were
9
following the minimum or the least stringent PRC-024,
I took the
10
that's what we're comparing the rest to.
11
talk about the events coming up, that's what we'll use
12
to kind of use for a barometer.
13
to look at these three curves versus, I think it was
14
like nine on the last one.
15
And when we
And it's much easier
So when you look at this kind of comparison,
16
you'll see that -- a couple observations, right?
17
PRC-029 and IEEE 2800, they share the same continuous
18
operation bands, so both of those standards are saying
19
that for these bands of frequency, continuous operated.
20
So that's an alignment that's good for the rest of the
21
discussion after reading all the comments that we've
22
gotten, but they deviate pretty significantly kind of
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specifically at the maximums in the short timeline.
2
So, I mean, if you look at kind of farther out in
3
the 200-302nd range, we're not that far off.
4
pretty well aligned.
5
seconds where we see the massive deviations both from
6
2800 and from the original PRC-024.
7
8
They're
It's just this kind of first six
So if you go to the next slide, please, we can
compare that to our major events.
9
So y'all stole my thunder a little bit here by
10
doing your due diligence, which is great, but none of
11
the major events -- none of the 10 major events we've
12
released reports on were outside even the continuous
13
operation bands.
14
very small, very skinny yellow rectangle, that is the
15
worst frequency deviation and time out of all of the
16
events, and that's Blue Cut in 2016.
17
that's well, well within both PRC-024, within the
18
continuous operation bands, and it's well within both
19
PRC 2800 -- or sorry -- IEEE 2800 and the draft PRC-
20
029.
21
22
And if you look at the little -- the
And you can see
So this kind of shows us that for those types of
events -- you know, keep in mind that these disturbance
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events happen somewhere around like system normal,
2
right?
3
expecting to see a massive crazy change here.
4
system's about normal when these are happening.
5
what we get, because operators are doing their jobs
6
well, because we have things to do and procedures to
7
mitigate when these events happen, the deviations
8
aren't that bad, at least from what we've observed.
9
Things will change as we change penetration, but we'll
So we might not see -- you know, we're not
The
So
10
have to assess the risks and how we get there and how
11
we can kind of guess or study or estimate what they
12
will need in the future.
13
major events.
14
many of them were, you know, in the order of 10 to 30
15
seconds or something like that, so about the same
16
rectangle shape but much, much smaller on the graph.
17
So this was system normal,
Again, this was the worst case.
Very
So all I have to say is that when we observe our
18
major disturbances, we've got a little bit of leeway
19
with everything proposed so far.
20
right up against anything at the moment, but all
21
solutions seem to be viable as far as riding through
22
the major event reports.
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So if you go to something on the next slide, which
is, you know, not system normal.
This Uri and Elliot.
They're bigger, right?
4
rectangles are bigger.
5
same-ish as the major disturbance reports.
6
Cut graph very skinny, not a very large deviation,
7
somewhat long-ish.
8
right?
9
The
Elliot was, again, about the
So the Blue
But the interesting thing is Uri,
So Uri, if you notice, it kind of kisses the
10
purple curve there, and that corner of the purple curve
11
is actually ERCOT's frequency Ride-through, so we were
12
very close.
13
protection things directly on the curve, like we
14
observed quite a bit of in the alert data.
15
very, very, very close to seeing additional tripping
16
because of frequency protection on the criteria, so,
17
and if that would've happened, that would be the first
18
time we've observed it.
19
I'd say folks are starting to put
We were
The last slide -- you don't have to go back --
20
what the last slide said -- I said nearly all
21
frequency-related tripping was due to mis-operate --
22
not mis-operations, but incorrectly set parameters,
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instantaneous measurements.
2
"nearly" on the slide to cover it, but none of those
3
were based on criteria.
4
too, that they weren't anywhere close to the criteria.
5
None of those -- I wrote
You can see on the last graph,
So at this point in the past, right, the bounds,
6
we haven't gotten close to the bounds of any of things
7
that we're proposing now, except for 2024 in Uri, and
8
Uri was a massive, massive event, right?
9
we're at a point now with this data that, you know, we
10
might know that we might need to improve upon PRC-024.
11
What we do to improve on 24 comes from all the input
12
we're going to get from our panelists, the OEMs and
13
their capabilities from the system folks in what they
14
want or need or desire, and what kind of information we
15
need to show that, hey, I can't do this and I'm going
16
to prove it to you or not, or what's sufficient proof,
17
or how do we study things moving forward.
18
So maybe
So all of this can hopefully -- I'm trying not to
19
get into too many details.
20
tell us all the things from their mouths, different,
21
from them.
22
our data, it's not a ticking time bomb.
I want the panelists to
So this is just to show that if we look at
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time bomb in construction, right?
2
an immediate tomorrow problem, but it's maybe a
3
something we should focus on moving forward.
4
again, both things we're proposing, or, you know, we're
5
talking about through all the comments, the main topics
6
we're talking about are 2800 and PRC-029.
7
those would have, you know, written through these
8
events.
9
It's a -- it's not
But
Both of
So if you go to the next slide, please.
10
Just to summarize, none of the events we analyzed
11
were outside of the continuous operation bands.
12
the next bullet is something a little bit interesting,
13
is that because of that, we have no benchmark event,
14
right?
15
know, they say you make benchmark events.
16
an event or look at a past solar or flare event and see
17
what's happened and use it as a basis for, you know,
18
setting up your parameters.
19
benchmark event, right?
20
of them are saying what you have right now is
21
insufficient.
22
on.
And
When we did the GMD standard, they had -- you
So think of
So we don't have a
We've had disturbances.
None
So we don't have anything to base that
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So, you know, say we had an event that was exactly
2
the PRC-029 proposed curve, then that's great, right?
3
We say, hey, we saw an event.
4
Our bounds need to be outside of this event.
5
say online, well, the operators do their jobs and fix
6
the system.
7
so with that, there's kind of three ways, right?
8
a benchmark event, it's doing detailed studies into the
9
future, or it's saying that give us the best you can do
We witnessed this event.
We don't have that.
So we all
We've also seen
-It's
10
until we either hopefully never get a benchmark event
11
or improve our study practices and data practices to
12
have some meaningful forward-looking studies.
13
So looking at the data we're receiving in our
14
Level 2 alerts, both modeling and IBR performance, and
15
kind of the fact that none of the 15,000 megawatts that
16
tripped offline were predicted in the model space, I
17
don't know at the current moment if the industry's
18
ready to say, hey, here's a study I'm going to hang my
19
hat on that says here is the level of frequency Ride-
20
through I can get my system to do and use it as a
21
benchmark event, right?
22
modeling, improve our studies, improve our
We need to improve our
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parameterization, and then maybe we can trust that for
2
something as important as setting these things.
3
So what you can do now is you have kind of two
4
things.
5
possible and show us that with data and not, like --
6
you know, show us that literally if you exceed this,
7
you'll burn, right, or come offline or damage
8
something, or come up somehow with some criteria that
9
happens to be able to be accomplished by everybody,
Either set your protection settings as wide as
10
right?
11
we take as far as, like, putting some data-driven
12
decisions there, right?
So at this point, those are the branching paths
It's maximize --
13
And if you go to the next slide, please.
14
Maximize your settings or use those and feedback
15
and that kind of stuff, just come up with bounds that
16
are reasonable for everybody.
17
to meet them, but if we have criteria where the number
18
of folks who can't meet them is a number that we're
19
happy with -- or not maybe happy with, but okay with,
20
you know, operating the grid width, then we're moving
21
the industry forward, right?
22
Maybe some will be able
So this is a recommendation from our Level 2 alert
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on IBR performance issues, and I'll read this and then
2
I'll tell you where it came from.
3
what we're saying is expand your voltage protection
4
setting as widely as possible and minimize AC
5
instantaneous voltage dripping.
6
pieces of both of those bullets, there's language in
7
the standard addressing those things.
8
frequency and voltage protection should be based on the
9
equipment capability.
And so, basically,
So the instantaneous
But again,
We've been saying this in the
10
alert.
11
is actually a recommendation that was in Blue Cut, the
12
very first disturbance report.
13
recommendation to expand as much as you can since the
14
first event.
15
The reason why it's in the alert is that this
It's been a
So it's very important to maximize your
16
capabilities as you can because, otherwise, you know,
17
you're leaving things on the table, right?
18
make any sense to, you know, have a certain frequency
19
Ride-through or voltage Ride-through ability and then
20
set your parameters, you know, 30 percent inside that
21
curve, right?
22
for that.
It doesn't
You're not helping anybody on the system
So that's why this recommendation is here.
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This is the recommendation I was reading.
2
published, so it's not my opinion, and, again, repeated
3
in basically every disturbance report and the alerts.
4
And it's not in the modeling alert, but it's been
5
repeated, and it's kind of what we're saying is a good
6
path moving forward.
7
So next slide, please.
8
So what do we do, right?
9
right?
It's
You got to balance,
There's balance between what the system needs
10
to be safe and what you can do with the things that are
11
out there on the system, right?
12
two into a -- the Venn diagram I made, hopefully, if
13
you use technical capabilities to inform what you can
14
do to meet bulk power system needs, then you get
15
effective and efficient criteria, right?
16
power system says I need 80 hertz per 10 seconds, and
17
the IBR says I can only do 75 hertz per 10 seconds --
18
I'm picking random numbers to not get close to anything
19
we're talking about -- then you got a problem, right?
20
And then you would ask, hey, how many of you folks
21
can't meet this, and you get a number, and if that's
22
the whole system, maybe that's not a good criteria.
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If the bulk
If
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it's 10 percent, maybe you can live with that, right?
So when we talk about bulk power system needs,
3
what are they, right?
4
can fix it, right?
5
their jobs and restore the system, and be effective and
6
efficient when we're reducing risks.
7
things in 901 data, modeling studies, all that kind of
8
stuff.
9
high level and in two bullets only, and then you have
Ride through things so that you
Stay online while the operators do
So that's all the
Those are the bulk power system needs, very
10
to compare those things to how do you get that, right?
11
If I have a new criteria and I see you must meet this,
12
how soon can you put something on my system that meets
13
it, right?
14
That's something that OEMs will talk about, I'm
15
sure, is the development cycle for products, right?
16
Usually requirements inform design of IBR, right?
17
used to ask for requirements all the time when I was at
18
the OEM, you know, please tell me what you want so I
19
can build it and give it to you.
20
takes a while, right?
21
things, right, if we -- if every other year we have a
22
new kind of proposed thing, then it gets kind of hard,
We
The problem is that
And nd if you keep changing
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right, to make sure we're designing things.
2
keep resetting the cycle every couple years, we're just
3
kind of, you know, we're wasting money, you know, IBRs
4
become more expensive, power becomes more expensive,
5
and it's just kind of a big technical thing the OEMs
6
will really probably correct me on and expand upon.
7
And if you
Next, we also have hardware limitations at legacy
8
IBRs.
9
from all the panelists.
We're going to hear all about that, I'm sure,
The fact of the matter is,
10
some of it -- some of the IBRs won't be able to Ride-
11
through any criteria, right?
12
on the system now that don't meet PRC-024.
13
IBRs that don't meet PRC-028 -- or sorry -- PRC-029.
14
There are IBR out there that don't meet IEEE 2800.
15
whenever you have a requirement, if you look backwards,
16
there's always going to be some level of equipment that
17
can't meet it, and what do you do about that is kind of
18
the answers -- is one of the answers we're hoping to
19
get from the folks who are talking here.
20
There are IBR out there
There are
So
And the last bullet here is that you kind of get
21
some diminishing returns, the capability extremes, and
22
I kind of referenced it a little bit earlier, is if,
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you know, say we're all buying a car.
2
is 50.
3
someone says, well, you have to have a car that can go
4
a hundred miles an hour.
5
that can go a hundred miles an hour if the speed limit
6
is 50, right?
7
towards what about their requirements are, and if you
8
really expand those to the bounds of equipment
9
limitations, you know, it might be very expensive to
The speed limit
All the cars I can buy go 50, right?
But then
I'm not going to buy a car
So the products are going to be designed
10
get that last extra hertz, right, or extra hertz of
11
criteria, an extra couple seconds of time.
12
So really, that goes back to the effective and
13
efficient and reasonableness thing, right, is probably
14
if we set some parameters very wide, in a few years
15
after the development cycle, people could meet it, but
16
what does that mean?
17
turbine now because, you know, it costs $2 million to
18
get it to 63 hertz, but, you know, 68 might be some
19
crazy amount of engineering or design and all that
20
extra work.
21
it starts with the needs.
22
the needs, and then you have to balance it with what
Is that, like, a $10 million wind
So the balance here is very important, and
Basically, it starts with
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can I do and what can I do for some reasonable amount
2
of, you know, effort, resources, that kind of thing.
3
Next slide, please.
4
So for new equipment, so I'm going to talk about
5
new equipment, and then we'll go back to legacy stuff.
6
So for new equipment, criteria need to be reasonable
7
when compared to current and future capabilities.
8
if everybody's designed for one thing right now and we
9
go 10X that, it might not be reasonable, right?
So
If
10
everything's been designed for something, when we
11
change that criteria to expand it, we have to make sure
12
that it's at a level of expansion that keeps the grid
13
safe while also making sure that we're not putting --
14
we're not going to make things cost an extremely large
15
amount of money, right, because we're trying to meet
16
these future capabilities and that kind of stuff.
17
So if criteria are outside of equipment
18
capabilities, like we're -- we know we've gotten some
19
comments about from our written comment submittal, we
20
need lead time, or the industry needs lead time, right?
21
It takes time to build a new inverter.
22
to do research and testing and all that type of stuff
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to be able to build something that you can sell to
2
someone to install, and they'll still give me input,
3
but probably five-ish years, you know, a ballpark.
4
And again, testing time, right?
So you design it
5
and you build it, and then you test it to make sure
6
that it can do these things.
7
test systems in the world that can handle a, you know,
8
a giant wind turbine or a full-sized inverter.
9
there's lines from major companies to test these
There's not that many
So
10
things, so that also adds into the lead time necessary,
11
right?
12
show proof that you can do it, right?
13
proof of what you can do.
14
testing it and showing you Ride-through.
15
You got to build it and you got to test it to
We're asking for
You can't do that without
So the bottom bullet is in red, and we're leading
16
into the panel this afternoon, but input from
17
manufacturers is crucial, right?
18
who know what's in the box, right?
19
the box, they know how you got to what's in the box,
20
and they know what's possible within the same box and
21
what it means to build a brand new box, right?
22
their input is very crucial to kind of do the balancing
Scheduling@TP.One
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Those are the folks
They know what's in
So
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act that we need to do for the efficiency part of that
2
Venn diagram.
3
So next slide, please.
4
So for legacy equipment, we'll go very quick
5
through this because I want to leave some time for
6
questions, but there's a bunch of different things you
7
can do.
8
protection change, or software tuning to make your
9
Ride-through a little bit better.
So the easiest thing, software-based
For those folks who
10
had a 65-hertz capability and set their protection
11
setting at 63, software change, right?
12
capability that's in your software.
13
cheap and relatively easy to do.
14
sometimes it might not be, but it's significantly
15
cheaper than hardware based.
16
Put it to your
That is relatively
It could be free,
So hardware based has kind of two buckets, right?
17
It could be small, hardware-based retrofits of
18
equipment, maybe a new transformer, maybe something --
19
you know, a new smaller piece of equipment that's going
20
to be more expensive than a software-based solution,
21
but it's definitely going to be cheaper than repowering
22
the whole plant, right?
So that kind of nuance in the
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timeline of resources necessary from left to right,
2
that's going to be very crucial to hear from OEMs,
3
right?
4
thoughts about doing that?
5
could answer that.
6
know, at what point does a retrofit turn into a
7
repower, right, and at which point does that mean
8
you're not going to operate your facility anymore?
9
Those are the types of balance and things that we need
What is a small hardware based?
What are your
Maybe the generator owners
What are you comfortable with?
You
10
to hear from industry and from the OEMs to give us this
11
information so the Drafting Team can update the
12
language to make sense for all of us.
13
So again, I think this is the second of three
14
times I wrote that.
15
critical, right?
16
documentation, having it ready for folks to read and
17
review, very important.
Manufacturer input is very
Diesel documentation, sharing the
18
So next slide, please.
19
And this is my engineering slide.
There's no
20
pictures, and it's four bullets and, you know, four
21
sub-bullets, five sub-bullets.
22
big text wall for us.
Figured we'd want one
So are exemptions necessary?
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I'm going to really leave this up to everyone else to
2
talk about, and I would just keep it real high level.
3
So we all know some amount of IBR may not be able to
4
meet any of the proposed criteria or current criteria
5
because they were installed before current criteria was
6
made.
7
path -- simpler path.
8
are needed for software upgrades are not sufficient, so
9
if I can't just set it back to whatever, what else can
Again, software-based upgrades could be a simple
10
I do?
11
That's very important.
12
Additional considerations that
How do we do it?
We need to put for that.
But the third bullet here is that exemptions could
13
allow legacy equipment to remain connected while
14
maximizing capabilities, but then there's like a giant
15
burden of proof for that, right?
16
more than someone saying, my manufacturer said they
17
can't, right, and they attested to this, right?
18
probably not sufficient as far as documentation, right?
19
We're looking for things like show us a curve that, you
20
know, shows you're going to damage something.
21
documentation that your software-based protections
22
aren't sufficient, right?
It's going to take
That's
Give us
New software can't go into
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old equipment maybe sometimes.
2
limited.
3
capability, right?
4
Maybe it's firmware
Maybe they're already set at their maximum
And then we need someone to be able to review
5
these to assess risk and to basically see if they're
6
true, right?
7
and they won't give you any documentation, then it's
8
hard for us to take that as, you know, a firm piece of
9
validated data to make a massive decision, like
10
changing Ride-through parameters for everybody.
11
what we can say, and I think this is pretty not
12
contentious, is that, you know, blanket exemptions with
13
nothing, right, blanket exemptions for everybody who
14
asks for one is likely not as sufficient solution,
15
right?
16
leads us to that path, which they may or may not,
17
they're going to have to come with some data to back it
18
up.
If someone says, hey, I can't do that,
So
So exemptions, if we get there, if the input
19
So next slide, please
20
So we do have some data.
21
Level 2 alert for IBR performance.
22
was just solar PV and BES, and I realize that the
The data is from the
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numbers are super small.
2
data is that about 70 percent-ish of those folks who
3
gave us their frequency protection settings said that
4
they were not based at the maximum hardware capability.
5
So we have reported data that says about 70 percent of
6
the IBRs out there right now can do some sort of
7
software-based something.
8
something big enough to meet PRC-029?
9
manufacturers will tell us.
10
11
So the first piece of the
Is that software based
The
So we do have some room to
make some adjustments.
What we also have is they gave us their protection
12
settings for their inverters, and I didn't want to
13
give, like, real megawatt values, but I put them in
14
percentages.
15
that were given to us where they said that they were at
16
their maximum capability, and I'm going to walk up here
17
and read it because I can't see.
So this pie chart is all of the settings
18
So if you look at this thing, this is the -- all
19
of them are within maximum capabilities, and we start
20
with PRC-024, so this is the small blue chunk.
21
percent of what's been reported to us is within PRC-
22
024, so current requirements, about seven percent are
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reported inside that.
2
percent of those inverter settings are within 2800,
3
which means that, if the data is true, right, if the
4
data they gave us is right, and they're at their
5
maximum capabilities and that's what they're at, then
6
we got about 30 percent of what's out there right now
7
within 2800, which is somewhat actually in line with
8
the data we got back from some of the folks who
9
submitted that to us in writing with real numbers.
10
The next biggest chunk, about 32
So the big chunk is things that are within PRC-
11
029, right?
12
within PRC-029, and that makes sense, right?
13
make the curves wider, fewer and fewer equipment are
14
going to be able to meet it, right?
15
things wider, we'll have to -- we're going to have to
16
deal with a large number of potential hardware-based
17
solutions.
18
in the spectrum of curves is going to be dependent on
19
what we can do, what we're happy with not meeting
20
criteria and what we do with those things.
21
22
Sixty-one percent of the total maximum are
As you
So as you make
And what that number is and where we land
So this is just to kind of quantify and to show
that it's very important to pick the right, you know,
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criteria so that we don't end up with, you know, a
2
circle that says a hundred percent of equipment can't
3
meet it, right?
4
to pick -- the onus is on us the Drafting Team and as
5
an industry to pick some criteria that we are happy
6
with the things meeting and happy with the things that
7
can't meet.
8
know, documenting limitations and providing that as
9
evidence to be used for drafting decisions, right, and
10
We don't want that at all, but we got
And potentially, like we've discussed, you
that kind of stuff.
11
So next slide, please.
12
I'm going to go very quickly so we have some
13
questions time.
14
going to talk about it in a moment or after lunch.
15
new IBR, what criteria to build for?
16
procure test locations?
17
at the extremes, right, the capabilities get really
18
expensive, right?
19
expensive.
20
software solutions might not be sufficient, and legacy
21
equipment was tested with applicable criteria in mind,
22
right?
So manufacturer challenges, they're
So
How do you
Long lead times.
And again,
The extremes of anything get really
For legacy equipment, hardware limitations,
So there's actually a decent number of stuff
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out there that we don't know what the -- we don't know
2
what it can do because it was tested for PRC-024 or
3
slightly more than PRC-024.
4
It's never been tested and it's likely that it's
5
never going to get tested, right?
6
you know, take down a wind turbine and drive it to
7
Europe or maybe been a boat or a plane, right, and put
8
it in a container and test it.
9
unknown there as well, and coordinating and
You're not going to,
So there's a lot of
10
implementing effective solutions is difficult,
11
obviously, right?
12
isn't -- has not been easy for any of us to kind of
13
agree on and get a solution ironed out, so it's
14
difficult for all of us.
15
Next slide, please.
16
So industry challenges:
We're having this conference.
This
deciding which equipment
17
will be needed to meet new requirements, getting
18
evidence that equipment can or can't meet,
19
communicating technical details to everybody.
20
you do that, how do you post them, what are you
21
posting, and that's for new equipment.
22
equipment, how do you manage stuff that can't do it,
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For old
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right?
2
hard is it to get data?
3
learned through our two Level 2 alerts, both of which
4
had the first ever extensions of deadline, it's hard to
5
get data.
6
about today, protection settings, and we gave about 90
7
days, a hundred days for that, and we had difficulty
8
getting protection settings in that time.
9
How feasible is the software solution?
How
Apparently very hard.
We
And we were asking for things we're talking
We've extended the deadline again, so we feel
10
industry's pain.
11
get data.
12
technical.
13
get data that looks good, but it's wrong, right?
14
it's very difficult to communicate all of that forward
15
between all of us and to get to a solution where
16
probably no one's happy and then we'll know we did the
17
right thing.
We know it's a thing.
It's hard to
The data's really specific and really
If you ask the wrong question, you might
So
18
So next slide, please.
19
So key takeaways, another big red bullet at the
20
bottom.
21
manufacturer/industry input, extremely important to
22
know what we can and can't do.
I've said all this before, but
We are recommending or
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we have recommended for eight years now to maximize
2
your Ride-through capability.
3
validated and accurate is difficult to obtain but will
4
be critical moving forward.
5
Next slide.
Documentation that's
I think that's it.
Great.
And we
6
have eight minutes for questions, but it's my birthday,
7
Manish.
Be nice.
8
(Laughter.)
9
MR. PATEL:
Well, where is the party tonight then?
10
(Laughter.)
11
MR. SHATTUCK:
12
MR. PATEL:
We can talk later.
All right.
So, Alex, great
13
presentation.
14
compared PRC-024 with IEEE 2800.
15
right thing to do.
16
actually do is actually compare PRC-006, which is under
17
frequency load shed standard, and it requires
18
transmission planner/planning coordinator to design in
19
the frequency load shed programs, such that frequency
20
does not go beyond certain thresholds, right?
21
far as the generator Ride-through capability is just
22
outside of those thresholds, we are good, unless
So couple of thoughts.
You know, you
That is absolutely
And then another thing we can
Scheduling@TP.One
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And as
--
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there is a thought out there that, oh, wait a minute,
2
in future we are going to allow transmission
3
planner/planning coordinator to go beyond the
4
thresholds in PRC-006 right now, right?
5
this is another data point that, okay, if the
6
transmission planner and planning coordinator is never
7
going to allow frequency to go beyond certain
8
thresholds, then what's the point in requiring a Ride-
9
through from a generator, right?
10
So this is --
Okay.
So then you presented hurricane -- not hurricane
11
-- Winter Storm --
12
MR. SHATTUCK:
13
MR. PATEL:
14
MR. SHATTUCK:
15
MR. PATEL:
Uri.
-- Uri, right?
Mm-hmm.
So NERC's -- it's a good comparison.
16
I just wanted to point out that that is actually not
17
very appropriate because that event unfolded over many,
18
many, many minutes, right?
19
right, 30 minutes or so.
20
MR. SHATTUCK:
21
MR. PATEL:
22
I think, if I remember
Mm-hmm.
And actually, NERC System Protection
Control Working Group ended up writing a white paper
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saying, well, look, we cannot design PRC-024 or
2
PRC-006, which is automatic under frequency load shed
3
standard to something that happens over tens of
4
minutes.
5
things happening in matter of seconds where operator
6
has no time to blink, right?
7
comparison, but I think it's a little bit of apples and
8
oranges.
9
Those two standards, 006 and 024, are for
So anyhow, that was good
So anyhow, going back to we have to look forward
10
-- figure out a way -- for path forward, I think we
11
could take an approach that is taken in PRC-024 and 006
12
that, you know, for certain regions, the requirements
13
are a little bit more stringent than other regions,
14
right?
15
know, I was a vice chair.
16
nowadays.
So when we wrote IEEE 2800, those who don't
My middle name is 2800
I get bad rap quite a bit.
17
(Laughter.)
18
MR. PATEL:
And I'm also proud -- I'm also proud
19
sometimes saying that, you know, we didn't know what is
20
the right answer, so we flipped a coin five times and
21
decided which way to go.
22
2800, what we did was, well, we don't want to write a
But so when we wrote IEEE
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standard that is based on most stringent PRC-024,
2
right?
3
interconnections, assuming that for two other regions,
4
there might be a reason to require slightly more Ride-
5
through capability, and those two regions will write
6
their own variance of it, right?
7
option we could consider is can we take different Ride-
8
through capability for different regions.
9
was not a question, a comment.
10
We wrote a standard that met two largest
MR. SHATTUCK:
So I think that's the
I guess that
Thank you.
Thanks, Manish.
Yeah, there
11
certainly is precedent for having different curves.
12
It's in 024, and it is a possible solution to move
13
forward.
14
MR. KAPPAGANTULA:
Good morning.
I understand I'm
15
standing between everybody and lunch, so I'm just going
16
to make a quick -- a quick comment on one of the slides
17
that you had that talks about software changes are
18
being a little bit cheaper than hardware changes.
19
that may be true, but just understand that software
20
changes are not necessarily cheap.
21
MR. SHATTUCK:
22
MR. KAPPAGANTULA:
That
Mm-hmm.
As an example I could give you,
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just to make some software changes on one of our
2
battery projects, we got a code of nearly a million
3
dollars, right?
4
talking about something is cheap, it's probably going
5
to be relative --
And so when we're -- when we're
6
MR. SHATTUCK:
7
MR. KAPPAGANTULA:
Mm-hmm.
-- very relative.
So I just
8
wanted to point that out that, you know, just because
9
we're saying we can change software on some of these
10
things, that it's going to be cheaper is not true.
11
then you also have to factor in the points that, you
12
know, if you made a software change, you have to figure
13
out how the rest of the equipment would react to that
14
software change and if the rest of the equipment can
15
actually support, you know, making that software change
16
on just an inverter, for example, right?
17
wanted to make that clear and take into consideration
18
when we're saying, hey, software is really cheap.
19
MR. SHATTUCK:
20
MR. KAPPAGANTULA:
And
So I just
Yeah.
The other piece also is when
21
you're changing some parameters, that may not
22
necessarily be a software change.
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that goes into it, so let's not uniformly say that the
2
idea of, you know, we can make a few tweaks here in the
3
software and that's going to just do the job.
4
true.
5
It's not
That's what my technical experts are saying.
MR. SHATTUCK:
Thanks.
Yeah, everything was
6
presented as relatives, right?
7
us the details after lunch.
8
those folks, but they'll give us probably some real --
9
MR. KAPPAGANTULA:
And the OEMs will give
I don't want to speak for
No, I'm, I'm looking forward to
10
that, so I would rather hear from them saying, hey,
11
software is not cheap --
12
MR. SHATTUCK:
13
MR. KAPPAGANTULA:
14
(Laughter.)
15
MR. KAPPAGANTULA:
16
Yeah.
-- than me just saying --
us what you charge, too.
-- yeah, because you can tell
17
(Laughter.)
18
MR. ROGERS:
Yeah.
I'd appreciate that.
So real quick question.
You
19
showed us the curves that had the, you know, frequency
20
excursion events that we've witnessed within them and
21
plotted, and we touched up against one of them.
22
that was, you know, the actual, you know, what we
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witnessed with the frequency.
2
-- you know, one of the contentious points of this is
3
the rate of change of frequency.
4
MR. SHATTUCK:
5
MR. ROGERS:
But another part of the
Mm-hmm.
You know, we're looking at 5 hertz
6
per second in the proposed language.
7
witnessed in these events as far as rate of change, of
8
frequency that, you know, really drives to the need for
9
that 5 hertz per second because, you know, that's one
What have we
10
of the issues, especially with the legacy equipment.
11
Rate of change of frequency wasn't even a design
12
consideration.
13
high enough or the parameter's wrong.
14
thing.
15
know, it just wasn't a consideration.
16
looking at as far as an actual need based on the
17
evidence for the rate of change of frequency, or is
18
that even something that we have the evidence to speak
19
to yet?
It's not that, you know, it's not set
It wasn't a
Whenever a lot of this stuff was built, you
20
MR. SHATTUCK:
21
think I have that data.
22
recorded data.
So what are we
Yeah, great question.
I don't
I don't think we have that
We have the frequency traces, but it's
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that, like, SCADA data granularity, right?
2
-- a specific data point we don't have at the moment.
3
The only kind of information data points we have on
4
ROCOF is -- that's rate of change of frequency for
5
everyone else -- is, you know, international building
6
standards or equipment standards that are used in a lot
7
of IBR equipment facilities, right, the non-IBR pieces,
8
the transformers, the other pieces of equipment.
9
data point we have for those are the, you know, the
So that's
The
10
standardized ROCOF requirements, so, like, that's the
11
only thing we really point to because we don't have the
12
data from the actual events.
13
MS. CASUSCELLI:
All right.
I think we've got a
14
hard stop, but maybe time for one online question.
15
software expansion study and accurate models are
16
required.
17
are required and when they are often not able to
18
represent most IBRs?
19
So
How will NERC support when standard models
MR. SHATTUCK:
Great question, yeah.
So I would
20
-- I would like to point everyone to NERC's published
21
that modeling guidance, which says that if you want to
22
do something like a detailed study, right, an
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interconnection study, a study on your own facility to
2
evaluate your design, for a local reliability study, if
3
I'm Texas -- oh, that's a bad example -- that's a bad
4
example -- if I'm New York studying New York, we are
5
recommending user written models, equipment-specific,
6
manufacturer-specific models, we're aware, right,
7
obviously that many folks can't submit them.
8
not allowed.
9
2023, which says to submit both the standard library
They're
But I would point also to FERC Order
10
model and a user-defined model.
11
totally recognize that if we're using a standard
12
library model, we're not going to be able to represent
13
most of these things we're talking about, specifically
14
the detailed protections and that kind of stuff.
15
And, you know, we
So we're recommending to use those more detailed
16
models specifically for what was in the question,
17
right?
18
Nothing's been captured, right?
19
predicted, none of the major events.
20
that's why we have a modeling alert out right now,
21
right?
22
through, you know, proper use of more detailed models
We know that what's out there is insufficient.
Nothing's been
There is --
The idea is to raise the floor of study work-
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where appropriate, not to say that standard library
2
models have no place anywhere.
3
the result, if you want it to be accurate, if you want
4
to be able to take that study and put it into a product
5
or vice versa, you've got to use something more
6
detailed like a -- usually a defined equipment-specific
7
model.
8
9
MR. MAJUMDER:
Alex.
But if you care about
Rajat Majumder.
Thank you so much,
This is music to my ear, but I'll just make a
10
very quick comment.
11
be able to provide that.
12
major ISOs do not allow it.
13
problem.
14
room.
15
working with any of the leading manufacturers not being
16
able to provide the model.
17
are really tied with certain ISOs, and it's going to
18
that direction.
19
convince those ISOs that they should use the user-
20
defined model, not rely on the generic model.
21
please be aware of that.
22
It is the ISOs who are not allowing it to make that
You just said some people may not
The flip side is most of the
That's the -- that's the
I mean, manufacturers are on the -- on the
They can tell.
I haven't had much trouble
They can, but their hands
We have many problem trying to
So
It's not just from the OEM.
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happen.
2
MR. SHATTUCK:
3
MR. BENNETT:
4
Okay.
So it appears we've come to
the end of our discussion for now, so, Alex, thank you.
5
MR. SHATTUCK:
6
MR. BENNETT:
7
Will do that.
Thank you.
Great presentation.
Very
informative.
8
(Applause.)
9
MR. BENNETT:
So with that, we're here at noon
10
Eastern Time.
11
break, so we'll be back at 1:00 Eastern.
12
questions/comments, if we did get them addressed right
13
now, they are going into kind of an archive folder, and
14
we'll circle back to them at another point of our
15
Technical Conference over the next day or two.
16
they're not gone.
17
them, and we'll bring them up as appropriate.
18
19
We're going to take a one-hour lunch
They're not forgotten.
So
We have
And with that, I think we'll take a break.
Lunch
is just around the corner, and we'll be back at 1:00.
20
(Luncheon recess.)
21
MR. BENNETT:
22
As for online
Okay.
So I'm showing 1:00 here, and
it looks like we have most everybody back here in the
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room.
2
getting ready to start.
3
So for our online participants, I think we're
So this will be our first pan of panel discussion
4
of the day on "OEM Perspectives on Voltage and
5
Frequency Ride-through Criteria."
6
through that, we have Standards Committee member,
7
Charlie Cook, from Duke Energy, as well as Alex from
8
NERC here to help us through that.
9
turn it over to the panel.
10
(Sound checks.)
11
MR. COOK:
Good afternoon.
So to walk us
So with that, I'll
My name is Charlie
12
Cook.
13
I am here representing the Standards Committee.
14
As Todd said, I work for Duke Energy, but today
MR. SHATTUCK:
All right.
Alex?
My name is Alex
15
Shattuck.
16
because we're going to keep everyone on a two-minute
17
time per question, so making sure we keep track.
18
I'll get my stopwatch ready for everybody
So my name's Alex Shattuck from NERC.
You heard
19
from me just moments ago, and I guess we'll just jump
20
right in if you want to ask -- get us started with the
21
first question.
22
MR. COOK:
Yeah.
Could we have the panelists,
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starting down at that end, please introduce yourself?
2
Tell us a little bit about yourself and who you
3
represent today, again, keeping an amount -- I'm sorry
4
-- keeping in mind that we are time limited, so.
5
MR. SCHMIDT GRAU:
All right.
My name is Thomas.
6
I'm representing Vestas.
7
to 15 years, and I'm heading our Power Plant Solutions
8
Group that covers everything from development, sales,
9
construction, and service, and it includes every single
10
I've been with Vestas close
topic related to grid interconnection and reliability.
11
MR. KARPIEL:
Scott Karpiel, SMA America.
Been in
12
renewables for about 15 years with various different
13
OEMs.
14
knowledge and expertise to the panel and the committees
15
here today, and thank you for having me.
16
Hope to bring kind of a broad spectrum of
MR. KOERBER:
Arne Koerber.
I'm representing GE
17
Vernova, and specifically the wind side of GE Vernova,
18
and we also do other things.
19
team for controls and software, and a lot of the
20
discussion here today was around software and controls,
21
so that's why I'm here.
22
various roles around controls and software.
I lead the product line
Been with GE 15-plus years in
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MR. DAHAL:
9/4/2024
Page 140
Good afternoon, everyone.
I'm Samir
2
Dahal.
3
responsible for model integration, parameter rises, and
4
for all our (inaudible).
5
I represent Siemens Gamesa on source side.
MR. PATTABIRAMAN:
Hi.
My name is Dinish
6
Pattabiraman.
7
Corporation, Americas.
8
inverter-based resources, you know, meeting grid
9
requirements for various ISOs, and analyzing grid
10
11
I'm
I'm a development engineer here at TMEIC
I work on modeling of our
events and finding solutions.
MR. COOK:
Thank you.
So the way we're going to
12
do this today is I'm going to ask the first question
13
directly to an individual, and then I'd like
14
like the rest of the panels to pay attention and
15
listen, and then if you have anything significant to
16
add to what has been presented already, please do so.
17
We'll give you each chance to comment.
18
-- so I'd
So question one says, do you anticipate challenges
19
with your equipment meeting the voltage Ride-through
20
criteria as specified in Attachment 1 of the draft PRC-
21
029, and there are three subparts to that.
22
all being, if you do so, do you have an estimate for
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how many products will be affected?
2
does the estimate change when considering IEEE 2800?
3
Third part, how does the estimate change when you
4
consider PRC-024 boundaries?
5
question first to Dinish.
6
MR. PATTABIRAMAN:
Second part, how
So I'll direct that
So for TMEIC inverters,
7
especially inverters existing in the field, you know,
8
we won't be able to meet IE 2800 at this point.
9
newer inverters, we'll be able to meet IE 2800
For
10
requirements.
11
most inverters in the field can meet PRC-024
12
requirements.
13
be able to meet it.
14
we won't be able to eliminate parameterization for some
15
older generation products.
16
Coming down to PRC-024 requirements,
Newer inverters, obviously, we'll also
But in terms of parameterization,
For PRC-029, based on the language that is
17
written, none of our inverters will be able to meet the
18
requirements, especially given that there are
19
requirements such as instantaneous or voltage
20
protection should have at least one cycle of filtering.
21
That's something that we wouldn't be able to meet even
22
for all inverters.
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MR. COOK:
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Page 142
Starting down at the end, anything else
2
to add, specifically, would you or would you not be
3
able to meet the requirements?
4
MR. SCHMIDT GRAU:
5
MR. COOK:
Okay.
Repeat that one.
It says, do you anticipate
6
challenges with your equipment meeting the voltage
7
Ride-through criteria --
8
MR. SCHMIDT GRAU:
9
MR. COOK:
10
draft PRC-029?
11
Yep.
-- as specified in Attachment 1 of the
MR. SCHMIDT GRAU:
No.
Only for Type 1 and Type 2
12
turbines, which is very limited install base in U.S.
13
And we do see end of life cycle in the near future and
14
potentially be powered to different projects.
15
Type 3/Type 4 turbines, we anticipate to meet the
16
requirements for Ride-through requirements for PRC-029.
17
Those requirements are also aligned with the new design
18
philosophies and also with the IEEE 2800.
19
MR. COOK:
20
MR. KARPIEL:
Okay.
Thank you.
For the
Next, please?
So future, current, previous
21
generations of our inverter stations, I have no
22
problems with the voltage Ride-through.
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1
stuff that's going back 10 or so years, clips a little
2
bit of a corner on one of the Ride-through corners, but
3
then with the exemption, it shouldn't be a problem.
4
5
6
7
MR. COOK:
I'm Sorry.
about the exemption?
MR. KARPIEL:
Could you clarify that
What was that statement?
Well, does it not state for voltage
that there's an exemption?
8
MR. COOK:
9
MR. KARPIEL:
Yes.
Voltage, yes.
10
MR. COOK:
11
MR. KOERBER:
Yes.
Okay.
Just want to be clear.
Next.
Similar to my colleagues here, I
12
think we have to really split this between new products
13
that are under development and the installed base.
14
new products, plants are generally aligned with IEEE
15
2800, so we're evaluating what's the difference.
16
impact does that have for the installed base?
17
expect that the majority of the installed base does not
18
meet these voltage Ride-through curves.
19
might be close.
20
evaluation, voltage drops across the collector system,
21
it might be possible to meet it, but on paper and
22
curves taken strictly as stated, we do expect that the
For
What
We do
Some cases
In some cases with a project-specific
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majority of the installed base does not meet those
2
curves.
3
That's on the curve.
And then it's important to point out that
4
Attachment 1, Items 9 and 10 have additional
5
requirements that weren't previously requirements.
6
We've already had a quick discussion this morning on
7
the instantaneous voltage and on multiple fault Ride-
8
through, and we do expect both of those to be
9
challenges for the installed base.
10
MR. COOK:
11
MR. PATTABIRAMAN:
Thank you.
Yeah.
We have a similar
12
comment as our colleagues with G.
13
we can Ride-through the curves, just the curves, with
14
software, unlimited hardware upgrade, but items listed
15
in 9 and 10, multiple Ride-through instantaneous,
16
that's not something that we've been tested and
17
evaluated, so that would require a thorough
18
investigation from our part.
19
like it has been brought a couple of times, there is a
20
possibility for legacy turbine to be retested against
21
the newest standard is, I don't think that's going to
22
happen.
For legacy turbines,
And the testing part,
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MR. COOK:
2
MR. PATTABIRAMAN:
Okay.
3
exemption on those.
4
MR. COOK:
5
MR. PATTABIRAMAN:
6
Thanks.
MR. COOK:
8
MR. SHATTUCK:
10
But for the new lines, we would
completely design our product to comply with IEEE 2800.
7
9
We will have to ask for
right, here.
Thank you.
So I guess most of us are wind,
So we're missing our estimate
participant, but I guess, Dinish, since you're the --
11
(Side conversation.)
12
MR. SHATTUCK:
All right.
So for y'all's
13
perspective, like, what's the -- kind of similar
14
responses with some varied, you know, actual numbers,
15
but what are the main differences for kind of the
16
failure to meet or challenges between wind and solar,
17
you know, just the technologies as a whole themselves?
18
Like, I guess what are the limiting elements when we
19
say something can't meet one of the requirements?
20
it -- is it a software?
21
firmware?
22
Is it a hardware?
Is
Is it old
Is it a specific piece of equipment?
MR. KARPIEL:
So for PV and BES, battery energy
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storage, it's both, right?
2
limitation as to how long the holdup -- the backup for
3
the communications and everything can withstand.
4
whether they're using a battery, a UPS, a super cap, or
5
whatever they're using to have that buffer installed,
6
so that's a hardware limit -- that could be a hardware
7
limitation.
8
9
There's a hardware
So
And the other one is parameterization, right, the
software that's the firmware that's used in inverter
10
technology.
11
the different OEMs and legacy products here at SMA is
12
the firmware has a limitation of how far it will allow
13
you to Ride-through in amplitude and time.
14
usually set by some other kind of hardware limitations
15
so you don't damage the equipment.
16
necessarily for the wind side of things, but for the
17
inverters, the PDs and better energy storage systems,
18
it's a combination.
Amongst the experiences that I've had with
19
MR. SHATTUCK:
20
MR. PATTABIRAMAN:
That's
So I can't speak
Thank you.
Just to add to it, yeah, the
21
same.
22
and hardware for at least the Ride-through curves by
It's pretty similar reasons.
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themselves.
2
I think the gentleman from GE also brought this up
3
before -- the instantaneous overvoltage protection,
4
having one cycle of filtering is something our hardware
5
cannot do.
6
handling capability, so having a one-cycle requirement
7
significantly exceeds the capability of our products.
In terms of other requirements that are --
You know, IGBTs have very limited voltage
8
MR. SHATTUCK:
9
MR. DAHAL:
Thank you.
I would like that for wind especially.
10
You have so many components inside the turbine, right,
11
converter/inverter being able to do something doesn't
12
necessarily mean the turbine can hold can do it.
13
for us, software limitation is there, and there is also
14
hardware limitation.
15
because converter can do it, you know, we are not going
16
to be comfortable telling wind turbine as a whole can
17
do it, right?
So
For us to be certain that just
18
And also, when we are talking about software
19
parameter parameterization, we cannot forget about the
20
models, right?
21
parameterized or firmware get updated, corresponding
22
model is expected to be provided, and rightfully so,
Every time the software gets
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right?
2
operating for 20 years and no longer in design phase,
3
models were provided when they were first commissioned.
4
I don't think anybody actually started using those
5
models and providing feedback to us, so we saw no
6
reason to update those models.
7
turbine, we do not have any reason to keep them updated
8
since we never got a feedback on a -- if there is any
9
need to be updated.
For our legacy turbines that have been
Like, for the legacy
So all of a sudden asking not only
10
to change the parameters, but also provide the model in
11
a reasonable time -- updated model in a reasonable time
12
that works with today's simulation environment, it's
13
going to be a huge challenge.
14
but it's going to take a lot more than six month or a
15
year.
16
I mean, it can be done,
We have -- we currently have closer to 15, 16,000
17
units installed, right?
18
not have the same firmware.
19
right?
20
have some flexibility on changing the parameter as they
21
deem necessary, you know, based on their field
22
experience or what have you.
Each of those turbine might
I know it.
They don't,
And also, our customers or the assets owner do
That information we do
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not have.
2
provide a -- you know, to meet the new standard with
3
those software or, you know, hardware parameterized,
4
and I don't want anybody to forget that, you know?
5
Yeah, you can -- we can do it.
6
can be done in, let's say, a year, but getting our
7
corresponding model will take a lot more than that,
8
yeah, especially validating as well.
9
So there is significant challenges just to
MR. SHATTUCK:
Thank you.
Parameterizing software
The mic was off, but
10
they said, especially validating those models, and I'll
11
ask one more follow-up before we go to the next one.
12
Sorry.
13
Thomas, did you have something?
MR. SCHMIDT GRAU:
Yep.
No, and even if we have
14
the models available, often that's -- to Rajat's
15
comment earlier, ISOs and utilities don't allow those
16
models to be used that is accurately representing
17
studies for the -- evaluating PSE, so that's one of the
18
challenges.
19
software upgrades and pure parameters with our
20
software, but we are not able to do the evaluation of
21
what parameters are required for that specific site
22
because the utilities often don't allow us to use the
We have -- we, to some extent, can do
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right models for that evaluation.
2
MR. SHATTUCK:
Thank you, and I'll ask, I think,
3
the last question.
The end of this might be a little
4
faster, so we'll dig into some details here.
5
detail question.
6
inverter/converter in the turbine in the -- in the
7
inverter.
8
this is a -- you know, it's a resource standard, right?
9
The IBR must ride through, so are there challenges in
10
11
One more
So we talked about kind of the
What about balance of plant equipment?
So
balance of plant equipment as well?
MR. SCHMIDT GRAU:
Yes.
So if we look at the
12
frequency response, that's where -- there's no design
13
standards as we are aware of, that designs for
14
plus/minus 4 hertz per six seconds.
15
cooling systems and substations be affected.
16
all the different equipment and the turbines being
17
affected.
18
some flexibility, but we cannot forget all the
19
auxiliary component sensors, cooling systems, relays,
20
protections, transformers, that is not designed for
21
plus/minus 4 hertz per six seconds.
22
So you will see
It's not about the inverter.
MR. KARPIEL:
You have
Inverters have
And let's not forget the medium
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voltage transformer that comes with the inverter
2
station.
3
low frequency, you'll put your magnetics in the
4
saturation, right?
5
causes breakdown.
6
whole picture, the entire balance of plant to ensure
7
that the inverter-based resource unit -- I know there's
8
a lot of talk about what that definition is, but the
9
station itself needs to be able to ride through 299
Those situations that have high voltage and
Saturation causes heat.
Heat
So we have to be looking at the
10
seconds, 660 seconds of this voltage or that frequency.
11
And it has to be looked at by the OEMs going back
12
throughout all the legacy, all the generations of their
13
product, not just the current and future.
14
going to be some gaps that are going to happen in the
15
technology.
16
MR. DAHAL:
So there's
I also want to bring attention to the
17
concept of repower, right?
18
this and talking about repower.
19
seen so far have been efficiency driven, right?
20
repower happens because you want to get more power out
21
of the old turbine, not necessarily the electrical --
22
new set of electrical performance.
Like, we're talking about
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So
We retain the main
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brain converter/inverter system, cooling system as it
2
is, just change the rotor from the wind side.
3
the term, "repowering," doesn't mean what you guys are
4
thinking about repowering, you know.
5
you get new set of performances from them, and that's
6
not true at all.
7
happen.
8
has been purely mechanical repower, and it is very
9
essential to consider that as well.
10
11
12
So just
Oh, you repower,
The market is not there for that to
The repower project that we have done so far
MR. SHATTUCK:
Thanks.
Is that the same for
solar?
MR. SCHMIDT GRAU:
Oh, sorry.
Maybe also to add
13
to that, even if you do a full repower in a cell and
14
hub from one OEM to another, it's often older
15
technology that gets installed because the tower, the
16
foundation, and structure is not built for the latest
17
rotor sizes in inverters, so that even if you are able
18
to fully repower, it's still going to be legacy
19
equipment that's going to be repowered.
20
MR. PATTABIRAMAN:
Just answering the question on
21
the balance of plant equipment.
22
registers that are also included in the design of a
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typical IBR plant.
2
end of a feeder through wide overvoltages, absorb
3
overvoltages, and so on.
4
sites are already designed with certain energy levels
5
for these protectors and surge protectors, and any
6
level of higher overvoltage could physically damage
7
these protectors.
8
instantaneous overvoltage, like I said earlier, is
9
that, you know, having a one-cycle delay could
They're typically located at the
And the problem is that these
But that kind of also includes
10
basically be the difference between damaging and not
11
damaging these arresters.
12
MR. SHATTUCK:
Thank you.
All right.
I think
13
it's time to move on to our next question, which is the
14
same question, but for frequency but just one tiny
15
piece to add in is we mentioned transformer saturation.
16
There's other things that happen when the transformer
17
saturates, like harmonics or SSR, which aren't
18
necessarily this specific Ride-through, but they're not
19
particularly good, friendly phenomenon, so causing that
20
saturation somehow is not always great for the BPS as
21
well.
22
So we'll jump into the next question.
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the same question but frequency.
2
Arne, and we'll go down the line, but do you anticipate
3
any challenges with your equipment meeting the
4
frequency rate through criteria, as specified in
5
Attachment 2 of Draft PRC-029, and then the same kind
6
of sub-bullets, yeah, estimates for how many products
7
for 029 and 2800 and PRC-024?
8
first and go down the line, yeah.
9
MR. KOERBER:
Yeah.
So we'll ask it to
So we'll go with Arne
And for us, there's about --
10
preliminary analysis looking into this, we estimate
11
there's about 20 gigawatt of installed capacity.
12
are some of the oldest units, substantially before
13
2014.
14
requirement if comparing against the S-design curve.
15
What it would take, not in a position to comment on
16
this.
17
the answer really doesn't change whether it's IEEE 2800
18
or PRC-024.
19
20
These
That would not meet the frequency Ride-through
It's about 20 gigawatts installed capacity, and
MR. SHATTUCK:
And that's for legacy.
It's all
-- that's all --
21
MR. KOERBER:
22
MR. SHATTUCK:
Yeah, legacy.
We'll go down the line.
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forward, yeah.
MR. KARPIEL:
So for SMA, the frequency Ride-
3
through requirements are not an issue for our inverters
4
as well as our inverter stations and the magnetics that
5
are on the unit, and that's going back to all -- even
6
our legacy equipment, and it doesn't change, right?
7
The frequency curve for 029 is larger than the 2800 or
8
the 024, so if we can meet 029, we
9
MR. SCHMIDT GRAU:
can meet the rest.
I might've jumped the gun a
10
little earlier before, but, on the frequency.
11
Vestas, we cannot meet the frequency plus/minus 4 hertz
12
per six seconds on our legacy turbines, and that's the
13
installed fleet in U.S., I think around 15,000 units.
14
And it's not in design consideration for any new
15
products, and that's simply coming due to ancillary
16
equipment in the turbine.
17
standardization for any, like, sensors, transformers,
18
relays today that is meeting that.
19
potentially have cascading effect causing reliability
20
issues if you have a frequency that is plus-4 hertz,
21
minus-4 hertz for that long duration of other loads and
22
things in the grid going offline.
But for
There's no design process
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It will also
So we don't have it
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into consideration of design as there's no suppliers in
2
the industry that can meet that today.
3
4
MR. SHATTUCK:
And sorry.
You said 15,000 units.
Do you have a megawatt estimate for folks?
5
MR. SCHMIDT GRAU:
6
MR. SHATTUCK:
7
MR. DAHAL:
I will find it.
Okay.
Thank you.
I second Vesta's response to that.
8
Our legacy turbines cannot meet PRC-029.
9
considered PRC-029, those curve for six second in our
We have not
10
new design either.
11
that will meet -- that will comply with PRC-029
12
frequency Ride-through in its entirety.
13
2800, we meet our newer turbine and our legacy turbine
14
with some software and hardware modification, mainly
15
software.
16
17
So as of today, we have no product
Regarding IEEE
We will be able to meet IEEE 2800.
MR. SHATTUCK:
With all legacy or with all your
legacy equipment?
18
MR. DAHAL:
19
MR. SHATTUCK:
20
MR. DAHAL:
Except for Type 1 and Type 2.
Okay.
Yeah.
Type 2 and Type 4, yes.
And then our
21
restrictions comes from -- for whatever was mentioned
22
already.
We do not have motors that we can source that
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will be able to Ride-through all the ancillary
2
equipment, you know.
3
IEC requirement, IEC 60034, IEEE 50-1, they all have
4
plus-3/minus-5 requirement for these motors, and that's
5
what -- you know, that is in line with IEEE 2800, and
6
that's what our design philosophy is.
7
add our -- it'll probably come later, but design cycle
8
-- design-to-market cycle is five years for wind
9
turbine.
I think if you look at what other
And let me also
So any new standard that has that much of an
10
effect needs to be given at least five years, if not
11
more time, to be applicable.
12
cost prohibitive or anything like that, then that's
13
going to be another issue.
14
MR. SHATTUCK:
15
MR. PATTABIRAMAN:
And if it's, you know,
Thanks.
So for older TMEIC inverters,
16
especially thousand-word inverters and before, we have
17
hardware limitations in terms of what can be done in
18
the order.
19
plus or minus 3 hertz.
20
change in frequency was the maximum capability of the
21
equipment.
22
as, like OX equipment, fans, or whatnot for cooling may
So the typical design that was used was
During the time, 5 percent
So we may have hardware limitations, such
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have some hardware limitations.
2
that.
3
like, having 5 hertz per second were not part of the
4
design criteria back then, and it would require a
5
significant change in software to achieve 5 hertz per
6
second.
7
could do or a simple software update.
8
extensive design.
9
We are still exploring
But even on the software side requirements,
It's not a simple parameter change that it
There's
And especially for our older inverters, we have
10
limitations in our control board that would prevent us
11
from downloading new software onto it, or like with
12
excessive new capabilities, so they would require
13
hardware changes to even get some of these software
14
fixes.
15
maybe a retrofit kit for some of these existing
16
inverters and an entire development cycle dedicated to
17
developing new firmware for a new control environment
18
or a development environment, so that would take a
19
significant amount of time and resources.
20
probably be less expensive to just repower some of
21
these older inverters with newer inverters.
22
So they would require a new control board,
It would
For newer inverters, yes, they have wider
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capability to meet some of these wider frequency
2
requirements.
3
perspective, but from a power system perspective, we
4
still don't see the need to have these wide
5
requirements, especially given that none of the
6
existing events or none of the existing studies have
7
pointed to any evidence of wider frequency
8
requirements.
9
10
But we still -- not from OEM
MR. SHATTUCK:
next question.
Thank you.
Oh, Thomas, go ahead.
11
MR. SCHMIDT GRAU:
12
MR. SHATTUCK:
13
14
We'll move on to our
Forty gigawatt.
Forty gigawatts?
Okay.
Thank you.
Yeah.
MR. COOK:
Jamie, do we have these comments
15
captured, the responses captured from all of the
16
panelists in writing?
17
MS. CALDERON:
Yes.
18
MR. SHATTUCK:
We have someone recording, and then
19
we also -- most of them submitted these comments in
20
writing prior to this.
21
22
MS. CALDERON:
Yeah.
There was one or two, I
think, we were waiting on, but -Scheduling@TP.One
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MR. SHATTUCK:
2
MR. COOK:
We got them, I think.
Okay.
Yeah, that's what I thought.
3
looked, and I didn't find them all.
4
provided comments, written responses to these
5
questions, please do so.
6
numbers and stuff going back and forth.
7
court reporter somewhere, but she may be -- are you
8
getting all this?
9
COURT REPORTER:
10
MR. COOK:
11
(Laughter.)
12
MR. COOK:
I
So if you haven't
There's a lot of complicated
We have a
(Off mic comment.)
God bless you.
Okay.
Thank you.
Next question,
13
Question Number 3:
14
from manufacturers to -- I'm sorry -- to prove which
15
hardware limitations exist that would prevent your
16
equipment from meeting the criteria in Draft PRC-029,
17
Attachments 1 and Attachment 2?
18
MR. KARPIEL:
what documentation is necessary
Go ahead.
Yeah.
There would have to be some kind of
19
a declaration, obviously, from the manufacturer stating
20
that you don't meet this requirement or that
21
requirement due to this hardware limitation, this
22
software limitation.
We're not going to share our IP,
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obviously, but we do need to provide indication of what
2
portion of the standard that it's not going to meet,
3
why it's not going to meet that rather -- if that's --
4
this unit doesn't have enough buffer in that -- the
5
buffer doesn't have enough energy to Ride-through zero
6
volts for X seconds, this is why there's no space
7
available to install a UPS or something of that nature.
8
It's going to be basically our responsibility to put
9
together a declaration, like I said, and with examples,
10
curves, graphs pointing to certain specific hardware
11
components that are not available for -- because
12
they're not available on the market to provide back to
13
the GOs and then back to the TOs.
14
MR. COOK:
And how would you envision that being
15
presented as like this -- here's all the model numbers,
16
here's what they can and can't do, and issue that
17
generically or based on requests from a specific
18
generator owner?
19
MR. KARPIEL:
We would probably do it on a
20
specific request because the inverters themselves have
21
different hardware configurations.
22
look at that specific project's build to understand
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what is or is not included in that machine and what
2
generation it is so that we can accurately provide
3
detailed information regarding the equipment that's in
4
that plant.
5
6
7
MR. COOK:
Thank you.
Just pass it over to your
left.
MR. SCHMIDT GRAU:
Oh, we echo that as well.
I
8
think for frequency, it has to be a declaration.
9
There's a lot of things that cannot be studied in any
10
study world on it, specifically of all the auxiliary
11
equipment, and in the turbine there's also all the
12
rotating part -- motors, your motors, et cetera.
13
For voltage evaluation at planned -- sorry --
14
point of interconnect, I think it's really important,
15
again, come back to the OEMs are required to provide
16
adequate models and also that the industry is allowing
17
to use them because then you can do the proper
18
evaluation.
19
We look at these graphs and they're very static on a
20
PowerPoint, but the voltage will dynamically change
21
based on your current injection profiles, your site-
22
specific tuning, your nearby generation, so it's not
That's both for legacy and also future.
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enough just with the document.
2
adequate design analysis for it.
3
MR. KOERBER:
We also need to do the
Just to add what was said,
4
especially for wind turbines, these Ride-through
5
capabilities are really complex system-level
6
interactions.
7
goes above the one limit, that this one component
8
limits.
9
interact on Type 3 wind turbines, these interactions
It's often not there's one voltage that
It's many auxiliaries, many systems that
10
with the hardware side, the loading side, and it's not
11
as simple as here's the one limit.
12
something can't be done in a system that involves
13
multiple software systems, it's actually really hard.
14
Like, how can we as a manufacturer of equipment and
15
then say, this can't be done, we don't know how to do
16
it.
17
right?
18
And proving that
That's a very hard thing for -- to attest to,
We will provide the capability of the turbine.
19
This is what the turbine can do.
Here's the testing.
20
Here's the evidence that we have.
But showing that
21
something can't be done, it's a risk, but also it
22
involves opening up our entire design process.
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are our design limits?
2
a lot of IP involved, and we don't see us being in a
3
good position to provide documentation on capabilities,
4
on limitations beyond what's the stated, published
5
product-level capability.
6
very unbounded problem.
7
can do with modern software -- modern software systems
8
if you had all the time and all of the funding in the
9
world to solve this problem.
10
What are our margins?
There's
It's speculation, and it's a
There's a lot of things you
So declaring this can't be done, maybe for some
11
small sub-problems, it can be done, but generally, we
12
see significant challenges, not technical challenges,
13
but just how we -- how we handle providing this
14
documentation.
15
this is impossible, and what happens if someone does
16
it?
17
can't be done?
18
What can we actually sign up to say
What happens if we are wrong when we declared this
MR. DAHAL:
Yeah, I completely second that, and I
19
would like to add that each turbine needs to be
20
evaluated on its own.
21
-- forget about the fleet level, right?
22
models so far with various power-rated power output
We will not be able to provide a
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from them.
2
20 different statements saying our -- this fleet can do
3
this.
4
indicated, seeing what is inside the turbine, what
5
component was resourced, and what kind of documentation
6
we ourselves have that can be used to provide you all
7
with what you need.
8
very timely.
9
So we won't be able to provide, let's say,
It has to be per turbine based, as has been
So that exercise, again, will be
You know it will take time.
And also, I'd also like to highlight the fact that
10
just because, let's say, converter can do it doesn't
11
mean the turbine can do it.
12
highlight that because every change in the parameter
13
requires load and control analysis to see if tower can
14
sustain if there is enough vibration, if there is
15
enough harmonic generated.
16
be done for every change in parameter when it comes to
17
frequency and voltage, and that exercise is very time
18
consuming as well.
19
won't be able -- we won't be able to do that either,
20
you know.
21
saying, oh, it's a simple software upgrade, then you'll
22
be able to do it.
Again, I'd like to
And all that study needs to
And for legacy units, I mean, that
So there is a lot of nuance than just
That's not the case.
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MR. COOK:
2
MR. PATTABIRAMAN:
Thank you.
Generally, I agree with most of
3
what was said, would be able to provide some
4
documentation on capabilities that are already
5
published.
6
have to undergo investigation, and we would probably
7
provide a document on our company letterhead signed by
8
the appropriate officer on the capabilities of the
9
equipment.
But in terms of new capabilities, we would
10
MR. SHATTUCK:
11
MR. KARPIEL:
Go ahead.
So a comment.
The five of us up
12
here are employed by highly successful OEMs.
13
to be a consideration taken for those OEMs that haven't
14
been so successful.
15
MR. SHATTUCK:
There has
Thank you, and I guess the next
16
question bled into this one, but -- and we'll start
17
from Thomas and come back down the line.
18
follow-on to that last question is -- and I think the
19
answer is -- y'all touched on it, but, you know, what
20
documentation are y'all comfortable with sharing,
21
right, with someone like the -- a transmission planner
22
or NERC or, you know, your utility or entity, because
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But I guess a
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it sounds like there's a clash of IP and sharing
2
information, right?
3
BPS is reliable, right?
4
maybe middle ground of IP and/or justification or
5
something we can all be comfortable with on both sides,
6
but I'm interested to hear what y'all are comfortable
7
with and what that might look like.
8
9
But we also have to make sure that
MR. SCHMIDT GRAU:
So there's got to be some
Yeah.
Yeah, Thomas.
I think a lot of it was
said already on that part, but to reemphasize, I think
10
all OEMs, at least I can speak investors here, we
11
provide some kind of general description and
12
specification that we stand within, and all third-party
13
components we source has to comply with that.
14
might be slightly better, some might not meet -- will
15
just meet the specification on it, so I think that
16
documentation is key to keep and also to trust.
17
might be declarations, like rate of change of
18
frequency, that you cannot simulate, where you have to
19
have some declaration, where we have to look at site
20
measurement, where we have to do some attestations
21
around that.
22
FERC orders.
Some
There
I think that also aligns with some of the
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And then I will go back to the modeling again.
We
2
see the recommendation for EMT models, detailed models.
3
They will most likely or they have to live up to those
4
specifications and then trust that and implement that
5
in the study phase to get a more detailed instead of
6
looking at paper, basically.
7
MR. KARPIEL:
Yeah, I agree with you a hundred
8
percent.
9
what the OEMs are going to be willing to share publicly
Without an NDA in place, it's a fine line of
10
and openly, so, but we're going to have to find that
11
line and provide enough information that a decision can
12
be made.
13
MR. KOERBER:
Yeah, very similar comments.
We're
14
generally comfortable sharing existing product
15
capabilities.
16
features that operators may or may not have used and
17
implemented on their turbines.
18
capability, product specifications, comfortable sharing
19
this.
20
say, indicated fleet demographics as part of NOGRR245
21
for ERCOT.
22
curve?
This also includes existing optional
This is fully-designed
We also have very consistently provided, let's
How many turbines are impacted by what
And we generally plan to do so to help you kind
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of run scenarios.
2
happen if we do that, generally reasonably, and we plan
3
to continue doing that.
4
What's the impact?
What would
We really ask for an understanding, is that we --
5
like, it's very hard for us to publicly commit on
6
capabilities that haven't been developed yet.
7
just not solid practice because we don't know what
8
issues we will encounter.
9
sharing IP, so that's where we see the biggest
It's
The only way of doing it is
10
challenge is on kind of speculating for the future,
11
informed speculation, but --
12
MR. DAHAL:
I agree.
I completely agree with
13
that.
14
whatever VRT set points, you know, FRT set points, all
15
the curve, all the reactive power capability document,
16
all the simultaneities that we call for (inaudible).
17
You know, if the frequency varies more than one person,
18
you will need to sacrifice active or reactive power or
19
both.
20
have it, and we regularly provide that.
21
22
Our customers should already have, like,
All those documentation, they should already
Like, when it comes to unit model validation like
ERCOT requires for the new project, we provide the
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report to go with those as well.
2
needs to adequately address what kind of test needs to
3
be completed, in what manner, in what setting, with
4
what margin, and what kind of report are they expecting
5
at the end of the day.
6
ask us to, you know, provide all the -- all the, you
7
know, documentation when there is -- the requirement is
8
so vague.
9
future requirement.
But it can't be open-ended and
And obviously we can't speculate on the
10
the future needs.
11
it's designed.
12
But any standard
Nothing gets designed anticipating
You kind of touch bases whenever
During the first year of the design is where we
13
reach out to our customer and everybody and say tell me
14
your requirement, right?
15
that practice is closed, and we are solely focused on
16
designing whatever the feedback we got.
17
retroactively, like, for the ROCOF of 5 hertz per
18
second, even if we have the product right now, there is
19
no way for us to go back for the product that we are
20
currently entering the design phase to implement that.
21
We are already too late on that.
22
in mind as well.
And then after second year,
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We need to keep that
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MR. SHATTUCK:
2
MR. PATTABIRAMAN:
Thank you.
Very similar comments.
The
3
documentation we can share is often based on our
4
judgment internally and what the capabilities of the
5
inverter are.
6
share is often very limited because of IP issues.
7
yeah, that's essentially what we can share.
8
9
Even with an NDA, the information we
MR. SHATTUCK:
Thank you.
So
Before we go to the
next question, maybe suggest that the other panels, we
10
kind of hit on this topic and kind of understand the
11
other side of what would -- what they would be
12
comfortable with -- well, whoever they're representing
13
would be comfortable with getting, and, like, you know,
14
feelings on NDAs and all that kind of stuff and
15
process.
16
maybe next panel we can hear from what we're
17
comfortable with as evidence, and maybe we'll meet in
18
the middle.
19
So, like, we heard you, all sides, and now
We can go to the next question now.
MR. SCHMIDT GRAU:
Sorry.
Maybe quick comments on
20
the evaluation.
21
well because we have seen a lot of this evaluation for
22
it done in the past with PRC-024.
I think that's really key for this as
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People basically
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take our specification and plot the curves on top in
2
Excel of the -- of the curve and say, oh, we're
3
compliant or not compliant.
4
truth, and I think that's also why we see some of these
5
requirements, to some extent, go overboard on
6
capability because we might not understand what is
7
truly needed.
8
obligation to help providing guide with that adequate
9
information so we can understand the limitations of the
That's so far from the
And I think we as OEMs also have the
10
equipment.
11
it today, but I think that's really important as part
12
of the documentation is how to evaluate it, if you're
13
compliant or not.
14
understand that, we won't know what to provide.
And, yeah, it's a great step to talk about
15
MR. SHATTUCK:
16
MR. COOK:
If that's not specified and clear,
Thank you.
Next question, Question 5, what is the
17
generalized length of time associated with any design
18
of current products to meet the criteria specified in
19
PRC-029 without exception?
20
MR. KARPIEL:
So we had one number here as five
21
years.
22
important to understand is it economical to redesign a
It could also last longer.
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I also think it's
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complete turbine.
2
and it'll be installed five to 10 years from now, if
3
that platform gets completely obsoleted and we cannot
4
sell it, where does the investment money come to
5
redesign?
6
comply with, that every time we have a new standard, we
7
have to obsolete the old turbines.
8
important for us that we also get some money back to
9
keep investing and improve the products so we don't go
If we have designed a turbine today
So we're going to hit a race that we cannot
So it's really
10
into that race for it.
11
the platforms if the standards go in this direction.
12
MR. KARPIEL:
So five years and maybe killing
So I've been in manufacturing a long
13
time, and you have to understand that we're all lean
14
manufacturers, not only from a manufacturing supply
15
chain standpoint, but also a resource standpoint.
16
have a roadmap, and our resources are currently booked
17
up for the next couple of years, if not more, going --
18
looking at next-generation products, operations, you
19
know, the sustaining engineering that happens on the
20
existing equipment, future generations, new designs.
21
And then if we have to introduce something new, where
22
does that go in the schedule?
We
You've got design,
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you've got testing, you've got model validation and
2
certification that has to happen, so minimum five to
3
six years on a new design.
4
MR. KOERBER:
And this is going to be a classical
5
"it depends" answer, I think, for just new designs,
6
turbines that are being designed, can they meet all
7
these standards?
8
mentioned here by my colleagues up here seem
9
reasonable.
Some of the numbers that have been
That's about the right order of magnitude.
10
We generally foresee the biggest challenge for products
11
that are not no longer being manufactured, and when we
12
internally evaluate it, what would a retrofit take?
13
What does it take?
14
reasons.
15
have a lab.
16
around.
17
We very quickly jumped to internal
We no longer have a prototype.
We no longer
Some of the simulation tools are no longer
But it's really not just the internal reasons.
18
They are -- that's on us to overcome.
19
of investment, and it's also external reasons.
20
one hand, let's say, supplier relationships for
21
products that we no longer manufacture, we may not be
22
in business anymore with the suppliers of those subScheduling@TP.One
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It's a question
And on
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components, which also have software, which have
2
firmware, which we have to reactivate, which just like
3
you are asking us the questions, what it takes, they
4
will come back to us and say, hey, if there's no
5
business, if you don't need to do a retrofit, we are
6
not supplying to you actively anymore because we're not
7
shipping those products anymore.
8
supply chain that may have to get rebuilt up to even
9
work through the engineering.
10
It's just a whole
And then the second external kind of reason that
11
makes this difficult is in our relationship with
12
customers.
13
in many cases, operate them.
14
10, 15 years.
15
their own services teams.
They have -- may have
16
retrofit those turbines.
They may have replaced
17
electronics.
18
don't know what state they're in, and they will ask us
19
to guarantee that they meet the Ride-through
20
performance if we do a -- if we do a retrofit.
21
will also want a warranty that whatever new software,
22
whatever new component we install actually works and
We manufacture these turbines.
We don't,
They've been operating
Self-performing customers, they have
They may have replaced actuators.
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They
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doesn't impact the rest of the turbine, as I mentioned,
2
complex mechanical, electrical software system.
3
And then we won't -- we'll have trouble signing up
4
for this without individually turbine-by-turbine,
5
project-by-project, surveying and almost custom
6
designing a solution for an asset that's been running
7
for 15 years.
8
why it's hard to give a timeline and talk about maybe
9
the economics of what it takes to design a retrofit
All of this can be overcome, but that's
10
package for a product that no longer ships.
11
where the -- a lot of the uncertainty is coming from.
12
Internal reasons, labs, all of this, it's one thing.
13
It's the supplier and the customer relationships that
14
come on top of it that make this fairly difficult and
15
not very practical.
16
MR. DAHAL:
And that's
I'd also like to highlight the fact
17
that turbines today has not been like -- you know, we
18
do not design a new product every five years, right?
19
There've been accumulation of the experiences gathered
20
throughout 15, 20 years, right, what worked in year
21
one, what didn't work.
22
components, like our experience, what failed on the
We base the design on those
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field, what do we need to improve.
2
excited to participate in IEEE 2800 and very static,
3
you know, when it was approved.
4
So we are very
Now, for OEM, it's, like, there's now one standard
5
that we can design it for and maybe sustain it for
6
relatively longer period of time without having to
7
design to very specific market and have 10 different
8
variation of the product.
9
just creates that, you know.
And now deviating from that
We have to now face a
10
decision:
11
product just to kill it in five years, and what does it
12
mean by killing it?
13
modeling support.
14
good luck.
15
talking about, killing the platform.
16
means.
17
shifting toward like grid forming/grid following.
18
does it make sense for us to create a new
Then you are not getting any
If you have any issue on the field,
I mean, we're -- like, that's what we are
That's what it
And looks like whole industry is kind of
So I guess everybody needs to sit and think, like,
19
what is the benefit that we're going to achieve?
20
is it worth it for OEM to force them to push back on
21
getting, like, one percent of the capability more
22
versus letting them invest on R&D to come up with new
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next generation of product, right?
2
something to keep in mind.
So that's also
3
MR. PATTABIRAMAN:
4
answers said by other OEMs.
5
we start working on it right now, maybe it'll take
6
three years to five years, design retrofit packages,
7
design software in a completely new development
8
environment, create all these packages for our
9
customers.
So I agree with most of the
In terms of timelines, if
But the other important point is, you know,
10
we also have a roadmap, what we are going to comply
11
with in the next two, three years.
12
being significantly adopted, and our team is working on
13
those requirements right now.
14
pipeline.
15
whatnot.
And we see 2800
We have a product
We have development resources assigned and
16
So what I think these legacy requirements and
17
retrofitting old equipment with new technology is going
18
to do is kind of push out compliance for these newer
19
sites coming in to maybe three further years down the
20
line, you know, which is going to cause even more
21
problems because there are more new resources coming
22
online than there are legacy resources already out
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there.
2
you know, not just does it delay implementation for
3
legacy, but it also delays existing or new products
4
under development.
5
MR. SHATTUCK:
So not just does it delay existing products or,
Thank you.
We have one more
6
question before we go to online questions, but I think
7
most of it -- most of y'all have already touched on it
8
briefly, so if you could maybe keep them to like 30-
9
second answers, do rapid-fire summary of your already
10
11
stated responses.
So the last question is, and we'll start with
12
Thomas at the end, is, for currently in-design or, you
13
know, future considerations -- or future considered
14
products -- that's not good grammar -- are any of those
15
able to meet PRC-029 criteria?
16
-- products that are currently in design or planned to
17
be designed on your roadmaps, like we talked about,
18
that would meet PRC-029.
19
MR. SCHMIDT GRAU:
Yep.
So currently designed
When I speak today and
20
also talk about it, the PRC-029, I'm solely talking
21
about the 4 hertz per six seconds.
22
very, very supportive of the standard, but that
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specific requirement is depending on so many sub-
2
manufacturers, redesign of the cells, different
3
equipments, relays, that there is currently no product
4
available with it.
5
turbines for it, and there is no product in design for
6
future to meet plus/minus 4 hertz per six seconds.
7
We can't retrofit any legacy
So that is the limiting factor for Vestas.
Again,
8
just want to emphasize that we're greatly supportive of
9
the PRC-029, but that specific requirement will require
10
complete new platform.
11
offshore market, it cannot go into the onshore market
12
either, and there's no design for it.
13
MR. KARPIEL:
It will not go into our
Fortunate for us, there's no --
14
we're already meeting the requirements.
15
and future products will as well.
16
say, as you can tell, that not all inverters and
17
inverter stations are created equal, especially the
18
legacy equipment that's out there.
19
MR. KOERBER:
All current
What I would like to
Generally, all our new product
20
designs are aligned with 2800, so we're evaluating what
21
it takes.
22
me, several times, the big concern is around the legacy
As I've mentioned, several of us, including
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fleet, not new units.
2
generation equipment, meeting grid codes is a key part
3
of it.
4
PRC-029.
5
were mentioned in our comments.
6
talked a lot about here that we do see as requiring a
7
bit of a realignment on our side would be multiple
8
fault Ride-through, going from two events to four
9
events in 029, in general aligned to 2800, evaluating
Generally, design power
There's some specific technical requirements in
Some of them were mentioned.
Some of them
The one we haven't
10
what it would take to realign.
11
and most of the comments are really around the legacy
12
fleet, not new developments.
13
MR. DAHAL:
The stronger concern
I completely agree.
Our newer
14
products will comply with 2800, but we do not have --
15
we haven't considered this 64-hertz-per-6-second
16
criteria in any of our currently-being-designed
17
product, so not the new one.
18
that, and I don't think just a -- preliminary analysis
19
doesn't allow us to be able to meet it just because of
20
all the auxiliary motors that are in the turbines.
21
And, you know, we are not going to get any assurance
22
from our vendor that their motor would be able to Ride-
We haven't considered
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through those.
So we don't -- we have no product.
2
MR. SHATTUCK:
3
MR. PATTABIRAMAN:
Thank you.
Dinish?
So for products in development
4
in the future, we'll be able to meet 2800.
5
our planned roadmap, but there are at least a few
6
constraints with PRC-029, which limit us from meeting
7
it.
8
one of the examples is one-cycle filtering for
9
instantaneous overvoltages, which we won't be able to
Some of these were mentioned before.
That's in
You know,
10
meet.
11
1.8 per unit, you know, there's not overvoltage going
12
to occur on the grid side, but things could happen
13
internal to the plant, which could trigger that kind of
14
overvoltage.
15
There could be a failure of one of the components that
16
could cause a severe overvoltage.
17
studies done, called temporary overvoltage studies, to
18
determine how much energy a surge arrestor can handle
19
and so on.
20
from, you know, achieving this one-cycle filtering for
21
instantaneous overvoltages, including inverter
22
protection, inverter components, OX components within
I heard somebody mention that, oh, greater than
There could be a resonance condition.
There are extensive
So the various constraints would limit us
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the inverter.
The other constraint I see being a challenge is
3
the 25-degree phase-jump requirement.
4
phase-jump requirement is also there in 2800, but there
5
is additional wording added here in the PRC-029
6
language, which states 25-degree phase jump initiated
7
by a non-fault event, this is allowed to trip.
8
other kind of phase jump is allowed to trip, which is
9
something -- which is the first from 2800.
The 25-degree
No
Also, it
10
creates complications because the exception only states
11
for phase jumps created by a non-fault event.
12
fault events are actually going to create phase jumps,
13
you know.
14
between non-fault-initiated or fault-initiated phase
15
jumps.
16
A lot of
The inverters really cannot distinguish
Significant phase jumps.
So essentially, the
17
language states that if there is a fault event causing
18
a significant phase jump, like a 90-degree phase jump,
19
the plant is supposed to Ride-through.
20
something that we cannot really ensure, you know, the
21
significant phase jump is going to instantaneously
22
cause the current to jump significantly high and trip
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the plant.
2
differences between 2800 and PRC-029, which pose
3
challenges.
4
differences between 2800 and PRC-029 when 2800 has been
5
discussed extensively, approved widely by a lot of
6
people, and there's also test procedures coming in with
7
2800.2.
8
9
So these are the differences -- the key
That's why I mentioned earlier and why the
MR. SHATTUCK:
Thank you.
I think at this time we
have 10 minutes for Slido questions or questions from
10
the room.
11
asked a couple, so Howard, you go ahead.
12
We'll let Howard go first.
MR. GUGEL:
Thanks.
You've already
Howard Gugel, NERC.
So I've
13
heard a comment a couple of times today that is a
14
parity issue for me because it's different from what
15
I've heard in the past.
16
OEMs have accurate models that you've tried to provide
17
to the ISOs and utilities, and they refuse to allow
18
those models to be used.
19
utilities, they say we can't get accurate models
20
because the OEMs refuse to provide them because it's
21
IP.
22
-- we're hearing it from both sides and I don't -- I
So I'm hearing that you as
When we talk to ISOs and
I don't -- what's the right answer because that's
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can't figure it out.
2
MR. SCHMIDT GRAU:
We have the models, and we
3
provide them to anyone that requested.
4
least from Vesta's perspective, talking with different
5
ISOs.
6
can we provide you updated, accurate models?
7
very big interconnect projects in in U.S. coming on
8
board, and it's our bread and butter to sell turbines.
9
So we are, at
We are reaching out to them proactively saying,
We see
If we have any incident in the grid, it's going to
10
cause a political storm first, so we need to make sure
11
that the equipment we sell is reliable operating, on
12
the grid, and the best tool we have is for the models.
13
So we are really emphasizing utilities to ask and
14
accept the equipment-specific models, and we also are
15
trying proactively to ask what requirements do you have
16
for usability of our models and tools.
17
technology out there that can streamline.
18
one thing that can be used for EMT/RMS that will
19
significantly improve for utilities.
20
There's
SGRET B4 is
So we need a mechanism to allow to use the
21
adequate information, and we need ISOs/TSOs to be more
22
upfront with the usability requirements for our models
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and validation requirements for it.
2
accountability we have to take on as an OEM, but again,
3
that it's -- we can't afford any reliability issues
4
either, yeah.
5
course, not for all OEMs.
6
anything else, please reach out, and we can definitely
7
deep dive into that.
8
9
So that's an
So for sure, I speak for Vestas here, of
MR. MAJUMDER:
Any concerns, if you heard
Hey, Alex, if I may, just as a GO,
who has opportunity to work with all of them who are on
10
the podium.
11
easy.
12
interconnection requirement from each of those ISOs.
13
It's documented.
14
any user-defined model, so you don't have to get your
15
answer based on speculation.
16
They don't allow it.
17
To answer your question, Howard, it's
Please go ahead and look at the generation
They clearly state we will not accept
It's there, documented.
I have had my fair share with working with all of
18
the ISOs where they would want accurate model, and they
19
are absolutely refusing to work with a user-defined
20
model.
21
your generic model is inaccurate?
22
very difficult position because we cannot say that we
And then the question we get, so are you saying
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That puts us in a
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have given an inaccurate model, which is not true, but
2
it's what it is.
3
MR. KARPIEL:
4
MR. RODRIGUEZ:
It's generic, generic by nature.
This is Fabio Rodriguez.
I'm a
5
transmission planner for Duke Energy Florida, and a
6
concern about the models, it's very simple.
7
a system impact study, the OEM sends a model.
8
the study.
9
is, and there we go.
When we do
We do
We determine what the impact on the system
Then if there is a new model in
10
our interconnection requirements by FAT 002, there is a
11
requirement that if there is a modified change, the
12
model has to be restarted to see what the new system --
13
new impacts are on the system, and that's the -- that's
14
the process.
15
So when you guys come up with a new firmware or a
16
new software upgrade, or, you know, different settings,
17
if there is a modified change, which every utility
18
should have in their interconnection requirements, you
19
know, one of the modified changes, it's a new model.
20
One of the modified changes is, you know, more than
21
five percent in this setting.
22
change, the TO, or me as a transmission planner, I
So if you have that
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cannot accept your model until I do a new study to
2
determine if there is any new impact on the system by
3
those changes, and that's the process that we have.
4
It's a process that should work.
5
So you know, new models are working for any TO.
6
The thing is that they have to be restarted if there is
7
a modified change determined by the utility, by the TO,
8
and they have for -- you know, due to -- I mean, in FAT
9
002, every TO, every utility has to expel what the
10
requirements are or what the -- what they call modified
11
change to trigger the restudy.
12
13
MR. SHATTUCK:
Thank you.
I think maybe we'll get
back to frequency real quick.
14
MR. COOK:
15
MR. SHATTUCK:
Yeah.
The modeling piece, just keep in
16
mind, we have -- NERC has published modeling guidance
17
that says if you want accuracy in your studies, use a
18
user-defined model simply.
19
the website.
20
dynamic modeling guidance," and you'll get what we
21
recommend as NERC, and you can read that and adopt them
22
if you want to, adopt the recommendation.
They're in -- they're on
They're posted.
Just Google "NERC
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question.
MS. CASUSCELLI:
Okay.
I'm going to interject
with a question from the --
4
MR. SHATTUCK:
5
MS. CASUSCELLI:
Yes.
Thank you.
-- from online here.
So in order
6
to assess all of the Ride-through defined in the
7
standard, do the OEMs agree that a plant-level EMT
8
study is needed to confirm Ride-through?
9
10
11
MR. DAHAL:
Absolutely.
MR. KARPIEL:
Always a plant -- it's always a
plant-level model.
12
MR. SCHMIDT GRAU:
13
MR. DAHAL:
14
MR. SHATTUCK:
15
16
That was easy.
Yes, EMT plant-level models.
Yes.
So yesses all around?
All right.
No questions like that before that.
MR. MAJUMDER:
Again, Rajat from Invenergy.
17
Before I ask my question, first of all, I would like to
18
thank Alex for a very insightful presentation that he
19
did before lunch.
20
referring since from the beginning, and my apology for
21
being the broken record.
22
That's precisely what I was
So based on Alex's very quantitative presentation,
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we have seen expanding plus/minus 4 hertz per six
2
seconds has not been established as a sufficient risk.
3
It's clear.
4
manufacturers, and especially to Scott's point, that
5
there are probably little less successful manufacturers
6
who are not even around the table.
7
not there, and they do not see the reason, as of now,
8
because there is no basis of expansion of that.
9
We have just heard about all the
The technology is
So my question to the Standard Drafting Team and
10
the leadership is, so far no incident that can be
11
pointed has happened because of that expansion.
12
the standard goes ahead with this, we are essentially
13
going to go ahead, make all of those plant noncompliant
14
and open the breaker.
15
bulk electric system reliability, which has not been
16
the reason of any reliability risk.
17
in in that frequency Ride-through.
18
MR. SHATTUCK:
19
MR. AL-HADIDI:
So if
How is that helping with our
Again, I'm zeroing
Thank you.
Thank you very much.
Husam from
20
Manitoba Hydro.
21
off my involvement in the standard itself.
22
take these standard looking at low frequency 57 hertz
So maybe I have few questions based
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for almost five minutes.
2
not an issue, so you go only 56.1 hertz per six second
3
become an issue or how that really change, because
4
really it's a fluxing issue.
5
issue.
6
what's the difficulties on that for a low frequency?
7
Then I'll go about our frequency, which is normal
8
auxiliaries even for today's surplus machine where,
9
under load rejection, the frequency goes to 70, 80,
10
11
You guys okay with that, it's
It's a time-related
So if you can understand five minutes, then
whatever the case.
So it's not -- it's not abnormal for short time,
12
even for current existing synchronous machine, which
13
deal with the same auxiliary to some level, which is
14
the cooling and all that, which can stand for a large
15
frequency deviation for a soft-load rejection.
16
open the breaker.
17
think it's an -- a big concern?
18
if it's a big concern, we need to consider it, but I
19
just want to understand why this concern become
20
significant, where it's not really that much of a
21
change, at least from where we are right now.
22
What's the difference?
MR. SCHMIDT GRAU:
Why you guys
What I think it's --
I can maybe start.
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We just
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all the auxiliary equipment in the turbine is not
2
designed or certified for it, for those values.
3
mentioned earlier, also, we manufacturers have to rely
4
on manufacturers, and there's no certification, there's
5
no standard for any equipment we can go out and
6
purchase to put into our machines today that will
7
comply with that.
8
across a ton of equipment.
9
inverters here only.
So as
So it will require industrial chains
We are not talking
We are talking everything.
You
10
will have equipment in your substation that is not
11
designed to Ride-through, so you might have your
12
substation tripping offline before the turbines.
13
might have loads nearby that will go offline as well.
14
So the requirements exceeding, to my knowledge, all
15
industrial practices and other design standards.
16
MR. AL-HADIDI:
You
Yeah, but it's already existing.
17
As I said today, load rejection on any generator, it
18
create very large overfrequency or very large under
19
frequency, depend, but it's already -- the document is
20
already there which can Ride-through it, so it's not
21
something which is not manufactured before.
22
standard as saying continuous operation or just
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I see the
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integrated operation for certain number, but doesn't
2
prevent it from running.
3
already like exception criteria in the standard.
4
it voltage per hertz?
5
equipment --
6
7
And voltage per hertz is
Is it what the limitation of the
MR. SCHMIDT GRAU:
We are talking frequency
plus/minus 4 hertz per six seconds --
8
MR. AL-HADIDI:
9
MR. SCHMIDT GRAU:
Okay.
-- that there is no standard
10
to, what I at least know, that is designing any
11
equipment or certifying to that.
12
So is
MR. AL-HADIDI:
Okay.
So it does mean it's only
13
that 57 is okay, and for other frequency up to 62
14
hertz, that's what you guys guarantee, or is this
15
really the -- where we are right now, we need to move
16
to that direction?
17
MR. SCHMIDT GRAU:
18
MR. AL-HADIDI:
19
MR. SCHMIDT GRAU:
Ask if it -- we had to do R&D?
Yeah.
Is it R&D?
It's not R&D.
It's about we
20
are not able to source equipment that is designed or
21
certified to that for the auxiliary systems.
22
MR. AL-HADIDI:
Okay.
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MR. SCHMIDT GRAU:
2
MR. AL-HADIDI:
Today.
Does that mean that whenever you
3
guys now are manufacturing, the protection setting is
4
set on the border of this curve and you say --
5
MR. SCHMIDT GRAU:
6
MR. AL-HADIDI:
7
MR. SCHMIDT GRAU:
Yes.
So that's -We have pretty much maximized
8
out, and also to be able to -- there's always margin,
9
but it's -- we have certification for that equipment.
10
I'll let others maybe also reply, but we are maxed out,
11
at least for the Vestas equipment, where we are with
12
our specification today, and we have done the research.
13
Even with long extension here on the equipment, we
14
can't get signoff from any supplier with any of our
15
auxiliary in the frequency.
16
MR. KARPIEL:
So I don't really consider it
17
margin.
18
we've already pushed those limits.
19
believe we're all saying the same thing, that we're
20
already pushing those operational limits where we feel
21
safe for our equipment.
22
I consider it a safe operating limit, and then
MR. AL-HADIDI:
Okay.
I'm sure -- I
What about ROCOF?
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hertz per second something you -- is it something
2
feasible to do, or it's -- where we are in that 5 hertz
3
per second for legacy or for future design?
4
MR. SCHMIDT GRAU:
Vesta's turbines, Type 3 and
5
Type 4, all do 5 hertz per second, yeah.
6
3 and 4, it's public.
7
the NOGRR245 of August last year.
8
9
MR. DAHAL:
units.
You can go in.
Vesta's Type
They comply with
For SDRE, that's true only for new
We do not provide -- we do not have any proof
10
from our legacy turbines that we can go and do 5 hertz
11
per second.
12
the one that has already been installed.
13
That is only applicable for new ones, not
MR. PATTABIRAMAN:
Our legacy equipment, there was
14
no requirement for rate of change of frequency at the
15
time these inverters were sold or commissioned.
16
standard at the time, I think, UL defined maybe 1 hertz
17
per second as a requirement for some of these
18
inverters.
19
tested at 1 hertz per second and safe to operate in 1
20
hertz per second without tripping.
21
earlier, changing the software, it's not a simple
22
parameter where you can go and update 1 hertz per 5
The
And so most of our legacy inverters are
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hertz per second.
2
extensively, and our legacy products don't support
3
that.
4
software in some of the legacy inverters.
5
6
7
8
9
10
Software has to be changed
We would have to change hardware to even change
MR. AL-HADIDI:
Maybe I'll go to the second -- to
the question about transient overvoltage.
MR. SCHMIDT GRAU:
So I'll just add a comment on
the ROCOF first -MR. AL-HADIDI:
Sure.
MR. SCHMIDT GRAU:
-- which I think is important.
11
Avesta's turbine don't have ROCOF protection.
12
equipment, again, that is potentially not able to Ride-
13
through, so I think that's also really important to
14
understand when we evaluate these.
15
very detailed, accurate EMT studies for ROCOF.
16
can do a million hertz per second.
17
will never trip because ROCOF is not a protection
18
setting in the turbine.
19
auxiliary equipment and stuff that is not certified or
20
designed for these things.
21
It's really important to understand that it's just not
22
only inverters.
It's the
I do see ISOs run
They
The PRC CAP model
So there is, again, a lot of
This is just one example.
We have a lot of rotating masses,
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sensors, a lot of things in turbines.
MR. COOK:
Folks, we have about two more minutes
left, so we'll take one more question.
MR. AL-HADIDI:
Yeah.
Just quick question about
5
transient overvoltage.
6
question about transient overvoltage.
7
second/one-cycle filter, it's difficult to achieve and
8
may create some damaging issue.
9
10
11
MR. PATTABIRAMAN:
They may help us with this
You guys see one
It's not possible in our
inverters.
MR. AL-HADIDI:
Well, and understanding that the
12
standard is saying that if you need to protect yourself
13
from damage, you could trip, so it's really -- it still
14
is there to cover for that.
15
what's your guys' recommendation how to address it in
16
the standard to ensure that transient overvoltage for
17
just a spike, it's not really a noise or anything in
18
the measurement which cause the unit to trip, how we
19
should deal with it in the standard in better way.
20
MR. PATTABIRAMAN:
But the question now,
There are two ways.
I think
21
one is already the NERC recommendation, which is
22
maximize settings to the extent possible, limit
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instantaneous -- add additional filtering to
2
instantaneous protection internally, and the other path
3
is to kind of adopt 2800.
4
MR. AL-HADIDI:
5
MR. COOK:
6
7
Okay.
Thank you.
We'll take one more from the gentleman
that's behind you.
MR. HAKE:
Thank you.
Appreciate that.
I'll be
8
quick.
9
So we heard a lot this afternoon about the challenges
This is Sam Hake with AS Clean Energy again.
10
in evaluating what we cannot do, obviously relating to
11
equipment limitations.
12
wanted to ask is if you guys see similar limitations
13
also applying to the concept of maximizing inverter
14
performance.
15
experience, we've run into a lot of issues when we open
16
these questions about how can we maximize performance.
17
We get similar feedback as to what we've heard about
18
what we cannot do and are we limited.
19
if anybody has comments on that.
20
One point or a question that I
We also hear a lot about that, and in our
MR. KOERBER:
Yeah.
So just curious
It's a -- it's a similar
21
concept and some of the -- some of the challenges are
22
similar.
Maximize, where's the limit of maximize?
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Does it mean you have to invest 10 years of R&D into
2
maximizing it?
3
understood as make sure the settings are right, make
4
sure all already-available optional features are
5
applied.
6
by the OEM.
7
my own opinion.
8
challenges that I was talking about earlier is when we
9
are asking us as OEMs to essentially invent something
Generally, maximizations are often
We actually maximize to the capability stated
I think that's fairly straightforward, in
And where we run into the same
10
new that gets more capability out of the already-
11
installed hardware.
12
software can change, but what happens if a sub-supplier
13
firmware needs to change, or in order to update
14
firmware, you need a better processor?
15
spirals.
16
really do we go beyond stated capability, including all
17
already-designed options?
18
19
And parameters can change,
But I would say structurally similar.
MR. COOK:
Yeah.
It's
Yeah.
I don't know if you want to add
to that.
20
MR. SCHMIDT GRAU:
21
MS. CASUSCELLI:
22
Then it quickly
I want to echo it.
All right.
We'll do one last
question here if that's okay, Todd.
Scheduling@TP.One
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Thanks.
There's a
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question remotely here that asks if any of the
2
panelists work with AEMO and provide source code for
3
their models to the AEMO planners and operators and can
4
speak to that.
5
MR. SCHMIDT GRAU:
I can speak to that.
I think
6
AEMO is a very, very good example of the modeling
7
challenges we are facing here in U.S. providing source
8
code.
9
That caused a lot of issues with PSSE studies, showing
We simplified that source code significantly.
10
a lot of false positives, which we also see here in
11
U.S. with the generic and standard library models.
12
AEMO is now moving towards full EMT real-time
13
simulation, probably obsoleting RMS, and I think that's
14
going overboard.
15
lot of mature manufacturers here.
16
route and we start forcing EMT and so strict
17
requirements, in my opinion, it will not kill, but it
18
will slow down innovation, new players, competition in
19
the market significantly.
20
it's healthy for innovation or for the industry as a
21
whole.
22
MR. KOERBER:
And to the point earlier, we are a
Yeah.
If we go down that
And that's -- I don't think
I assume AEMO -- Australia
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Energy Market Operator, or is that another AEMO?
2
interpret this question as being about Australia, one
3
of the most strict grid codes in the world, requires a
4
lot of transparency, is a significant challenge, but
5
it's also very structured.
6
with AEMO is they've also been very open in kind of
7
walking the process with us on what's needed.
8
been -- they've had several requirements.
9
on MFRT, multiple fault Ride-through, where Australia
10
has probably the strictest requirements in the world,
11
but they're also very open, very technical in working
12
through some of those challenges with the industry.
13
Real code, actual source code, actual product-
I
And our experience working
They've
I commented
14
level code is a challenge so far providing this in
15
compiled form where the code -- the source code is not
16
visible, but the performance actually 100 percent
17
matches.
18
implementation challenges.
19
comes to working with AEMO.
20
discussion for here, but yeah, we, we work with them
21
extensively, and it's been a journey.
22
The product has been a way to go,
MR. DAHAL:
There's many layers when it
I don't think that's a
It's not related to that question, but
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I do like to bring something to attention as well when
2
we're talking about the model AEMO and all.
3
I think Rajat mentioned, like, most of ISO requires
4
generic model.
5
people are getting so familiar and comfortable with
6
generic model, that they are changing the model
7
significantly when they're submitting, you know, the
8
model of their plan to ISOs and RTOs.
9
nothing about, right?
You know,
And what we are seeing from OEM side is
That we know
There is a lack of manpower that
10
I don't think anybody has talked about because not a
11
lot of developers are capable of running the study --
12
plant-level study on their own, so they have to
13
outsource that study to somebody.
14
such a way that there is a, you know, severe lack of,
15
I'd say, knowledgeable people to run the study.
16
And the market is in
So that model that gets submitted by the OEM to
17
the customer might not be the same model that gets
18
submitted by the customer to the TSO/RTOs as well, so
19
that is also something to keep in mind.
20
talking about, oh, OEMs are hiding their control block,
21
we need access to control blocks, we need access to --
22
we need access to that parameter and that parameter,
Scheduling@TP.One
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Everybody's
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while forgetting the fact that, you know, if you were
2
to use the OEM/UDM model, you'll get a very accurate
3
representation.
4
you have to come to us.
5
possible and what is not with generic model.
And if you have to make changes, then
Then we will tell you what is
6
Then people get very comfortable using those and
7
not realize that changing parameter might drastically
8
change the behavior of the turbine.
9
recently, a lot of inquiry that comes to us is after
And, like,
10
the fact that, oh, your model is not -- your IRMS model
11
is not behaving like EMT model, and when you look
12
through it, it's been completely altered, and that's
13
also the challenge that needs to be addressed.
14
hold the timeline, six-month applicability, one-month
15
applicability, knowing that plant-level study has to be
16
done and is this feasible amount of time to achieve
17
that, that's also -- that also needs to be considered.
18
MR. SHATTUCK:
And
Thanks, and I think we're out of
19
time, but let's just maybe do one "yes" or "no" at the
20
end.
21
know, getting a model back that was changed.
22
no idea what's in there.
So this last situation was just described, you
You have
We'll go "yes" or "no" from
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Have you experienced that?
2
MR. SCHMIDT GRAU:
3
MR. KARPIEL:
Yes.
4
MR. KOERBER:
Sorry.
5
6
Yes, pretty much all sites.
Could you -- can you just
restate the question, please?
MR. SHATTUCK:
So the situation that was described
7
where, you know, you've given a model out and then you
8
get it back later from generator owner, utility, or
9
whomever, and it's different, and you had no idea.
10
MR. KOERBER:
I've not personally experienced
11
this, but maybe I'm at a different part of the
12
organization, so I can't comment on that.
13
MR. SHATTUCK:
14
MR. KOERBER:
15
MR. SHATTUCK:
16
MR. PATTABIRAMAN:
17
MR. SHATTUCK:
18
MR. DAHAL:
Okay.
Thank you.
I assume yes, but I can't confirm.
Finish?
You already answered.
Yeah, I already --
Yeah.
Yeah, absolutely.
In fact, we have
19
provided RECA models, and we have received REECC back
20
for some reason.
21
(Laughter.)
22
MR. SHATTUCK:
All right, good.
Scheduling@TP.One
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I think we're
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done then.
MR. BENNETT:
All right.
Well, thank you for our
3
well-informed panelists.
4
technical.
5
achieved what we were hoping it would achieve today.
6
So I don't know, just them a round of applause.
7
appreciate you.
I think that was very
That was very informative.
8
(Applause.)
9
MR. BENNETT:
I think that
We
So with that, I just want to let
10
everybody know there are a number of questions online.
11
We're collating those.
12
panelists and see if we can get some answers later
13
today.
14
and we'll come back with our last panel of the day to
15
talk about some challenges with the current criteria
16
for PRC-029.
We'll get those to the
But with that, let's take a 15-minute break,
Thank you.
17
(Break.)
18
MR. BENNETT:
Okay.
So it looks like we're
19
getting everybody together back in the room here.
20
We've got our panelists seated and ready.
21
like Charlie's smiling at me.
22
let's introduce our last panel of the day.
It looks
So with that, I guess
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So we're going to talk about Addressing the
2
Challenges of Voltage and Frequency Ride-Through
3
Criteria.
4
Charlie Cook from Duke Energy, as well as Howard Gugel
5
from NERC.
6
So to lead us through that is once, again,
So take it away.
MR. GUGEL:
Excellent.
I guess before we start,
7
if we could just have everybody just briefly introduce
8
who they are and who they work for.
9
Manish Patel, EPRI.
10
Andy Hoke, National Renewable Energy Lab.
11
MR. CHWIALKOWSKI:
12
Todd Chwialkowski, EDF
Renewables.
13
MR. LAUBY:
Mark Lauby, NERC.
14
MR. GUGEL:
A man who needs no introduction.
15
MR. COOK:
Yeah.
Once again, I'm Charlie Cook,
16
and I work for Duke Energy, representing the Standards
17
Committee.
18
on when I walked into the bathroom.
Thought of a funny, though.
19
(Laughter.)
20
MR. COOK:
I had this mic
But then I realized, hey, John Belushi
21
did a similar skit on "Saturday Night Live," so I
22
turned it off, so.
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MR. GOGGIN:
2
MR. GUGEL:
3
Michael Goggin with Grid Strategies.
I always think of Lesley Nielson and
"The Naked Gun" when he did that same thing, too.
4
MR. COOK:
5
MR. GUGEL:
I'd probably do that, too, yeah.
I'm afraid of that.
I'm Howard Gugel
6
with NERC, and thank you all for participating on this.
7
I promise I won't ask any questions about models during
8
this -- during this panel.
9
conversation that we had earlier talking about voltage
But do want to continue the
10
and frequency Ride-through, and the first question that
11
I'll have is specifically, Mark, from NERC's
12
perspective.
13
identified -- has NERC identified any challenges about
14
understanding and evaluating the impact of generators
15
failing to meet either PRC-029 or IEEE 2800?
And that would be, you know, have we
16
MR. LAUBY:
17
(Laughter.)
18
MR. LAUBY:
Models, no.
One of the -- I think one of the
19
challenges is it reminds me of when I used to work in,
20
in Asia, and they'd come to me and say, well, how much
21
coffee do you want, and I'd say, how much did you make.
22
We're almost in that situation now where we're saying
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to folks, well, you know, please give me this amount of
2
frequency or voltage, and they say, well, how much do
3
you need, and we can't answer the question, even 2800,
4
of course, which is a global standard, right?
5
kind of a -- I'll call it a global foundation, but we
6
haven't done the hard work.
7
hard work" is, you know, doing the system analysis to
8
understand what are the frequency response that we
9
need.
It's
And what I mean by "the
How do we know that what we're putting in the
10
standard is going to ensure that we have sufficient
11
amount of Ride-through, be it voltage or frequency?
12
Now, we have some data, you know, some -- and we
13
had -- you know, that's on some of the -- some of the
14
events that Alex went through, which was helpful,
15
though, of course, we did have substantial amount of
16
spinning machines out there to help us with the
17
frequency when there was a need for frequency, or
18
operators that were taking action, like shedding load
19
to make sure the balance is kept.
20
So I think that's one of the hard parts is having
21
the data and the models and the simulations.
22
get beyond the inverter-based resource and what it can
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do to getting to what do we need, and then how will --
2
how will we drive the -- a standard to get there, so
3
what's a good starting point?
4
leave it to the Drafting Team and the people -- and the
5
folks here, but, you know, clearly we're -- it's kind
6
of like a golf site, the old flat start.
7
to start someplace, and then over time, we'll find out
8
as this evolves, if we need more or less.
9
Well, you know, I'll
We're going
There are places -- I talked to Jason -- not there
10
yet -- 2800 would actually cause you problems, voltage
11
collapse problems if you -- if everybody finally went
12
2800.
13
some places I'm going to have to have less than 2800,
14
and that's okay, it's easy to do that, and some places
15
you're going to need more depending on where you're at,
16
but then that's okay, too.
17
standard, and less, just make sure you have the
18
technical reasons for doing that.
19
and you need good models and good simulation tools.
20
So you got to do this hard work to say, hey, in
MR. GUGEL:
Yeah.
You can do more than the
So it's not easy,
So to -- so to kind of build on
21
that because now we -- I think we kind of see the
22
issue, maybe we could talk about the magnitude of the
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problem here.
2
your perspective, you know, what percentage of the
3
existing portfolios would be affected by the draft PRC-
4
029 criteria, and how would that change?
5
be less or more affected if you changed that criteria
6
to meet 2800?
7
So from the rest of the panelists, from
MR. GOGGIN:
I can start.
Would there
So the numbers I've
8
seen, and, you know, we heard on the previous panel
9
from folks on the wind and solar side it's a
10
significant share of the fleet.
11
from developers who will be speaking today and
12
tomorrow, 20 to 50 percent of their fleets, and, you
13
know, again, this is out of a base of several hundred
14
gigawatts.
15
talking about the frequency Ride-through requirements
16
in PRC-029.
17
The numbers I've seen
And this is -- I should clarify.
I'm
So, you know, 20 to 50 percent of several hundred
18
gigawatts is a hundred-plus gigawatts of existing
19
resources that have major challenges with this, would
20
either require extensive retrofits or complete
21
retirement and replacement of the resources.
22
know, we've heard a lot about the wind, but, you know,
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anecdotally, we've seen with solar and batteries, I
2
think it's an issue of just, you know, these -- all
3
these plants were designed before the standard was
4
thought of.
5
months' notice to go out and find out what the
6
capability of the plant is and, you know, how perform
7
-- just trying to meet this.
8
9
And so it's very difficult with a few
And so we really don't know, and, you know, I'll
come back to, so what is the solution?
This is why we
10
don't do retroactive standards.
11
get them right and make sure that they work for
12
existing resources.
13
only prospective standards at FERC and NERC, and it's
14
for a good reason, and on the frequency side, we need
15
that.
16
doesn't work.
17
what the industry is designing towards.
18
if you make that effective, you know, as of the, you
19
know, basically, when the standard takes effect all
20
interconnection agreements signed after that date have
21
to meet that.
22
going-forward basis.
It's really hard to
There's a long history of doing
It has to be on the table.
Otherwise, this just
And I think going forward, IEEE 2800 is
And, you know,
I think that works for the industry on a
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Existing plants, again, weren't designed for 2800,
2
and so, you know, we need this -- it needs to be a
3
prospective standard only on the frequency side.
4
you know, just given the magnitude of what's at risk
5
here, a hundred gigawatts taken offline potentially
6
permanently or at least for extensive retrofits, is a
7
major reliability risk.
8
any good we're doing if that's -- if that's going to be
9
the result, so this has to be fixed.
10
11
And,
We're doing way more harm than
So an exemption
for existing IEEE 2800 for going forward.
MR. CHWIALKOWSKI:
I'll go next.
EDF, again, EDF
12
renewables, a developer, and I'll go down the path of
13
we've had an opportunity already to do some of our
14
analysis with ERCOT.
15
and they went forward with their Nodal Operating Guide
16
245, and they're looking at, at this point, forcing us
17
to maximize -- at least analyze the maximization of our
18
sites within the ERCOT region.
19
Now, ERCOT jumped ahead of NERC,
So we've had a chance to work very closely with
20
the OEMs and try to figure out where do we stand with
21
our current fleet.
22
I don't mind sharing them, but I'll also ask the other
And I have some numbers for you and
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developers in the room please share that information.
2
I know some of you have some numbers, and we aren't the
3
biggest developer out there, but our numbers are also
4
pretty significant.
5
029, similarly, as we looked at NOGRR245 and IEEE 2800,
6
we're looking at almost 40 percent of our fleet being
7
affected by this and affected in multiple ways, not
8
just frequency alone, not just voltage alone.
9
you look at our older fleet, our older turbines in the
So for us, looking at the new PRC-
But when
10
ground, it's both the voltage and the frequency Ride-
11
through that's an issue.
12
And then looking specifically at ROCOF, looking at
13
the phase-angle jump, looking at multiple excursions,
14
from the OEMs, we're getting the kind of information
15
that says until we test this, I cannot give you a
16
definitive answer.
17
definitive answer, right?
18
respond to the regulator, but I can't get that.
19
you just heard the previous panel saying that's very
20
tough to come about.
21
are my source of truth.
22
information from them, where do I go?
Well, as a developer, I want a
I want to know how do I
How do we test that?
And
The OEMs
If I can't get that
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supposed to do as a developer or as a generator to get
2
that information to answer the regulator?
3
MR. HOKE:
So, you know, I'm not a generator owner
4
or an OEM.
5
basically let everybody just listen to what we've heard
6
from the previous panel, what we've heard from these
7
guys up here.
8
the legacy fleet.
9
been brought up before, that when we wrote 2800, IT
I'm a -- I'm a researcher.
So I would
It's a pretty significant percentage of
I'd also comment, I think this has
10
wasn't designed to be retroactive, and so applying it
11
retroactively causes all the problems we've heard
12
about.
13
apply it retroactively, right?
14
uncertainty in what does the grid need.
15
installing solar and wind plants.
16
on the grid for 20 years or more, and we don't know
17
what the grid's going to need in that period.
18
there's this desire to be a little bit conservative and
19
get as much Ride-through as we can because we might
20
need it.
21
22
Now, and I also understand why people want to
We have a big
We're
They're going to be
And so
But I think what Mark said at the beginning, let's
get something that -- what we can get from industry
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right now without slowing down the deployment of these
2
plants and without causing, you know, PEP companies to
3
go out of business and get what we can now.
4
meantime, researchers like us will try to figure out
5
what the grid is really going to need and have a better
6
idea of that, and maybe we need to revise it and come
7
back to this in the future.
8
fruit now, get a good Ride-through standard now that
9
everyone can be on board with, and then if we need to
10
11
And in the
So get the low-hanging
revise it in the future, we can revise it.
MR. PATEL:
So I have nothing else left to say
12
really, but I'm looking at some of the notes my wife is
13
sending me right now.
14
(Laughter.)
15
MR. PATEL:
Just like how my weekends go before I
16
open my mouth in front of family and friends, you know.
17
So I think Andy mentioned this.
18
was a forward-looking standard, and some of the
19
requirements in there does not exist today in any NERC
20
standards, right?
21
NERC standard.
22
PRC-024, for that matter, is not a Ride-through
When we wrote 2800, it
Phase-angle jump never existed in a
ROCOF never existed in a NERC standard.
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2
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3
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It is voltage and frequency trip-setting
So when we wrote 2800, we had this question:
what
4
does grid need and what can IBRs do?
5
definitive answer on either of these questions.
6
tried to find a middle ground somewhere based on
7
engineering judgment, right, a lot of head scratches,
8
and talking to a lot of OEMs about can equipment really
9
do this or not do this.
And we don't have
We
And even then at the time, I
10
remember a very difficult conversation with couple of
11
OEMs on something very specific in the standard, and
12
few OEMs said, Manish, for us to answer this question
13
with any confidence, we have to be able to test our
14
equipment first, and we have never tested our
15
equipment, so we cannot affirmatively say that we can
16
or cannot meet certain requirements, right?
17
So anyhow, we wrote lot of 2800 requirements
18
thinking about future grid.
19
involved, 400-plus, and they all agreed to some of
20
those requirements.
21
portfolio will be affected by either PRC-029 or IEEE
22
2800, you heard OEMs.
A lot of folks were
As far as how many GOs or
I think a couple of numbers
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stuck to my head was one OEM said 40-gigawatt capacity.
2
Another one said 50 to 60,000 units, right?
3
60,000 units.
4
Fifty to
So that's just few examples.
I work -- all my career I've worked on
5
transmission side of the business, so I don't know the
6
numbers.
7
the equipment that was placed in service five, 10, 15
8
years ago, and not having that same equipment in a lab
9
anymore to test it for future new requirements is a
10
11
But forward-looking standard, applying it to
challenge.
MR. GUGEL:
So, and maybe we'll start at the far
12
end and work our way back for this next question.
13
and this may be a difficult one to answer, and if you
14
don't have the answer for it, I think that's fine, too.
15
But what would -- what do you think would be the
16
limitations that would need to be fixed, if you will,
17
or changed in order to meet the voltage -- we'll just
18
talk about the voltage criteria -- the voltage criteria
19
that's spelled out in proposed PRC-029?
20
what hardware do you think would need to be worked on
21
for that, if you will, or what are some reasonable
22
solutions that we could come to, to maybe not even to
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necessarily meet that, but to come close to what's
2
shown in PRC-029?
3
MR. PATEL:
Yeah.
I'm sorry if I say something
4
wrong.
5
at the bar.
6
Ride-through requirements were forward-looking
7
requirements.
8
to when we were writing 2800 -- and then PRC-029
9
voltage Ride-through almost mimics the IEEE 2800
My friends who are OEMs don't come talk to me
But I think -- I think again, voltage
I think at the end of day, it came down
10
voltage Ride-through.
11
to a lot of auxiliary equipment, all this wind turbines
12
and, in some cases, BES and solar inverters and then
13
VSC HVDC, right?
14
wind plants that it -- that connect to AC transmission
15
system via VSC HVDC converters.
16
At the end of day, it came down
The IBR definition includes offshore
So all these are very different technologies, and
17
limitations for one technology might not be the same
18
limitation for another technology, but it seems like at
19
the end of day, a lot of these things came down to a
20
lot of auxiliary equipment that is designed on some
21
other industry standards -- IEC NEMA curves, all that
22
kind of stuff that is sourced by OEMs of wind turbine
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generators, solar PV BES, and VSC HVDC to go along with
2
their equipment.
3
auxiliary equipments.
4
MR. HOKE:
So it comes down to a lot of
Not a whole lot more to say there
5
because, I mean, it's sort of summarized pretty well
6
what we've heard from the OEMs in the previous panel.
7
You know, it's equipment specific.
8
be auxiliary.
9
power for the controls at low voltage for a certain
Sometimes it might
Sometimes might be that you need some
10
amount of time, but -- and sometimes maybe it's a
11
software change.
12
software changes, you have to go back and retest that,
13
so it's not just a matter of updating new firmware.
14
I'm basically just summarizing what we've already
15
heard, so I'll leave it there.
16
MR. GUGEL:
But as we heard, even with those
Well, maybe I can take us in a little
17
bit different direction then because there's a question
18
that I've had.
19
vast majority of inverters that are at least on the
20
legacy equipment and may be specified for now, tend to
21
be more grid following.
22
those inverters to grid forming, would that maybe solve
If we made a switch, it seems like the
If you made a switch to take
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some of the issues that we're talking about for voltage
2
and frequency Ride-through?
3
4
MR. HOKE:
All right.
I'll jump in if no one else
wants that one.
5
(Laughter.)
6
MR. HOKE:
I think you're going to run into a lot
7
of the same issues, and maybe even more issues because
8
now you're not just doing Ride-through, you're also
9
doing a whole different type of low-level control for
10
the inverter.
11
are out there can be retrofitted to become grid
12
forming.
Others need a new inverter to become grid
13
forming.
Again, it's a commit-specific question.
14
the Ride-through issues, that doesn't make the Ride-
15
through issues go away.
16
still there.
17
You still need the control power to be there.
So I
18
don't think it necessarily solves that issue.
It's
19
another super important issue to talk about, but I
20
don't know if it necessarily helps with the Ride-
21
through.
22
I know that some of the inverters that
And
The Ride-through issues are
You still need the auxiliaries to work.
MR. GUGEL:
Good.
That's a question that folks
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have asked me in the past.
2
stay at a Holiday Inn Express recently, so I didn't
3
have a good answer for it, but I thought maybe some of
4
the smarter heads here might have a good one for that.
5
MR. PATEL:
And, you know, I didn't
I think that question may have some
6
value in terms of what does grid need.
7
following gives what grid needs versus what grid
8
forming, but I don't think you can compare grid
9
following Ride-through versus grid forming Ride-
Does grid
10
through, and challenges, and all that kind of stuff.
11
think that question may have value when we talk about
12
grid needs.
13
MR. GUGEL:
Yeah.
I
Just the question that had come
14
up for me was, does the fact that maybe it's less
15
dependent upon the frequency that's provided by the
16
system allow for some different controls that might
17
make the ability to Ride-through different as opposed
18
to looking at the frequency on the system and reacting
19
to that internally into the inverter.
20
MR. PATEL:
So I think repeating myself and
21
repeating with everyone else on the previous panel, I
22
think a lot of this limitations is not only the wind
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turbine or the -- or the inverter.
2
auxiliary equipment, right?
Grid forming won't change
3
in the auxiliary equipment.
It remains same, so.
4
MR. GUGEL:
5
(Cross talking.)
6
MR. HOKE:
Right.
It's a lot of
Okay.
-- for the synchronization issue just
7
real quick there, and maybe grid forming helps with
8
that, but that's just one piece of the puzzle of the
9
Ride-through, right, everything else that everyone else
10
11
had mentioned.
MR. CHWIALKOWSKI:
Before we go down that path of
12
grid forming/grid following, let's go back to that
13
previous question of, you know, will hardware fix a lot
14
of these voltage Ride-through issues?
15
to the source of truth, but I also want to -- I also
16
want to expand a little bit upon that because as a
17
generator owner operator, we're being asked that right
18
now, what will be necessary to maximize our turbines
19
down in the ERCOT 4 region, for instance?
20
to explain that process to you a little bit better
21
because this is not a trivial process.
22
And I'll go back
And I want
We rely on the source of truth, the OEM, to give
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us that information about the turbine.
2
the first step because then you take it to the
3
substation, and you start looking at how are we
4
protecting the components of the substation?
5
any change downstream at the turbine level, how is that
6
going to affect my substation?
7
better idea of how that affects the plant on the
8
medium-voltage side and the high-voltage side, then I
9
go back to the -- I hate to say it -- the modeling
But that's just
If I make
And then once I have a
10
side, which could take far more time to even go through
11
that process because, again, we look at the source of
12
truth, the OEM for the models.
13
months to a year sometimes to get those models from
14
that and then expand the models to the entire plant.
15
And that could take six
Now, if you have a homogeneous system and you have
16
one OEM, one model type, that works out pretty well.
17
You put two model types out there, it gets a little
18
more difficult.
19
it even more difficult.
20
and multiple model types.
21
model set together to submit.
22
we go through, but again, to answer your question, on
Two OEMs each having one model makes
We have a site with three OEMs
It's easily a year to get a
That's the process that
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the hardware side alone for the turbine, the OEM.
2
mean, if we can't get an answer from them in a
3
reasonable time, that's where we stand.
4
MR. LAUBY:
I don't want to hear myself.
I
I think
5
the challenge here, too, is to understand what's the
6
risk.
7
before.
8
current situation based on certain events.
9
ask folks to provide us what they can, and I don't know
I think some folks kind of mentioned this
We saw some charts that Alex put up on the
If we just
10
how you define that, what's reasonable versus
11
unreasonable, and then looking forward, making sure
12
that we stay to one particular standard that we can
13
count on.
14
you do the technical studies, that you may actually not
15
want to implement a Ride-through criteria that might be
16
like a 2800 or 029.
17
bit shorter.
I think -- I think we can stay in front
18
of the risk.
I think the main -- the main thing is to
19
ensure that those can -- those devices out there that
20
can provide more within the reasonableness that -- you
21
guys can decide what's reasonable versus unreasonable
22
-- to take advantage of it.
And realizing that, again, sometimes when
Maybe we need something a little
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There may be some regions, though, or
2
interconnections where that's a real issue for them,
3
and Texas might be one of them.
4
interconnection, very -- more and more dependent on the
5
inverter-based devices there because they're building a
6
lot of them over a period of time.
7
have a bit more of a need in certain interconnections
8
versus other interconnections.
9
MR. GOGGIN:
It's a small
And so they may
I totally agree with that.
I think,
10
you know, the need needs to drive this, not the
11
capabilities, and that was a little confusing this
12
morning kind of hearing the -- from the Drafting Team
13
that they kind of -- you know, that their logic was,
14
oh, well, IBRs can do this, so we're going to make
15
them.
16
it's just not a good standards practice.
17
And that's backwards, it's discriminatory, and
You should define the need, and I think it's clear
18
that the plus or minus 4 hertz per six seconds is not
19
based on any real need, based on, you know, the charts
20
we've seen this morning and the 10 NERC reports.
21
know, there's never been a frequency deviation that
22
large, and, you know, just thinking about what would
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happen.
2
conventional generator would've tripped off, you know,
3
or at 59 hertz, all the load would've tripped off
4
around then, too.
5
are we trying to achieve here by making IBRs stick
6
around while every -- the entire other power system --
7
rest of the power system goes black?
8
9
If the frequency is down at 56 hertz, every
You know, what's the point?
What
I don't think -- I don't -- I haven't heard any -I've been asking all day.
I think -- I don't think
10
anybody has heard a good technical justification for
11
what we're trying to do here.
12
bounds here are just so far beyond, you know,
13
everything that I think is based in, you know, actual
14
needs, and so what is that need?
15
by interconnection, you know, the standard connection.
16
NERC has done analysis showing it's -- you know, even
17
with very high penetrations of inverters, maybe with,
18
you know, extremely high contingencies, you know, 3X,
19
you know, losing 7,000 megawatts in contingency, you
20
still have very tightly-controlled frequency.
21
22
You know, these -- the
And yes, it may vary
And with IBRs that have fast frequency response,
grid-forming capability, and other things, frequencies
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are even more tightly controlled with lots of
2
batteries, with, you know, controlled renewables.
3
think we're moving to a where frequency is even more
4
tightly controlled than it is today.
5
know, first establish that need and then work backwards
6
from that, and then set the requirements based on that.
7
Let's not go with this backwards route of, oh, we can,
8
you know -- we think inverters can do this, so we're
9
going to make them.
10
MR. GUGEL:
I
And so let's, you
The only caveat that I would provide
11
-- and sorry, Mark, I'll speak out of turn, and you can
12
clean up for me.
13
is the examples that were provided this morning and
14
that kind of show some of the events that occurred,
15
were just specifically rated to -- related to inverter-
16
based resource events that we've seen over the last
17
three or four years.
18
seen frequency excursions larger than that.
19
that we haven't recently seen those.
The only caveat that I would provide
It doesn't say that we haven't
It's just
20
If you go back in history, we have had in Florida
21
somewhat, fairly large, you know, frequency excursions
22
that have occurred.
And we're trying to protect not
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just for some of the things that we've seen recently,
2
but for events that could occur on the system that are
3
much more drastic than that.
4
of that.
5
6
7
MR. GOGGIN:
Sure, and I was including Uri in
that, which was not an IBR.
MR. GUGEL:
We're trying to stay out
It was a gas event.
Well, yeah, but, again, that's just
8
some of the more recent.
9
some of our more historic legacy issues that maybe got
If you were to go back to
10
us into why we got our name and our purpose you would
11
see a little bit more of those issues that are there.
12
And, Mark, I think Edison probably had some good
13
comments --
14
MR. LAUBY:
Yeah, Edison, and I saw that.
No, I
15
think you're right, Howard.
16
see this as a discriminatory act.
17
Team is struggling with what -- with the tools they
18
have and the experiences they have.
19
challenge has been that we're saying throw a ball, but
20
we won't tell them how fast we're throwing it and how
21
far it's got to go because we haven't done the studies.
22
Back in the day when you were adding a generating
I think that -- I don't
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I think the
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plant, you ran all sorts of different contingencies,
2
and you made sure that you didn't impact your neighbor,
3
that you had all the models right, and you knew how
4
that thing was going to play within the system.
5
seems that we haven't done that in some -- in these
6
cases, maybe because there's just so -- the number is
7
so large and has overwhelmed the system.
8
9
It
But we have to get back to, to your point, what do
we need and how do we tune the system, and that
10
includes the in grid-forming inverters.
11
going to tune the system so the controls work together
12
and provide the self-healing smart, you know,
13
resilient, reliable grid that we envision this is going
14
to result in?
15
How are we
Thank you.
MR. PATEL:
So may I add something real quick?
I
16
think -- I think we have been focusing -- so we're in a
17
football season, so let me give you an analogy.
18
team lost the football game over the weekend.
19
I'm here so I can forget about all that.
20
-- they're a pretty good defensive team, but they
21
couldn't move the ball on offense.
22
game, right?
My
I'm glad
But they were
You can't win the
So we are talking about Ride-through
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capability, this frequency deviation for this time.
2
And there is
3
does IBRs do, or any other resources do, when the
4
frequency is abnormal for certain amount of time?
5
-- a big other side of it is that, what
The new IBRs probably can respond much faster
6
during frequency deviation, right?
7
storage can respond much faster.
8
can put some solutions together for the system where
9
the frequency's arrested before it goes too low or too
Battery energy
I think -- I think we
10
high, right?
11
plus or minus 4 hertz per six seconds, or whatever
12
other hertz per 299 second, the other piece, which is
13
not part of PRC-029 right now, which is okay.
14
think there are other ways to make sure that the system
15
together holds, right, and the frequency arrested, and
16
it turn around back to 60 hertz in a -- in a timely
17
manner.
18
I don't think we have to only focus on
MR. GUGEL:
Yep.
Charlie, I've kind of dominated
19
the questions here.
20
you'd like to add at this point?
21
MR. COOK:
22
MR. GUGEL:
But I
Have you -- have you got anything
No, keep going.
Okay.
You know, one of the -- and I'm
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going to go off script here.
2
that we've got here, but one of the things that we saw
3
in the past was an issue with sampling frequency, and
4
the fact that -- sampling frequency.
5
may be harmonics or subharmonics may be affecting what
6
the inverter or other equipment sees as being a
7
frequency or voltage excursion, how do we solve that
8
problem?
9
to in my mind to say, okay, well, I'll just get some
It's not even a question
So the issue that
Is it -- is it -- I mean, it'd be very easy
10
sort of a frequency smoothing device or sampling issues
11
or whatever.
12
can maybe address that and come away with a feeling
13
that we're actually sampling what's occurring on the
14
system and not getting influenced by harmonics that
15
might be out there?
16
MR. HOKE:
But is there -- is there some way that we
That's not in the script, but we can
17
say a little bit about it.
18
and a whole bunch of other people in this room are
19
writing IEEE 2800.2, which is the procedures to verify
20
conformance IEEE 2800.
21
what that does is it takes an IBR unit, which is an
22
individual turbine or an inverter, and do some tests,
So right now, Manish and I
And from a really high level,
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whether that's in a lab or in a field or even in a HIL
2
setup.
3
do any certain thing, but just make sure that its
4
behavior matches its model.
5
model or that IBR unit, which is now verified to match
6
the behavior of the -- of the device itself, and you
7
build a plant-level model, and you do a couple -- a few
8
simulations, fairly simple simulations, really, on
9
that, to make sure that it meets the behavior and --
10
that you need for my IEEE 2800, for example, or from
11
whatever other source requirements document you're
12
looking at.
13
And just doesn't try to make sure that it can
And then you take that
And so you can use a process like that to verify
14
whether a plant is going to trip, for example, when
15
there's a phase jump and confuse that phase jump with
16
the frequency change and trip.
17
phase jump through that plant model, and if it's going
18
to confuse --
19
and think, oh, whoops, the frequency's 72 hertz, I'm
20
going to trip, it's going to fail that test.
21
can use a process like that.
22
If you can then play a
if it's going to get its PLL confused
So you
You would also see it in the testing phase 2
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because you would've put a similar event through the
2
event -- through the actual hardware inverter or
3
turbine, and you would've seen, oh well, that turbine
4
didn't behave how we hoped it would.
5
through that sort of a process, which, you know, like I
6
said, right now we're writing this in 2800.2, but these
7
are processes that manufacturers are already using.
8
Manufacturers are already testing their devices, not
9
exactly using the procedure we're writing because we're
And so I think
10
writing them now, but they're also validating their
11
models against their hardware, at least I believe all
12
the manufacturers that we saw up here this morning are.
13
And so that's one approach to that question is sort of
14
a testing -- combination of testing and modeling, I
15
guess, would be the short answer.
16
MR. GUGEL:
Okay.
17
MR. LAUBY:
One thought I had on this is, what
18
we're getting to is, you know, inverters themselves
19
have wonderful characteristics of being able to move
20
very quickly.
21
up our sampling or monitoring very quickly because they
22
need sometimes to act at the speed of light to protect
And so we need to be able then to ramp
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themselves.
2
the sampling rates have to increase or monitoring rates
3
need to increase so that then the remedial actions and
4
mitigations can take place, and also, that that
5
information can flow to other inverters in the area.
6
I'm going off, this is the reason why, and, of course,
7
then they can act accordingly, too.
8
9
So I think, you know, the -- I think that
MR. CHWIALKOWSKI:
I'm going to add to Mark's
comments because I think this is a great place to
10
digress, as an example, PRC-028, for instance, asking
11
for additional data.
12
developer generator that would say we want less
13
reliability.
14
not the case.
15
ERCOT's NOGRR255, looking at IEEE 2800 Table 19, we
16
know this is not easy.
17
stuff.
18
though it's hard, we're willing to do that because we
19
think data is the answer to move forward, to move
20
prospectively through some of these requirements
21
because having the right data will help us make better
22
decisions in the future.
I don't know of a single
That's not the case.
That is absolutely
And looking at PRC-028, looking at
This is hard.
This is not easy
It will cost money, but it's -- you know, even
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Yes, it's hard, yes, we're willing to do it, yes,
2
we have a understanding, but it's not wholly understood
3
yet what kind of equipment we'll have to retrofit out
4
in the field to get this data, but we're willing to do
5
it.
6
comments, too, Mark.
7
That's where we come from, and that backs up your
MR. COOK:
So there's question from the script
8
that I'd like to have addressed right now, and it's
9
Question Number 3.
And it says, what are reasonable
10
solutions to ensure legacy equipment can be compliant
11
with the frequency criteria in Draft PRC-029 Attachment
12
2?
13
MR. GOGGIN:
Yeah, I can offer some thoughts
14
there, and I think it's instructive to go back to Order
15
901 from FERC.
16
PRC-024 that has equipment limitation exemption
17
process, and, you know, there are some things similar
18
in the current draft of PRC-029 for the voltage-related
19
requirements.
20
existing resources.
21
22
They pointed to the language that's in
I think that's what is needed for these
You know, I think we heard on the last panel that
there needs to be reasonable accommodation for, you
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know, using declarations or attestations or something
2
like that in cases where it's just not practical to
3
test because, you know, the OEM that built a piece of
4
equipment is no longer there, or, you know, it's no
5
longer supported by the manufacturer, or just, you
6
know, you just -- in many cases you can't physically
7
test for these things.
8
kind of guess what it was, and that's -- you know, I
9
think that's -- again, it's why we don't do retroactive
You have to run simulations and
10
standards.
11
retroactively is extremely challenging.
12
needs to be some reasonable accommodation, yeah.
13
don't want to have a blanket exemption, but at the same
14
time, like, you know, there has to be understanding of
15
the realities of how you can validate this.
16
In many cases, proving a negative
And so there
We
And, you know, I think, again, having this
17
equipment limitation in there is essential.
18
there's a massive cost potentially incurred here if we
19
don't have an exemption for the existing resources.
20
And with, you know, no real upside reliability, it's
21
just going to be, you know, a hundred-plus gigawatts
22
taken offline.
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And, you know, I think, you know, we've heard
2
about, you know, what Order 901 says.
3
exemption for frequency is entirely consistent with
4
FERC's directive there.
5
I have a little insight here.
6
don't work at FERC and I'm not a lawyer, but FERC was
7
responding to comments that I helped ACP CIA write when
8
it talked about the exemption for voltage Ride-through.
9
And we'd had a back-and-forth in the NOPR, the notice
I think having
If you read it contextually -I'm not -- obviously, I
10
of proposed rulemaking, with FERC about the voltage
11
requirements, and basically we said, you know, there
12
might be some challenges with existing resources, and
13
then FERC was basically saying, okay, you can have an
14
exemption for existing resources that would have to
15
replace hardware to meet the voltage requirement.
16
FERC was silent on frequency Ride-through
17
requirements because we weren't talking about that in
18
the comments that we were submitting.
19
that they were okay with exemptions for resources that
20
would have to replace their equipment, and, you know,
21
FERC's logic is there's not a lot of these, they're
22
going to be replacing their equipment anyway as
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inverters age out, and, you know, we're repowering the
2
wind fleet anyway, and so there's no reliability risk
3
here, so we can have these exemptions.
4
That logic all applies for frequency Ride-through,
5
and so I think, you know, there's very clear logic from
6
FERC as to why there should be an exemption process
7
that looks like what's in PRC-024.
8
again, pointed to PRC-024 when they were directing NERC
9
how to set up this exemption process.
10
MR. GUGEL:
Yeah.
And FERC actually,
I would even extend on what you
11
said earlier, not only looking at reliability benefit,
12
but reliability deficit for the retirement of, you
13
know, hundreds of gigawatts of energy that's out there.
14
You know, that should be taken into account, too, so I
15
think -- I think that's a really good point.
16
MR. LAUBY:
I would add to that, I think it's
17
important that we understand -- we planning engineers
18
understand what is the state of the network.
19
the state of the generators in the sense that when I do
20
my studies and I have an overfrequency, I know which
21
ones are going to go out and which ones are going to
22
hang on.
What is
I also want to understand the implications of
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the ones that go out on the ones that did stay on, and
2
do they create more of a frequency issue.
3
going through the process of -- you know, going through
4
the attestations and understanding the state of the
5
generators that are on the network, plus, of course,
6
those that we're adding, that when we do our system
7
studies, we'll have a much clearer picture of really
8
where we stand.
9
MR. GUGEL:
Yeah.
So I think
I think, not to get too far off
10
topic here, and we want to go to the questions online
11
and in the room.
12
has pointed to is the fact that we need to have these
13
same conversations about models as we get into the next
14
phases of 901.
15
crucial that we get us in the room again and talk about
16
those issues through that.
17
have any questions here in the room or online.
18
Bueller?
I think one of the things that today
19
(Laughter.)
20
MR. YEUNG:
And I think it's going to be very
With that, let's see if we
Yeah, I'm on.
I had to get clearance
21
from Jamie first before I asked this question because
22
I'm a -- I'm a moderator for tomorrow.
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question is solely from the ISO/RTO perspective.
2
name is Charles Young with Southwest Power Pool, and
3
I'm not sure if there's many other RTOs in the room
4
here today, so I thought -- I want to raise this issue.
5
My
First of all, I want to point out what Mark said.
6
I'll call that Letter A.
7
frequency response provides a lot of automation and
8
adds resiliency to the grid.
9
knowing that the proliferation of IBRs is jeopardizing
Mark mentioned this expanded
So that's very important
10
some of that stability, you know, operating in the
11
unknown states, right?
12
said, and I'll call that Letter B.
13
very clearly PRC-024, it's not a Ride-through standard.
14
It's a -- basically a frequency limitations-settings
15
standard to prevent, you know, resources from dropping
16
offline during conditions or the where the grid is, you
17
know, in excessive frequency declines or rises.
18
an operator, as an ISO/RTO operator, I'd like to get to
19
Letter A, Mark's model, the future resiliency and
20
automation, produce light things to work and not have
21
to intervene to avoid Letter B, you know, this relay
22
operation when frequencies are either excessive or
The second thing is what Manish
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So as
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high.
So how does an ISO do that?
How do -- how do we
3
get resiliency without getting into PRC-024 operations?
4
The only tools we have as operators is operator
5
intervention, and that can be a range of things, right?
6
We can reconfigure the grid, we can put resources on
7
resources online, and, as an RTO, it could be out of
8
merit, more than likely out of merit, or we can do
9
curtailments of those assets we believe are at risk.
10
So that's our choice.
11
about the operator's tools and how these benefit the
12
operator.
13
MR. LAUBY:
I'm not hearing a lot today
I left it on this time just in case.
14
I think the way to get to it, of course, as a -- I'm
15
thinking operational planning drop, right?
16
-- like you say, we got to model this stuff.
17
know -- we don't want to be running the system in
18
unstudied states, so we need the information on what
19
the expectations are.
20
Every one of these plants, how are they going to be
21
behave under certain system conditions so that when we
22
study them ahead of time, you can pre-position yourself
You got to
We got to
How are they going to behave?
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rather than kind of go, oh, surprise, guess what,
2
another thing happened and another thing happened.
3
The idea that we need a unique models for every
4
one of these, I hope we can get around that, but at
5
some point or another, at least being able to
6
understand that during certain events, what your
7
expectations are going to be.
8
into your IRO standards about contingencies that you're
9
going to run on your system because you have a certain
10
expectation that when a line-to-ground fault comes on,
11
you're going to lose 500 megawatts of solar voltaic,
12
and so then you got to make sure you're ready for that,
13
as opposed to running blind.
14
And that feeds right
Of course you can haul the planners in later on if
15
you want and say, hey, you got to fix this.
16
the planning stage, right?
17
getting into, well, what the standard is and what's --
18
what equipment we're going to be acquiring going
19
forward.
20
right.
21
because you don't have the models, and you don't have
22
the knowledge of how those devices are going to perform
That's in
And that's when you start
But I think you're -- right now, you're
You're kind of running a little bit blind
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during certain events.
2
fly.
3
MR. PATEL:
You're kind of learning on the
So real quick, Charles, I think that's
4
a million-dollar question that we don't know the answer
5
to.
6
perspective, but if you think -- I used to be a
7
transmission owner or protection control engineer until
8
recently, and, you know, to protect my system, I need
9
to know what the system will look like or what the
I mean, you asked the question from ISO/RTO
10
system will be able to provide in terms of falcon or
11
what type of falcon, and then I can set a protection.
12
But I think it's a million-dollar question that we
13
don't know the answer to yet.
14
days a year and then 20 years out in future, right, you
15
have very different operating scenarios when you go
16
through different days, different months, different
17
years, so.
18
MR. CHWIALKOWSKI:
Thinking of 24/7, 365
I'll add one thing to that,
19
also, just to answer your question.
20
you out, we do need better modeling, no question, but
21
better data also is important.
22
the things that I think are very important that we can
I think to help
I mean, that's two of
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look at retrospectively versus prospectively, where we
2
have the technical capability and it's also
3
commercially reasonable.
4
that balance, right, of going down that path.
5
going to quote Alex from earlier this morning where he
6
mentioned, you know, what is it that we should focus on
7
moving forward?
8
right there, right in front of us -- better data
9
collection and then better modeling -- and for that, we
That's where you establish
I think a couple of solutions are
10
need our source of truth, the OEMs.
11
there.
12
And I'm
MR. SCHMIDT GRAU:
So, Alex, you're
So Thomas, Vestas, here.
Just
13
kind of a segue of this as well.
14
following, at least from Vesta's perspective, is the
15
same hardware.
16
states.
17
when we talk about the PRC-029, for me, that's a
18
capability requirement.
19
has to perform.
20
tools of we're going to get data, better modeling, and
21
so on, what is the kind of vision to start developing
22
some more direct performance requirements on how to do
Grid forming, grid
That's different software at current
So I think it's also important to understand
It's not about how the plant
It's an envelope on it, and with these
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-- because what are we going to do as an OEM?
2
should we design our control for if the frequency goes
3
to 58 hertz for hundred milliseconds or 200
4
milliseconds or 300 milliseconds?
5
What
I don't -- I don't see that kind of in the
6
performance on the standards today, and that also
7
creates a lot of different implementation possibilities
8
and different behavior on it.
9
direction on performance requirements and how that
10
11
So I'm looking for some
should look like.
MR. GUGEL:
I'll take the first step on that.
12
Nice for the compliance guy to jump in here, I know,
13
and you're all fading.
14
to the technical experts to develop some reliability
15
guidelines around that.
16
we -- what we set up at NERC for reliability standards
17
as being the guardrails, if you will, the extremes.
18
But I think once you operate within that, then really
19
you're looking toward your technical experts to decide
20
what should be a best practice.
21
air quotes there because everybody's hates to do that
22
because they're public utility commissions, hold to
You know, I really would look
You can kind of think of what
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them the different things.
2
within that, there's probably better ways to operate
3
and less better ways to operate.
4
least from our perspective, we wouldn't define that in
5
a reliability standard, but instead, that would be more
6
operating practices.
7
from the panel here on that?
8
9
MR. PATEL:
But, you know, when you're
I don't think, at
Any other thoughts from the --
So real quick, I think -- I think -- I
think what you mentioned is very important, but I think
10
the answer to some of those questions will be system
11
dependent, right?
12
system can perform a little bit differently than a 50-
13
megawatt on a 46 KV system, right?
14
very difficult to standardize how to utilize some of
15
those performance requirements.
16
on system studies and need of the grid, and all that
17
kind of stuff.
18
that kind of provides an educational material to
19
engineers about how to utilize some of those
20
capabilities, but I think standardization is too early
21
for something like that.
22
A 200-megawatt solar on a 500 KV
So I think it's
I think it'll go based
So maybe your reliability guideline,
MR. SCHMIDT GRAU:
It makes perfect sense because
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I think it's very important to, you know, as you said,
2
Manish, also, we should have the equipment, try to
3
correct the frequency before we hit the envelopes, and
4
that, for me, goes in into some of the performance.
5
know we have extremely fast sampling from a plant
6
level.
7
that sometimes turns out to be very negative as well.
8
In Texas where you have a very small deadband of
9
frequency, we sometimes go in and out of frequency
I
I can talk more on that in one-on-ones, and
10
control 25 times in four seconds, you know.
11
re reacting too fast because there's a performance
12
requirement stating you're not allowed to have any
13
artificial delay on your response, so we just like bang
14
in and out, in and out constantly.
So we're
15
So that's where some of these performance and
16
understanding is also faster is not always better.
17
also have to slow down things, and that's where we need
18
to balance it.
19
20
MR. GUGEL:
We
You probably also have situations
where you have units fighting each other, right --
21
MR. SCHMIDT GRAU:
22
MR. GUGEL:
Yeah.
As they're popping in and out, they're
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actually reacting to each other on that too, which --
2
3
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MR. SCHMIDT GRAU:
Ask Todd about that with his
three OEMs in one plant.
4
MR. COOK:
Yeah, excuse me.
Scott, you stood up
5
while ago, and I didn't recognize you.
6
Do you have a question or did it get answered or asked?
7
MR. KARPIEL:
8
MR. COOK:
9
MR. GUGEL:
10
I apologize.
(Off mic comment.)
Okay.
I tried to lead us there, but, you
know.
11
(Laughter.)
12
MR. VENKITANARAYANAN:
Nath Venkiti, GE Vernova.
13
My question is, I think there is a general intent to
14
try and align PRC-029 somewhat to IEEE 2800, you know,
15
not exactly.
16
to have a basis in IEEE 2800, but there are also some
17
substantial differences, and I wanted to understand if
18
those substantial differences are intentional or if
19
they might actually be accidental.
20
examples.
21
22
But like, the Ride-throughs curves seem
I'll give you some
Like for example, IEEE 2800 has an MFRT
requirement, and it starts off with a paragraph, and
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the first bullet under that paragraph says that the IBR
2
shall not be required to withstand more than four
3
consecutive voltage dips.
4
picked up in PRC-029.
5
say in the second and third and fourth bullets that if
6
the voltage dip is less than 50 percent, then it only
7
needs to withstand two consecutive voltage dips and not
8
four.
9
PRC-029, and that kind of raises a question in my mind
10
11
Okay.
That first bullet was
Now, IEEE 2800 then goes on to
So those subsequent bullets were eliminated from
as to whether this is really intentional or accidental.
Another example, IEEE 2800, the example that I
12
brought up this morning about the one-cycle Ride-
13
through requirement for transient overvoltages.
14
heard that there is -- there's kind of -- some kind of
15
intention behind that, but accidentally, what that has
16
done is impose a requirement that the IBR units
17
withstand any transient overvoltage that is less than
18
one cycle, an infinite magnitude of that voltage that
19
is less than one cycle, right?
20
it's been translated to.
21
22
Other examples:
Now, I
That's exactly what
IEEE 2800 said wind turbines,
which a typical wind turbine with its blade at its
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12:00 position can be -- an offshore wind turbine can
2
be as tall as the Empire State Building.
3
said, if you have mechanical resonances during MFRT
4
events, then the wind turbine is allowed to trip to
5
protect itself from those resonances.
6
in PRC-029.
7
for -- right?
8
certain equipment standards for auxiliaries and said if
9
you go outside the envelope of V over F or F over V
So IEEE 2800
That part is not
Another example IEEE 2800 says V over F,
For V over F, it said -- it referenced
10
capabilities as specified in those standards for those
11
auxiliary equipment, then you're allowed to modulate
12
reactive power so as to adjust voltage and try to stay
13
within those limits so that you don't trip.
14
requirement was f eliminated from PRC-029.
That
15
So again, I'm just asking for the view of this
16
panel is, do you think this is intentional or maybe
17
accidental?
18
MR. GUGEL:
So at the risk of providing a non-
19
answer, I'm not sure that this panel could speak to
20
that because they weren't on the Drafting Team.
They
21
weren't the ones that made the decision on that.
I
22
think that would be a good question to have the
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Drafting Team and then also the Standards Committee as
2
they're looking at making this modification.
3
don't know that this panel could speak to the intent as
4
to whether or not it was intentional or not.
5
MR. VENKITANARAYANAN:
Okay.
But I
Yeah, I didn't find
6
another forum to ask the question, so I just wanted to
7
see if there was any -- if this --
8
9
MR. PATEL:
May I -- may I?
So with all due
respect to Husam and Shawn, I'm not a member of the
10
Standard Drafting Team, but I joke that I'm an honorary
11
member because I'm equally vocal as an observer --
12
(Laughter.)
13
MR. PATEL:
-- and they value the input that
14
encourages me to talk.
15
voltage dip and transient overvoltage are the biggest
16
nightmares of my life.
17
dead.
18
frequency Ride-through -- is a good 20-page material
19
that was written by a lot of folks very carefully, and
20
PRC-029 is, what, three page requirements document?
21
we went into 2800 and picked up few tables and few
22
statements and put it into PRC-029.
I think -- so consecutive
I'll remember it until I'm
The Clause 7 in 2800 -- that is voltage and
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I think that's the risk, right?
This 20-page
2
story in 2800 became a three- or four-page writeup in
3
PRC-029 with all the measures and every other fluff
4
that needs to go into the NERC standard, right, and
5
that's actually the problem.
6
Nath.
7
go and pick some bits and pieces from 2800 and put it
8
somewhere else, we have to make sure that the dots are
9
connected appropriately so there is no ambiguity or
10
I do agree with you,
I think we have to be very careful that when we
unintentional consequences.
11
MR. VENKITANARAYANAN:
12
MR. MAJUMDER:
Thank you.
I'll just offer this to answer
13
Nath's question that it was not accidental.
14
it there.
15
intentional, I would not get into that.
16
would offer is the standard of thinking needs to
17
understand models are very important, but let's not
18
make reliability standard only thinking of PSCAD and
19
PSSE.
20
equipment, everything Nath just said.
21
are extremely important, so I'm so glad that in
22
Technical Conference, we have great participation from
I'll leave
Whether it -- whether or not it was
It way beyond PSCAD and a PSSE.
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It's a physical
Those insights
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the OEMs who are sharing their insight.
This is one, in my mind, is a missing piece.
The
3
Standard Drafting Team needed to consider that what are
4
the physical insight.
5
changing from 1.7 to 1.8 can be done in seconds, but
6
the consequence of changing that 1.7 to 1.8 does not
7
happen instantaneously.
8
that is there, and even in the model, not just mention
9
about the mechanical resonance, not a single PSCAD
Going into a PSCAD model and
There is a massive process
10
model would capture this.
11
rise on a DC chopper, which model is capturing that?
12
We have issue of temperature
So therefore, when we get a question like, okay,
13
let's find out what hardware element, I think the
14
previous panel said many times it's not -- you cannot
15
just put your finger one specific hardware element,
16
that's the reason.
17
combination, so it's not only just an IP.
18
is an issue, but the outcome of so many complex element
19
creating a trip, it is -- it is not easy.
20
think beyond modeling space, let's think from an
21
equipment perspective, and listen to all these expert
22
while we are making further decision.
It can be a very complex
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Of course IP
So let's
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MR. BENNETT:
Okay.
Thank you.
I don't think
2
we're terminating this panel just quite yet.
3
we can take a couple questions from online and give
4
them an opportunity to participate?
5
MS. CASUSCELLI:
6
MR. BENNETT:
7
MS. CASUSCELLI:
Yeah.
I'll ask a couple of questions
from online.
9
for land-based resources.
11
Thanks, Todd.
Okay.
8
10
Yeah.
I think
So most of the discussion so far has been
Are there different voltage-
related concerns for offshore wind?
MR. GOGGIN:
I'm not going to get into the
12
technical details.
13
I have mentioned the need to have the standard apply
14
prospectively from the signing of the interconnection
15
agreement and not being placed in service as it is in
16
the current draft is because of the long lead time for
17
offshore wind, but also, you know, other land-based
18
wind, you know, and solar and batteries also can have
19
long lead times between, you know, when they sign the
20
interconnection agreement and -- I'm sorry -- when
21
they, you know, start developing the project and, you
22
know, buy equipment and develop settings and things
I would note part of the reason why
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like.
2
effect for plants in service as is in the current draft
3
would not work for these longer lead assets.
4
that's -- you know, that's necessary to, you know, set
5
the requirements and have them take effect based on
6
resources -- signing the interconnection agreement
7
after the date, you know, the implementation of the
8
standard.
9
And so, you know, having the requirements take
MR. LAUBY:
And so
I was talking to my friend from EDF
10
here because they have a lot of offshore and, you know,
11
many times the collector systems are DC, and one would
12
have to do the study work to see if that has any
13
implication.
14
offshore than they are onshore, but that might be one
15
study that needs to be done, see if there's
16
implications of the AC-to-DC collection and the --
17
another set of inverters there.
18
But certainly they're more rugged
MR. GUGEL:
Probably interconnection methods would
19
be another way of looking at it, whether or not it's
20
radial or whether or not it's connected at multiple
21
points, because a radial one would have different
22
voltage issues, I would think, than something that
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would be more of a network connection.
2
MS. CASUSCELLI:
All right.
Thank you.
One more
3
from online.
4
all of the vendors, and so how does NERC plan to
5
address the different IBR technologies that were not
6
represented on the panels?
7
The OEM panels do not seem to represent
MR. GUGEL:
I guess a good answer wouldn't be
8
we're just going to make up some stuff for the rest of
9
it.
10
(Laughter.)
11
MR. GUGEL:
No.
So there's -- this is still a
12
very public process, and I know the Drafting Team in
13
the past has tried to reach out to OEMs to get as much
14
information as they can.
15
more OEM representation online at this point.
16
that the Drafting Team and others would welcome any
17
comments and any input that you would have from your
18
perspective on that, too.
19
we know there's also some that, you know, are no longer
20
in production.
21
information from those, but kind of information that
22
can be provided to help further a knowledge about what
I'm hoping that we have even
I know
Certainly from active OEMs,
It'd be very difficult to get
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is out there on the system and what is going to be
2
projected out there in the future would be very much
3
welcomed.
4
MR. GOGGIN:
I would just chime in that this is
5
all the more reason to not do retroactive standards.
6
It's extremely challenging to make sure that those
7
standards work for everything that's out there,
8
including the stuff that was built decades ago by
9
somebody that no longer exist, and prospectively to use
10
2800 because it's what the industry is designing
11
towards, and so that process has already played out.
12
You know, Order 901, we're having to do this very
13
quickly and that approach of not retroactive and IEEE
14
2800 prospectively is the safest way to avoid causing
15
major unintended problems.
16
MR. GUGEL:
Yeah.
So I understand the concern,
17
but we have many standards that are retroactive
18
standards when they go into place.
19
that we need to -- we need to have a concept and a --
20
and a -- and a -- and a -- and a context of how this
21
all fits in, but just because something is a legacy
22
piece of equipment doesn't mean it needs to have
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So I understand
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reliability issues and reliability constraints placed
2
around it as it operates on the system because it can
3
affect reliability just as importantly as things that
4
are placed in the future.
5
MR. GOGGIN:
Yeah, I don't disagree with that.
I
6
think, you know, again, if we do have concerns about
7
existing resources, we should start with the, you know,
8
reliability needs and work backwards from that and
9
design a solution.
You know, this is an extremely fast
10
process, and we need to be careful we're not causing
11
unintended problems in this process.
12
there are real reliability concerns that are left on
13
the table I think there's an opportunity to come back
14
and address those later.
15
greater upside -- or downside risk of, you know, taking
16
off -- unintentionally taking off large amounts of
17
operating resources and causing a reliability problem
18
than there is in, you know, maybe missing a reliability
19
problem that might emerge at some point in the future,
20
then we can fix that later.
21
22
MR. PATEL:
We can -- if
But I think there's much
May I -- may I say a few things?
I
think I agree in general that legacy equipment cannot
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be detrimental to the reliability of the system, right,
2
but I think we also need to look at a little bit bigger
3
picture.
4
presenting earlier today, is that all the disturbance
5
reports that have come out in last seven, eight years,
6
those were because of something like momentary
7
cessation or incorrect measurement of frequency, things
8
like that, a spontaneous reaction of controls to system
9
disturbance.
I wanted to mention this when Alex was
10
When we are talking about frequency Ride-through,
11
I think we are talking about plus or minus 4 hertz per
12
six second.
13
that were actually brought up, right, in disturbance
14
reports then -- and then we make sure that the new IBRs
15
do provide frequency response in a manner that we don't
16
actually get to the boundaries, right, I think -- I
17
think we'll have our problem solved.
18
So I think if we fix some of those issues
MR. GUGEL:
I think potentially that's the case,
19
yes.
20
we continue in every one of these disturbances to see
21
more things that come up, and I think being reactive
22
for each one of these is not really a long-term
The only caveat that I would provide to that is,
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solution for reliability.
2
the parameters and then -- I hate to use the word
3
"force," but have generator owner, operators, OEMs,
4
others go out and validate that they can perform within
5
those parameters, then you don't get into the situation
6
where you fix one problem, and then a year later, you
7
have another issue that occurs on the system that is
8
somewhat related, but not exactly the same as what that
9
previous one was.
I think, instead, if you set
I think that's the concern that, at
10
least we've seen from NERC, is that yeah, we go out and
11
fix things as they happen, but you can't just continue
12
to be reactive.
13
sand and say, these are the performance parameters that
14
need to be met.
15
MR. LAUBY:
We need to at least draw a line in the
Yeah, I agree with you Howard, and
16
again, this gets back to handwaving.
17
beyond handwaving and actually do the hard work, do the
18
modeling, do the simulations.
19
say is true or not until I see the runs, so we can't do
20
it heuristically.
21
are that are mounting on the grid and how do we
22
mitigate them, and what's the pathway to the end state.
We got to get
I don't know if what you
We got to understand what the risks
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So I agree with you a hundred percent, Howard.
2
MR. HOKE:
One other quick comment on that, though
3
-- so I see the -- I see both sides of this.
4
see wanting to go back and fix some of the older stuff,
5
at least the stuff that can be fixed, without going to
6
extreme measures, but I also see the side of, we want
7
to get a Ride-through standard through in a reasonable
8
time frame because in the meantime we're installing
9
even more legacy stuff day by day.
Like, I
And so maybe
10
there's a path where we separate those two things, just
11
put that idea out there, where the legacy -- the legacy
12
retroactive stuff maybe is separate from the -- from
13
the forward-looking stuff.
14
MR. GUGEL:
It might be a good conversation for
15
some of our panels tomorrow, I think that'll be good,
16
yeah.
17
MR. BENNETT:
That's kind of what I was thinking,
18
also, on this is maybe this is a good spot to break for
19
today.
20
collected many questions online.
21
we're going to run out of time to do the Slido polling
22
and kind of go through that exercise, but tomorrow
I will let everybody know that we have
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there'll be an opportunity for that, and I think we're
2
going to circle back to some of our online themes
3
tomorrow once we have -- can maybe discuss that a
4
little bit more internally.
5
about we give everybody a round of applause for this
6
great panel.
7
(Applause.)
8
MR. BENNETT:
9
So I think with that, how
So yes, not just this great panel,
but everybody today.
This was very informative, this
10
was a great session, and I do think we have maybe just
11
a couple small things here at the end.
12
with us today.
13
NERC Board member, and she is the liaison to the NERC
14
Standards Committee.
15
share here at the end of the day?
She is our -- first of all, she's a
16
MS. KELLY:
17
MR. BENNETT:
18
And do you have any remarks to
I do.
Would you like to come over here and
share them or share from over there?
19
MS. KELLY:
20
(Laughter.)
21
MS. KELLY:
22
Sue Kelly's
(Off mic comment.)
I just want to thank everybody who
came today, both virtually and in person, and I want to
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thank the Standards Committee members who are doing all
2
of this work on top of their day jobs.
3
appreciate that.
4
because I know they've spent countless hours working on
5
these issues, and I appreciate those who came today to
6
explain the decisions they made and why they made them.
7
We owe them our thanks.
8
9
Very much
And I want to thank the Drafting Team
I want to talk a little bit about what I've heard
today.
This is a scary thing for me to be doing it,
10
but I'm going to do it anyway.
11
information that we have, the better, and the earlier
12
that we have it, the better.
13
things.
14
had had earlier would've been better.
15
First, I think the more
I think that's one of the
A lot of stuff is coming out today that if we
David Ortiz noted that FERC issued Order 901 based
16
on the record before it.
17
notice and comment rulemaking.
18
took comments, and then they made a decision based upon
19
the comments that they'd gotten.
20
there might be some people who wish they'd been more
21
active earlier on in that docket at FERC, and there's a
22
lesson there.
They did what's known as
They gave notice, they
And in retrospect,
That lesson is be there or be square.
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You really need to participate both at FERC, and now
2
we're obviously following onto the work that FERC
3
assigned us, so it's important to be active earlier
4
rather than later.
5
Second, what I heard is that the role of the
6
original equipment manufacturers is crucially
7
important.
8
glad they came today and spoke about their concerns,
9
and I hope they stay engaged.
They need to be part of the dialogue.
I'm
We heard a lot about the
10
inability to comply with certain of the proposed
11
requirements of PRC-029.
12
today with a better understanding of our need at NERC
13
to ensure that their equipment does not contribute to
14
reliability events in the future.
15
it is going to be installed, so that issue becomes more
16
and more important.
17
I hope they, in turn, leave
And more and more of
Third, I loved Alex Shattuck's Venn diagram.
I
18
love Venn diagrams from sixth grade.
19
few mathematical concepts I was able to absorb.
20
much future Ride-through performance should we demand
21
from our resource base, and how much are we going to
22
have to pay to get that?
It's one of the
How
We cannot use today's
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regional grids and generation mixes to decide how much
2
is enough because, again, as David pointed out this
3
morning, we're anticipating a very quick ramp-up in
4
IBR-based resources.
5
under our feet, and the requirements are going to have
6
to shift as well.
7
And so the ground is shifting
The conservative reliability-based response is to
8
do what I would call the Ride-through standard
9
equivalent of belt and suspenders to, you know, make
10
sure eight ways to Sunday that we are covered on
11
reliability, but that could come at a very high cost,
12
so we have to balance those things as we go through
13
this.
14
generation, as was just referred to, and the efficiency
15
and effectiveness calculus that Alex laid out for us
16
may be different for these resources than for new ones.
17
We also need to consider the issue of legacy
So I'm going to be thinking about all this
18
tonight, and I'm sure you will as well.
19
we'll have another productive day tomorrow.
20
back 9:00 tomorrow, and I will note that breakfast and
21
lunch are up one level -- this is my most important
22
duty -- up one level in River Birch A, and there will
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We'll be
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be signage to direct you.
2
at 8:00.
3
very much for your time and attention and deep thinking
4
today.
Breakfast will be available
I hope to see everybody there.
5
(Applause.)
6
MR. BENNETT:
Thank you
So with that, Sue shared my
7
logistical information, so I believe we're adjourned
8
for the day.
9
So thank you very much, Sue.
[Whereupon, at 3:49 p.m., the Technical Conference
10
was adjourned, to reconvene at 9:00 a.m., Thursday,
11
September 5, 2024.]
12
13
14
15
16
17
18
19
20
21
22
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CERTIFICATE OF TRANSCRIBER
I, Charlene Williamson, do hereby certify that, to the best of my knowledge and belief, the
attached transcript is a true and accurate transcription of the indicated audio recording.
I further certify that I am neither attorney nor counsel for nor related nor employed by any
of the parties to the action; further, that I am not a relative or employee of any attorney or
counsel employed by the parties hereto or financially interested in this action.
9/9/2024
____________________
DATE
_____________________________________
Charlene Williamson
TRANSCRIBER
Technical Conference Day 1
WORD INDEX
<$>
$10 115:16
$2 115:17
<0>
0.1 59:11
0.9 55:15
002 187:10
188:9
006 129:4, 11
024 122:22
129:4 130:12
155:8
024-3 49:18
029 77:13
78:22 102:4
104:20 123:11
140:21 154:7
155:7, 8 181:9
210:4 213:5
224:16
<1>
1 8:19 30:9
50:15 52:22
53:19 54:1, 15
59:20, 21 66:6
87:8 88:20
140:20 142:9,
11 144:4
156:18 160:17
195:16, 19, 22
1,200 72:5
1.2 89:19
1.7 253:5, 6
1.8 88:6 89:16
91:14 182:11
253:5, 6
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1.8-per-unit
89:11
1/Category 32:2
1/Type 36:16
1:00 137:11, 19,
21
10 6:9 26:1
35:3 62:3
83:10 87:8
91:17 99:5, 17
104:11 105:14
112:16, 17
113:1 143:1
144:4, 15 173:2
175:14 177:7
184:9 199:1
217:7 225:20
10,000 99:7
100 61:10
201:16
10X 116:9
12:00 250:1
127 7:10
12th 52:5
138 7:13
14 6:11
15 139:7, 12
148:16 175:14
176:7, 20 217:7
15,000 99:6
109:15 155:13
156:3
15-minute 41:12
47:3 205:13
15-plus 139:21
15th 52:8
16,000 148:16
1830s 14:22
184 7:21
18th 51:22
19 234:15
1970s 15:19
1980 14:22
1980s 15:19
<2>
2 6:16 27:9
30:10 31:1, 21,
22 32:2 35:5
36:16 46:18
54:15 91:3
109:14 110:22
121:21 126:3
142:11 154:5
156:18, 20
160:17 232:22
235:12
2.1 58:14 60:2
2.2 58:13
2.22 60:3
2.3 59:6
2.4 60:4
2.5 60:18
20 30:15 32:4
148:2 154:11,
16 164:21
165:2 176:20
210:12, 17
214:16 243:14
200 51:15 245:3
2002 48:18
200-302nd 104:3
2008 63:4
200-megawatt
246:11
2014 154:13
2016 13:17
22:21 99:6
104:16
2020 48:17, 21
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2020-02 35:20
2021-04 33:10
2022 30:12, 18
48:18 49:4
50:5 72:5
2023 20:5
27:18 28:1
48:16 50:6
135:9
2024 1:13
107:7 266:11
2026 28:2
2030 35:4, 6
205 8:11
20-page 251:18
252:1
215 19:5
22nd 52:5
23 6:14
24 69:14 107:11
24/7 76:5
243:13
244 8:18
245 212:16
25 56:5 76:5
79:20 247:10
25-degree 183:3,
6
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
15, 22 141:2, 8,
9 142:18
143:15 145:6
154:7, 17 155:7
156:13, 15
157:5 177:2
178:11 180:20
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Page 2
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www.TP.One
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183:18
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266:10
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
ABDOLLAHY
2:2
ability 38:22
55:5 111:19
221:17
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28:10, 13 29:8
31:17 33:3, 6
35:15 36:8, 11
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63:11 78:10
84:10 85:8
90:9 92:4
110:9, 16
114:10 117:1
120:3 121:4
123:14 134:17
135:12 136:4,
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142:3 147:11
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152:17 156:15
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20 242:5
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abnormal 49:14
191:11 230:4
9/4/2024
Page 3
absolutely 32:10
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AC/DC 12:12
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accept 185:14
186:13 188:1
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accepted 78:17,
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access 202:21,
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accident 96:14
accidental
248:19 249:10
250:17 252:13
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249:15
accommodation
235:22 236:12
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110:9
account 238:14
accountability
186:2
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176:19
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84:22
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255:16
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www.TP.One
add 43:14 57:1
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Addressing 8:9
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240:8
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
adequate 37:20
162:16 163:2
172:8 185:21
adequately
170:2
adjourned
266:7, 10
Adjournment
8:21
adjust 250:12
adjustments
122:10
adopt 81:6, 22
82:3 188:21, 22
198:3
adopted 178:12
advantage 17:3
63:12 224:22
advised 68:7
73:12
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6, 12, 22 201:1,
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5:8, 17 93:7
affect 223:6
258:3
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216:15
afford 186:3
afraid 207:5
afternoon 77:15
117:16 138:11
140:1 198:9
afternoon's
68:12
age 238:1
AGENDA 6:1, 2
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9/4/2024
Page 4
24:1, 7, 15, 16,
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110:22 111:10
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75:8, 21 76:10,
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103:20
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Scheduling@TP.One
www.TP.One
Alliant 4:4
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88:13 120:13
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184:17 185:20
186:16 221:16
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68:8 70:12
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247:12 250:4, 11
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68:18 136:22
162:16
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already-designed
199:17
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alternate 40:8
ambiguity 252:9
America 6:21
139:11
AMERICAN
1:5 2:15 4:17
Americas 4:21
140:7
amount 25:20,
22 32:17 67:2
85:22 115:19
116:1, 15 120:3
139:3 158:19
203:16 208:1,
11, 15 219:10
230:4
amounts 258:16
amplitude
146:13
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
AMY 2:19
analogy 229:17
analysis 34:11
37:4, 18 38:10,
14 49:8, 13, 16
54:4, 5, 10
73:11 83:11
91:18 154:10
163:2 165:13
181:18 208:7
212:14 226:16
analytics 38:19
analyze 212:17
analyzed 108:10
analyzing 140:9
ancillary 155:15
157:1
and/or 19:12
167:4
ANDREW 3:11
ANDY 3:19
8:15 206:10
215:17
anecdotally
211:1
angle 56:4
answer 57:2
58:2 80:12
119:5 129:20
154:17 166:19
174:5 184:21
186:10, 15
208:3 213:16,
17 214:2 216:5,
12 217:13, 14
221:3 223:22
224:2 233:15
234:19 243:4,
13, 19 246:10
250:19 252:12
256:7
9/4/2024
Page 5
answered
204:15 248:6
answering
152:20
answers 114:18
178:4 179:9
205:12
ANTHES 2:7
anticipate 44:1,
9 140:18 142:5,
15 154:2
anticipating
170:9 265:3
Antitrust 6:6
10:1, 4, 8
Anybody 23:12
111:21 148:4
149:4 198:19
202:10 226:10
anymore 119:8
174:22 175:6, 7
217:9
anyway 11:10
14:18 17:10
75:20 237:22
238:2 263:10
apologize 92:14
248:5
apology 189:20
app 26:17
apparent 77:21
Apparently
126:2
appear 10:4
67:22
appears 137:3
Applause 23:16
95:18, 20 137:8
205:6, 8 262:5,
7 266:5
apple 20:1
apples 129:7
applicability
53:8, 16 203:14,
15
applicable
50:14 53:17
124:21 157:11
195:11
applied 87:15
199:5
applies 238:4
apply 64:6
77:5 91:13
214:13 254:13
applying 77:8
198:13 214:10
217:6
appreciate
20:13 23:10
48:8 95:7
132:16 198:7
205:7 263:3, 5
approach 46:11
81:6, 22 82:3
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233:13 257:13
approach-wise
50:11
appropriate
13:6 27:4
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128:17 136:1
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28:8 252:9
approval 19:12
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approved 53:4
177:3 184:5
Scheduling@TP.One
www.TP.One
April 51:13
AQUINO 2:8
archive 43:15
137:13
area 37:14
70:18 102:13
234:5
areas 20:7
99:15 102:3
Arevon 3:22
arguing 13:16
arguments 12:12
ARISTIDES
4:13
ARNE 4:5
7:20 139:16
154:2, 7
arrested 230:9,
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arresters 153:11
arrestor 182:18
arrestors 90:8
artificial 247:13
as-built 36:11
as-designed
36:11
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asked 40:12
43:13 80:11
184:11 221:1
222:17 239:21
243:5 248:6
asking 41:17
43:17, 18 67:20
72:16 117:12
126:5 148:9
175:3 199:9
226:9 234:10
250:15
asks 121:14
200:1
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
aspect 38:16
39:9
aspects 32:22
34:18
assess 105:10
121:5 189:6
assessment
64:12 66:21
68:3 74:17
assessments 34:9
asset 176:6
assets 36:18
148:19 241:9
255:3
assigned 178:14
264:3
assist 65:4
assistance 19:11
associated 49:2
61:12 100:18
172:17
Associates 2:2
Association 2:5
3:7 4:17
assume 200:22
204:14
assuming 130:3
assumptions
16:15
assurance
181:21
assure 25:13
assuring 28:22
37:4
asynchronous
36:20
atom 66:6
attachment 66:6
87:8 140:20
142:9 144:4
9/4/2024
Page 6
154:5 160:17
235:11
Attachments
160:17
attending 9:9
attention 27:4
82:6 140:14
151:16 202:1
266:3
attest 163:16
attestations
167:20 236:1
239:4
attested 120:17
attorney 21:16
attribute 51:1
66:1, 3
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audience 9:14
August 52:5, 8
195:7
Australia 77:2
200:22 201:2, 9
Australian 77:4
authorities 9:16
automatic 129:2
automation
240:7, 20
auxiliaries
163:8 191:8
220:16 250:8
auxiliary 150:19
162:10 181:20
191:13 192:1
193:21 194:15
196:19 218:11,
20 219:3, 8
222:2, 3 250:11
availability 62:4
93:14
available 13:11
29:1 40:9 54:7
67:9 68:3
149:14 161:7,
11, 12 180:4
266:1
avenue 28:17
averseness 98:20
Avesta's 196:11
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16:17 66:7
91:18 240:21
257:14
avoidance 10:3
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135:6 136:21
150:13
awareness 29:8
B4 185:17
BABIK 2:9
back 27:17
48:16, 17, 18
51:4 66:20
76:22 88:12, 16
91:10 92:2, 4
100:9 106:19
115:12 116:5
120:9 121:17
123:8 129:9
137:11, 14, 19,
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158:4 160:6
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162:15 166:17
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173:8 175:4
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Scheduling@TP.One
www.TP.One
203:21 204:8,
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211:9 215:7
217:12 219:12
222:12, 14
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228:8, 22 229:8
230:16 235:14
258:13 260:16
261:4 262:2
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back-and-forth
237:9
background
27:20 48:4
49:6 90:16
backs 235:5
backup 146:2
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114:15 225:15
227:5, 7 258:8
bad 105:8
129:16 135:3
BAGOT 3:7
balance 63:2
112:8, 9 115:20,
22 119:9 150:7,
10 151:6
152:21 208:19
244:4 247:18
265:12
balancing
117:22
BALDWIN 2:10
ball 228:19
229:21
ballot 51:14
52:7, 12 53:5
balloting 78:18
ballpark 117:3
ban 77:19
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
band 69:12
83:19
bands 69:2
83:12, 17, 21
84:22 103:18,
19 104:13, 18
108:11
bandwidth
37:21
bang 247:13
bar 20:22 218:5
barometer
103:12
base 17:12
56:4 69:13
70:2, 13 91:21
108:21 142:12
143:13, 16, 17
144:1, 9 176:21
210:13 264:21
based 20:7
21:19 36:10
39:5, 6 44:11
57:7 60:6
64:14, 15, 16
66:15 67:10
68:3 69:8, 14
70:15, 16, 21
76:4, 12 79:6
80:15, 18 82:22
83:21 87:6
89:6 91:8, 17
93:13 94:5, 12
97:13 100:5
107:3 111:8
118:15, 16
119:3 122:4, 7
130:1 133:16
141:16 148:21
161:17 162:21
165:3 171:3
9/4/2024
Page 7
186:15 189:22
190:20 216:6
224:8 225:19
226:13 227:6,
16 246:15
255:5 263:15, 18
bases 170:10
basically 88:22
103:8 111:2
112:3 115:21
121:5 153:10
161:8 168:6
171:22 211:19
214:5 219:14
237:11, 13
240:14
basis 20:17
34:1 39:9
108:17 190:8
211:22 248:16
bathroom
206:18
batteries 47:15
211:1 227:2
254:18
battery 131:2
145:22 146:4
230:6
bear 22:1 92:18
BECKMANN
2:11
becoming 13:3,
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began 13:16
beginning 15:3
21:3 189:20
214:21
behalf 48:11
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233:4 241:19, 21
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behavior 203:8
232:4, 6, 9 245:8
believe 13:17
26:15 27:7, 10
47:11, 12 57:1
73:11 74:5
81:1 87:7
88:20 89:14
93:19 194:19
233:11 241:9
266:7
belt 265:9
Belushi 206:20
benchmark
108:13, 15, 19
109:8, 10, 21
bends 76:9
benefit 177:19
238:11 241:11
benefits 85:3
BENNETT 2:13
6:14 23:17, 21
47:7, 16 95:12,
21 137:3, 6, 9,
21 205:2, 9, 18
254:1, 6 261:17
262:8, 17 266:6
BES 49:12
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100:2 101:2
121:22 145:22
218:12 219:1
best 90:1 109:9
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167:14 197:19
199:14 215:5
222:20 223:7
Scheduling@TP.One
www.TP.One
234:21 243:20,
21 244:8, 9, 20
246:2, 3 247:16
263:11, 12, 14
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beyond 63:3
65:16 70:8
72:8 127:20
128:3, 7 164:4
199:16 208:22
226:12 252:19
253:20 260:17
BHESH 4:6
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7 20:1 82:21
83:19 101:11
114:5 119:22
122:8 123:10
126:19 180:22
185:7 191:17,
18 214:13 230:2
bigger 106:3, 4
259:2
biggest 84:17
123:1 169:9
174:10 213:3
251:15
BILL 5:21 99:1
Birch 265:22
birthday 127:6
bit 18:20 25:2
27:19 28:15
36:22 43:10
47:5 60:8
68:22 76:12
80:10 83:13
93:9 96:20
99:11 104:9
105:18 106:14
108:12 114:22
118:9 129:7, 13,
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
16 130:18
139:2 143:2
181:7 214:18
219:17 222:16,
20 224:17
225:7 228:11
231:17 242:20
246:12 259:2
262:4 263:8
bite 20:1
bits 252:7
black 226:7
blackout 82:20
blade 249:22
blanket 87:21
121:12, 13
236:13
bled 166:16
bless 160:10
blind 242:13, 20
blindly 77:8
blink 129:6
block 38:13, 17
59:19 202:20
blocking 59:10
blocks 202:21
Blue 22:21
104:16 106:5
111:11 122:20
Board 4:3, 10
6:9, 11 8:19
10:12 19:18
30:17 52:8
158:10, 14
185:8 215:9
262:13
boat 125:7
bomb 107:22
108:1
book 11:21
booked 173:16
9/4/2024
Page 8
booster 59:20,
21
BOP 91:9
border 194:4
BORIS 5:16
bottom 9:19
99:14 117:15
126:20
bounce 16:3
boundaries
56:16 141:4
259:16
boundary 70:16
bounds 107:5, 6
109:4 110:15
115:8 226:12
box 117:18, 19,
20, 21
boxes 38:19
BOYD 2:14
BPS 153:20
167:3
brain 152:1
branching
110:10
brand 117:21
BRC 69:14
74:16
BRC/TRT
74:11, 17
bread 185:8
break 33:9, 11
41:13 47:3, 6
137:11, 18
205:13, 17
261:18
breakdown
151:5
breaker 75:11
190:14 191:16
breakfast
265:20 266:1
Brief 96:6
Briefing 6:5
briefly 179:8
206:7
bring 14:5
70:12 82:6
137:17 139:13
151:16 202:1
broad 67:6
85:1 139:13
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broken 189:21
brought 20:4
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144:19 147:2
214:9 249:12
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Bueller 239:18
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Scheduling@TP.One
www.TP.One
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business 12:6
174:22 175:5
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buy 17:11
115:2, 4 254:22
buying 115:1
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calculate 62:20
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
73:6 169:16
188:10 208:5
240:6, 12 265:8
called 182:17
calling 88:17
calls 16:14
Camry 98:16
cap 146:4
196:16
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122:19 123:5
124:17 158:12
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capability 38:22
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capability-based
36:1 54:4
capability's 78:6
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capable 36:5
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capacity 101:5
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care 136:2
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Scheduling@TP.One
www.TP.One
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Challenges 8:10
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
19 210:19
221:10 237:12
challenging
53:1 58:1 90:2
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chance 140:17
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Scheduling@TP.One
www.TP.One
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colleagues
143:11 144:12
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collected 261:20
collecting 46:1
collection 99:20
244:9 255:16
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
collector 75:10
143:20 255:11
college 71:7
columns 40:5
combination
146:18 233:14
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combine 112:11
combined 50:3
come 13:15, 18
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Scheduling@TP.One
www.TP.One
companies
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Compliance 6:6
10:8 56:6, 9, 14
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
92:11 93:4
178:18 245:12
compliant 93:16
172:3, 13 235:10
complicated
160:5
complications
183:10
comply 79:17
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component
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147:10 161:11
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concept 76:2, 11
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concern 60:5
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Scheduling@TP.One
www.TP.One
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Consulting 5:2
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
97:17 99:3
169:3 207:8
259:20 260:11
continued 3:1
4:1 5:1 7:3 8:5
continuous 57:9
58:14 72:11
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9/4/2024
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converter 53:10
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Cooperative
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CORPORATION
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corrective 74:22
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Scheduling@TP.One
www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
123:20 124:1, 5,
15, 21 138:5
140:20 142:7
154:4 158:4
160:16 172:18
179:15 181:16
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currently-beingdesigned 181:16
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curtailments
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
94:16 123:16
191:13 197:19
dealing 88:21
dealt 94:17
decade 23:8
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decent 124:22
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9/4/2024
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definitely 20:12
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definitive
213:16, 17 216:5
degrees 56:5
79:20
delay 153:9
179:1, 2 247:13
delays 179:3
demand 264:20
DEMBOWSKI
3:5
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168:20
demonstrate
93:15
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13:2
depend 192:19
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123:18 221:15
225:4 246:11
depending
180:1 209:15
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215:1
describe 10:18
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203:20 204:6
describes 19:6
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167:11
design 29:15
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56:13, 15 73:18
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90:11 113:16
115:19 117:4
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Scheduling@TP.One
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34:15 35:7
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
143:13 158:16,
18 178:7, 14
179:4 182:3
developments
43:9 181:12
deviate 78:20
103:22
deviating 79:18
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90:8 94:19
99:22 102:2
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114:21
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
Ditto 14:16
dive 186:7
diverge 79:2
divert 79:9
division 81:4
docket 263:21
document 163:1
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dots 252:8
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
effective 29:21
64:5 98:11
112:15 113:5
115:12 125:10
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265:15
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(800.367.3376)
Technical Conference Day 1
154:3 155:6, 16
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
248:15 249:19
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
247:5 252:21
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extremes 114:21
124:17, 18
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finish 20:15
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Fire 22:21
firm 101:13
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
121:8
firmly 42:4
firmware 121:1
145:21 146:9,
12 147:21
148:18 158:17
175:2 187:15
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
224:11 234:19
242:19 244:7
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109:12 215:18
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Scheduling@TP.One
www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
Gas 2:7 228:6
gathered 176:19
GE 4:5, 9 5:15
7:20 87:2
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www.TP.One
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22 265:12
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
GO/GOPs 31:1
goal 96:11
God 160:10
goes 59:21
74:15 86:11
115:12 132:1
163:7 190:12
191:9 226:7
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
47:9 95:18
104:10 109:2
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133:20 134:19
137:6 153:20
172:10 234:9
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grids 265:1
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ground 12:19
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group 15:5
128:22 139:8
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groups 39:11
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175:19 193:14
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64:15
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
16 119:3 122:4
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heads 221:4
healthy 200:20
hear 13:8
18:10 63:7
77:17 81:15
114:8 119:2, 10
9/4/2024
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www.TP.One
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Holiday 221:2
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
homogeneous
223:15
honorary 251:10
hope 92:1
139:13 242:4
264:9, 11 266:2
hoped 233:4
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210:18 236:21
hundreds 238:13
9/4/2024
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
125:10
implicated 10:8
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255:13
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
install 117:2
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175:22
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
involved 24:5
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216:19
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
KELLY 4:3
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(800.367.3376)
Technical Conference Day 1
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
110:22 113:9
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
11 151:11
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
manufacture
174:21 175:12
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
182:4, 10
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216:16 217:17
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
140:3 147:22
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
nature 45:4
63:5 161:7
187:3
nd 16:11
113:20
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171:5
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
120:22 124:15
125:17, 21
135:4 142:17
143:12, 14
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101:4 206:21
9/4/2024
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nightmares
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
114:5 119:2, 10
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
129:5 201:1
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www.TP.One
page 51:15
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paragraph
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parameter
100:8 140:3
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
158:6 165:12,
16 195:22
202:22 203:7
parameterization
110:1 141:13,
14 146:8 147:19
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
72:16 76:3, 11
84:6, 19 93:4
109:14 111:1
121:21 151:22
175:20 198:14,
16 201:16
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
59:5 60:17
61:14 63:20
64:17 65:8
68:17 71:6
77:17 96:4
99:2 101:15
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104:19 122:21
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127:16 128:4
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PRC-02 33:12
PRC-02024
48:21
PRC-023 49:17
PRC-024 35:20
36:15, 17 48:20
50:17 52:11
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(800.367.3376)
Technical Conference Day 1
10, 11 154:7, 18
171:22 215:22
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240:13 241:3
PRC-0-24-03
49:5
PRC-024-3
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38:16 86:21
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PRC-029-1 6:20
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(800.367.3376)
Technical Conference Day 1
232:13, 21
233:5 235:17
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49:18 55:12
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120:21 135:14
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Scheduling@TP.One
www.TP.One
41:18 43:18
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
PSSE 200:9
252:19
Public 4:17
9:11 195:6
245:22 256:12
publicly 46:1
168:9 169:5
published 99:5
112:2 134:20
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9/4/2024
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putting 17:8, 9
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
93:11, 18 94:2
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react 131:13
9/4/2024
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
52:2 204:19
receiving 109:13
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
remedial 234:3
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remember 74:6
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
requiring 30:12
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
117:14 118:9
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
170:17 194:22
196:8, 11, 15, 17
213:12 215:21
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rode 38:9
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Scheduling@TP.One
www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
77:10 81:17
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89:18 119:13
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
119:15 166:20
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18 169:9
212:22 253:1
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
situation 10:9
203:20 204:6
207:22 224:8
260:5
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247:19
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
139:3 143:4
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
173:6 177:4
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
struggling
228:17
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22:8 28:8 29:8,
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119:21 154:6
sub-cycle 87:22
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Subgroup 91:3
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231:5
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64:11
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submittal 116:19
submitted 19:11
25:13 64:19
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202:7 237:18
subparts 140:21
sub-problems
164:11
subsequent 26:4
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substantial
208:15 248:17,
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substantially
154:12
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192:10, 12
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150:15
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199:12
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Summary 6:15
27:8, 22 179:9
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super 122:1
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Supply 3:7
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Scheduling@TP.One
www.TP.One
173:14 175:8
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71:10 179:22
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250:19 252:8
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265:10, 18
surface 60:6
surge 152:21
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
153:5 182:18
surplus 191:8
surprise 16:9
242:1
surprised 21:8
surveying 176:5
suspect 14:3
suspenders
265:9
sustain 17:14
165:14 177:5
sustaining
173:19
switch 219:18,
21
switching 89:12
90:10
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50:15
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222:6
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15:6
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36:16, 17 44:1,
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67:17 69:5, 9,
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Scheduling@TP.One
www.TP.One
takeaways
126:19
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129:11 143:22
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72:10 75:20
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131:4 135:13
147:18 151:17,
18 177:15
179:20 185:4
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
192:8, 9 193:6
199:8 202:2, 20
207:9 210:15
216:8 220:1
222:5 229:22
237:17 255:9
259:10, 11
talks 75:9
93:11 94:2
130:17
tall 250:2
tandem 34:16
tank 98:15
task 12:20 21:2
80:16
TB 58:8
teacher 18:12
team 28:17
33:14 42:1, 14
47:20 48:3, 7,
10, 17 49:9
50:2, 8, 11, 22
51:7, 9, 16 52:2
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209:4 225:12
228:17 229:18,
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251:1, 10 253:3
256:12, 16 263:3
teams 39:12
175:15
tear 28:11
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Technical 1:10
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20:21 24:20
25:7, 10, 12
26:12 27:14
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46:11 47:10, 14
52:9 69:1 81:7
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Technologies
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100:4
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253:10
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Ten 71:14
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Scheduling@TP.One
www.TP.One
163:19 174:1
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97:3 100:9, 21
135:3 225:3
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Thank 9:8
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17:20 18:7, 18
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18 190:18, 19
198:4, 7 204:13
205:2, 16 207:6
229:14 252:11
253:22 254:1
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
256:2 262:21
263:1, 3 266:2, 8
Thanks 18:9
45:10 68:20
70:22 130:10
132:5 145:4
152:10 157:14
184:12 199:22
203:18 254:5
263:7
themes 262:2
themself 85:20
thermal 69:15
THIERRY 4:16
7:17
thing 21:9, 17
25:19 30:4
38:18 44:14
52:10 65:13, 20
71:22 74:15
77:22 84:17
85:14 86:10
96:11 98:13
106:7 113:22
114:5 115:13
116:2, 8 118:7
122:18 126:10,
17 127:15
133:14 134:11
163:16 176:12
185:18 188:6
194:19 207:3
224:18 229:4
232:3 240:11
242:2 243:18
263:9
things 12:19, 21
34:6 35:14
36:8, 10 37:6
41:3 44:16, 18
67:8 72:7, 10,
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21 259:7, 21
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262:11 263:13
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13 197:20
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19 201:19
202:3, 10
203:18 204:22
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18 208:20
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215:17 216:22
217:14, 15, 20
218:5, 7 220:6,
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20, 22 224:4, 6,
17, 18 225:9, 17
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Scheduling@TP.One
www.TP.One
227:3, 8 228:12,
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18 261:17
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120:12 141:3
249:5 264:17
third-party
167:12
THOMAS 3:14
5:7, 14 7:16
139:5 149:12
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
159:10 166:17
167:7 179:12
204:1 244:12
thorough 144:17
thought 12:10
54:8 56:2
69:19 74:14, 16
76:13 84:11
86:3, 9 89:7
128:1 160:2
206:17 211:4
221:3 233:17
240:4
thoughtful 44:21
thoughts 80:3
119:4 127:13
235:13 246:6
thousands 98:22
100:20
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157:16
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15:13 16:17
20:17 23:19
24:16 30:5
33:9 34:12, 15,
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57:8 59:12
74:1, 2, 12
103:13 109:7
119:13 140:21
178:6, 11, 19
223:19 227:17
248:3 251:20
252:2
three-legged
34:8 38:1
thresholds
127:20, 22
128:4, 8
9/4/2024
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throw 228:19
throwing 228:20
thrown 29:12
thumb 16:13
thunder 104:9
Thursday
266:10
ticking 107:22
tie 69:9
tied 136:17
ties 37:22
TIFFANY 5:19
tight 20:10
tightly 227:1, 4
tightlycontrolled
226:20
time 10:11
13:11, 15, 18, 20
14:14 20:17
23:9, 14 25:20
26:7, 9, 13
27:18 31:18
32:17 33:21
34:3 35:6 39:7
40:12, 13 41:5
48:15, 18 50:6,
20 51:11 52:5
56:17 57:15
58:7 59:21
60:8, 22 62:9
63:14 64:20
68:18 70:10
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84:3, 5, 11, 12
89:17 95:14
99:9 104:15
106:18 107:22
108:1 113:17
115:11 116:20,
21 117:4, 10
118:5 124:13
126:8 129:6
134:14 137:10
138:17 139:4
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148:11 153:13
157:11, 19
158:19 164:8
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219:10 223:10
224:3 225:6
230:1, 4 236:14
241:13, 22
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21 266:3
timeline 20:10
51:6, 10 104:1
119:1 176:8
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timelines 178:4
timely 165:8
230:16
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191:4
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40:18 41:6
119:14 124:16
129:20 144:19
180:22 184:13
247:10 253:14
254:19 255:11
tiny 153:14
TMEIC 4:21
7:18 78:14
140:6 141:6
157:15
Scheduling@TP.One
www.TP.One
today 11:4, 17,
19 12:16 13:9
14:3, 4 15:21
19:22 23:20
24:3 25:2
35:22 39:13
40:18 42:10
45:2 46:15
47:20, 22 48:11
63:7 71:13
72:20 73:18
77:14 96:7
101:19 126:6
138:12 139:3,
15, 20 140:12
155:18 156:2,
10 172:11
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179:19 184:13
192:6, 17 194:1,
12 205:5, 13
210:11 215:19
227:4 239:11,
22 240:4
241:10 245:6
259:4 261:19,
20 262:9, 12, 22
263:5, 9, 13
264:8, 12 266:4
today's 9:18, 22
14:19 148:12
191:8 264:22
TODD 2:13, 20
6:14 8:15
23:20 138:12
199:22 206:11
248:2 254:5
told 96:18
tomorrow 11:4
12:16 13:9
35:2 40:18
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
68:13 72:20
108:2 210:12
239:22 261:15,
22 262:3
265:19, 20
ton 192:8
tone 23:20
tonight 127:9
265:18
tool 26:15
185:12
tools 174:15
185:16 209:19
228:17 241:4,
11 244:20
top 45:14
77:17 100:19
172:1 176:14
263:2
topic 41:4 78:4
81:10 139:10
171:10 239:10
topics 108:5
TOs 161:13
total 99:9
123:11
totally 135:11
225:9
touch 66:19
73:3 170:10
touched 132:21
166:19 179:7
tough 213:20
tower 152:15
165:13
Toyota 98:16
traces 133:22
track 12:18
33:5 138:17
tracking 98:8
traditional 50:10
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traditionally
29:3
TransAlta 2:16
transcript 43:8
transform 11:10
transformation
11:6, 7 16:4
17:5
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11:20
transformer
65:22 72:2
77:12, 18, 21, 22
91:6, 7 92:10
98:3 118:18
151:1 153:15, 16
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91:13 134:8
150:20 155:17
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15:10
transient 88:21
89:4 90:5 91:8
196:6 197:5, 6,
16 249:13, 17
251:15
transiently
89:16
transit 90:17
transition 44:15
95:14
translated
249:20
Transmission
2:15 31:2, 5
53:7, 12, 16
61:12 65:1, 2
71:15, 19
127:18 128:2, 6
166:21 187:5,
22 217:5
218:14 243:7
transparency
201:4
transporting
15:9
TRAVIS 5:11
trees 27:16
tremendously
23:2
tried 62:6
94:13 184:16
216:6 248:9
256:13
trigger 33:20
34:4 37:5, 15
38:22 182:13
188:11
triggered 37:10
39:9
triggers 37:7
38:14
trigonometry
18:14
trip 55:11 56:3,
8 59:17 60:12,
13, 16 61:6
67:12 75:11
76:6 85:20
87:4, 9 88:3, 11,
13 89:20 91:20
183:7, 8, 22
196:17 197:13,
18 232:14, 16,
20 250:4, 13
253:19
tripped 67:3
72:3, 4 109:16
226:2, 3
tripping 61:5
66:8 75:1
Scheduling@TP.One
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100:21 106:15,
21 192:12
195:20
trippings 49:14
trips 88:14
92:2, 4 101:9
trip-setting
216:1
trivial 222:21
trouble 136:14
176:3
TROY 2:15
true 66:15
121:6 123:3
130:19 131:10
132:4 152:6
187:1 195:8
260:19
truly 172:7
trust 110:1
167:16 168:4
Trustee 10:12
52:8
Trustees 4:3, 10
6:9, 11
truth 172:4
213:21 222:15,
22 223:12
244:10
try 17:1 57:14
59:14 62:1, 7
65:5, 17 66:7
67:5 68:17
84:4 89:8 90:1
93:8 96:18
212:20 215:4
232:2 247:2
248:14 250:12
trying 16:22
42:16 67:20
83:15 84:17
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
107:18 116:15
136:18 185:15
211:7 226:5, 11
227:22 228:3
TSO/RTOs
202:18
tune 229:9, 11
tuned 44:22
60:15
tunes 15:19
tuning 118:8
162:22
turbine 69:15
100:8 115:17
117:8 125:6
144:20 147:10,
12, 16 148:7, 17
150:6 151:21
155:16 156:13
157:9 162:11
163:18, 19
164:19 165:3, 4,
11 173:1 176:1
192:1 196:11,
18 203:8
218:22 222:1
223:1, 5 224:1
231:22 233:3
249:22 250:1, 4
turbine-byturbine 176:4
turbines 50:15
142:12, 15
144:12 148:1
150:16 155:12
156:8 163:4, 9
168:17, 21
173:7 174:6
175:12, 16
176:17 180:5
181:20 185:8
9/4/2024
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192:12 195:4,
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218:11 222:18
249:21
turn 10:11
15:20 119:6
138:9 227:11
230:16 264:11
turned 206:22
turns 247:7
tweaks 132:2
twice 99:8
101:10
two 32:15 33:4
35:8, 11 38:19
40:3, 4, 5 42:15
48:5, 9 50:3
54:17, 18 55:7,
17 66:13 71:6
80:21 88:9
91:19 92:1
95:16 99:8
110:3 112:12
113:9 118:16
126:3 129:4
130:2, 3, 5
137:15 159:21
178:11 181:8
197:2, 20
223:17, 18
243:21 249:7
261:10
two-minute
92:14 138:16
type 16:6
27:16 34:20
36:15, 20 50:15
69:16 116:22
142:11, 15
156:18, 20
163:9 195:4, 5
220:9 223:16
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types 30:5
68:11 104:21
119:9 223:17, 20
typical 153:1
157:18 249:22
typically 20:20
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typo 103:6
U.S 23:6 41:22
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UL 195:16
unbounded
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
151:7 155:5
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
view 37:14
250:15
vintages 22:7
violate 10:4
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webinar 9:11,
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Wednesday 1:13
weeds 96:19
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
week 67:13
weekend 229:18
weekends
215:15
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34:2
Welcome 10:15
25:11 256:16
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well 10:20, 21
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Westinghouse
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whatnot 157:22
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widely 9:13
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widen 63:9
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widespread
49:10
width 110:20
wife 215:12
willing 168:9
234:18 235:1, 4
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
willingness 14:8
win 229:21
wind 16:7, 8
36:16, 20 49:12
50:15 54:19
55:8 81:12
100:7, 10, 13, 15,
17, 21 101:5, 7
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windows 99:9
Winter 101:12
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7, 17
witnessed 109:3
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wonderful
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wondering
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world 15:17
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Wrap-Up 8:19
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writing 43:5
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written 11:21
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Scheduling@TP.One
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130:2 214:9
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Xcel 2:19
XIAOYU 5:18
6:21
y'all 96:9
104:9 166:19,
20 167:6 179:7
y'all's 145:12
Yeah 44:13
46:12 48:3, 6, 7,
8, 10, 11, 12, 13,
14 49:3, 14
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172:10 186:4
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197:4 198:20
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 1
199:17, 18
200:22 201:20
204:16, 17, 18
206:15 207:4
209:20 218:3
221:13 228:7,
14 235:13
236:12 238:10
239:9, 20
247:21 248:4
251:5 254:5
257:16 258:5
260:10, 15
261:16
year 20:20
23:5 28:19
32:7, 19 35:8
39:15 50:20
51:8, 12, 22
64:5, 6 113:21
148:15 149:6
170:12, 14
176:20 195:7
223:13, 20
243:14 260:6
years 13:17
20:17 33:4
35:12 48:5, 9
62:3 71:15
76:5, 13 88:15
92:5 99:7
114:2 115:14
117:3 127:1
139:7, 12, 21
143:1 148:2
157:8, 10
172:21 173:2,
10, 17 174:3
175:14 176:7,
18, 20 177:11
178:6, 11, 19
9/4/2024
Page 71
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243:14, 17 259:5
yellow 104:14
Yep 142:8
149:13 179:19
230:18
yesses 189:14
YEUNG 5:20
239:20
York 135:4
young 71:7
240:2
zero 59:13
161:5
zeroing 190:16
zone 60:12, 16
ZURETTI 5:21
Scheduling@TP.One
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800.FOR.DEPO
(800.367.3376)
Transcript of Technical Conference Day 2
Thursday, September 5, 2024
Conference for North American Electric Reliability Corporation
www.TP.One
800.FOR.DEPO (800.367.3376)
Scheduling@TP.One
Reference Number: 145661
Technical Conference Day 2
9/5/2024
Page 1
1
2
3
4
5
6
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
(NERC)
7
8
9
10
Standards Committee and NERC Ride-through
Technical Conference
11
12
13
Thursday, September 5, 2024
14
9:01 a.m.
15
16
17
18
19
20
21
22
Scheduling@TP.One
www.TP.One
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
1
9/5/2024
Page 2
PARTICIPANTS
2
SHAHIN ABDOLLAHY, MPR Associates
3
MARK AHLSTROM, NextEra Energy
4
SYED AHMAD, FERC
5
MELISSA ALFANO, Solar Energy Industries Association
6
HUSAM AL-HADIDI, Manitoba Hydro
7
JOEL ANTHES, Pacific Gas and Electric
8
ROMEL AQUINO, Southern California Edison
9
JOHN BABIK, JEA
10
REBECCA BALDWIN, Spiegel & McDiarmid/TAPS
11
CHRISTIAN BECKMANN MENIG, Siemens Gamesa Renewable
12
Energy
13
TODD BENNETT, AEC, NERC
14
KELSI BOYD, NERC
15
TROY BRUMFIELD, American Transmission Company
16
ADAM BURLOCK, TransAlta Corporation
17
JAMIE CALDERON, Invenergy, NERC
18
JOHNNY CARLISLE, Southern Company
19
AMY CASUSCELLI, Xcel Energy, NERC
20
TODD CHWIALKOWSKI, EDF Renewables
21
KEVIN CONWAY, Western Power Pool
22
CHARLIE COOK, Duke Energy
Scheduling@TP.One
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Technical Conference Day 2
1
9/5/2024
Page 3
PARTICIPANTS (continued)
2
MIGUEL COVA ACOSTA, Vestas
3
SAMIR DAHAL, Siemens Gamesa Renewable Energy
4
MIKAEL DAHLGREN, Hitachi Energy
5
JOEL DEMBOWSKI, Southern Company
6
GERARD DUNBAR, NPCC
7
NANCY E. BAGOT, Electric Power Supply Association
8
MOHAMED EL KHATIB, Invenergy
9
PAMELA FRAZIER, Southern Power Company
10
SEAN GALLAGHER, SEIA
11
ANDREW GALLO, ERCOT, Inc.
12
MICHAEL GOGGIN, Grid Strategies
13
HOWARD GUGEL, NERC
14
THOMAS SCHMIDT GRAU, Vestas
15
MARK GREY, EEI
16
SAMUEL HAKE, AES
17
JOSH HALE, Southern Power Company
18
JOE HENSEL, Minnkota Power Cooperative, Inc.
19
ANDY HOKE, NREL
20
KATIE IVERSEN, AES Clean Energy
21
RHONDA JONES, Invenergy
22
SRINIVAS KAPPAGANTULA, Arevon Energy
Scheduling@TP.One
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Technical Conference Day 2
1
9/5/2024
Page 4
PARTICIPANTS (continued)
2
SCOTT KARPIEL, SMA
3
SUE KELLY, NERC Board of Trustees
4
FRANK KENNEDY, Alliant Energy
5
SOO JIN KIM, NERC
6
ARNE KOERBER, GE Vernova
7
BHESH KRISHNAPPA, SEIA
8
MARK LAUBY, NERC
9
DOMINIQUE LOVE, NERC
10
JASON MACDOWELL, ESIG
11
RAJAT MAJUMDER, GE Vernova , NERC
12
ROB MANNING, NERC Board of Trustees
13
HAYDEN MAPLES, Evergy
14
DAVID MARSHALL, Southern Power Company
15
ARISTIDES MARTINEZ, NextEra Energy
16
AL MCMEEKIN, NERC
17
PATTI METRO, NRECA
18
THIERRY NGASSA, Power Electronics
19
LATIF NURANI, American Public Power Association
20
KAREN ONARAN, ELCON
21
MOHAMED OSMAN, NERC
22
MANISH PATEL, Electric Power Research Institute
Scheduling@TP.One
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Technical Conference Day 2
1
9/5/2024
Page 5
PARTICIPANTS (continued)
2
DINISH PATTABIRAMAN, TMEIC Corporation Americas
3
LEVETRA PITTS, NERC
4
RYAN QUINT, Elevate Energy Consulting
5
SAM RAMSEY, ACP
6
ROBERT REEDY, DOE Solar Technologies Office
7
FABIO RODRIGUEZ, Duke Energy Florida
8
DANE ROGERS, OG&E
9
THOMAS SCHMIDT GRAU, Vestas
10
RUCHI SHAH, AES Clean Energy
11
ALEX SHATTUCK, NERC
12
JOHN SKEATH, NERC
13
TRAVIS SMITH, EEI
14
EWGENIJ STARSCHICH, Siemens Energy, Inc.
15
JEB STENHOUSE, Invenergy
16
KYLE THOMAS, Elevate Energy
17
VAIDHYA VENKITANARAYANAN [Nath Venkit], GE Vernova
18
BORIS VOYNIK, FERC
19
QIUSHI WANG, AES Clean Energy
20
XIAOYU [SHAWN] WANG, NERC
21
TIFFANY WASHINGTON, NERC
22
CHARLES YEUNG, Southwest Power Pool
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Technical Conference Day 2
1
2
9/5/2024
Page 6
PARTICIPANTS (continued)
BILL ZURETTI, EPSA
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
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AGENDA
2
AGENDA
3
ITEM
4
E
5
Recap of Day 1 and Introduction to Day 2
PAG
6
Todd Bennett, AEC
9
7
Soo Jin Kim, NERC
9
8
9
10
11
12
Panel Discussion with Q&A:
Discussion on
Frequency Ride-Through Exemptions in PRC-029-1
Moderators:
Charles Yeung, SPP, and Alex
Shattuck, NERC
Panelists:
Howard Gugle, NERC; Dane Rogers
13
OG&E; Jason MacDowell, ESIG; and Mark
14
Ahlstrom, NextEra
15
16
17
18
19
20
14
Meeting Participants Q&A and Discussion
Presentation:
15
85
Outlining Objectives of a Ride-
Through Definition
Moderators:
Joel Anthes and Husam Al-Hadidi,
2020-02 Drafting Team Members
Q&A and Discussion
116
125
21
22
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2
3
AGENDA (continued)
4
AGENDA
5
ITEM
6
E
7
Presentation:
8
9
PAG
Detailed Review of Milestone 2
Plans
Jamie Calderon, NERC
10
Panel Discussion:
11
Plans and Effective Dates
12
13
14
Moderators:
Strategizing Implementation
Charles Yeung, SPP, and Jamie
Calderon, NERC
Panelists:
152
Howard Gugel, NERC; Sam Hake, AES;
15
Manish Patel, EPRI; and Rhonda Jones,
16
Invenergy
17
157
Meeting Participants Q&A and Discussion
18
Slido Polling:
PRC-029 Voltage and Frequency
19
Slido Polling:
PRC-029 Voltage and Frequency
20
142
198
211
Brought Online in the Future
21
Slido Polling:
22
Closing Remarks and Next Steps
212
Consensus on Implementation Plans
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Todd Bennett, AEC
214
2
Sue Kelly, NERC
222
3
Adjournment
225
4
5
6
P R O C E E D I N G S
MR. BENNETT:
Okay.
Good morning, everybody, and
7
welcome to Day 2 of our technical conference.
8
seen a lot of familiar faces here back in the room, and
9
I think we're starting to fill up online.
We've
So just want
10
to welcome all of our online participants as well as
11
those in the room.
12
As far as major notes this morning, I don't have a
13
lot to add other than I'd just like to encourage our
14
participants to continue the momentum from yesterday
15
and the engagement from yesterday.
16
and I can tell you there was a lot learned from it, and
17
it provided a lot of good data points to help the
18
Standards Committee move forward.
19
Jin, do you have anything you'd like to add?
20
MS. KIM:
All right.
It was top notch,
So with that, Soo
I will be very brief.
I
21
just want to say thank you so much for everyone that
22
participated yesterday.
I think yesterday was a really
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great day.
2
I think we heard from a lot of different voices that I
3
think filled in a lot of the gaps for the different
4
issues that we saw come through on the comments with
5
regards to the standard.
6
I think that we got a lot accomplished, and
I would be really remiss if I did not thank the
7
people who put this event together.
8
what a tremendous task it was to get this type of a
9
conference put together in just a few weeks.
I cannot tell you
So Jamie
10
Calderon, first, I want to thank you because I don't
11
know if everyone understands under her leadership,
12
we've done so much work.
13
with so many different departments and had to bring so
14
many people together just getting these panels
15
together, just getting everyone informed, putting
16
together this agenda, it was under her leadership, so I
17
just want to thank you for that.
18
And we've had to coordinate
Also, we have a tremendous staff here at NERC, and
19
so Levetra, Tiffany, Wanda.
20
not be here today:
21
can't -- the list goes on and on about how many people
22
had to come together to make this event happen.
Also, the staff that could
Alison Oswald, Nasheema Santos.
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All of
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your hard work is so greatly appreciated, and we know
2
we could not have done this event without the
3
tremendous effort that came together in just a very
4
short amount of time.
5
working late at night, early in the mornings, just to
6
make sure that this event came through very seamlessly,
7
not only in person, but online, we owe them a
8
tremendous gratitude.
9
And when I say everyone was
And then I, also, for the other departments that
10
are contributing, the engineering staff, Alex Shattuck,
11
J.P. Skeath, all of the other engineers that have put
12
together a tremendous amount of technical input,
13
provided a lot of advice, thank you for being here.
14
Howard and Mark, thank you for your leadership and also
15
being here today.
16
your participation and all of your remarks because,
17
again, it has been a very collective and collaborative
18
effort, and I think that we are moving forward, and
19
we're making a lot of progress.
20
like to thank the SC members.
21
volunteers here to lead this SC effort.
22
a NERC effort:
Robin, Sue, thank you so much for
Also, I just would
We did get some
It is not just
Todd, Amy, Troy, Charles, everyone
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who's volunteered, thank you so much because after
2
today, there's going to be a tremendous amount of work
3
to get a next draft put together.
4
I just want to remind everyone of our charge.
5
When the Board invoked Rule 321, there are several
6
obligations that we have to meet.
7
to remind everyone that we are addressing this
8
particular project.
9
have been coming in, many people would like to see an
And so I just want
I know based on the comments that
10
expanded effort.
11
open up other standards.
12
have to focus on this Ride-through issue.
13
next task.
14
won't be opening any other standards, and we will be
15
focusing on the particular issues that we had to
16
address with regards to Rule 321, and that is with
17
Ride-through.
18
There are some comments asking us to
I just want to say that we
That is the
That is what's going out for ballot.
We
We get one more ballot, and again, tomorrow starts
19
the new drafting effort.
20
sheet of paper.
21
comments.
22
submitted to NERC staff is lost.
It will not be just a blank
We're taking into account all of the
Nothing that has been submitted online or
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had a limited amount of time, and there's some
2
consternation with regards to submitted questions.
3
Everything is being reviewed.
4
tremendous amount of time to walk through all of the
5
comments.
6
public process, and so we are very committed to that,
7
not just as a department, but as NERC.
8
want everyone to be very assured that if there's any
9
concerns, please reach out to me, and we will make sure
We are taking a
And this is also a very transparent and
10
that comments are addressed.
11
walk through the process with you again.
And so I just
12
We were -- or have to
And the last thing I just want to say is that as
13
we are required to under Rule 321, this will go out to
14
Ballot One more time, and we have to conclude this
15
effort by the 30th.
16
everyone, we are under a very tremendously tight
17
deadline, and so by the 30th, we have to conclude this
18
process in order to present something to the Board in
19
October at an open call for adoption.
20
And so I just want to remind
And with that thank you so much for all of your
21
time.
22
thank you again for being here and online.
I look forward to today's discussions, and I
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(Applause.)
2
MR. BENNETT:
Okay.
Thank you so much, Soo Jin,
3
for those sentiments and kind words and details about
4
the path forward, so thank you so much.
5
So moving right on into our agenda today, I see we
6
have a panel discussion on Frequency Right Through
7
Exemptions in PRC-029.
8
going to be -- help us be a moderator that as well as
9
Alex from NERC, so I believe that if we want to get our
10
So today, I believe Charles is
panel together, we can commence.
11
(Pause.)
12
MR. YEUNG:
Okay.
Good morning.
My name is
13
Charles Yeung.
14
a member of the Standards Committee, also vice chair of
15
one of their subcommittees, the Project Management of
16
Standards Projects.
17
I'm with the Southwest Power Pool.
I'm
Yesterday we heard quite a bit about the frequency
18
Ride-through requirements and how they differ from, of
19
course, PRC-024 and also the IEEE 2800-2022.
20
panel, we're going to be talking about what was left
21
out of the current draft, which is exemptions from
22
frequency Ride-through requirements.
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yesterday, we heard quite a bit about a lot of the
2
obstacles and challenges to meeting PRC-029 frequency
3
Ride-through.
4
talk about, you know, what exemptions would have as far
5
as an impact on how the industry can move forward as
6
far as IBR Ride-through requirements.
7
want to ask the first question, and we can down the
8
panel?
9
So today, our panelist is assembled to
MR. SHATTUCK:
Sure.
So Alex, you
Yeah, we'll get started, and
10
we'll probably just ask one and do follow-ups as we go
11
down the line.
12
the panelists is, what are the financial and practical
13
impacts between hardware- and software-based solutions?
14
And Mark, you can us get started.
15
So our first question today is -- for
MR. AHLSTROM:
Sure.
Mark Ahlstrom.
I'm
16
representing NextEra Energy.
17
to be careful not to underestimate the impacts of, you
18
know, the complexity and the effort of software as well
19
because, as we know, with all the emphasis on modeling
20
and getting all the analysis done, you know, even doing
21
a software upgrade, you know, it takes a lot of
22
engineering analysis, working with every --, you know,
You know, I think we have
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every OEM for the various pieces, not just wind
2
turbines or the solar inverters themselves, but the
3
balance-of-plant issues, you know, coming up with an
4
engineering redesign creating the models, verifying the
5
models.
6
And as I -- as I wrote in my comments, you know,
7
that has to be done on a plant-by-plant basis.
8
plant is different.
9
for a particular wind turbine, for example, you might
Every
Even if you're using the same OEM
10
have different converters.
11
converters in our NextEra fleet, you know, so it takes
12
a lot of effort.
13
talking about having to go out, even for software, to
14
many dozens of plants and many thousands of turbines.
15
And I did put in my written comments by the way, that
16
-- if you'd like to see them, I'd be happy to share
17
them with anybody even if -- I don't know if NERC is
18
going to post them or not, but I'm happy to share them
19
where we went through the entire fleet and looked at
20
the impact, and we'll get to that for the various
21
curves in a bit.
22
We've got more than 10-plus
And then, you know, literally, you're
But I think software impacts are reasonable to
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bring up to 2800 compliance.
2
a couple years to do that because it's a complicated
3
process.
4
magnitude more difficult because all of the engineering
5
with that, and also, like, with wind turbines, you have
6
some up-tower things, you know, you can't --, you know,
7
it can be much more expensive.
8
complicated processes, and we should not underestimate
9
the impact of either of them.
10
I think you have to allow
The hardware upgrades are an order of
MR. MACDOWELL:
Yeah.
But both of these are
Thanks, Mark.
You kicked
11
us off well.
12
here.
13
with GE Vernova's Consulting Services for the last 25
14
years, and, really, you think of GE Vernova as an OEM.
15
Certainly GE Vernova is an OEM.
16
stakeholders here and participants that you heard from
17
yesterday.
18
on systems integration, working not only as an OEM, but
19
more representing system operators and system
20
integration.
21
22
Good morning, everyone.
Jason MacDowell
I actually wear two hats in industry.
I've been
We have a lot of OEM
I work in a group that really focuses more
But the hat I'm wearing today is the second role I
play in industry as the chief system integration
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officer of the Energy System Integration Group.
2
like Mark, we have multiple roles, and Mark
3
representing ESIG as well in some of this -- the
4
industry work that he's doing as president of the board
5
there as well.
6
Just
So I wanted to just build on what Mark was saying
7
relative to the cost implications, and I think, Mark,
8
you alluded also to schedule implications, which is the
9
next question.
And I think, you know, we all recognize
10
that any upgrades that are needed, whether it be
11
software or hardware, is more than just toggling a bit
12
or just installing a part.
13
a manufacturer's point of view, and all the way across
14
the chain with the developers, the plant owners,
15
equipment owners, the system operators, the utilities
16
that needs to be done to accommodate any changes
17
relative to what we'll call standard application
18
products, right?
19
There's a lot of rigor from
And, you know, when there -- if there's a need for
20
a software upgrade or a hardware upgrade, in order to
21
account for that and understand the implications of the
22
benefits of those changes and, ultimately, the impacts
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on their -- on the performance of what they will do to
2
the grid and to the plant design, as Mark alluded to,
3
is looking at the overall implication to the fleet,
4
looking at the overall implication to that set of
5
products.
6
It includes a lot of analysis on the implications of
7
the overall integration of the wind turbine or the
8
solar inverter and the solar system or the plant for
9
that matter.
That includes a lot of engineering analysis.
But it also includes a substantial amount
10
of effort to really understand the implications in
11
terms of modeling.
12
And then there's the open question of when you do
13
the modeling, you got to validate, but what are the
14
aspects that you need to validate that may cause a
15
material change, right?
16
software/hardware implications that we have are to
17
improve the performance, but there are still -- there's
18
the reality that the system operators and the utilities
19
do have processes for interconnection and material
20
change clauses, that if you do change something for the
21
better or otherwise, if you make any upgrade, there is
22
a process to reevaluate that from a system impact point
And no doubt any
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of view, right?
2
considerations and costs that go into system upgrades
3
and what's needed on existing products.
4
So I think those are all of the
For implications on new products, there's a new
5
product, I would say, introduction or integration and
6
new technology integration evaluation that all system
7
-- all OEMs will need to do and be able to communicate
8
that through models, through documentation, and that
9
takes time as well.
So it's -- again, any changes that
10
are made are made deliberately to look at how the
11
product will respond and what is the implication of
12
those changes relative to the lifecycle of the
13
equipment and the -- and also the impact that that
14
would have on the rest of the grid.
15
As Mark also alluded to, any of those changes,
16
particularly around frequency, really depends on the
17
technology, and it depends on the overall design.
18
it's not as easy as a broad sweep to say, oh, that one
19
change to meet a wider band of frequency Ride-through
20
is going to have this implication on this product for
21
this amount of time.
22
design.
So
It really depends on the overall
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There's probably, and I'm reaching out a little
2
bit, and I would love to hear some feedback from my OEM
3
colleagues because this is ultimately an OEM question
4
about the cost implications.
5
the biggest implications, especially on, you know, a
6
system like a wind turbine and also, you know, other
7
aspects like solar inverters and what have you, is
8
looking at the impact of frequency deviation on
9
auxiliaries, right?
But really the -- one of
And those auxiliaries are not --,
10
you know, are not necessarily implicitly modeled in a
11
lot of the system models when we look at the overall
12
performance.
13
And I tell you know, I was on the first PRC-024
14
Drafting Team back in 2007 when we started this journey
15
long time ago, and on -02 as well, and that was the
16
first time that I had experienced, you know, the NERC
17
drafting team process where FERC mandated through Bob
18
Snow, and, Mark, I think you remember Bob, you know,
19
his comments there well, that we needed to have a
20
standard that was completely technology agnostic.
21
22
At that time, the Ride-through curves on both
voltage and frequency were more difficult.
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we had a lot of debate about what is fair, what's
2
reasonable, what's capable, what does the system need
3
relative to the technology at that time, over a decade
4
ago.
5
machine technology, especially on frequency relative to
6
inverter-based technology even at that time.
7
think that's also the case today where we have
8
frequency deviations that are a lot more sensitive on
9
rotating equipment that are not inverter based than the
And it was far more constraining for synchronous
And I
10
inverter based.
11
mind, too, about when we go down the path of looking at
12
the costs relative -- the cost of compliance relative
13
to what the system performance will be, and how each
14
resource will be, you know, integrating and looking at
15
their -- the individual performance.
16
And I think we have to keep that in
We're engineering a system.
We're not engineering
17
one piece of the system in a bubble, and I think, you
18
know, that's a big consideration around the cost of
19
compliance relative to what we expect from renewables
20
to Ride-through compared to the rest of the system.
21
I'll leave it at that.
22
MR. ROGERS:
So
Maybe to take just a little bit of a
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different course because that explains some of the
2
technical difficulties at a high level pretty well.
3
Maybe look at what the actual practical impacts are
4
going to be and financial impacts for the -- for the
5
GOs and how that -- how that has to be considered to
6
some extent.
7
What we've heard a lot today is we don't quite yet
8
know what it's going to take, especially for these
9
legacy -- you know, these much older legacy and even
10
some of the stuff, you know, built in the past decade,
11
what it's going to take to be able to allow those to
12
meet the requirements as set forth in the current
13
draft.
14
be?
15
possible in some instances.
16
We just don't know.
Again, we don't know.
What is that cost going to
We don't even know if it's
So right now with this, you know, and looking
17
specifically at the discussion around exemptions for
18
frequency Ride-through, if passed today as written, we
19
don't know what the impacts -- reliability impacts
20
specifically, but also cost impacts, to eventually the
21
end users, what those reliability impacts are going to
22
be to the bulk power system.
We have no idea, and that
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hasn't been quantified yet.
2
through capability, ROCOF, everything, all these
3
technical issues that have been discussed, do they need
4
to be considered, especially moving forward?
5
Absolutely.
6
that that's not the case.
7
today, if the standard was to pass as written, we don't
8
actually know what the reliability impacts of the bulk
9
power system would be, and there's a chance that it
Does frequency Ride-
I don't think anyone in this room saying
But right now, where we sit
10
could be a net negative.
11
when you're looking at a reliability standard, you have
12
to take very heavy into account.
13
And I think that's something,
So I think I'll just leave it at that.
There's
14
some really excellent discussion about the technical
15
aspects that I'm not going to be able to talk, so -- or
16
top.
17
right now, when we're looking at financial and
18
practical impacts, we don't know what those are going
19
to be, and especially with the practical impacts, we
20
don't know what the scope of that's going to be.
21
don't know how bad it's going to hurt.
22
So I think that's just really my takeaway is
MR. GUGEL:
We
Thank you.
So Howard Gugel, vice president of
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regulatory oversight at NERC.
2
opine on the financial and practical impacts of these,
3
but I just want to opine a little bit on an area that I
4
can, and that's the reliability impacts.
5
that a little bit earlier.
Not sure I can really
You've heard
6
You know, we're in a situation even today where in
7
some of the markets, there are times when 99 percent of
8
the energy being absorbed by the consumer is being done
9
by inverter-based resources, green resources.
If in
10
those scenarios we have frequency excursions that take
11
those offline, nobody's going to ask after the fact
12
what were the financial and practical impacts?
13
going to say, why didn't you guys solve this problem
14
before we got into it?
15
NERC.
16
that we need to make sure that we've got that on --
17
that in our focus.
18
They're
And that's -- I'm not saying
I mean, that's going to be industry as a whole,
So, but I think also you've got to take that into
19
account with what are the practical and financial
20
implications of that.
21
that out the door.
22
a scenario where we are almost entirely being provided
I'm not saying that you throw
I'm just saying that if we get into
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energy by inverter -based resources, and we know that
2
there's an issue with frequency Ride-through or voltage
3
Ride-through, and we haven't addressed somebody's --
4
that we're going to have a lot of questions that we'll
5
have to answer at that point.
6
to take that reliability impact into account when we
7
think about the practical and financial impacts.
8
9
So just, I think we need
In addition, you know, we -- you heard yesterday
that projections are at this point that potentially by
10
the end of the decade, we're going to be at about 50
11
percent of resource that will be inverter-based
12
resources overall, not just at certain times of the
13
year.
14
benefits and reliability impacts that have been
15
provided by synchronous generators can still be
16
provided on the system.
17
impact there also.
18
19
20
21
22
And so we need to ensure that the traditional
MR. YEUNG:
So you've got to look at that
Alex, do you have any other comments
or questions for the first question?
MR. SHATTUCK:
Nope.
Nope.
We can move on to the
next one.
MR. YEUNG:
Okay.
So thanks, Panel.
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lot of unknowns on costs, especially from Dane, his
2
comments, but of course, the other dimension of
3
implementation and compliance to PRC-029 is how long
4
does it take, so the next question is about a timeline.
5
So what is the timeline of this one, specifically about
6
software-based updates, necessary to meet the PRC-029
7
frequency Ride-through requirements, and how does that
8
differ with hardware based?
9
comments that even if it's a software-based solution,
Yesterday we heard some
10
there could be limitations or requirements for hardware
11
upgrades as well.
12
take to do software updates for PRC-029, and does that
13
differ from hardware?
14
So the question is, how long does it
Also, I'd like to add one more dimension based on
15
a lot of the discussion we said yesterday.
16
question is asking about meeting PRC-029 criteria, but
17
if you can also add whether that changes, whether it's
18
2800-2022 criteria instead of the PRC-029 criteria.
19
you want to go this way?
20
21
22
MR. GUGEL:
This
So
I don't think I can opine on that
because, again, that's kind of outside of my bailiwick.
MR. ROGERS:
Yeah.
Again, the technical aspects
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are going to be better handled by the two gentlemen to
2
my right here.
3
can speak to is, you know, from our discussions with
4
our -- with our OEMs, is the uncertainty on this.
5
We've been told, you know, it may be possible for some
6
of the equipment, especially with legacy equipment,
7
it's a -- it's a big unknown if there are going to be
8
software updates that are possible.
9
hardware updates, I mean, to some extent, when you --
But one thing, again, I think that I
And if there's
10
when you use the term, "hardware," eventually it is
11
going to be possible, right, if you go far enough up
12
and build enough things out, you change enough things,
13
you're going to get there.
14
become, you know, much more like a repower and not an
15
update?
16
But at what point does that
Not certain on that.
But again, I think the primary concern, at least
17
from where I sit, is the uncertainty around this and
18
the inability -- the inability for us to know if
19
software-based updates are going to be available for
20
these, if hardware updates are going to be available
21
for these, not necessarily just the timeline, but are
22
they going to exist?
And then if they do exist, what
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is the timeline, and I don't have answers for that,
2
again, back to the uncertainty.
3
MR. MACDOWELL:
So the reason I'm pausing here is
4
because I think, as always, the answer depends.
5
depends on the nature of the upgrade and whether it's
6
software or hardware based.
7
I just said earlier, it's more than just toggling a bit
8
or just installing a part, right?
9
rigor that needs to go into evaluations on the overall
10
equipment, on the integration design, on the modeling,
11
on the validation, on, you know, evaluating if you need
12
to do anything more from the interconnectivity point of
13
view.
14
how much -- how much time does it take manufacturers to
15
decide how to -- how to change things from a software
16
or hardware perspective, but we really need to look at
17
the overall picture of the implication to actually get
18
that deployed and to get it in place so that, you know,
19
the implication of that software or hardware changes
20
realized on the grid.
21
22
It
Like I alluded to and what
There's a lot of
So, you know, the question I think was aimed at
Software changes obviously tend to be a bit
quicker than hardware upgrades as a general point of
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view, but not always, right?
2
of analysis that's needed.
3
responses, as I said before, we're looking more
4
probably at some of the evaluations on impact on the
5
auxiliaries and not, and then that brings up the
6
question, well, how do we represent that at all in our
7
capabilities and modeling?
8
generally through the Ride-through curves and the
9
protection that's applied to fundamental frequency
It depends on the amount
Generally, with frequency
And that's typically,
10
phaser domain models, and maybe in a little bit more
11
detail in EMT models, right?
12
But to generate those curves, it sounds simple,
13
right?
14
that are overlaid with the frequency and the voltage
15
profiles that the models are given.
16
good deal of effort to actually generate those curves,
17
or at least look at the impact of any changes that are
18
happening and see whether there is an -- you know, a
19
need to reevaluate the curves themselves.
20
in a series of systemic, design-based modeling, and
21
also, if needed, testing, depending on the upgrade.
22
So that whole process can take on the order of
They're just a bunch of stepped-based curves
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weeks to months, sometimes even longer, depending on
2
the implication, for a software upgrade.
3
hardware upgrade, it could take on the order of years,
4
right, to go through the overall testing and capability
5
implications on the turbine and on -- you know,
6
ultimately leading up to the modeling and impact on the
7
rest of the grid.
8
thing.
9
consideration on, you know, ultimately how long it's
For a
So I think it's not an overnight
It's something that needs to take in careful
10
realistically going to take to get this overall
11
capability deployed, not just changing, you know, the
12
software or hardware in the equipment itself.
13
MR. SHATTUCK:
Okay.
Before we move on, just to
14
make sure we compare the things we talked about
15
yesterday, but do you have any kind of thoughts, Jason
16
the difference between a timeline for meeting 029 draft
17
language and 2800?
18
MR. MACDOWELL:
Yeah.
I don't have any specific
19
things yet because we haven't done the evaluation
20
specifically relative to everything we have, and,
21
again, I'm speaking on behalf of ESIG --
22
MR. SHATTUCK:
Yep.
Mm-hmm.
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MR. MACDOWELL:
-- not on behalf of GE Vernova.
2
But generally, you know, and many of you know Julia
3
Matevosyan, chief engineer at ESIG, who's been very,
4
very much in the NERC/IRPS -- you know, with you, Alex,
5
in the leadership of IRPS.
6
discussion overall, not only with PRC-029, but Ride-
7
through, and there's a lot of discussion and debate
8
about the overall implications of that.
9
so going back to the discussion that you and I had,
This has been a central
And I think,
10
Mark, maybe even last week, you need to do the
11
analysis, right?
12
look at what specific things are you trying to fix?
13
What are the specific issues that we know that are out
14
there?
15
There needs to be a set of studies to
And I'll caveat this, Alex, with your question to
16
say you did a really nice job outlining what is the
17
real issue in your presentation yesterday morning,
18
looking at all the events that have happened, the
19
frequency deviation on those NERC events that are
20
primarily driven by other things outside of the
21
implication on frequency, right?
22
cessation.
You have momentary
You have all of these questions about how
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solar will respond.
2
bit of wind in that, but it was mostly solar
3
responding.
4
events that were on the order of a gigawatt to maybe
5
gigawatt and a half had very little implication in
6
terms of the grid frequency itself, so it wasn't a
7
frequency Ride-through issue really at all.
8
other things that needed to be coordinated and modeled
9
and taken care of.
10
In some cases, there was a little
The frequency deviation due to those
It was
So I would say, let's look at the issues that
11
we're really trying to resolve, understanding what the
12
real implications are, and then try to solve those
13
instead of having a theoretical what if this happens.
14
And, you know, let me take a step back in PRC-029:
15
what would really cause a frequency deviation that
16
would be that big?
17
large deficit of instantaneous generation tripping
18
offline, very large power plants, likely not renewables
19
at this point, maybe could be if you had gigawatt class
20
renewables, but it could be large nuclear plants.
21
could be a large part of the grid tripping offline that
22
would cause, you know, an underfrequency or a large
You would have to have a very, very
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load like data centers, multiple gigawatts tripping
2
offline, causing an overfrequency.
3
HBDC station tripping offline that caused that event.
4
It's really not renewables that would be the cause of
5
it, but we want to make sure that in those cases, that
6
we don't have a disproportionate of any type of
7
generation tripping offline causing a further
8
reliability risk, right?
9
Could be a large
So those are the types of analyses that we need to
10
be doing.
11
today?
12
And I really think that, you know, as we transition
13
from a world that has a lot of synchronous machines
14
today -- large nuclear, large coal to renewables --
15
those design basis events from that perspective are
16
going to get a little bit smaller.
17
centers that we're seeing and all these large loads
18
that are integrated, those design basis events may be
19
causing us to get bigger.
20
understanding what the frequency deviations are and try
21
to solve for that, and understand what the implications
22
are across all the fleet.
What are the design basis events that we see
What are they -- what are they looking forward?
But with the data
So let's look at that,
And I think that would be
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much better placed to understand the system.
Now, the last thing I'll say about PRC-029, and I
3
will say something about GE -- put my GE hat on just
4
for a second.
5
commissioned to do a study for the Wind Energy
6
Institute of Canada, backed by the renewable -- the
7
Canadian regulator, and worked with David Jacobson,
8
worked with all his system utilities across the board
9
to understand what was the impact.
Several years ago, GE Consulting was
And the big thing
10
that we took away from that is that Manitoba and Quebec
11
had very large and wide frequency bands in their Ride-
12
through characteristics because there are very specific
13
system needs for that.
14
connections in remote parts of the grid that, on
15
purpose, really created the need for these wide
16
frequency Ride-through capabilities.
17
They have large HBDC
And the Canadian grid codes for those provinces
18
tackled that, but generally in most other places around
19
-- all of the interconnections across North America
20
don't need that wide frequency ban.
21
the grid codes there, but we want to make sure that
22
we're looking at fit for purpose across -- a need
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across all of North America.
2
specific needs in any region, making sure those regions
3
have the protections in place to suit those particular
4
needs as needed.
And then if there's any
5
MR. SHATTUCK:
(Off mic comment.)
6
MR. AHLSTROM:
Sure.
I actually think we do have
7
pretty good emerging evidence about the size of the
8
elephant with regard to costs and effort and the
9
difference between the 029 curves and the 2800 curves.
10
Now, NextEra, of course, has a lot of solar and
11
storage, but -- in addition to wind, but we've been in
12
wind a long time.
13
actually for Question 3 in terms of the exact
14
difference in terms of megawatts and turbines for 029
15
curves and IEEE 2800 curves.
16
And I'll give specific numbers
But let me just start by saying that we've done a
17
thorough analysis of -- based on the information we had
18
available from our OEMs and everything on the plants.
19
NextEra has Type 3 and 4 wind turbines.
20
gigawatts, 150 plants with 13,700 turbines using 14
21
major turbine models with sub-model configurations in
22
addition, four wind OEM models, and more than 10
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These go back as far as the early 2000s.
You know, and based on discussions with the OEM so
3
far, our estimate is that, you know, using the 029
4
curves, I'll just mention here briefly and I'll go into
5
details on the difference with others later, 66 percent
6
of those turbines would require a hardware exemption
7
with the current PRC-029 curves.
8
percent of the gigawatts, 66 percent of the turbines
9
because we're talking mostly about older wind turbines,
10
11
Now, that's 22
obviously, you know.
So as I said, I'll go into details about how
12
that's improved by going to IEEE 2800 or -- and how
13
that compares with PRC-024 in a moment, but, you know,
14
that's what we're looking at here.
15
hardware impacts of this, I think, quite well.
16
don't have specific costs because we don't have the
17
quotes on -- from the OEMs and the other components and
18
all that, but, you know, this is a substantial impact
19
that would have hardware requirements, you know.
20
We understand the
We
So I guess we'll just go to the next question.
21
I'll give more detail, but, you know, that gives you a
22
side -- you know, we actually -- I think other
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independent developers out there, other renewable
2
developers are doing a similar exercise.
3
just mentioned is documented in my written comments,
4
and I'd be happy to discuss it with you in more detail.
5
MR. SHATTUCK:
6
MR. GUGEL:
Thanks, Mark.
Everything I
So yeah, we'll --
Real quick, that there was something
7
that I could weigh in on the points that I heard.
8
Jason, if I could, with all due respect, I do
9
understand wanting to look at actual scenarios and
And
10
things, but part of what we're charged with doing and
11
part of what our industry is charged with doing is
12
considering what-if scenarios.
13
Our reliability coordinators and our transmission
14
operators need to understand predictably how units are
15
going to occur on the system and how they'd be able to
16
do in an emergency operation system.
17
have that, and if what we're saying here is that we
18
really don't understand, in general, how that's going
19
to happen, I am concerned that they're going to be
20
flying blind.
21
028, 029, and 030 is providing that predictability for
22
them to be able to understand, at a minimum, for units
If they don't
So part of what we're doing with PRC-
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going forward, but also understanding where we're at a
2
place right now, if that makes sense.
3
MR. MACDOWELL:
It does.
Yeah, completely agree,
4
you know, and I think that forward predictability is
5
complex and it's difficult.
6
we've been really focused on at ESIG and also with GE
7
Vernova with some of the planning work that we're doing
8
with system operators, is really focused in a lot more
9
on integrated system planning to the regard of
And one other thing that
10
understanding where are the real pinch points, right?
11
And a lot of the planning that has been historically,
12
and with no fault at all.
13
have been planned out today have practices that have
14
been in place for decades around understanding where
15
are the system stress conditions on peak load, on light
16
load, maybe a shoulder condition.
17
It's just the systems that
And those conditions are no longer the biggest
18
risk.
19
not associated at all with peak load, light load, or
20
traditional shoulder conditions.
21
needs relative to the variability and uncertainty of
22
inverter-based resources, variable energy resources.
There are other risks around peak IBRs that are
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There's limitations on headroom for frequency response
2
and Ride-through.
3
conditions are and try to solve for those, and what is
4
the frequency deviation and frequency response going to
5
look like in those system conditions?
6
right?
7
Understanding what those system
Absolutely,
So that's what I was saying is, looking at this
8
deterministically and a bit stochastically with
9
integrated system planning saying, what do we expect
10
when we see penetrations of renewables going out to
11
2030, 2040, and understanding what those frequency
12
deviations really will look like, and then what is the
13
resource mix that needs to respond to that and be
14
resilient against that.
15
use a forward-looking view with integrated system
16
planning to help plan out those scenarios.
17
And that's all I'm saying is
And perhaps, you know, I have to give credit to
18
the Drafting Team.
19
in the past, I know how difficult it is to balance a
20
lot of these issues when we don't have all the
21
resources to do deep technical studies, right?
22
a lot of work that could and should and probably would
Being part of NERC drafting teams
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be done if we had a different organizational structure,
2
but realizing that, you know, the drafting teams have
3
the limitations that they do with the visibility on
4
what's looking forward.
5
opportunity to look forward more, not only for Ride-
6
through, but looking at integrated system planning as a
7
core part of our practice moving forward across
8
utilities, across, you know, NERC requirements in
9
response to Order 901, in response to 2023, in response
But I think this is an
10
to 1920.
11
opportunity to look a lot better at and really define
12
what problems are we trying to solve.
13
saying.
14
15
Those are the things that I think we have an
That's all I was
Thank you.
MR. SHATTUCK:
Thank you.
Well, we'll get into
the detailed question here, Mark.
16
(Laughter.)
17
MR. SHATTUCK:
So Question Number 3 here is, do
18
you expect equipment to fail to meet the frequency
19
Ride-through criteria as specified in Attachment 2 of
20
draft PRC-029 due to hardware limitations?
21
sub-questions just to kind of quantify them, but, you
22
know, what's your estimate of products that would be
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affected?
2
and how does this change when you consider PRC-024?
3
So, you know, any estimates or real numbers or
4
megawatts would be super helpful for kind of
5
quantifying all of this.
6
How does this change if you consider 2800,
MR. AHLSTROM:
Sure.
Well, yes, there are
7
hardware impacts, and I've got the numbers here.
8
with the PRC-029 as drafted for the wind fleet that I'm
9
looking at here, you know, we'll have to do a similar
So
10
analysis on solar storage, but it's not quite as
11
substantial there.
12
the 27 gigawatts would require an exemption for
13
frequency Ride-through due to hardware limitations.
14
That involves 9,000 turbines, all four of our window
15
OEMs, and all 10-plus of our converters, so it's quite
16
substantial.
17
moving to the IEEE 2800 curves.
18
4.5 gigawatts out of the 27 impacted to some extent,
19
6,400 turbines, but just two of the OEMs and two of the
20
converters that would have to be -- have hardware
21
upgrades.
22
know, if you go to PRC-024?
We estimate that 6 gigawatts out of
It's much significantly improved by
That would still be
How does that change with respect -- you
It's only 200 megawatts
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that would require exemptions, 200 turbines, one OEM,
2
one converter model.
3
So clearly it could be argued -- you know, I think
4
IBRs should actually do what they reasonably can to
5
support the grid.
6
services, reliability services, as you know, and that
7
inverters are going to be cornerstone of the future.
8
We, you know, so I'm not saying we shouldn't go to the
9
2800 curves.
I'm a huge believer in grid
It could certainly be argued that it's
10
discriminatory, but I get that it's, you know, what can
11
we get out of this technology.
12
know, with PRC-024, you know, we're basically compliant
13
today with the wind fleet, and I think also with solar
14
and storage, you know.
But the reality is, you
15
So it could be argued that the technology agnostic
16
fair path would just be to say, look, all legacy stuff,
17
just continue to comply with PRC-024.
18
as soon as we can get the new OEM models out, you know,
19
you comply with 2800 curves.
20
way, of complying with 2800 is I think that will be our
21
stepping stone toward grid-forming inverters that we're
22
trying to accelerate as fast as possible, so within
All new stuff,
And a good reason, by the
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hopefully five years or so, you know, we can have a
2
fair number of -- a fair share of those inverters doing
3
grid forming, which would further, you know, support
4
the grid and the grid services and the response to the
5
disturbance there as well.
6
pathway forward toward 2050 when, you know, I think the
7
legacy fleet will be a minuscule piece of the IBR fleet
8
at that point, and the IBR will be state-of-the-art,
9
you know, inverters and enough grid forming that we
And that provides our
10
have an extremely good, stable set of grid services to
11
deal with this, in addition to balancing and
12
flexibility and so forth.
13
So I'll leave it there.
The difference between
14
PRC-029 as drafted and 2800 curves is significant and
15
has a big cost impact, and certainly on the number of
16
hardware upgrades and the cost and effort to get those
17
done.
18
Thanks.
MR. MACDOWELL:
Yeah.
So I want to parse this
19
answer again with my ESIG hat on.
20
general consensus of what Mark just said is that the
21
difference between the proposed curves in PRC-029
22
relative to 2800 is substantial.
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numbers across the fleet across North America, I mean,
2
I think we still need to evaluate that just because of
3
the evolving nature of the standard.
4
especially on, like you said, Mark, on legacy units,
5
we've been well served with PRC-024 to date.
6
to what you've said so far with your analysis
7
yesterday, there was no implications that any of the
8
big events that have happened over the past almost
9
decade were due to a frequency Ride-through issue.
But I think
According
10
for existing units, there's really not an issue that
11
we're trying to solve today.
And
12
To your point, Howard, what are we trying to solve
13
for in the future, right?
14
but I think the very, I would say, the middle ground
15
that seems to be the most reasonable at this point, we
16
put a lot of thought into the 2800 requirements, as
17
Mark said, and manufacturers are really engaged in
18
getting all of the capabilities built into the new
19
equipment.
20
retrofits, and I think some of you know, some of the
21
things that are happening there.
22
most of the 2800 capabilities and requirements are
We need to evaluate that,
There are certain areas that are looking at
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achievable with a reasonable amount of effort in terms
2
of the capabilities.
3
Compare that relative to what's proposed in PRC-
4
029, that's a much bigger gap that needs to be overcome
5
with a substantial cost -- potentially a substantial
6
cost and a substantial timeline to that.
7
back to my points before is, one, there is that
8
substantial amount of effort and cost and time that's
9
relative to what's proposed in PRC-029.
And I go just
We want to
10
make sure that it's a cost that is very well understood
11
and very well spent to understand is it really the
12
problem that we're trying to solve, right?
13
back to fleshing that out, when do we need to solve it?
14
Is that really an issue in all systems, or is it an
15
issue in a specific system that we're trying to scale
16
in ways that don't -- doesn't necessarily need to be
17
scaled across interconnections?
18
that question yet without having the analysis done to
19
back it up.
20
So going
Well, we can't answer
So going back again to the integrated system
21
planning, evaluating what scenarios would we need any
22
sort of Ride-through capability from any resource, not
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only inverter-based resources, to me, is a very
2
critical step along the way.
3
MR. ROGERS:
Yeah.
So again, focusing on -- more
4
on specific impacts, I guess, to generator owners and,
5
you know, speaking for -- you know, my opinion on
6
OG&E's position, as well as a lot of the other GOs who
7
are connected to our transmission system, we have a
8
pretty aging renewable fleet, specifically talking
9
about wind, in our part of the country.
And answering
10
the question specifically, do you expect equipment to
11
fail to meet the Ride-through requirement, the criteria
12
in Attachment 2, yes.
13
megawatts of wind that we own.
14
meet the Ride-through criteria in PRC-029 as written.
15
We have approximately 500
All 500 would fail to
Looking at IEEE 2800 and PRC-024, that shrinks
16
significantly.
17
is still compliance with PRC-029, even if you were to
18
make the modifications and shrink the --
19
shrink the Ride-through zone to something a little bit
20
different, is rate of change of frequency.
21
equipment that we have installed and many others in our
22
part of the country was built, rate of change of
One thing that does not change, though,
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When the
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frequency wasn't a design consideration.
2
something that was talked about.
3
some industrial standards that took things into account
4
for specific pieces of hardware, but to try and apply
5
that to the system as a whole and say that it's even
6
capable of -- to state, you know, with the rigor
7
necessary to demonstrate compliance with the
8
reliability standard, that it's capable of performing
9
at any given rate of change of frequency, would be very
It wasn't
There were probably
10
difficult to generate any such claim and be able to
11
stand behind it.
12
Now, that's not to state that it can't do -- you
13
know, do so.
14
changes that have some rate of change of frequency, and
15
it can do so.
16
it, and then how do you have evidence to demonstrate
17
that you're capable of doing so is a whole nother
18
question.
19
back to the uncertainty.
20
these things for this?
21
owner, we're in a very difficult position with our
22
resources to try and be able to make these
It's obviously withstood frequency
But what is that, how do you determine
And I'm not -- again, this kind of comes
How do you even determine
You know, us as generator
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determinations, relying back on the OEMs to some
2
extent.
3
you know, with projects, hardware and software, and
4
everything else, that the projects were probably kicked
5
off a lot of this stuff in the late 90s -- mid- to late
6
nineties -- with installation had taken place in the
7
early 2000s.
8
to build up what these are actually capable of on
9
things that weren't necessarily considered at the time
10
of building, and then presenting a GO with an estimate
11
on what these things, you know, can actually perform in
12
these -- you know, with these parameters, such as rate
13
of change of frequency or frequency Ride-through
14
capability, how long can we, you know, withstand a
15
whatever, 4 hertz frequency change for -- you know, can
16
we do it for 6 seconds, can we do it for 3 seconds,
17
whatever the case may be.
18
And then when you talk about the difficulties,
Getting those archive designs out, trying
And I'm going to lean back a little bit on some,
19
you know, some different industry experience I have
20
working in manufacturing.
21
about all these legacy components that are in these
22
devices that were built a very long time ago, they were
So when you start talking
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spec'd out to a very specific thing, right?
2
specs everything out.
3
requirements to the -- to the OEM.
4
going to give those requirements to all their subs.
5
Those requirements are what was built to at the time.
6
Everybody
We gave -- you know, we gave the
The OEM is then
There may be variations in components that are in
7
these things that are not necessarily -- we're not able
8
to account for today because they met the requirements
9
that were given to all these subcontractors, everyone
10
that built your parts, but they're still going to
11
perform differently on criteria that weren't accounted
12
for, and that's something that you were going to see
13
across the fleet on a lot of these things.
14
it gets back to this concept of uncertainty with --
15
especially with these legacy equipment.
16
be very careful to make sure that I'm not saying this
17
looking forward.
18
things that were built in the past, especially, you
19
know, kind of at the beginning of the transition, so to
20
speak.
21
22
So again,
So I want to
This is about exemption criteria for
So when you're looking at these assets that were
put in the ground, you know, say circa 2005, there's
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aspects of this that we can -- we're quite certain we
2
can comply with, especially looking at IEEE 2800 and
3
PRC-024 with the -- you know, with the bands as far as
4
frequency with your curves for frequency Ride-through.
5
But there are other considerations that just aren't
6
necessarily accountable for and that we'd have to rely
7
on the OEMs to some extent to give us that information.
8
And, you know, kind of with some insight I have that
9
some of that information is going to be very, very
10
difficult to state with certainty that, again, meets,
11
you know, again, back to what we're talking about here,
12
reliability standards, that meets the criteria to
13
demonstrate evidence of compliance with a mandatory and
14
enforceable zero defect reliability standard.
15
that's going to be very, very challenging for a lot of
16
these older assets.
17
MR. GUGEL:
And
Well, that was a little loaded.
So
18
I'm going to probably reserve my comments until we get
19
to the legacy thing because I think that's something
20
we're going to have to deal with throughout all this,
21
but very much appreciate the comments that I've heard
22
so far.
I'm hoping at some point we get away from the
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mindset of zero defect and start talking about effects
2
on the system, but yeah, let me -- let me reserve until
3
we get to the legacy issue.
4
5
MR. YEUNG:
Okay.
Thank you.
Can I
get a time check, Jamie?
6
MS. CALDERON:
7
MR. YEUNG:
8
questions and d
9
Thank you.
We have plenty of time.
Okay, because we have three more
MS. CALDERON:
10
MR. YEUNG:
11
MS. CALDERON:
12
MR. YEUNG:
There's plenty of time.
Okay.
(Off mic comment.)
Okay.
All right.
So the next
13
Question Number 4, I think, Dane, you alluded to it.
14
Again, thinking in terms of what kind of exemptions
15
should be allowed for frequency response -- I mean,
16
frequency Ride-through capabilities.
17
for GOs, what are some of the difficulties you might
18
have in obtaining the data to assess your compliance
19
from the OEMs?
20
available especially for legacy equipment, as you said.
21
And again, the context of this question is about the
22
need for exemptions.
The question is,
You know, what are -- you know, is it
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MR. AHLSTROM:
So again, this comes back to what
2
is currently available on this, and what is currently
3
available is what was provided initially on build.
4
we know what the -- if you look -- you know, so if you
5
look at a lot of this equipment, it wasn't necessarily
6
even in the -- framed in the context of Ride-through
7
capability.
8
term, tolerance bands, bands of operation this
9
equipment can successfully perform through.
So
But you're looking at, lack of a better
You know,
10
and sometimes it's given in, you know, plus or minus
11
percentages.
12
absolute hertz, whatever the case may be.
13
you know, that's what we have currently, so as far as
14
the difficulty in obtaining any further information, a
15
lot of that is going to fall back on the OEMs to
16
provide this based on analysis of these -- of these
17
older -- of these older equipment, the -- you know, the
18
components that went into it, how that -- how that
19
stacks up and what the outcome of that is.
20
Sometimes it's given in, you know,
But that's,
So I don't think I can accurately speak to, you
21
know, what the -- what the technical challenges are
22
going to be because that's -- you know, that's not
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something that I'm going to be privy to as far as the
2
efforts that are going to go into performing these
3
analyses or potentially testing, or some combination of
4
both, on these legacy assets to determine what the --
5
what the capabilities are.
6
know, the difficulty is that, you know, that
7
information doesn't currently exist in a lot of cases,
8
especially for this --
9
relatively speaking, for what we're looking at here,
10
11
But for us right now, you
for this very -- you know,
old equipment.
MR. AHLSTROM:
Yeah.
Jason wants me to go next as
12
a GO, and then I can turn it back to him as an OEM in
13
this case, I guess, because, you know, look, this is
14
going to take a highly cooperative, collaborative
15
process between the GOs and the OEMs with regard to the
16
IBR devices we're talking about across the board.
17
we heard a lot of this yesterday, that, you know, the
18
IBR are still on a very fast learning curve, which
19
means that we're going to continue to see dramatic
20
price improvements where they get cheaper and cheaper,
21
but it also means that they are innovating more on the
22
scale of electronics and software rather than on the
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traditional scale of generators as we know it, right,
2
which means every three to five years, they're coming
3
out with a whole new generation of inverters, in
4
particular, turbine -- you know, wind turbines.
5
So in other words, the whole -- all of the
6
engineering expertise of the OEMs is devoted to a new
7
product line, as we heard about yesterday, building for
8
that next product version.
9
their development engineering staff looking at the
They don't have, you know,
10
older devices.
11
going to be.
12
this stuff once they've done that and taken that old
13
version out of production.
14
through the interconnection process, no, we have a
15
problem with -- you know, I wouldn't call it a problem.
16
It's an opportunity, I think, with IBRs that, you know,
17
if you had -- if you're delayed for several years to
18
get through the interconnection queue, by the time we
19
actually get our, you know, our GIA, the model of
20
equipment we may have thought we were going to use is
21
no longer in production.
22
available, but it's different, you know, with different
They're looking at what the next one is
They've retired the test bench on all
As those of you who go
We have a better one
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models and so forth.
2
But that's the reality, and that's the advantage
3
of IBRs is that they're innovating to respond to what
4
the grid needs and what the market needs faster than
5
we've ever done with conventional resources.
6
does create this challenge that, you know, how do you
7
-- especially with retrofits, I mean, you have to -- I
8
think, by the way, it's beneficial to have a hardware
9
exemption process to encourage everybody to immediately
But that
10
get started on looking at what are the impacts with
11
their OEM, you know, rather than just you get to the
12
compliance period where, okay, here's what I can do.
13
And then you say, well, that's -- you know, we think
14
you could do more, and then you have to go back and go
15
to the OEM again, and it just delays the process and
16
delays the implementation actually.
17
So I think 2800 with an exemption process makes a
18
lot of sense, but you have to be sympathetic that, you
19
know.
20
engineering talent back on this.
21
balance a plant, you know, the plant models that have
22
to -- or the GO's responsibility with some other
We're not -- it's not easy to get the
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consultant or other in-house experts, you know.
2
big deal to figure this out, you know.
3
It's a
So I think I'll leave it there, Jason, and let you
4
take a, you know, next crack at it.
5
the -- you know, the process of doing this and getting
6
those retrofits out to the field, you know, it involves
7
the OEMs as well as the GOs, and it's highly
8
complicated.
9
dunk, whether it's software or hardware.
10
But the logistics,
You know, you don't -- it's not a slam
MR. MACDOWELL:
Yeah.
That's why I had him go
11
first.
12
agree, and nd to me, you know, the question is well
13
founded about what the challenges are.
14
certainly goes beyond just documentation.
15
documentation is one element of it to look at what
16
those legacy units are capable of, and then, you know,
17
also realizing that those legacy units were designed to
18
a particular fit-for-purpose form earlier mentioned.
19
And now we're looking at a, you know, a situation where
20
we need to have, you know, looking forward, a much
21
broader set of capabilities than that equipment was
22
necessarily designed for or tested for, modeled for,
Well put, Mark, you know, and I completely
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integrated for.
2
comes in very -- in a very deep way as needed between
3
GOs, OEMs.
4
And this is where that communication
And I'll also say, from an OEM perspective, and
5
Arne pointed this out yesterday in the OEM discussion,
6
is that it's not only the OEM, but it's really a matter
7
of all of the packaging of all the components, all the
8
equipment, all the -- all the auxiliaries that the OEM
9
has to pull together in the wind turbine, in the solar
10
and battery resource, right, and any other resource for
11
that matter.
12
steam turbines.
13
systems behind the fence that have to be coordinated.
14
And a big deal about that documentation and
15
capability understanding is that some of those legacy
16
units are sourced with equipment from companies that
17
maybe don't exist anymore or that have substantially
18
changed.
19
you want to think about it, to understanding how do you
20
go back and reevaluate those legacy systems for, you
21
know, all the components that maybe don't have
22
companies are around anymore, or at least don't have
Same thing with gas turbines, right, or
There's a whole bunch of complex
So it trickles down or trickles up, however
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documentation for that old -- that older equipment, and
2
that may not exist anymore, right?
3
more complicated.
So it is -- it is
4
You know, if we were to have a test bench that we
5
could test for that old equipment, that would be easy,
6
but it's not easy to take an existing piece of
7
equipment that's been in the ground 15 years or more
8
and pull together a complete test regime that typically
9
is done in a lab environment where you have a lot of
10
capability to replicate the grid.
11
know NREL, CGI, and there's other test facilities that
12
are out there for this purpose.
13
and type testing environment is there, fit for purpose
14
for performing thousands of tests under very specific
15
conditions.
16
renew the capability that we want to do with a piece of
17
equipment that's in the ground, and, you know, and we
18
need to retest for another purpose that it was never
19
meant to do.
20
challenges, right?
21
It's about the entire testing and modeling process it
22
takes again, to show, hey, how could we be compliant or
And many of, you
That lab environment
How do we replicate that in the field to
So I think those are some of the biggest
It's not only about documentation.
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not?
Now, that said, it's not that everything is going
3
to be all incredibly difficult.
4
that's needed, we can do some sort of analysis in some
5
cases and say, okay, we'll have a sense whether it's --
6
it has a big impact or not, but there still needs to be
7
that evaluation.
8
OEM's fleet at tens of thousands to hundreds of
9
thousands of units, you know, depending on who, where,
10
what, how, it really does get, you know, a substantial
11
amount of effort that's needed in that with resources
12
that are fully focused on meeting the needs of the
13
requirements, PRC-024, PRC-029, whatever it happens to
14
be, IEEE 2800, on new units alone.
15
an unlimited number of resources to look at both, so I
16
think that's the balance we need to strike.
17
18
If it's a small change
And that evaluation, if you take any
MR. SHATTUCK:
Thanks, Jason.
And we don't have
Thank you.
I think you're
last, right?
19
MR. MACDOWELL:
20
MR. SHATTUCK:
Was I last?
Okay.
It seems like the last question
21
might be a bigger discussion, and we probably covered a
22
lot of the next question.
So I would say let's maybe
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be mindful of our time for this next question so we can
2
spend it on questions from the group and the final
3
question.
4
is, what difficulties do generator owners have when
5
attempting to coordinate their plant to successfully
6
meet criteria specified in Attachment 2 of the draft
7
PRC-029?
8
far, so yeah, just keep it -- be mindful.
9
So we'll go with our fifth question, which
I think we all alluded to a lot of this so
MR. AHLSTROM:
Yeah, very, very briefly.
I think
10
the bottom line is all of the OEMs we're talking about
11
are global OEMs, part of the global supply chain.
12
we heard yesterday, none of them have a product in plan
13
that would be compliant with the PRC-029 curves.
14
Yes, you know.
15
from a supply chain on a global basis.
16
we're trying to move toward global unified IEEE-IEC
17
standards, I think, for IBRs in the future because of
18
this global supply chain nature.
19
complying with 2800 is not going to fly in terms of
20
being able to get the equipment we need and be in
21
production with this.
22
advantage, if there isn't one, you know, justifies the
As
2800?
So I think you have to look at this
If anything,
And, you know, not
And I don't -- I don't think the
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disruption in that and how much that would slow down
2
and increase costs for the U.S. market on those
3
products as well.
4
starter for me.
5
MR. MACDOWELL:
So it's just really not a -- not a
I think I probably addressed this
6
in my last comment as well.
7
take the opportunity to talk a little bit about a
8
related subject on exemptions, particularly, because I
9
do think there's a big benefit to the exemption
So I would like to maybe
10
process, specifically, in terms of the fact that
11
exemptions will get you a level of documentation,
12
right, and understanding maybe what the gaps are, and I
13
think that is valuable.
14
right?
15
capability to actually look into what the difference
16
maybe would be relative to what the old products are.
17
So it's not that you get a free pass even if you get an
18
exemption, but what you do get out of an exemption is
19
at least an understanding of maybe where the gaps are,
20
right?
21
22
Exemptions also take effort,
Exemptions do take a certain amount of
And that in itself for planners, for GOs, and OEMs
is valuable to understand what are the gaps in the
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performance that we see today based on the models that
2
were provided and integrated of the plant at that time,
3
relative to meeting a certain requirement, like the
4
Ride-through of PRC-029.
5
at least considering and having an exemption process in
6
place for frequency Ride-through that allows us
7
visibility as to why we can't meet something.
8
9
MR. ROGERS:
So I think that's my plug for
quite well stated.
No, I think that was -- that was
You know, as far as the
10
difficulties in attempting to coordinate the plant, you
11
know, it goes very much hand in hand with what we
12
talked about previously, having all the necessary
13
information, having the necessary parameters, and, you
14
know, knowing all these things from your plant, top to
15
bottom, to be able to run the appropriate studies and
16
determine, you know -- you know, are they coordinated
17
appropriately as per the draft standard.
18
I think, again, everything that was just stated
19
was very spot on as far as the need for exemption and
20
what that allows, and the benefits that that does
21
provide as far as, you know, having not just a blanket
22
write-off, you know, can't meet it/move on type
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exemption, but having something where you really fully
2
document the known capabilities of the plant.
3
document the unknown capabilities because, you know, it
4
-- as we stand right now, and maybe this changes as
5
OEMs, you know, are able to develop more information on
6
these legacy pieces of equipment, that'll shrink.
7
right now, there are some unknowns, and documenting
8
those unknowns are -- you know, would be very
9
beneficial as well for anyone who's attempting to
You also
But
10
assess the reliability of the system as a whole.
11
Howard, to get to your point just a minute ago about,
12
you know, moving from that mindset of zero defect,
13
mandatory enforceable, to looking at the impacts of any
14
particular thing on the reliability of the bulk power
15
system as a whole, I think the exemption criteria
16
really does help with that because it allows for what
17
information we do have, especially right now.
18
information do we have today right now that, by the
19
time that this -- you know, this standard gets filed
20
with FERC and then becomes effective, you know, we'll
21
have -- we'll probably have more information.
22
are probably going to determine some things, but we're
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still not going to have it all.
2
for whatever in information we do have to start
3
immediately flowing, and I think there is real benefit
4
for that.
But that will allow
5
You know, Alex, some of the stuff that he talked
6
about yesterday with those studies and everything, it
7
allows for further examination within -- with that new
8
information on where the risks are, what are we seeing,
9
what's causing these issues, what other things -- you
10
know, what systemic things do we have?
11
things specific to this location that we can -- that
12
can be mitigated outside of this very specific issue of
13
frequency Ride-through, and what things can be done to
14
address those more systemically?
15
rambled a little bit, got a little bit off topic, but
16
building off of what the previous commenter said here,
17
I think that that's -- you know, there's a lot of
18
benefit in that.
19
MR. GUGEL:
Are there
And so sorry, I
Yeah, I would agree, and certainly, at
20
least personally, I'm a supporter of trying to figure
21
out some way of finding an exemption that would work.
22
I think as we get into the next question, we'll
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probably get into some of the more technical details on
2
that, and hopefully they haven't started the vat of tar
3
with the feathers out there for me when we get to that
4
topic.
5
We'll see.
MR. YEUNG:
Okay.
Thank you, Panel.
Our last
6
question hopefully will wrap up a lot of the things
7
that have been discussed, and I believe it will based
8
on this last -- the responses to this last set of
9
questions.
Last question, it's kind of lengthy.
I
10
don't know if everybody has the actual wording, so I'm
11
going to read through it as clearly as I can, and then
12
kind of give a little kind of a summation about what
13
the question's asking for.
14
So the question is, many commenters have said that
15
it would only be fair to grandfather existing
16
facilities and those in construction facilities -- the
17
ones that are already in the pipeline -- grant them
18
exceptions from Ride-through requirements due to the
19
cost of retrofitting, and we've heard a lot of that.
20
Other commenters have said that their facilities have
21
an expected shelf life of up to 030 years, meaning
22
there may be facilities in place well into 2050, and at
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that time, IBR penetration is expected to be much
2
higher, the system will have changed, and that they are
3
not able to comply with the requirements that are
4
written today, these PRC-029 requirements.
5
should NERC balance the burden on generators, the cost
6
burdens, who may be asked to incur large retrofitting
7
costs with the burden on the transmission owners, the
8
planners, in my case, operators, who like certainty,
9
and the end use customers from poor or unexpected IBR
10
11
So how
performance?
So in a nutshell, that question is asking about
12
really the -- there's going to be a lot of industry
13
costs, effort to meet the frequency Ride-through
14
criteria, but there needs to be a balance between those
15
costs and the benefits they have to the system
16
reliability.
17
MR. GUGEL:
Yeah, I would agree, and this is the
18
point at which I'll be able to lean in, I think, a
19
little bit more.
20
construct some exemption criteria because it only makes
21
sense.
22
additional capacity out there when we know the margins
I do think we've got to carefully
The last thing we need to be doing is retiring
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are already tight at this point.
2
know, to me that's off the table.
3
So that's -- you
I think where it becomes a little bit more
4
difficult when you start sharpening your pencil is how
5
do you define "legacy?"
6
equipment that's been out there for 15, 20 years, and I
7
do a software upgrade or a hardware upgrade, and have
8
the ability at that point to make a change, is it still
9
considered to be a legacy piece of equipment?
If I've got a piece of
Would I
10
be required to make sure that I can meet the new -- the
11
new requirements, whatever they are, that we set up for
12
PRC-029?
13
equipment no longer meet the definition of "legacy,"
14
but it has enough new pieces of equipment that it's --
15
that it's considered to be something that should be
16
brought up to speed?
17
You know, at what point does a piece of
And then the other, I think, complicating thing
18
that we have here is, you know, there is a significant
19
amount of generation that's in the queue right now,
20
especially offshore wind.
21
that they're talking about being larger than 2
22
gigawatts connecting onto the system, which is just --
There's some sites out there
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I mean, it's huge.
2
eyes glossed over and I got very panicky.
3
be considered to be in construction at this point if
4
it's in the queue, or would -- you know, would it also
5
be that we need to take those generating units and make
6
them comply with PRC-029?
7
I think we need to struggle with.
First time I heard about that, my
Would that
Those are the questions that
8
At some point, we need to draw a line in the sand
9
say, no new generation that's put in place, IBR based,
10
can be put in that doesn't meet this criteria.
11
whatever the criteria that's developed eventually for
12
PRC-029, you know, we need to make sure that we've got
13
a date certain that says after this point, nothing new
14
can go on the system that doesn't meet the performance
15
requirements that we have in this.
16
personal opinion.
17
documentation issues for generator owners, for OEMs,
18
and trust me, it's going to create a lot of issues for
19
the auditors as they go out trying to figure out what's
20
what.
21
both making sure we have the exemptions for existing
22
facilities, but then also making sure we've got a line
And
That's just my
I know that creates a lot of
But it's the right thing, in my opinion, to do,
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in the sand that says, we know going forward that these
2
units will be able to perform in a certain way.
3
MR. ROGERS:
No, I think that was very well said.
4
You know, there's really nothing to disagree with that.
5
You know, I think we need to be careful, though, kind
6
of looking at the question specifically, when we start
7
using terms like "grandfathering in" and then, you
8
know, "cost of retrofitting," and things of that
9
nature.
So grandfathering in, specifically, maybe I
10
would disagree with that concept, right?
11
look at something and it was built prior to whatever,
12
you know, it's good, right?
13
off and we're done with it, and I don't think -- I
14
don't think that's the case.
15
back to these very detailed exemptions.
16
all the information you can about your equipment, and
17
you do the best that it can do to provide these
18
services, right, this frequency Ride-through, this
19
voltage Ride-through, this, you know, withstanding rate
20
of change of frequencies.
You ensure that it can do
21
the best that it can do.
You know, it's not just it's
22
old, well, let it run, it's good, that's fine.
Like, if you
Just wave a hand, bless it
I think, again, it gets
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So I think, you know, we need to be careful
2
whenever -- you know, and speaking as a GO, we need to
3
be careful when we look at concepts like this.
4
to make sure that the equipment in the ground is
5
performing at the best that it can do.
6
think you also need to stay away from terms, or
7
potentially stay away from terms, like we heard a
8
little bit yesterday about like "maximization" and
9
"maximizing capability," and what does that really mean
We need
Now, then I
10
because a lot of this stuff, again, you're looking at
11
very specific design parameters that this stuff was put
12
in the ground with, and you need to ensure that you're
13
operating as such because, otherwise, you're looking
14
at, you know, well, let's push it a little more, let's
15
push it a little more, let's push it a little more.
16
Well, now we're running risk of this equipment,
17
and what's the bigger reliability risk now?
18
-- you know, and especially in some pockets of the
19
country.
20
different areas, but, you know, you're looking -- you
21
know, we're out here on where we're located, on the
22
western edge of Eastern Interconnect, and we haven't
Is it this
And maybe this is actually different in
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seen a lot of -- a lot of the same issues that maybe
2
have been witnessed to other places.
3
performing the best that our equipment can perform, we
4
document our known -- our known issues, and we submit
5
those to the relevant people, who need to perform the
6
studies to see what is actually capable, and what we
7
need to be looking out for, and what else we need to be
8
mitigating, you know, I think that's where this goes.
9
I don't think it's necessarily this grandfathering in
10
11
So if we're
clause.
Also, when we talk about, you know, balancing
12
burden and retrofitting costs, and, you know, you've
13
got the burden on the TOs and the transmission
14
planners, and, you know, reliability coordinators,
15
whoever the case may be, and you're trying to balance
16
that with the cost of the GO to do stuff.
17
think at some -- at some point, you got to look at this
18
from a GO perspective.
19
providing -- you know, being a reliable partner in the
20
bulk power system.
21
do that best of our ability.
22
equipment, as you've heard many people up here state,
Again, I
The cost of doing business is
We have to do that, and we have to
And with this existing
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that probably involves exemption criteria to some
2
extent.
3
we'll probably get some better feedback specifically
4
from the OEMs on some of this as well.
5
I'm not sure I have much else to add.
MR. MACDOWELL:
Yeah.
I think
Thanks, Dane and Howard.
6
think that was really well said.
7
quantifying the problem we're really trying to solve,
8
the easy answer is, you know, don't leave any
9
performance on the table that's easy to extract.
I
I think going back to
If it
10
can, it should, right?
11
might have the unintended consequences of leaving some
12
performance on the table, so making sure, though, we're
13
understanding of those plants or those resources that
14
may have limitations.
15
having visibility to when they do or when they don't.
16
A blanket exemption really
I think the bigger issue is
And some of the aspects of when these pieces of
17
equipment may not be able to meet some of the
18
requirements, especially like what we're talking about
19
in Ride-through, are not necessarily visible in the
20
models that we have, right?
21
is not only an IBR issue.
22
power system modeling ubiquitously across the board.
And the model -- and this
This is an issue across
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Synchronous plants have the same issue.
2
the auxiliaries in detail in synchronous plants either.
3
We tend to look at the power system's impact of the
4
main power circuit and have a very rough estimate of
5
the Ride-through capability with those simple Ride-
6
through protection curves that are overlaid, that
7
represent a lot of the capability.
8
9
We don't model
Let's talk about a thermal unit, for example.
It's the protection of the auxiliaries.
It's the fuel
10
path in a gas turbine that is very complex, a lot more
11
complex than the auxiliaries in a -- in a -- in a wind
12
turbine or a solar inverter.
13
limitations, right?
14
understanding that is very important to have in terms
15
of what is the real reliability risk.
16
Those have the same
And I think it's that level of
Another aspect that, you know, going back to the
17
discussion you and I had, Mark, last week, really
18
trying to quantify those conditions that we're trying
19
to solve for, so whatever that happens to be, right?
20
Whatever curves that you land on or whatever system
21
conditions that you're trying to land on, do the
22
homework with understanding what the future system
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conditions look like, right?
2
there are different scenarios of future renewable
3
build-out, future load build-out.
4
conditions we're really trying to solve for.
5
back to integrated system planning, again,
6
understanding what the implications are for those
7
future conditions, and then understanding the
8
implications of things like Ride-through on that, and
9
having that serve as the guide to determining what
10
11
Understanding, you know,
Those are the system
Going
those curves really should look like.
Some of that was done, to a certain degree, in
12
getting feedback in the process of 2800 from the regard
13
of having a future-looking case or future-looking cases
14
to really get to the point of the problems that we're
15
trying to solve from a system needs point of view,
16
right?
17
through in 2800, generally, was -- had a lot of
18
feedback, and it was -- it really serves as a good
19
baseline for the problems we're trying to solve going
20
forward.
21
planning processes today is this viewpoint of doing the
22
system analysis on these future cases to identify all
And that's why I think the process that we went
But that said, I think what's missing in our
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of those system conditions that none of us really have
2
had to plan for up to this point.
3
So I would say that is probably the more -- the
4
bigger need than to really evaluating, hey, are we
5
going to meet PRC-029 curve or not with system
6
equipment?
7
know, that's only getting us halfway to the reliability
8
issue and really mitigating that reliability issue at
9
hand.
10
Do we need an exemption or not?
That's my opinion.
MR. AHLSTROM:
Yeah.
Well, you
Thank you.
This question was added
11
actually to the question list late last week, and my
12
initial impression was that this is a real red herring
13
question.
14
to conventional resources than it does to IBRs, to be
15
quite honest.
16
this question applies to what about the -- you know,
17
the thermal fleet in 2050, right?
18
You know, I think it actually applies more
I mean, everything we said -- asked in
As I pointed out, you know, we're on a very fast
19
learning curve with IBRs.
20
even though it -- they may have an engineering life of
21
25 years or so, we're actually replacing inverters much
22
more frequently than that.
There's a lot of reasons why
We're doing a lot of, you
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know, repowering of wind plants more frequently than
2
that.
3
keeps getting better, more capable, and less expensive.
4
So when we re-contract it or whatever, we'll put in the
5
next version of equipment to get, you know, more energy
6
into the next contract or whatever, you know.
7
There's lots of drivers because the technology
There's lots of drivers for this, not just
8
incentives by the way, but other business reasons why
9
we're actually -- like with a battery storage plant.
I
10
mean, you're -- almost the entire life of the plants,
11
you're upgrading with additional storage in there to
12
maintain full capacity and, you know, upgrading
13
inverters as well.
14
replaced/repowered much more quickly with the IBR fleet
15
than it is with a conventional fleet.
16
replace it, we can't -- we won't be able to buy an
17
inverter that's not compliant if we force the OEMs
18
toward 2800 here and what we're doing here.
19
So equipment is going to be
When we do
So without question, you know, I agree with Howard
20
that, you know, when we repower, that we should be in
21
full compliance with that, and I agree with Howard very
22
much that, you know, we also have to look at balancing
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resources and all that.
2
lot of innovation on that from the IBR side as well
3
with the longer duration storage side that we can't
4
predict by 2050.
5
looking at what new standards are becoming necessary
6
between now and then, you know.
7
additional standards that apply to this and additional,
8
you know, things we try to do to improve the fleet,
9
both conventional and IBR.
I think we're going to see a
It's not like we're going to stop
We will probably have
10
And I must say, this concept and the question
11
about imposing a burden on transmission owners and
12
transmission planners, this is what TOs and TPs do is
13
they -- the reason they get a regulated return and
14
always have in all the decades of thermo fleet is to
15
reliably and economically deliver the energy from the
16
generators to the loads, right?
17
different with IBRs, you know, but I have very little
18
sympathy on this burden part of the question.
19
Why would it be any
But, you know, fundamentally, I think, as I
20
pointed out, with the technology going on here and our
21
path toward additional capabilities and IBRs, including
22
grid-forming capabilities.
The thing to do is to build
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your way past this so that the future IBR fleet, which
2
will dwarf the size of the current legacy IBR fleet, is
3
highly capable and will support an entire grid with the
4
grid services and the balancing services and everything
5
we need to maintain reliability, which is what we're
6
all here for.
7
whatsoever if this creates reliability problems or has
8
any reason why we would slow the deployment of new
9
technologies to the grid.
10
And it serves the IBR interest in no way
So I'll leave it at that, but, you know -- you
11
know, I don't -- I don't think -- even I don't think
12
that it's wise to be thinking that, well, we have to
13
have a hundred percent IBR fleet by 2050 or anything
14
like.
15
including legacy resources, including thermal
16
resources, you know.
17
think that IBR should be expected to step up to the
18
plate by going PRC-024 to the IEEE 2800 curves, and do
19
what they can with the capabilities, you know, that are
20
reasonable and cost effective, and can be -- can be
21
deployed, and get it out there and do the right thing.
22
So I'll leave it at that.
We have to coexist with other resources,
So I think we can do that, and I
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MR. GUGEL:
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Page 80
Yeah, Mark, I would kind of add into
2
that that I think that word "burden" was just a little
3
bit misleading there also.
4
going to stray away, I think, a little bit from the
5
panel here, but we've talked a lot about the
6
limitations and stress at that point.
7
really good advantages that inverter-based resources
8
can add to reliability.
9
and understand that, the fact that they can react much
We've talked a lot, and I'm
There are some
And I think as we go forward
10
quicker to system disturbances and be able to dampen
11
those disturbances quicker, we're going to find that
12
there are some advantages those resources have that we
13
could never get out of the conventional fleet.
14
And so I feel a little bit disappointed that, in
15
some respects, we've concentrated on the negative
16
yesterday and today.
17
MR. AHLSTROM:
18
MR. GUGEL:
19
20
Yeah.
There really are some good, positive
things that are going to come out of this.
MR. AHLSTROM:
Yeah, and in my comments, I alluded
21
back to what we did on the ERSTF and so forth.
22
know, there are quirks of conventional resources that
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we're very used to because we've been dealing with them
2
for a hundred years, right, you know, like, after a
3
disturbance.
4
responding resource where you have to inject a whole
5
lot of energy to get it back up to 60 hertz?
6
know, that's not an advantage of inertia.
7
is slow.
8
IBRs can do.
9
about, well, how fast do you want us to be because we
Do you really want a really slow
No, you
The recovery
It's mind-boggling is slow compared to what
In fact, with IBRs, now we have to worry
10
don't want to be too fast.
11
get it, right?
12
there's advantages of all the technologies.
13
figure out how they fit together for system benefit.
14
We create instability.
I
But that's what we have to work out is
MR. MACDOWELL:
We have to
One thing I'd like to just
15
conclude with, and on a positive note, right?
16
we all recognize that there are big challenges that we
17
need to overcome.
18
are the fact that we're a victim of our own success,
19
right, and it's a good thing.
20
seeing a lot of the change that we're seeing in the
21
transformation really going towards meeting bigger
22
goals, to meeting policy needs for planning,
I think
And these challenges, fundamentally,
The fact that we're
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decarbonization goals, a hundred percent of something
2
by sometimes, somehow just go do it.
3
part is actually, you know, what we're really
4
struggling with right now.
5
that happen?
6
Well, the do it
How do we actually make
And I'd like to offer maybe, you know, maybe some
7
platforms of discussion to consider where we can help
8
each other.
9
already engaged in.
And those platforms many of you are
First of all, want to congratulate
10
the Drafting Team, first of all, for really a job well
11
done and understanding how to wade through all these
12
issues, but also want to congratulate the work done by
13
the NERC IRPS, the Inverter-Based Resource Performance
14
Subcommittee led by Alex, led by Julia Matevosyan, led
15
by Ryan Quinn in the past, and, you know, a lot of
16
input and really great discussion to understand what
17
the issues are and how do we mitigate them.
18
And one of the things that we're doing in ESIG in
19
the Reliability Working Group, specifically, and I work
20
with Mark with ESIG and lead that working group with
21
Julia Matevosyan, is understanding the implications of
22
the gaps today, solving the chicken/egg problem of how
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do we get the technology that we need in -- not only
2
installed in equipment, but deployed on the grid
3
through requirement standards, markets, mechanisms that
4
will actually get these performance characteristics in
5
the grid, get them deployed.
6
need to keep everyone whole in order to do that.
7
can't break, you know -- the need to actually have
8
these elements still being profitable enough so that
9
there's investment that wants to continue going forward
And oh, by the way, we
We
10
in these projects.
11
back to your point, Howard, to have a resource adequacy
12
issue on our hands.
Otherwise, we're going to, to go
13
So that's the very tight balance, keeping all of
14
these things together, and recognizing that when OEMs
15
build this equipment into the capabilities, they're not
16
building that capability to their immediate customers
17
necessarily, right?
18
specific need to install equipment and make money by
19
the revenue that is given simply selling power.
20
order to do that, we need to make sure that you can
21
optimize the output and stay online, don't get
22
curtailed.
The generator owners have a very
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So that's the real genesis of the KPI that the
2
developers really need to maintain, but oh, by the way,
3
we also need to do all of these things to keep the grid
4
stable.
5
different aspect of how OEMs need to give that new
6
technology to the grid companies, right, which are, you
7
know, fundamentally the customers and the constituents
8
of -- downstream of the generator owners.
9
So that's a very different element, a very
So really, having that transfer function of
10
technology development from OEMs all the way through to
11
grid owners, operators, developers, that's a transfer
12
function that is becoming more difficult to have,
13
right?
14
today that demonstrates the capabilities of the new
15
technology.
16
Global Power System Transformation Consortium, where we
17
are looking at the capabilities of implementing grid-
18
forming capabilities and making sure that we have good,
19
sound, robust mechanisms in place to demonstrate those
20
capabilities of grid forming on the grid, showing the
21
benefits through demonstrations across the grid, but
22
also showing that we're not going to have any
But also, we need to do things, to me, in a way
And this is where we are with ESIG and the
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unintended consequences of oscillations/interactions
2
between the grid-forming technology to the grid-
3
following technology, grid forming to other grid-
4
forming resources, grid forming to synchronous.
5
And those are the types of things I think we need
6
to invest in across the community, across OEMs,
7
developers, system operators, utilities, regulators,
8
and I really want to thank Mark for your participation
9
in that, and, Mark Ahlstrom, for your leadership in the
10
-- in the Council we have in order to institutionalize
11
that.
12
system planning work that we're doing with that as
13
well.
14
know more about the ESIG and GPST activities about
15
maybe what we can learn together and then have real
16
foundational elements of what problems are we trying to
17
solve and what regulatory impact do we want to have
18
with, you know, understanding how to actually get the
19
deployment of what we need.
20
And then that feeds back into the integrated
So we'd like to invite others that would like to
MR. SHATTUCK:
All right.
Do we have time for
21
questions.
Yeah, I think we have a half hour for
22
questions.
We'll do the room and alternate with Slido.
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Manish has already jumped up.
MR. PATEL:
So this is not a question.
I'm not
3
even sure what I'm allowed to advocate or not as an
4
EPRI employee.
5
(Laughter.)
6
MR. PATEL:
I'm still learning that.
So this is from -- this is from Manish
7
Patel with couple of degrees in electrical engineering
8
and some experience in industry.
9
seriously, I think some of this has been submitted as
But I think --
10
EPRI comments in writing with various drafts of the
11
standard and all that.
12
But let's take a step back.
13
the technical conference, right?
14
written, allows exemption for legacy IBRs with hardware
15
limitations, right?
16
to the system or does not, yet to be determined.
17
does pose a risk to the reliability of the system, then
18
we are going to figure out a solution.
19
solution that calls for, you know, retrofitting IBR.
20
It may be a solution that is out on a transmission
21
synchronous condenser, [inaudible 01:31:07], name it,
22
right?
Why are we here at
So PRC-029, as
We don't know if that poses risk
If it
It may be a
We don't know yet.
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The only reason we are talking about frequency
2
Ride-through is for two reasons.
3
as proposed, are very stringent, and there is no
4
exemption to legacy IBRs.
5
industry for some time now.
6
happens on the system are much more the number of times
7
frequency deviates significantly.
8
think Alex's presentation, none of the events caused
9
the frequency to deviate by the magnitude and for the
10
duration that we are talking about in PRC-029, right?
11
But I was a protection engineer for living for some
12
time, and, my god, lightning strikes and line trips,
13
very common.
14
climb, something trips, right?
15
frequently than the frequency deviates from nominal.
16
One, PRC-029 curve,
I have worked in the
Number of times fault
Even yesterday, I
Snake climb somewhere it doesn't need to
Voltage sags much more
So PRC-024 went through a revision just about
17
couple of years ago, right?
18
to clarify that momentary cessation is not allowed.
19
Even then that Standard Drafting Team did not think
20
that we have to widen the frequency curves, right?
21
Just two years ago, we went through 2800 exercise.
22
mentioned this.
The intent at the time was
I was vice chair.
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justification that IEEE 2800 frequency Ride-through
2
curve is needed.
3
1547?
4
21.
Where it ended up coming from?
5
Where it came, 1547?
IEEE
I think California Rule
So when we were discussing frequency Ride-through,
6
we were thinking about future grid.
7
don't have studies.
8
and they said, yeah because they have to comply with
9
1547.
We don't know.
We
We talked to a lot of solar folks,
They will have IBRs that will comply with, you
10
know, frequency Ride-through curves.
11
to wind OEMs -- some of them are in the room -- and
12
say, well, look, we would like to keep this simple.
13
1547 already uses this frequency Ride-through curves.
14
Why can't we use it for transmission?
15
conversation we landed on that.
16
good idea.
17
029 comes along, and we have an even stringent, right?
18
So then we talk
After some
That sounds like a
So now, two more years go by, and then PRC-
I tell you, I think what Mark suggested earlier,
19
if we hold all legacy IBRs to PRC-024 Ride-through and
20
all new IBRs to IEEE 2800 Ride-through, then this gives
21
the certainty -- I think Howard mentioned earlier --
22
this gives the certainty to system planners what
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equipment will be able to do based on in-service date.
2
We have to decide what is legacy and what is not
3
legacy.
4
question.
5
like all legacy IBRs, PRC-024, that standard was in
6
effect anyway, right?
7
that anyhow.
8
PRC-024 Standard Drafting Team said we need more than
9
PRC-024 curves.
That's right.
That's still -- that's still a
But I think going forward, to me, it looks
Those plans are supposed to meet
But one has -- even two years ago, the
IEEE 2800 landed on whatever because
10
of 1547.
I just don't see why we need to go one step
11
further.
So anyhow, I think that brings a lot of
12
certainty.
13
Now, on a lighter note, IEEE 2800 and PRC-029,
14
it's very difficult for a tongue to say.
15
the powerful people are in the room.
16
IEEE 2800 and PRC 2900.
17
renumber the 029?
18
(Laughter.)
19
MR. PATEL:
20
I think all
Why don't we say
Very easier, you know.
Can we
You know, just move zero from front to
the back and add one more?
21
(Laughter.)
22
MR. AHLSTROM:
It's free.
Let me just say, I very much agree
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with you.
2
actually just fine, and, in fact, with IBRs, right,
3
we're actually looking at it as a Ride-through
4
standard, more stringent than, I say, it's viewed for
5
conventional resources, right?
6
That would be the simplest thing that would save NERC,
7
and all the compliance folks, and all of the OEMs, and
8
all of the GOs a lot of time and effort that could be
9
better used to put, you know, IEEE 2800 into the new
I think PRC-024 for legacy assets is
So I agree.
I agree.
10
generation of equipment more quickly and deploy it more
11
quickly, right?
12
made in my written points.
13
And that was the argument I actually
You know, on the other hand, I think the exception
14
process with 2800 is another good approach.
15
time consuming.
16
to create, to be honest, a lot more work for NERC,
17
especially with the other non-IBR resources coming in,
18
you know, under the new definitions of who's subject to
19
compliance.
20
I think, you know.
21
just sticking with PRC-024, but I'm perfectly fine with
22
2800 plus an exemption process as well.
It's going to slow down.
It's more
It's going
That's going to be a lot of work for NERC,
So I think you could simplify it by
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MR. GUGEL:
9/5/2024
Page 91
Yeah, the only thing that I would add
2
to that, and this point was brought up yesterday, is
3
that 024 is not a Ride-through standard.
4
the set points.
5
requirements for Ride-through, you really do have to go
6
a little bit different.
7
MR. AHLSTROM:
024 just does
And so, you know, if you need
My point Howard, I think the IBR
8
community actually ends up interpreting it as a
9
performance Ride-through standard, right, because with
10
electronics, what's the difference between protection
11
equipment and IBR is when you really get down to it,
12
right?
13
Ride-through standard to IBR, I think the IBR community
14
would be fine with that, and it would actually would
15
exceed what you're doing with conventionals.
So all I'm saying is if you applied it as a
16
MR. GUGEL:
17
compliance hat.
18
(Laughter.)
19
MR. GUGEL:
The only -- man, I hate to put on my
The only issue that we have there is
20
you've really got two communities in the IBR area.
21
You've got the one that is traditional generator
22
owner/operators that are with traditional utilities and
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understand NERC standards, and do that application.
2
You've also got now into this organization, financial
3
institutions that would just look at the letter of the
4
law as opposed to what was actually intent behind that.
5
And I think the issue for us is going to become
6
enforcing PRC-024 as a Ride-through standard when it
7
doesn't necessarily state that in the standard, but it
8
just says that your set points and your protection need
9
to be at a certain level.
10
So I agree that the curves for -- as we start to
11
look at things and start to interpret how legacy and
12
future things should go in, I think that,
13
traditionally, most folks have considered PRC-024
14
curves where they want the operating limits to be and
15
the constraints to be on there, other than the fact
16
that there were some that interpreted that curve that
17
if it was outside, it was a must trip as opposed to
18
can, you know.
19
misunderstanding straightened out with most folks.
20
And I think we've gotten that
I do think there's still that learning curve, and,
21
potentially, the concern that may be out there that
22
folks that haven't traditionally been in the NERC realm
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would not interpret PRC-024, the letter of that, to be
2
a performance standard, but instead just a setting
3
standard.
4
MR. AHLSTROM:
Agreed.
But I mean, couldn't you
5
put the PRC-024 in as the legacy must comply with PRC-
6
024 as compliance -- as a Ride-through standard into
7
PRC-029?
8
9
MR. GUGEL:
Yeah, I think that's potentially a
path forward, at least looking for some of those curves
10
and when you're talking about exemptions.
11
there's a potential there, yeah.
12
13
14
MR. YEUNG:
Okay.
I do think
We'll take the question from
the room.
MR. KOERBER:
Arne Koerber, GE Vernova Wind.
The
15
topic of this panel discussion was exemptions.
16
Yesterday, we mentioned a few things that make it hard
17
for us to sign up for not being able to do something.
18
And to embark on a product development, even if the
19
product is retrofitted, with the sole intent of finding
20
a roadblock where we can't do it.
21
22
In the discussion today, we went back to a lot of
-- we discussed a lot of, oh, we need documentation
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that allows a -- I don't know -- I'll call it a semi-
2
public design review of why we can't do something, and
3
this is -- this is a real question.
4
this to make a point.
5
how you would structure an exemption process that
6
doesn't rely on OEM saying we cannot do this?
7
how would -- how would you structure an exemption
8
process, again, that doesn't -- that doesn't go back to
9
proving something can't be done, which we have concerns
10
11
I'm not saying
Any thoughts from this panel on
Like,
with.
MR. GUGEL:
I'll start with this, and I think some
12
others might be able to lean in on this, too.
13
know, we struggled through this same issue when we
14
started talking about cold weather and design
15
parameters for units as they get down to extreme
16
temperatures, whether they're low or high.
17
basically, what it came down to was producing design
18
parameters, what was the unit designed for and having
19
that there.
20
information and say, look, this unit wasn't designed to
21
Ride-through a particular frequency, wasn't designed to
22
Ride-through a particular voltage because this was the
You
And
I think if you can pull out that
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specifications for that unit at the time, that would be
2
adequate documentation as opposed to trying to prove a
3
negative.
4
point.
5
that information to lean on is probably the best
6
documentation rather than some sort of a -- of a test
7
that says, hey, look, I tripped, so I know that it
8
can't do that.
9
And I'm just speaking for Howard at this
But I think having the design parameters and
MR. KOERBER:
Just to make sure I understood
10
correctly.
11
always goes up to the originally-stated capability from
12
potentially many years ago, but there would be no
13
intent to go beyond that?
14
So you would be saying all maximization
MR. GUGEL:
I would say that, yes, that basically
15
-- well, if you did modification to the plant that you
16
knew would take it in a different way, that you'd have
17
that documentation also, but, you know, if a -- if a
18
plant wasn't designed to do X, you can't expect it to
19
perform X today.
20
MR. ROGERS:
Now, that last point you got to is
21
kind of what I was going to get to as well, and I think
22
that that would be very important in the documentation
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process, the exemption process, is not trying to prove
2
the negative.
3
clearly communicating the positive, and there may be a
4
whole lot of unknowns, especially when I'm talking
5
about, you know, some of the fleets that -- you know,
6
that OG&E owns, the stuff was put in the ground, again
7
like 2005.
8
probably '98, '99 is when the design process on a lot
9
of that started.
It's stating the positive and it's
It was designed in 2000, or, you know,
We don't know these things.
We
10
wouldn't be able to state these things.
11
did some type of testing on one of these units, one,
12
may fry the unit, that's bad, what do you do, hook it
13
up to the next one and try the next unit?
14
like a bad idea.
15
And even if we
That sounds
Or if you're able to perform some type of
16
simulation, say you do get enough parameters to do
17
something, is that representative of my fleet?
18
know, these things have been in the ground for 20
19
years, one of them's been on top of a hill in Western
20
Oklahoma, one's been on the bottom of a hill.
21
one's been in the shadow of the tower, one's not, you
22
know, I mean, and degradation of electrical components
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over time is a very real thing.
2
to be very clearly communicated, and I'm glad that was
3
brought up so this can go on the record for the
4
Standards Committee and everyone else who's drafting
5
this to understand.
6
And I think that has
It's very important that we don't try to prove the
7
negative with this exemption process.
8
positive.
9
If there are things maybe that the standard talks about
We state the
We state what we can do and nothing more.
10
that we're not capable of doing, address those
11
specifically as unknowns, you know.
12
fill blank, right?
13
unknown.
14
with this capability in mind.
15
do it?
16
And I think being -- stating that and being very clear
17
about that is very important for the exemption process,
18
one, to be something that's workable, but also be --
19
provide the maximum value.
State, you know, this is an
This was not designed with this parameter or
No.
Does that mean it can't
That means we don't know what it can do.
20
MR. YEUNG:
21
MS. CASUSCELLI:
22
Don't leave the
Thanks.
Thanks.
We'll go online.
All right
Thank you.
have a number of questions online.
Scheduling@TP.One
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Yeah, we
So the first one
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is, if the protection at inverter terminals does not
2
comply, could the GO submit an exception without
3
dynamic analysis.
4
effort/availability of models.
5
MR. GUGEL:
Asking because of
I want to make sure that I understand.
6
Are you talking -- are they talking about the
7
protection -- the protection system of the units?
8
they talking about the design?
9
understand.
Are
I'm not sure that I
If you're -- if you're talking
10
specifically about the protection system, I would
11
struggle figuring out how a protection system couldn't
12
be modified for that specifically if you're -- if
13
you're just talking about that.
14
about how the unit actually performs, that's a
15
different conversation.
16
MS. SHAH:
If you're talking
I can probably add some color to this.
17
This coming from one of my SMEs.
18
understand is can we skip the dynamic model effort,
19
especially for operational sites where these models are
20
not available to us easily.
21
are trying to understand, that can the EMT modeling
22
part, if we don't have the models, can we skip that
What we are trying to
That's pretty much what we
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when we are submitting exemptions, or we are seeking
2
exemptions on some of those models, which we don't
3
have, are not available from the OEMs.
4
MR. GUGEL:
Yeah, I'd have to further understand
5
the requirement for an EMT model in that -- in the
6
exemption, so no.
7
voltage side for the exemptions?
8
MS. SHAH:
9
MR. GUGEL:
Is that requirement in there for the
Yeah, frequency,
And if it's not, I'm not sure --
10
nobody's talked at this point about -- at least I
11
haven't heard anything yet -- about specifics about how
12
that exemption would be designed for the frequency
13
side.
14
this point has proposed a requirement or not a
15
requirement for EMT studies.
So, I mean, it's a good question, but nobody at
16
MR. PATEL:
May I -- may I chime in real quick?
17
MR. GUGEL:
Yes.
18
MR. PATEL:
So I think this question is more
19
appropriate for voltage Ride-through capability than
20
frequency, right.
21
change a whole lot between the terminals of inverter or
22
wind turbine generator on the high side of the plant.
So capability frequency shouldn't
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For voltage, there is actually a paper that is up for
2
approval by RSTC, written by NERC System Protection and
3
Control Working Group, that actually shows one method
4
to use instead of EMT model to make sure your voltage
5
settings at inverted terminals.
6
does not require EMT.
7
is a bit conservative and shows, you know, one way to
8
evaluate your voltage settings compared to the
9
requirements of the POM.
10
MR. SCHMIDT GRAU:
And it does not --
You can do basic power flow.
It
And also to add, I think it's
11
also important that the OEMs take accountability and
12
provide attestations on that because certain equipment,
13
you can maybe do it for voltage without any studies.
14
But I also know from Vestas product, you will have to
15
do some kind of studies because of so many dynamic
16
factors.
17
voltage that is set way below the PRC-024 or 029 curves
18
in your equipment and still compliant -- comply at
19
plant level.
20
And you can have protection settings on
MR. GUGEL:
Yeah.
I think a positive that comes
21
out of everything that we've talked about for the
22
exceptions process is it forces communication.
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you're now basically enforcing a communication between
2
the OEMs, the generator owners, and the transmission
3
side to make sure everybody understands the parameters
4
on that as opposed to maybe assuming things that we've
5
done in the past.
6
MR. SHATTUCK:
And just to maybe add to Howard's,
7
you know, through the alert process, we've had quite a
8
bit of difficulty getting the extent of condition of
9
what's out there.
And an exemption process like this,
10
again, forces it so then we know what's out there,
11
right?
12
process, so it is a benefit.
13
online.
14
both.
15
And it's documented and through a really formal
We did two in a row?
Let's maybe do one more
Sorry.
You were kind of
We'll do one more online.
MS. CASUSCELLI:
All right.
I'm going to ask this
16
one.
17
adopting the consensus developed under IEEE 2800 rather
18
than developing new requirements under PRC-029?
19
What level of time and effort might be saved by
MR. GUGEL:
I think that's something that the
20
Standards Committee and the Drafting Team will have to
21
take under advisement as they go forward, but at least
22
at this point, they've had a couple of rounds of this
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going out.
2
yesterday and today are providing some clarity in
3
particular areas that have been raised for some of the
4
questions.
5
going to be something that would be helpful for them.
6
I think the conversations that we've had
And so I think all of this in context is
MR. YEUNG:
Let me just -- as a moderator, that
7
was one of our concerns, you know, trying to get some
8
clarity because The Drafting Team will have to -- well,
9
the Standards Committee will have to, you know, make
10
that assessment.
11
know, comparative data.
12
in our process, but that's absolutely something we're
13
going be looking at, you know.
14
of using 2800 versus 029?
15
MS. SHAH:
I think Mark has some good data, you
Hopefully we can get some more
Thank you.
What are the benefits
Ruchi Shah from AES Clean
16
Energy.
17
suggestions that were given today about PRC-029, what
18
possibly can be done as a resolution.
19
opinion, what Manish suggested, Mark suggested are
20
great suggestions, something that I'd highly recommend
21
considering as an option to move forward with the
22
standard.
First of all, I want to start with some of the
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A consideration or a question from my end is, as
2
we are discussing how exemptions should be provided, a
3
question that we have is, do we have the manpower from
4
OEM perspective, utilities' or entities' perspective to
5
support these exemption efforts as well, and where we
6
draw the line with legacy.
7
time, as we hear yesterday from the OEMs, if 95 percent
8
of the OEMs cannot meet PRC-029, isn't everything right
9
now considered legacy because we really can't meet PRC-
I think at this point in
10
029 with the existing technology?
11
question.
12
everything legacy until we get to a technology point
13
for frequency Ride-through?
14
Do we have the manpower?
So that's my biggest
MR. AHLSTROM:
Can we consider
I would -- I would just say that
15
working with the people in NextEra, who do a great job
16
of maintaining a huge fleet, the answer is no.
17
NextEra does not have the manpower to actually do this,
18
we'll find a way to get done what has to be done as we
19
always do.
20
are available to do this, the consultants that are
21
needed to provide the models, you know, the plant
22
models side is very limited.
Even if
But yeah, the pool of people that really
You know, all these
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things are in very short supply, you know.
2
going to consume -- compliance with this will consume a
3
huge amount of the resources on the OEM plant
4
operations side for at least two years, you know, even
5
if it's software only, right, on the best case.
6
So that's
So it's a big lift, but, you know, I do think that
7
that's what has to be done.
You know, we'll comply.
8
We'll find a way to do it.
But it -- I am concerned
9
that it pulls a lot of the OEM engineering resources
10
away from speeding up the build-your-way-past-this-
11
with-better-equipment side, and it will delay the
12
availability of some of the next generation of the
13
technologies that we most want and would be used for
14
any of the re-power's replacements, you know, to get us
15
to a more compliant fleet more quickly.
16
have to weigh that, what's the right balance between
17
how much resource do we put into the old installed
18
fleet versus accelerate the new fleet, right?
19
MR. GUGEL:
So I think we
I would provide a -- I don't want to
20
put words in your mark -- in your mouth, Mark, but I
21
think I'd provide a bit of a caveat.
22
that you use the existing curves that are provided in
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PRC-029.
2
instead the legacy stuff looked more like PRC-024,
3
would you have as much of a manpower issue --
Maybe a question back to you would be, if
4
MR. AHLSTROM:
5
MR. GUGEL:
6
MR. AHLSTROM:
No.
-- of providing that information?
Oh, no.
As I -- as I have
7
documented in my comments here, you know, we have 9,000
8
turbines, four OEMs for the current PRC-029 draft.
9
have about 6,000 turbines, two OEMs if we go to 2800.
10
And we have virtually nothing if we, say, comply with
11
PRC-024.
12
plant, one OEM.
13
compliant.
14
We got 200 megawatts.
MR. GUGEL:
It's nothing.
We
I mean, it's one
So I think that' it's
The caveat there is, it depends,
15
right?
16
-- is going to basically determine the amount of
17
manpower that'd be required on the OEM side and on the
18
generator owner side to provide that documentation.
19
Whatever curve you choose on that is going to
MS. SHAH:
And I agree with that.
I think my
20
question was more, if we go with the existing PRC-029
21
and we have to work towards exemptions, upgrades,
22
that's where I would speak for Clean Energy as well.
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We are concerned about having the skillsets and the
2
manpower to support this, while we are also at a future
3
looking -- forward looking, how can we ensure this risk
4
is mitigated and we are reliable.
5
MR. MACDOWELL:
Yeah, and I think, you know, well
6
said, Mark.
7
evaluating the capabilities on the GO and the OEM, but
8
there's also, again, with my ESIG hat on, there's also
9
a bigger, broader impact on capability even with the
I think that the biggest impact on
10
system operators and utilities that have to reevaluate
11
this as well.
12
and OEMs, but it's
13
that capability that needs to go through the
14
interconnection process again, or even determine
15
whether there's a material change, right?
16
So there's -- it's not only on the GOs
everyone that has to reevaluate
So I think across the board, and I -- from a
17
compliance point of view at NERC, too, there's going to
18
be some sort of impact.
19
done to look at what is existing on the ground that's
20
doing well enough to support reliability, not making
21
any changes, really relieves a lot of the stress on the
22
entire ecosystem that we're all fighting for the right
So I think whatever can be
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resources to be able to do this, whether it be OEMs,
2
developers, NERC, system operators.
3
resources capable of doing this type of work is very
4
small, right, and I think that that's the practical
5
reality of the issue that we're up against is time/cost
6
versus resources to get this stuff done.
7
MR. GUGEL:
The pool of
Yeah, and I think the good focus for
8
maybe the team that would be developing the next draft
9
on this is, you know, the idea is we want to establish
10
the bar for those units going forward, and then let's
11
figure out what should be done with the legacy.
12
I'm going to -- I'm going to use air quotes there
13
because I already talked about the issues.
14
what should be done with what's in the ground right
15
now, and let's make sure that at least from the line we
16
draw forward, that we have an expectation that plants
17
behave a certain way.
18
MS. SHAH:
And
But again,
And that leads me to my next question
19
about risk prioritization.
20
between what we have, the technology challenges and the
21
upgrades or retrofits that we are considering for
22
existing resources, for a ban that is using a scenario
As we are trying to balance
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as we all learn through the conversations in these two
2
days, that we are not sure if there are any studies to
3
back it up.
4
really comply with that ban, or should we really focus
5
on future forward-looking technology where we can
6
invest our efforts and for a better, reliable grid
7
condition, and really use the data from the other
8
performance standards that we are also moving forward
9
with, use that data, understand how this will impact
So should we focus on our efforts to
10
the grid, get more factual data?
11
really recommend the team to consider as we look
12
towards redrafting PRC-029, focus on the bans, consider
13
the exemptions for that.
14
So something that I'd
And one last point that I want to recommend to the
15
team is, as we consider the exemptions, and putting my
16
compliance hat on, documentation for the exemptions, we
17
do have OEMs that are not in business anymore.
18
getting documentation to even submit the exemptions
19
will be a challenge if we can carve out something in
20
the technical rationale in the standard.
21
-- it's hard to put too many caveats in the standard
22
when we are writing it, but somewhere if we can
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I know with
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document this, that there could be a possibility.
2
may not be able to provide a lot of data to support the
3
exemption.
4
all.
5
to get additional details.
6
We
What we know is what we know, and that's
We have no one to collaborate, communicate with
MR. GUGEL:
Yeah.
That's all.
Thank you.
Yeah, I'm not sure
7
how much of that would be able to be codified within
8
the standard, and I'm not sure how much comfort you're
9
going to get from my saying "trust me."
But we
10
understand that this is an issue, and I know that as we
11
look at compliance across the ERO, that we're going to
12
be looking at it from a risk-based lens.
13
OEMs that are -- that are out of business and you can't
14
get the documentation is one thing, but hopefully at
15
least you have the original design parameters for the
16
plant itself, and that would provide a lot, I think, of
17
the information going forward.
18
MS. SHAH:
19
MR. SHATTUCK:
Thank you.
Thanks, and we'll do one last
20
question from Slido.
21
MS. CASUSCELLI:
22
So, you know,
Thank you.
How about taking all
considerations from yesterday to get a set of
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classes/types of entities/IBRs, each assigned a
2
compliance threshold, incentivizing upgrading?
3
4
MR. GUGEL:
That sounds like an accounting
nightmare.
5
(Laughter.)
6
MR. GUGEL:
So, you know, we tried something
7
similar to this in other standards, and I know there
8
are folks online that maybe haven't been as
9
participatory in the standards development process as
10
others have.
11
protection standards and some of our maintenance
12
standards, doing a percentage increase over a year as
13
to how things are complied.
14
it becomes difficult to demonstrate X percentage of
15
your fleet/pieces of equipment when that number
16
calculates out to a decimal point, and it just -- it
17
just drives me nuts, and I'm sure it drives a lot of
18
folks nuts on that.
19
We have looked at, in some of our
And frankly, it becomes --
Instead, in my opinion, it's better to have that
20
line in the sand that says, look, everything after this
21
particular point needs to be at X, and prior to that,
22
we'll be looking at, you know, the exemptions, the
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facts and circumstances around that -- those units, and
2
making sure that it fits into the parameters that are
3
described in the standard itself.
4
idea.
5
practicality of those that it becomes the devil in the
6
details.
7
Sounds good.
MR. SHATTUCK:
So I mean, great
It's the implementation and the
Thanks.
Any other thoughts to
8
close this out?
9
everyone for participating with our panel, but any
We're at the correct time, and thanks,
10
closing thoughts from anyone before we all get off the
11
stage here?
12
MR. YEUNG:
I'm sorry.
I think we heard some
13
really good ideas, particularly the last comment about
14
the exemptions and information.
15
to be real key in helping the Standards Committee
16
determine what the exemption process looks like, so I
17
appreciate that.
18
MR. DAHAL:
I think that's going
Are we taking one more question?
I would like to make some comment.
19
I'm Samir from Gamesa.
20
questionnaires about can you meet PRC-029 as it is
21
written, right, no.
22
2800?
When we responded to your
Can you meet -- what about IEEE
We operated with the assumption that those
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curves are just curve setting.
2
the performance specification like ROCOF, multiple
3
excursion.
4
cannot meet IEEE 2800.
5
would definitely vary significantly.
6
something for the committee to take into account,
7
right?
8
points and not the performance.
9
number one.
10
We did not dive into
So if you were to consider that, no, we
So your response, as Mark said,
So that's
We're just talking about those protection
That's the point
Point number two on repowers, like I kind of
11
mentioned yesterday, there are different type of
12
repowers.
13
account is the repower mainly mechanical one to
14
increase the efficiency, or it's an electrical one
15
where we swap out the converters.
16
distinction, it will become very convoluted on what to
17
comply with, you know, what standard to comply with.
18
So committee or somebody needs to take into
So without that
Third point is on software update, model update.
19
Like, so if we said, okay, we can comply with -- for
20
some of the legacy units, depending on the definition,
21
we can expand the protection curve.
22
it, but if we have to provide models beforehand, that
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will delay the implementation process because, like I
2
mentioned, model might not have been updated, depending
3
on what -- how back in the past we want to go.
4
want the advantage right now, or are you willing to
5
wait couple of years for the model to get updated?
6
it's not just an OEM.
7
converter from other OEM that we need to reach out and
8
ask them to give us the model that will comply with
9
today's computational lead, right?
10
Do you
And
You know, we do source our
And then last point that I would like to bring up
11
in the prioritization, like Mark mentioned, like he
12
himself has 10 converter models, right?
13
certain converters on the field that we have in larger
14
quantity than the other, right?
15
guidance given, either based on the number of internal
16
capacity, or the reason that you guys from your
17
experience say, okay, this reason is more vulnerable,
18
so we can focus on this reason, make this a prioritize,
19
or based on the number, then that would help us out to
20
allocate our resources.
21
NOGRR, we are getting all OEM, all the operators
22
reaching out at the same time asking for the capability
So we have
So if there is a
Otherwise, learning from
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and the model update, and we have to -- we have no way
2
to prioritize.
3
then we won't be able to, you know, help them as -- in
4
the most beneficial way.
5
So they would go back on the queue, and
So those are my comments and I want -- I want
6
Drafting Committee and the NOGRR to take -- RTOs to
7
take those into consideration.
8
MR. SHATTUCK:
9
MR. YEUNG:
10
11
panel.
Thank you very much.
Okay.
So I think we can close this
Todd, you want to make some comments?
MR. BENNETT:
No, Charles, I don't think I have
12
anything else additional, other than to thank the
13
panel.
14
technical insights here.
15
for all their efforts here today.
This was a wonderful panel, a lot of great
16
(Applause.)
17
MR. BENNETT:
18
And I'm showing 11:05.
reconvene at 11:15.
19
(Break.)
20
MR. BENNETT:
Give them a round of applause
Let's
Thank you.
-- portion of the technical
21
conference.
22
here, and that's not a please hurry up.
So this is last thing between us and lunch
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2
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excited to hear about what you have to say.
So outlining objectives of a Ride-through
3
definition.
4
members here to come speak to us about this, but this
5
states specifically Joel.
6
I believe we have a couple Drafting Team
MR. ANTHES:
Yes.
So, Joel, take it away.
Good morning still, and I was
7
just telling Husam that this is the perfect time for us
8
to present because hopefully everybody will be hungry
9
and not want to ask us a lot of questions after our
10
presentation.
11
(Laughter.)
12
MR. ANTHES:
But my name is Joel Anthes.
I'm a
13
system protection engineer with a Pacific Gas and
14
Electric Company.
15
of the Drafting Team for 2020-02 for PRC-029, and I
16
have Husam Al-Hadidi with me, who's the co-chair of the
17
Drafting Team.
18
I'm from California.
I'm a member
So I was reading through the description of what
19
I'm supposed to present on, and it says, "a thorough
20
examination of the usage of the term, 'Ride-through,'
21
within NERC reports, IEEE, currently active Ride-
22
through, reliability standards, and other industry
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usage of the term."
2
don't think we could do that in 030 minutes, and I
3
would not be qualified to lead that discussion anyway.
4
My middle name is not "Ride-through."
5
(Laughter.)
6
MR. ANTHES:
So just to be upfront with you, I
But what I would like to give you is
7
an overview, the history of the Drafting Team's thought
8
process for how we got from beginning to draft to at
9
least our Ballot Three, our latest proposed IBR Ride-
10
through definition.
11
So if we could go forward a slide please.
12
So I reread the SAR, and the SAR directed us to
13
consider defining the term "Ride-through" as necessary.
14
Now, in our first ballot, we actually took the approach
15
of not defining Ride-through.
16
understand it, was to really define "Ride-through"
17
within the requirements of the standard itself, rather
18
than to give a comprehensive definition of "Ride-
19
through."
20
Team, which defines the triggers for when you
21
investigate Ride-through performance within 029, it was
22
a specific request from them that we go ahead and
Our intention, as I
But after meeting with the PRC-030 Drafting
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define the term, "Ride-through, "so that they could
2
index, so to speak, into the requirements of our
3
standard and reference it within their own.
4
two, we began by putting our first attempt at a Ride-
5
through definition.
So draft
6
If you could go to the next slide, please.
7
So some of the goals that governed our thought
8
process on this was we wanted to have a definition that
9
could be included in the NERC glossary of terms.
We
10
didn't want to unnecessarily tie it specifically to our
11
standard, and then we wanted other standards to be able
12
to refer to that definition when either indexing into
13
our requirements or referring to our requirements.
14
those were just a couple of goals that we tried to keep
15
in mind while we were drafting it.
So
16
Next slide, please.
17
So some of our goals were not -- we didn't want to
18
create additional performance requirements just by
19
defining "Ride-through."
20
performance requirements of Ride-through within the
21
actual requirements of PRC-029.
22
in mind when we look at how we kind of went through and
We wanted to keep the
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the evolution of our proposed definition is it wasn't
2
intended to be an all-encompassing performance
3
definition, only a definition, very bare bones
4
definition, so to speak, of "Ride-through."
5
Next slide, please.
6
So our first draft, I'm just going to read it:
7
"remaining connected" -- so this is going to be the
8
definition of "Ride-through":
9
synchronized with the transmission system, and
remaining connected,
10
continuing to operate in response to system conditions
11
through the time frame of a system disturbance."
12
then after reading through many pages of industry
13
comments from draft two, we ended up incorporating
14
those comments and tweaking the definition for draft
15
three, which is the latest that we've proposed.
16
that is a definition of "Ride-through":
17
plant facility remaining connected to the bulk power
18
system and continuing in its entirety to operate
19
through system disturbances.
20
So a couple of things.
And
And
the entire
We ended up removing "due
21
to industry comments were synchronized with" from draft
22
two, and "in response to system conditions."
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was some concern whether it was justified or not.
2
There was some concern with us using -- applying the
3
term and the concept, "synchronized," to inverter-based
4
generation.
5
not appropriate to use the term, "synchronized,"
6
because we weren't doing a standard for synchronous
7
machines, and we went ahead and removed that term.
8
And there were some who felt that it was
And "in response to system conditions," that had
9
generated some comment, as I recall, of what are those
10
conditions, what is appropriate response, all of which
11
we weren't trying to define merely through a Ride-
12
through definition.
13
concept of "entire" and "in its entirety" because there
14
was real specific concern, as I recall, from one
15
stakeholder, in particular, that if we -- if we didn't
16
clarify that, then generator owners and operators may
17
consider partial tripping of inverters when considering
18
the R3 requirements for returning to pre-disturbance,
19
real power levels.
20
clarify that.
21
It was an attempt to clarify that you couldn't subtract
22
partial tripping when you were required to come back to
And then we ended up adding the
And so this was an attempt to
It wasn't -- I'll just leave it at that.
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your pre-disturbance available power after a system
2
disturbance.
3
system" with "bulk power system," and I think the key
4
there is that we were trying to deliberately exclude
5
distribution-level IBRs, and bulk power system would be
6
exclusive of distribution -- solely distribution-
7
connected IDRs.
8
Okay.
9
So another thing we attempted to do was to use,
And then we replaced "transmission
Next slide, please.
10
wherever possible, NERC glossary of terms, so "bulk
11
power system" is clearly defined.
12
local distribution of electric energy.
13
is clearly defined.
14
conditions, perturbations, and frequency deviations.
It excludes the
"Disturbance"
It includes abnormal system
15
Next slide, please.
16
So one of the things that we referenced, there's
17
this most admirable definition from IEEE 2800, and we
18
drew from the concept of this.
19
you.
20
disturbances inside defined limits and continue as
21
specified."
22
directly use this definition is some of the nuances of
I'm going to read it to
It is, "ability to withstand voltage or frequency
So I think the main reasons that we didn't
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the language, "ability to withstand," for instance, may
2
not necessarily mean remaining connected to the
3
transmission system.
4
"ability to withstand," we used "remaining connected."
5
"Inside defined limits," we felt that that may
6
unnecessarily tie it to a specific standard.
7
attempting to make it a more standalone definition, and
8
similarly with "as specified."
9
like a standards requirement, a performance requirement
So instead of -- instead of
We were
Again, that's more of
10
you have to then perhaps specify along with your
11
definition of "Ride-through."
12
our thought process for avoiding some of those things.
13
That's why we didn't directly use the IEEE definition.
So those were at least
14
Next slide, please.
15
So in response to Ballot Three and Ballot Two, we
16
went through, looked at the comments.
17
proposed 11 different definitions of "Ride-through,"
18
and I read through all of them again last night.
19
had a headache, and so I thought I'd like to share that
20
with you.
21
(Laughter.)
22
MR. ANTHES:
Industry
And I
So I'm not going to -- I'm not going
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to comment on -- you know, rebut against each one.
2
think they all have some value in the way industry was
3
thinking, but in general, three things that I saw where
4
they kind of deviated from ours.
5
word order preference.
6
trying to say the same thing, but they didn't like the
7
way we worded it.
8
more significant, at least in my mind, were adding in
9
the concept of in -- adding in the concept to the
I
Some of it was just
You know, maybe they were
And then two other things that were
10
definition of "Ride-through," that your response needs
11
to be in support of grid reliability, and then also
12
maybe adding back in the concept of your response needs
13
to be as specified within the standard itself.
14
number one here, I think that one kind of merged
15
aspects of IEEE 2800's definition with ours.
So for
16
If we could go to the next page.
17
This one here, it seemed to kind of add back in
18
the concept of operation in support of grid
19
reliability.
20
individual dispersed power-producing resources,
21
remaining connected to the electric system, and
22
continuing to operate in a manner that supports grid
So it says, "Facilities, including all
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reliability throughout a system disturbance, including
2
the period of recovery back to a normal operating
3
condition."
4
were proposed within the industry, comments to the
5
Drafting Team, suggestions from industry for tweaking
6
the Ride-through definition.
So again, these are draft comments that
7
Next slide.
8
So this one seemed to want to remove, at least in
9
part, the concept of the plant operating in its
10
entirety, Riding-through in its entirety.
11
"Remaining connected, synchronized with the
12
transmission system, and continuing to operate by
13
delivering power in response to system conditions
14
through the time frame of a system disturbance."
15
next one, 5, "The entire plant remaining connected to
16
the bulk power system and continuing to operate the
17
system disturbances," very similar, I think, in
18
principle to what we proposed.
19
Next slide.
20
So 6 and 7 here.
So
The
"The plant facility remaining
21
connected to the bulk power system and continuing to
22
operate through system disturbances as defined within
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applicable reliability standards."
2
adds back in the concept of within defined limits of
3
the standards within specific operating limits.
4
"the entire plant facility remaining connected to the
5
bulk power system and continuing in its entirety to
6
operate as specified through" -- oh, I can move on to
7
8.
8
9
So 8 here:
So that one kind of
Seven,
"The entire plant facility remaining
connected and continuing to operate through the
10
duration of frequency and voltage disturbances, in its
11
entirety, from the start to the return to pre-
12
disturbance conditions," so it basically removed the
13
reference to the bulk power system.
14
entire plant facility remaining connected to the bulk
15
power system and continuing, in its entirety, to
16
operate as specified through system disturbances inside
17
defined limits."
18
concept of defined limits as specified within a
19
standard.
And then 9:
So that one kind of added back in the
20
Next slide.
21
I think is our last -- second to the last.
22
"The
"The
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producing inverters, remaining connected to the
2
electric system and continuing, in its entirety, to
3
operate in a manner that supports grid reliability
4
through a system disturbance, including the period of
5
recovery back to a normal operating condition."
6
me, that one also kind of added in the concept of you
7
need to operate in support of grid reliability, maybe
8
more of a system-level definition.
So to
9
Last slide, number 11, "The plant facility shall
10
remain connected and in service, maintaining the pre-
11
disturbance equipment configuration in operation
12
throughout the entirety of the system disturbance and
13
recovery."
14
concept of the entire plant operating.
15
So this one, again, kind of removed the
So I think the story in my mind of this is that
16
you could probably put a hundred different people in a
17
room and you'd get 120 different definitions.
18
there's -- I'm not minimizing the input and some of the
19
concerns and some of the things that industry has
20
highlighted, but there -- you know, at least maybe it
21
gives you a feel for what we went through in reviewing
22
all of the industry comments and trying to come up with
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something simple that met the goals.
2
it for -- do we have Q and A now?
3
you're all hungry.
4
(Laughter.)
5
MR. VENKITANARAYANAN:
So I think that's
Okay.
Hopefully
Nath Venkit from GE
6
Vernova.
7
and all the different definitions.
8
the "in its entirety part," and the way I read it is if
9
you have a wind farm with about -- with a hundred
Thank you for going through the background
I have a comment on
10
turbines, and if you have an event and one of them
11
trips, one out of a hundred trips, then the whole plant
12
is not compliant.
13
that this may be impractical.
14
have -- let me give you some examples.
15
a turbine that is losing its wind resource and is in
16
the process of gracefully shutting down.
17
RPM has gone below a certain threshold, and then it's
18
counting down to shut down, and that process is a
19
graceful shutdown.
20
Now, as an OEM, I would like to say
The reason is you can
You could have
So its rotor
Now, during this period, if you have a Ride-
21
through event, then you're not going to gracefully shut
22
down.
You're going to shut down, okay?
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going to take a few minutes before the turbine comes
2
back up.
3
examples where turbines are -- an individual turbine
4
may be seeing a combination of conditions -- wind
5
gusts, turbulence, whole bunch of other things -- that
6
is causing it to operate in what I would summarize as
7
survival mode, right?
8
trying to control that speed.
9
is to not shut down that turbine but to allow it to
10
manage that and come out of that survival mode into
11
normal operating mode.
12
a survival mode and an event happens, that turbine is
13
very likely to trip.
14
That's one example.
There could be other
So it's over speeding, and it's
And the whole objective
But if you are in that kind of
So for all these reasons, if you look at IEEE
15
2800, it says that after a fault, when you recover, it
16
is sufficient if you recover to 90 percent of available
17
power because it's possible that some of the inverter-
18
based units will -- would, would trip for some of these
19
conditions.
20
MR. ANTHES:
21
MR. VENKITANARAYANAN:
22
Yeah.
So in my mind, requiring
that not even a single inverter-based unit under
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whatever conditions it's operating in -- losing its
2
wind resource, gracefully shutting down, operating in
3
survival mode -- under any of these conditions, if it
4
should be able to recover, that can happen only in
5
theory and not impact this.
6
MR. ANTHES:
So if I could interrupt you because
7
I'm going to forget the first part of your answer if
8
you go too much further, but so my understanding is it
9
was not our intention to make a standard that was --
10
absolutely prohibited any tripping of a unit.
11
understand it, PRC-030, our companion standard, is
12
going to define the triggers for when you investigate
13
PRC-029.
14
reduction in real power, or 20 megawatts is, I think,
15
what they have in there.
16
reduction in real power or a trip of 20 megawatts, or,
17
I think, if it's your transmission planner operator
18
requests an investigation.
19
and how I've tried to explain it to my company is that
20
that is the trigger for then assessing your compliance
21
with PRC-029.
22
So as I
So I think as they passed, it's a 10-percent
So if you had a 10-percent
So that's my understanding
So I don't think it was our intention in putting
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in the concept of its entirety to absolutely prohibit
2
any tripping because that doesn't seem reasonable.
3
However, it came -- for better or worse.
4
it wound up in there is there were specific entities
5
concerned that you could have a disturbance on the
6
event.
7
You're expected to come back to your available active
8
power after the disturbance is cleared.
9
concern was, you know, unless we say something about in
So the reason
Twenty percent of your inverters might trip.
So their
10
its entirety, they might go, okay, well, my available
11
power is the 80 percent I have left on, so I'm totally
12
compliant, but they might have lost a significant
13
number of inverters due to the disturbance.
14
intention with this, and maybe it wasn't clear enough.
15
I'm thinking based on how many comments we've had like
16
yours, it probably wasn't clear enough.
17
intention wasn't to, I believe, absolutely prohibit any
18
tripping, but it was to disallow when you return to
19
pre-disturbance, subtracting things that tripped out
20
from your available active power.
21
22
MR. VENKITANARAYANAN:
So our
But our
Just to add to that to be
very clear, a clarification, we don't look at the
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individual unit, so really, IBR unit was not part of
2
our scope.
3
and you are able to go to -- recover to pre-disturbance
4
megawatt, even if you lose five, 10, 15, as long as you
5
could maintain the pre-level disturbance after the
6
event, you are in compliance with our standard.
7
added flexibility that if the TB or RC or whoever want
8
to give you a different level to say, no, recover to 90
9
percent, 95 percent, we couldn't.
So really if you have hundreds of IBR unit
And we
We said this is
10
going to be system dependent, and we lifted an open
11
flexibility on the standard.
12
is no requirement for every IBR.
13
-- the plant need to recover the pre-disturbance value.
14
So your concern if it's one unit and it's not going to
15
impact the plant --
16
(Cross talking.)
17
MR. AL-HADIDI:
18
MR. VENKITANARAYANAN:
So you are not -- there
You need to recover
It will impact.
-- then you have to bring
19
it -- the GO owner has to bring it back to their TB or
20
RC to see does that really need to be exempt from that
21
or how that need to read that.
22
standard, it's saying that if you're able to recover
But for now, the
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from the power, you have no issue.
2
there's a TPRC flexibility to provide a different level
3
other than a hundred percent.
4
MR. AL-HADIDI:
If you don't,
See, I don't see how that can
5
happen.
6
producing two megawatts, and one of them trips, okay,
7
you're not going to recover back to 200 megawatts.
8
You're going to recover 298 megawatts.
9
mean I --
10
If you have a hundred turbines, each of them
MR. VENKITANARAYANAN:
So, again, I
As I said, this is
11
reliability question.
12
this -- the number, which is it 95 percent?
13
What's the value?
14
-- require you to recover back, and the TPRC, based on
15
their system, they can provide any criteria as needed
16
to support their system.
17
there is flexibility in the standards.
18
That's why we couldn't determine
Is it 90?
MR. AL-HADIDI:
We say the standards require you to
So flexibility is there, so
Again, I mean, I don't want to
19
argue.
20
practical solution is also important.
21
have to draw a line that you can't have 20 percent of
22
the units tripping, but it's okay if you have two or
I think reliability is important, but having a
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three units stripping.
2
should be an element for that.
3
MR. ANTHES:
So somewhere, you know, there
Thank you.
So maybe to your, because I think you
4
had two points in there.
5
as you were discussing the scenario of a wind turbine
6
ramping down due to, you know, maybe wind has ceased,
7
and in requirement R3, we do specifically say you have
8
to return to available active power.
9
if your available active power is different because you
10
have lost wind or because cloud cover has affected your
11
solar production, we intended to account for that in
12
returning to available active power.
13
in its entirety was to not allow you to trip a whole
14
bunch of stuff off and go, well, I only had available
15
the stuff that didn't trip, if that makes sense.
16
(Off mic comment.)
17
MR. VENKITANARAYANAN:
18
MS. CASUSCELLI:
One thing that came to mind
Okay.
Yeah.
So if you have --
But the concept
Thank you.
I'll ask one of the online
19
questions.
20
specific language to align the language clearly with
21
PRC-030/defined the levels similarly?
22
Has the Drafting Team considered adding
MR. AL-HADIDI:
BRCT?
I don't remember.
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Actually, we create this definition to align with BRCT,
2
so that was the intent of adding the definition to the
3
standard, so really, it was mainly -- just really the
4
main intent.
5
So I thought we achieved that objective.
MR. GUGEL:
Hey.
Howard Gugel, NERC.
There was a
6
phrase that showed up in several of the definitions
7
that was triggering for me, so I just want to make sure
8
that you have a lens on for it, and it was "remained
9
connected."
And sometimes when you start talking about
10
momentary cessation, there's no mechanical disconnect
11
that occurs there, but it's an electronic change.
12
somehow, as you're looking at this idea of Ride-
13
through, make sure that you take into account it's not
14
just a mechanical change that could occur there, but
15
also any sort of a momentary cessation that might be
16
taken into account.
17
MR. AL-HADIDI:
I thought we did for that.
So
We
18
said to "continue exchange current," so we said it's
19
not -- and I believe that's the reason.
20
where we did not add to support the system, it was a
21
reason for, like, for R3.
22
performance requirement from the IBR.
But reason
We are not required any
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said that -- if we are now saying you need to support
2
the system, and now there'll be -- it's very hard now
3
to say if you Ride-through or not because if you do not
4
produce enough or change your megawatt to support the
5
system, it could be your Ride-through, but they're not
6
compliant because you did not meet the definition.
7
that's the reason sometimes we did not adapt some of
8
the suggested language from some of the stakeholder
9
because we felt that it may add more compliance
10
11
So
requirement, which we try to avoid to some level.
MR. ANTHES:
Yeah, and I did read through the SAR
12
again.
13
connected" were used extensively.
14
for better or worse, I think a lot of people view
15
"remain connected" as what it's intended to mean, which
16
is you Ride-through, you continue to exchange current,
17
you remain connected.
18
The concept and the specific terms of "remain
MS. CASUSCELLI:
Okay.
And I -- you know,
We've got more online
19
questions.
20
Team, it's not reasonable to prevent all tripping.
21
However, this is not how the draft is written.
22
this be explicit?
As stated by the panelist from the Drafting
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MR. ANTHES:
Well, again, as I see it, we have
2
three reliability standards.
3
data acquisition and monitoring, we have PRC-030 for
4
the event triggers, and then we have PRC-029 for the
5
performance.
6
when you evaluate PRC-029 compliance and performance
7
come from PRC-030, and the data that's necessary to
8
evaluate that is recorded based on your recording
9
equipment in PRC-028.
We have PRC-028 for the
So as I understand it, the triggers for
You know, maybe PRC-030 and PRC-
10
029 should've been one standard, but they're not, so
11
without reduplicating all of the requirements, I think
12
we tried to compromise and go, okay, these are event
13
triggers in PRC-030.
14
MR. PATEL:
So, Joel, we have talked offline, but
15
for everyone's benefit, I think we keep referring that
16
PRC-029 and PRC-030 are connected.
17
remember, PRC-030 -- so practicality is that we cannot
18
evaluate each and every Ride-through operation.
It's
19
just very difficult.
So the
20
way I see this is that PRC-030 has a criteria.
21
met, then you go investigate what happened.
22
doesn't mean that the plant is not in compliance or in
That is true, but
We have other jobs to do.
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compliance with the PRC-029.
2
10 percent or 20 megawatt over 4 second --
3
those are the numbers in PRC-030 -- all that means is
4
you go investigate what happened.
5
plant did not perform as expected.
6
the plant performed as expected.
7
as expected, out of compliance with PRC-029.
8
that's where even Nath's point came in, that if one
9
wind turbine tripped offline out of a hundred, you
10
11
If you reduce output by
I think
The answer could be
The answer could be
If it did not perform
I think
could be out of compliance.
MR. AL-HADIDI:
Yeah, but you have to remember we
12
do not quantify the number because you could have now 2
13
giga -- 2 giga or 5 giga plant, and now the 20 percent,
14
the 10 percent becomes significant amount of megawatt.
15
MR. PATEL:
16
MR. AL-HADIDI:
Yeah.
We leave that flexibility, and we
17
were not -- there was a huge push even for us to keep
18
that flexibility to say don't -- multiple people, you
19
won't to recover back to the hundred percent.
20
it's system dependent, and only -- we found the best
21
compromise way to deal with it is to leave it --
22
MR. PATEL:
We say
Yeah.
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MR. AL-HADIDI:
-- leave that open for the TPRC
2
based on their system need, to keep that exemption
3
because the standard said, yes, they can specify
4
different value than the hundred because we agreed
5
sometime hundred is unachievable target.
6
MR. PATEL:
I'm not debating that.
I think you
7
debated that enough with Nath.
8
is that there is a criteria in PRC-030, and that
9
determines if you're in compliance or not.
10
What I'm trying to say
It's a --
it's a -- it's a wrong understanding.
11
MR. AL-HADIDI:
12
MR. PATEL:
13
030 criteria is met.
14
The outcome of that investigation is plant failed to
15
perform or plant performed as expected.
16
perform, out of compliance with PRC-029, but the PRC-
17
029 stands on itself, right?
The way the standard is written, PRC-
18
MR. AL-HADIDI:
19
MR. PATEL:
20
MR. AL-HADIDI:
21
MR. PATEL:
22
No, no, I agree.
You investigate what happened.
If failed to
Right.
That's the debate.
Right.
We can talk about Nath's questions.
I
have the concerns with that, too, but we are not
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debating.
I think let's not link incorrectly the two
2
standards.
The only reason for PRC-030 is we cannot
3
investigate each and every Ride-through.
4
together a criteria, 10 percent, 20 megawatt, 4 second.
5
If that's met, we'll investigate.
6
plant fail to perform, out of compliance with PRC-029.
7
MR. AL-HADIDI:
We put
Answer could be
Yeah, absolutely right.
Right
8
now, PRC-002 is doing the setting for PRC-024, and it's
9
all the -- all the -- all the compliance part is done
10
with the PRC-002, but we can discuss offline.
11
you.
12
MR. KAPPAGANTULA:
One quick question.
Thank
Can you
13
shed some light on -- oh, Srinivas Kappagantula, Arevon
14
Energy.
15
definition specify voltage and frequency disturbance
16
like you had on one of the slides, especially when you
17
looked at the IEEE 2800 definition?
18
cover over-current type issues for electrically-closed
19
faults.
20
21
22
Can you shed some light on why doesn't the
It appears to
Any context to that would be great.
MR. ANTHES:
So why we didn't explicitly say
voltage and frequency disturbances?
MR. KAPPAGANTULA:
Yeah.
Yeah.
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MR. ANTHES:
9/5/2024
Page 139
Well, I think, you know, as I read
2
the glossary of term definition for "disturbance" that
3
I put up on one of those slides -- I don't know if we
4
could flip back to that.
5
so maybe it's not worth the effort, but it does talk
6
about system, perturbations changes to ACE.
7
mind, frequency disturbances, system perturbations
8
would be any electrical disturbance.
9
10
MR. KAPPAGANTULA:
MR. ANTHES:
12
MR. KAPPAGANTULA:
13
MR. ANTHES:
15
ACE, in my
So you're relying on the
glossary of terms definition for a disturbance.
11
14
It's probably 10 slides back,
I think that was our thinking -Okay.
All right.
-- was to lean on the defined terms
and the glossary of terms as much as possible.
MR. KAPPAGANTULA:
Okay.
Yeah.
In that case, if
16
-- when you're making a definition, maybe capitalize
17
the terms so it is in our glossary of terms.
18
MR. ANTHES:
19
MR. KAPPAGANTULA:
20
MR. ANTHES:
21
MR. KAPPAGANTULA:
22
MR. ANTHES:
I think we did.
Okay.
All right.
We should have.
Okay.
I believe "disturbance" was
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capitalized --
2
MR. KAPPAGANTULA:
3
MR. ANTHES:
4
Okay.
Great.
-- and "bulk power system" was
capitalized.
5
MR. KAPPAGANTULA:
6
MR. ANTHES:
7
MR. BENNETT:
Thank you.
Yeah.
Okay.
So I believe we've hit
8
lunchtime here and we've come to a stopping point for
9
the early afternoon.
So thank you to our panelists.
10
That was a great presentation on some very technical
11
terms that we're trying to make it through.
12
in addition, I believe we're going to utilize Slido
13
over lunch, so when you get a chance, take a -- take a
14
look.
15
The software will walk you through that.
16
what your favorite one is and see what you support, and
17
maybe give us a data point to see if there's some
18
industry support that'll help foster some decisions in
19
the near future.
20
And just
There's a poll out there on this definition.
It'll ask you
So with that, I think we are scheduled to come
21
back here at 1:00, after lunch, and we will start up
22
again, so thank you so much.
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(Off mic comments.)
2
MR. BENNETT:
Yeah, there'll be more to come on
3
Slido later.
4
So we've -- to make the most of our agenda, we've had
5
to shuffle a couple things around, but there'll be some
6
additional polling later.
There's going to be some additional ones.
7
(Luncheon recess.)
8
MR. BENNETT:
9
Okay.
It's a few minutes after 1:00
here, and I believe we're going to start to pull our
10
panel together and move on with our afternoon session
11
here.
12
I will say that the Slido poll, it was open over
13
lunch, and we're going to be shutting that down
14
shortly, and we'll review the results of that initial
15
poll here later this afternoon when we get to the other
16
Slido portion of our conference here.
17
a disclaimer or a heads up, as the results of those
18
polls, those quantitative results isn't necessarily the
19
path forward on a certain item, but it's definitely
20
helped framing the discussion for some decisions that
21
are going to have to be made over the next week or two.
22
So just please continue for that, and there's a lot of
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value there.
And with that I think, Jamie, I'll have you walk
3
us through Milestone 2 of the implementation plans, and
4
I'll turn it over to you.
5
MS. CALDERON:
All right.
So detailed, very
6
thorough review, which will actually be a summary in
7
about 15 minutes.
8
9
Implementation plans are incredibly important.
All of the details that are within the standard are, of
10
course, equally important to be able to say what's the
11
measure of compliance?
12
implementation plan holds those details as to when,
13
especially when we have the complication of three
14
different standards coming together that interrelate
15
and have phased-in implementation, compliance
16
extensions.
17
looking at the implementation overall.
What do I need to do?
But the
There's a lot to consider here when we're
18
So the slide, please.
19
So what is an implementation plan?
So just
20
starting from the top down, they're created for new or
21
modified standards.
22
standards.
They are created for retiring
They're created for new or modified
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definitions.
2
no overlap or gaps in time between versions, making
3
sure that there's a very clear definition of when
4
something will become effective and when something will
5
need to be complied with.
And it's entirely to ensure that there's
6
Next slide, please.
7
So the effective date.
Key terms within the
8
sections of the IP is that you're going to have an
9
effective date that's listed.
You may have more than
10
one.
11
January 1st, 2027.
12
approval by governmental authority.
13
to be six months after the approval by the applicable
14
governmental authority, which, in the U.S., is
15
generally FERC, and, of course, in Canada it's going to
16
be the provincial territories and those governmental
17
authorities.
18
It'll be either a specific date, say, like
It may be a time period after
So there's going
So it could also be something else where you have
19
a time period after another standard becoming
20
effective, which adds a layer of complication.
21
together a Gantt chart of this was something I
22
initially started to do with all three standards, and
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guess what was unable to accomplish?
2
much because we've got a phased-in implementation plan
3
portion of this as well.
4
effective dates are those.
5
retirement date, which is generally immediately prior
6
to the effective date.
7
effective on January 1st, retirement date's going to be
8
December 31st, the year before.
9
general considerations, things that you need to keep in
And that's pretty
So included within the
There's retirement -- a
So something takes place and is
There's going to be
10
mind as you're going through implementation, something
11
that might be impacted by another standard, something
12
that needs to be, you know, adhered to or communicated
13
with your regional entity or perhaps another entity
14
within your footprint.
15
you know, brought into the conversation need to go into
16
that section.
17
All the things that could be,
And then there's things that are just also just
18
standard specific.
19
actually a whole section for compliance extensions
20
because there are things outside the entity's control:
21
supply chain issues, you're not able to get contractors
22
and testing engineers onsite, but you've made good-
In the case with PRC-028, there is
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faith efforts and you can demonstrate that.
2
extensions are built into PRC-028's implementation
3
plan, and that's their -- considered as other standard
4
specific.
Compliance
5
Next slide, please.
6
So phased-in implementation plans, the bane of
7
compliance, which is -- like, Howard was alluding to
8
earlier, where you say 20 percent of these types of
9
units, but then, of course, the number of units you
10
have changes after the couple years, and when do you
11
calculate that a hundred percent benchmark?
12
based off of when the plan was originally initiated, or
13
is it based off of your current as-of-day asset list?
14
It can be very, very complicated, and nuances are
15
something that compliance deal with on a routine basis.
16
Is it
So we still do these even despite that because we
17
can't have your entire fleet come into effect all at
18
once.
19
The idea of not having everything in all at once is the
20
whole reason for having that phased-in implementation.
21
So it'll generally be milestones after the effective
22
date.
We can, but, you know, we try to avoid that.
So within PRC-028, we have 50 percent three
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years after the effective date, meaning FERC approves
2
it.
3
that complying with PRC-028.
4
complicated because we can't give an exact date because
5
we can't tell you exactly when it's going to be
6
approved by FERC.
7
to file it, but then it could be one quarter.
8
be the first day after the first quarter.
9
delayed and end up being sometime in the second
10
11
Three years later, you have to have 50 percent of
And this is where it gets
Generally, we know when we're going
It could
It may be
quarter.
So once we have that date, we can provide very
12
clear guidance and a specific date, but it does become
13
difficult to do earlier on in the process as we're
14
seeing with the IBR registration initiative and
15
bringing new Category 2 GOs into the mix.
16
know what and when, and so this kind of gets into the
17
reason as to why we can't give those dates because they
18
are subject to change based off of these trigger points
19
within the process.
20
They want to
So examples of, again, of phase-in implementation,
21
percentages facilities.
22
become effective on X date, and then Requirements 2
There's also Requirements 1
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through 7 become effective at a later date.
2
these are just due to the nature of how the
3
requirements are written.
4
process, and then 2 through 7 would implement that
5
process.
6
that, which we see within the standards that we have
7
for PRC-028, 029, and 030.
8
of it, which makes a little bit more complication, but
9
it's why we wanted to have the discussion here today
10
and have a quick panel discussion on as well because
11
being able to comply with these standards is as
12
important as being able to know what's in it and having
13
that criteria very well understood, is being able to
14
build out your compliance program in advance, making
15
sure that these things that are known issues on the
16
front end considerably with supply chain issues.
17
Sometimes
One may be -- have a
And so there could be even a combination of
It's somewhat of a gambit
You know, that's been talked about earlier today
18
with having access to sufficient contractors or
19
vendors.
20
month just prior to the effective date or the approval
21
-- or the -- that final compliance date, it's going to
22
be impossible to achieve just because you're not going
If everyone tries to go get that done in one
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to be able to get that.
2
there's preparation in this.
So we want to make sure that
It's all about planning.
3
Next slide, please.
4
So just overall, PRC-028, it's a new standard.
5
What that means is that there's not a retirement that's
6
coming with it.
7
what's in there is "shall become effective on the first
8
day of the first calendar quarter after the effective
9
date of the applicable governmental authority's order
It's an entirely new standard.
And
10
approving the standard," which probably March or April
11
1st.
12
first quarter after approval, assuming it gets approved
13
in the first quarter.
14
change.
15
quarter, it'll be, of course, down in July, but these
16
types of things become a little bit more complicated.
Probably April 1st will be the first day of the
That's, of course, subject to
If it doesn't get approved in the first
17
Next slide, please.
18
So within PRC-028 again, we have a phased-in
19
implementation for several things.
20
existing IBR resources, those that are in commercial
21
operation on or before the effective dates.
22
also the new BES inverter-based resources.
Scheduling@TP.One
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There are
There's
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also the non-BES inverter-based resources.
2
going to be the existing generators, the existing IBR
3
that meet that new Category 2 designation.
4
also going to be new ones coming online as well.
5
there are four sets of IBR within PRC-028 that you need
6
to be aware of.
7
implementation plan of 50 percent of them by a certain
8
date that are in -- that are in effect, but new ones
9
have their own information.
These are
There's
So
They each meet this phased-in
10
So on the next slide we'll get into that.
11
So for existing IBR, your existing BES IBR, 50
12
percent again by three years after the effective date
13
PRC-028, and a hundred percent of your BES IBR by
14
January 1st, 2030, and that 2030 number is from the
15
FERC order and is non-negotiable.
16
PRC-028 the ability to have compliance extension,
17
again, for the cases that are outside of your facts --
18
or your circumstances and/or ability to control, things
19
like supply chain issues.
20
to go past that 2030, but you do have to be able to
21
demonstrate that.
22
We do have within
Again, there's a potential
New BES IBRs, so those coming into commercial
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operation, but might be in the current design phase
2
after July 1st, 2025.
3
buffer for things that are currently iron in the
4
ground, going to be coming online within the next year
5
or two.
6
bandwidth or lead-way for at least some of those that
7
are currently being developed.
8
October, 2026 entity shall comply with requirements R1
9
through R7 by October 1st, 2026.
So that's going to be
10
the cutoff date for new BES IBR.
After that,
11
everything needs to comply.
That's to give a little bit of
We want to make sure that we're giving enough
But on or before
12
Next slide.
13
Existing non-BES IBR, a hundred percent by 2030.
14
That's just the blanket rule, everything by 2030.
15
the existing non-BES IBR, within 15 months following
16
the effective date of the standard of the commercial
17
operation date, whichever is later.
18
to make sure that there's a really clear consistency on
19
when the Category 2 generator assets are going to be
20
applicable.
21
-- or I'm sorry -- for that registration date for new
22
registrants by May 2026.
But
We've been looking
We have a cutoff date for that compliance
So what we've done here is
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make sure that nothing's going to be held compliant for
2
those Category 2 generator owner assets prior to that
3
initial cutoff date.
4
registration.
5
on early and becoming compliant with standards early.
6
We want to encourage early compliance, but we're not
7
going to penalize people, you know, prior to that May
8
2026 date.
Try to encourage early
Don't want to penalize people for coming
9
So again, there's the process for the compliance
10
extensions built into PRC-028, and that's intentional
11
and very important to ensuring that we have a strategy
12
that can be implemented.
13
risk assets first, perhaps the larger units in your
14
fleet first, and then you scale down as you're able.
You go after your highest-
15
Next slide.
16
For Project 2020-02, we're looking at PRC-029.
17
This also is a new standard.
18
project a component that is PRC-024, and that PRC-024
19
piece will have a new version that will become
20
effective and the old version will become retired, of
21
course.
22
after the effective date of the applicable governmental
We do have within this
But PRC-029 shall become effective 12 months
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authority approving the order approving the standard.
2
And on the next slide, this is where the key
3
pieces of information is.
4
requirements.
5
studies to demonstrate your IBR will Ride-through, have
6
the capability of riding through.
7
demonstrated through studies.
8
demonstrated potentially through EMT evaluations being
9
able to identify and demonstrate that you can meet the
There's capability-based
This is design, the ability to do
This is going to be
This is going to be
10
Ride-through capability.
11
effective date of the standard, and the non-BES IBR,
12
again, this is the Category 2, we're talking January
13
2027.
14
everything come in all at once for Category 2 GOs, so
15
we're staggering those out and we're working with
16
compliance and registration to ensure that happens.
17
within this batch of standards, we've looked to say
18
January 1st, 2027 is reasonable for these new -- these
19
new -- these new generator owners coming online.
20
So that's the capability-based Ride-through
For BES IBR, it's the
And that's in line with we're trying to not have
21
criteria, and this is a little bit of a different
22
phased-in implementation plan where we have a single
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requirement that has different aspects, one being that
2
design base that you demonstrate through studies, and
3
then it becomes the performance-based criteria that
4
that becomes effective later.
5
6
7
Oh, sorry.
before.
So we're looking at --
One slide previous.
No, before.
Yeah.
Yep.
One slide
Thank you.
So performance-based Ride-through criteria is for
8
both BES IBR and non-BS IBR.
9
it with your PRC-028 implementation plan, and that's
Nothing new here.
Align
10
because within PRC-028, you're installing new
11
equipment, you're working with your vendors, you're
12
working with supply chain, and you're getting that
13
installed.
14
performance at a generator that you haven't installed
15
that equipment at yet.
16
028's already sufficient to demonstrate that you've got
17
the -- you've got the risk resolved by having the
18
monitoring equipment installed and you have the
19
capability of demonstrating what you're doing onsite,
20
how it's performing.
21
your performance-based Ride-through criteria needs to
22
be demonstrated.
You shouldn't be required to demonstrate
The implementation plan for 0-
And at that point you become --
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And now we can go to the next slide.
2
All right.
So for Project 2023-02, new standard
3
again, PRC-030.
What we're looking for is -- this is
4
the analytics that base -- work off the same as 029.
5
We have an IP revised and current draft for formal
6
comments, so I actually cannot take questions on PRC-
7
030, but this is a public forum and we can briefly talk
8
about this because it's currently under ballot.
9
But what is in the revised IP?
We recently did
10
pass ballot, but due to some necessary conforming
11
changes to make sure that the PRC-030's implementation
12
plan was in line as intended with PRC-029 and PRC-030,
13
it's currently out for ballot just for those conforming
14
changes and some small revisions within the
15
requirements for R2.
16
ballot.
17
capability-based language from that IP, so now it's
18
only focused on just on the next slide when it becomes
19
effective.
20
So the IP is currently out for
We did remove the performance-based,
So it's later of the first day of the first
21
calendar quarter that is 12 months after the effective
22
dates or approving the standard or the first day of the
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first calendar quarter that is 12 months after the
2
effective date of the applicable governmental authority
3
order approving Reliability Standard PRC-029.
4
to say this is meant to align with your PRC-029
5
rollout, and PRC-029's rollout is meant to align with
6
PRC-028.
7
for that same basis of performance data criteria and
8
having the analysis that's triggering that data, and
9
having the data installed and that equipment being
All that
So these are all tied together for that --
10
installed at those sites are all in conjunction and
11
working together.
12
talked about yesterday.
So it's that three-legged stool we
It's one solution.
13
While there are three different IPs, they daisy
14
chain together intentionally to make sure that we're
15
not putting anyone into a compliance bind by having a
16
gap.
17
equipment installed, you shouldn't be held accountable
18
for performance that you can't demonstrate.
19
built into the IPs.
20
21
22
If you don't have disturbance monitoring
So that's
And at this point, I think we can go to the next
slide, which should be -- okay.
I did add this in just to -- as a callback from
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yesterday.
2
voltage frequency excursion occurs, and so you see
3
these two standards on the right.
4
together, and then on the disturbance monitoring side,
5
PRC-028 on the far left, all to say that all three of
6
these go together, and this is just a visual
7
representation, again, as a callback.
8
make sense yesterday, maybe it makes less sense today,
9
but hopefully it makes a little bit more sense.
We talked about how these tied together,
PRC-029 and 030 tie
If this didn't
It
10
makes more sense to me than it did when I originally
11
made it, so this is good.
12
But when it gets to making sure that you have an
13
understanding of this, ask questions.
14
your regional entity.
15
to help provide that guidance, so as these come out,
16
don't guess, of course.
17
officer is doing that, but if you have questions or
18
concerns, please raise those, bring those up.
19
regional entities are there to help.
20
think we can go to the next slide and take questions.
21
22
MR. BENNETT:
Reach out to
That compliance staff is there
I don't think any compliance
The
And with that, I
So, Jamie, on this one, I was just
going to ask, would you prefer to have questions on
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this now or kind of morph into your panel discussion?
2
MS. CALDERON:
3
MR. BENNETT:
4
MS. CALDERON:
5
MR. BENNETT:
Let's just do the panel, yeah.
And do it all at once.
Yeah.
Okay.
Yeah, let's do the panel.
Let's just -- let's just do
6
that.
7
starting to make their way to the stage.
8
going to be kind of continuing the conversation on
9
implementation plans and effective dates.
Okay.
So it looks like the panelists are
So this is
And Charles
10
Yeung, our moderator from earlier, is back with us as
11
well as Jamie to help moderate this conversation, and
12
with that, Jamie, whenever you guys get settled up
13
there, please start in.
14
MR. YEUNG:
So Jamie kind of recapped where we
15
were, and I think it'd be good to put that other slide
16
back on, her last slide with the three standards.
17
that possible?
18
what we're going to talk about on this panel.
19
to bring up the questions.
I think that's a good reference for
20
(Brief pause.)
21
MR. YEUNG:
22
Is
I need
Excuse me.
So let's start with introductions.
Maybe we'll start on the end, just who you are, who you
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represent, please.
2
MR. HAKE:
3
here.
4
Energy.
5
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Page 158
Yeah.
Hey, everybody.
So Sam Hake
I'm a NERC compliance engineer with a AES Clean
We're a renewable energy developer.
MS. JONES:
Good afternoon, everyone.
My name is
6
Rhonda Jones, and I lead the NERC compliance efforts
7
for Invenergy, and we're a developer and operator of
8
many projects throughout the United States, and we're
9
headquartered in Chicago.
10
11
12
13
14
MR. GUGEL:
And I'm Howard Google, vice president
of regulatory oversight at NERC.
MR. PATEL:
Manish Patel, Electric Power Research
Institute.
MR. YEUNG:
Again, I'm Charles Yeung. I work for
15
Southwest Power Pool, a member of the Standards
16
Committee, and we know Jamie is.
17
MS. CALDERON:
Yeah.
My name's Jamie Calderon
18
with NERC Standards Development.
19
have just bricked.
20
MR. YEUNG:
21
MS. CALDERON:
22
MR. YEUNG:
My computer seems to
Crowdstrike?
Yes, probably.
Well, I think implementation's a real
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important issue.
2
already passed.
3
the PRC-030, and hopefully as far as this conference is
4
concerned, we'll get to passing a standard for PRC-029.
5
I believe two of these standards have
One is under a final ballot, I think
I think one of the things probably not recognized
6
because it's still in development is the issue of
7
exemptions.
8
finalized exactly what that would look like, but I
9
think that might have some bearing on this
That's going to be -- yet have to be
10
implementation.
11
some of the comments we've heard so far about
12
exemptions and implementation because with exemptions,
13
certainly there's different types, different impacts,
14
and perhaps impacts on the implementation, too.
So maybe the panelists can consider
15
So the first question is, given the complexities
16
of these three standards -- PRC-028-1, PRC-029-1, and
17
PRC-031 -- what strategies would you recommend in
18
synchronizing implementation to avoid conflicts or gaps
19
in compliance?
20
they're all one big happy family, so we need to
21
synchronize those together.
22
considerations are needed to prevent potential overlaps
Again, with the explanation Jamie gave,
And then what
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or inconsistencies in that implementation?
2
to just start on the end?
3
MR. HAKE:
Yeah.
Yeah, absolutely.
So you want
So a couple
4
of points to make here.
5
should expect overlap.
6
existing implementation plans, that is acknowledged, as
7
Jamie just presented.
8
concern over the differentiation between the design
9
portion versus their performance.
I think, first of all, we
I think that currently in the
I do think that we have some
Particularly for
10
PRC-029, a lot of the challenges that we've heard
11
discussed -- you know, OEMs being out of business,
12
modeling information not being available -- those are
13
really going to impact us on the design side first,
14
right?
15
so I think that for our -- my personal view, I think
16
that the link that we currently see through the
17
performance requirements needs to be replicated also
18
for the design.
19
cleanly differentiate between those.
20
That's the first thing that we have to do.
And
I'm not sure that we can really
And then the second main point I wanted to make
21
was also referring to some discussion that we heard
22
yesterday about the design cycles for the equipment
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capabilities here.
2
years for the design cycle.
3
the equipment available, not installed in the field,
4
looking at another three years for deployment.
5
eight years there, we're already at the very end of the
6
-- you know, the 2030 hard date.
7
confused and concerned about that, and I think that
8
that's something that really needs to be seriously
9
considered as the Drafting Team and NERC moves forward.
10
MS. JONES:
So it was on the order of five
That's five years to have
So with
So we're certainly
Some of the things that we've done at
11
Invenergy to kind of prepare, yes, definitely we share
12
some of the same concerns about design with some of our
13
equipment.
14
kind of help get ahead of this is that we've already
15
started to kind of develop, like, timelines, in
16
specific, to the type of equipments that we have.
17
so we kind of map out current day, if this goes into
18
effect, what would it look like.
19
do today to be ready from a design perspective, being
20
probably proactive, and looking at equipment and who
21
we're going to procure that from, and what does that
22
look like?
But one of the things that we've done to
And
What would I need to
So we are really, like, starting earlier to
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kind of just planning side of it to really help us to
2
make sure that things are coordinated, and kind of
3
almost doing a gap analysis early to just kind of see
4
where some of those needs will be and trying to fill
5
those in and be proactive in that regard.
6
Also, too, as Jamie kind of talked about early,
7
kind of prioritizing those high-risk assets and those
8
that we would probably need to give -- that will
9
require the greatest need of support.
Say if an OEM is
10
no longer in business, what is our strategy or
11
contingency to kind of come up with how do we
12
articulate design in those cases and respond
13
accordingly?
14
just really big here is just we can't underestimate the
15
power of kind of mapping it out almost project style.
16
I have over 75 plants that I have to get ready for
17
this, and by the time, you know, we have to start
18
implementing and kind of installing equipment, I'll
19
probably be at 85, 90 plants that I have to do this
20
for.
21
and a schedule to get the different phases done.
22
And one of the things that we feel is
So just really strategizing early on a timeline
MR. GUGEL:
Yeah.
I'll kind of tie this back into
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the previous panel's discussion.
2
depend on how the next version of PRC-029 deals with
3
exemptions.
4
performance expectations map to what everyone is saying
5
that their current units can perform to, it'll be
6
easier to demonstrate that than if it varies from it.
7
So, you know, if there's a, an expectation by most
8
folks that, yeah, we can meet PRC-024, maybe if that
9
exemption is closer to that curve for existing units,
I think it's going to
I think the closer the exemptions and the
10
it might be a little bit easier to kind of work through
11
and demonstrate that than if all your existing units
12
you needed to demonstrate something that's a little bit
13
different from that, and would be different
14
documentation that you have in place.
15
MR. PATEL:
I don't have too much to add, but
16
before I forget, I think we need a Ride-through
17
standard for Jamie's laptop.
18
(Laughter.)
19
MR. PATEL:
Anyhow, so I think what Howard said is
20
absolutely right.
21
looks like in the next couple of weeks.
22
that, I think credit to all three standard Drafting
I think it depends on how PRC-029
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Teams.
2
implementation plans were pretty synchronized.
3
we can always debate is the time allowed enough or not,
4
but I think there was great deal of effort in
5
coordinating implementation plans of the three
6
standards, and there is an opportunity to tweak those
7
based on what the changes might look like.
I think, my personal opinion, the
8
MR. YEUNG:
9
MS. CALDERON:
I think
Yeah.
I have a follow-up question if I
10
may.
11
specific equipment, is there a particular type of
12
equipment that would be perhaps more difficult to
13
secure?
14
of your head, but just when it comes to the
15
installation of new monitoring equipment, is there any
16
that are more challenging to do on the front end
17
because, like, transformers have a long lead time.
18
just unfamiliar with the disturbance modern equipment
19
that's being required at the plant level and the -- and
20
the sub-plant level as well.
21
22
Yeah.
When it comes to the challenges with
And I don't know if you have this off the top
MR. PATEL:
Right, right.
I'm
So I think the PRC-028
Standard Drafting Team debated that a lot, right?
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one thing to draw up a CT or PT distance monitoring
2
equipment on a piece of paper, a single-line diagram.
3
It's another thing to actually go out, get an outage,
4
procure equipment, get the panel on which you will hook
5
on the equipment.
6
So I think the 028 team did take into
7
consideration all that, with the expectations or the
8
directives from Order 901, right?
9
clear in terms of when those standards need to be fully
Order 901 is very
10
enforced.
11
may have noticed that we realized that, you know, it
12
may be challenging.
13
are talking about.
14
standard for BES IBRs, we had some idea about how many
15
plants we were talking about.
16
staff had pulled up some data and said about 800 to
17
thousand BES IBR plants.
18
BES-IBRs, and we have no clue how many of them are out
19
there.
20
directive of the Order 901, and we have to realize that
21
there are some practical limitations based on which,
22
you know, equipment gets installed in the -- in the
But then if you remember, and some of you
I don't know how many plants we
I think when we were only writing a
I think someone at NERC
But then we rolled in non
So long story short, we have to honor the
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station or at the plant.
So the framework, there is a framework in the
3
implementation plan.
4
that beyond -- that is beyond their control, right,
5
then there is a framework in the implementation plan of
6
the PRC-028 standard that allows to seek exemption or
7
seek extension -- sorry -- extension of implementation
8
plan from the compliance enforcement authority.
9
anyhow, I think the PRC-028 team did as much as they
If the NTT provides reasoning
So
10
could to honor the directive and realizing actual, you
11
know, problems that might come up as industry goes
12
installing equipment.
13
MR. YEUNG:
Thank you, Manish.
Second question,
14
and, Panelists, if you have things to add, maybe you
15
can elaborate with the second question because it's
16
very related to the first one.
17
you anticipate would the -- with the -- will be the
18
most significant challenges when retrofitting or
19
modifying the legacy IBR -- and that's kind of what
20
Howard mentioned on the exemptions -- to comply with
21
these new standards?
22
on which one of the three, it just refers to all three,
So question is, what do
And the question's kind of silent
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but if there is a particular one that you want to call
2
out, I suspect there is, that's more challenging than
3
others, that'd be helpful.
4
practical solutions or best practices that have proven
5
effective?
6
getting started early, so thoughts on that, Panel?
7
this way or start down there again?
8
9
So can you share any
And I think we heard some things about
MR. GUGEL:
Yeah.
No, I can start again.
Go
So I
think that one of the huge challenges that we are
10
concerned with, again, as been discussed previously, is
11
resource availability both on the GO side, the OEM
12
side, really across the board.
13
uncertainty on the path forward makes that extremely
14
difficult, and I think it's going to hit every part of
15
the industry.
16
wanted to make here as far as challenging for
17
retrofits, you know, I'm focusing on PRC-029 here,
18
although I'm not sure I would want to opine on which is
19
more difficult.
20
exemptions, I made a similar point yesterday about
21
hardware- versus software-based exemptions, and again,
22
this goes into planning.
Having a confusion and
And then I think the second point I
But so specifically regarding the
We're not sure how to
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interpret this and what to do about it.
I do -- I just want to caution that I'm concerned
3
that the focus on hardware- versus software-based
4
limitations is missing part of the point.
5
concern, again, is on the modeling side, and as I
6
understand it, models are very literally a software-
7
based representation of the entire system, which
8
includes hardware and it includes software.
9
just driving the point home that having exemptions only
A lot of our
So again,
10
for hardware seems to be unnecessarily restrictive and
11
makes the assumption that the software issues can be
12
resolved much more simply, which I'm not entirely sure
13
is true.
14
MS. JONES:
Just to kind of add to that, I think
15
for us kind of doing just that commercial/economic
16
assessment now and being a part of, like, kind of our
17
long-term forecasting is, these solutions, even if we,
18
you know, do exercise exceptions, is going to require a
19
financial -- increased financial investment, and that's
20
just the reality of it.
21
they're saying, hey, Rhonda, how much is it going to
22
cost, and I'm saying, I don't know yet, but you want me
And I think what's hard is
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to buy it tomorrow.
2
does that number look like, but also, too, you know,
3
the challenge is kind of having that conversation with
4
the OEMs to kind of help us to get to a number that's a
5
strong, strong estimate of that.
6
And just trying to figure out what
So understanding the commercial and financial
7
impact, but also, too, being able to articulate the
8
return on this possible investment that we're making.
9
Hey, Rhonda, we're going to do this, and what does that
10
mean for us as far as production?
11
does this mean for us as far as return, and kind of
12
substantiating that is something, too, that's -- can be
13
a little bit of a challenge in that regard because it
14
needs data.
15
modeling -- I'm happy that we do have an in-house
16
modeling team to kind of help us with that.
17
also, too, is going to really kind of increase the
18
resource need there as we try to articulate our
19
position in that regard.
20
Hey, Rhonda, what
Just like my neighbor here, I think
But that
Also, too, we worry about -- another big challenge
21
is termination of services for the few OEMs that we
22
have equipment for that are no longer in operation and
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just trying to figure out what is that -- you know,
2
what is that story that we tell from an engineering
3
perspective to give our best understanding of what to
4
expect of these devices.
5
collateral impact to other standards.
6
PRC, but there's a lot of other NERC standards that are
7
going to have to be addressed once the standards are
8
approved and kind of putting things in place to kind of
9
address the -- I call it the collateral impact of these
And then also, too, just the
This is just not
10
standards going forward.
11
ratings, et cetera, and safety and also, too, and the
12
analysis and impact there, which is of great concern.
13
I think about my facility
But hey, yeah, those are the concerns, but how do
14
you kind of address those?
15
that have never really talked to their OEMs, get to
16
know them today.
17
Really get to know about your fleet and about your
18
equipment, about the type it is.
19
tech sheets, those specs.
20
the business as we are of acquiring already existing
21
projects, make that a part of your turnover package.
22
To really, really learn these assets, you're probably
I kind of encourage folks
Establish a relationship with them.
Find those, those
Sometimes if you all are in
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going to be more of an expert on the asset, and that
2
expectation is to know it there.
3
these conversations now even before the standards get
4
approved to just knowing what you're working with.
5
those are some things to do to kind of offset it.
6
You can start having
So
And then we are a big fan of the, you know,
7
hardware exemptions, and I think that that's a good
8
thing, but also, too, you can start now building that
9
story and what does that look like in order to
10
substantiate it.
11
to do it alone, but, you know, when you're an operator,
12
you're close to the action.
13
about effectiveness and what your limits are.
14
I don't think it's solely on the OEMs
You can tell the story
Part of the strategy that I have in my shop is
15
always about optimization.
16
story?
17
PRC-029, we're always in a position to demonstrate is
18
my equipment performing to the best of its ability and
19
this is why.
20
if it is used to substantiate an exemption, is
21
something that is knowledge that can go a long way in
22
helping you.
What is the optimization
And that's something that's -- with or without
And I think an optimization story, even
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MR. YEUNG:
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So let me kind of follow up with you
2
and Andy, Rhonda.
3
frames, yes, there -- we have a lot of these.
4
any particular one of these standards where the
5
implementation time frame really is just, you know, as
6
proposed is more problematic, or are your concerns
7
through both 028, 029 and 030 implementation?
8
9
MS. JONES:
As far as the implementation time
Is there
I would -- I would say that -- you
know, also, too, if I could have a longer runway, I'll
10
take it because like I said, I have about, you know, 70
11
to 80-plus projects to get ready for, and I just think
12
I'm concerned because one of the biggest thing is just
13
the bottleneck.
14
I went forth to my OEMs with what my needs and supports
15
are, do they have the capacity to fit the timelines
16
that are being proposed and those that we have
17
internally at in Invenergy.
18
things, just trying to merge their availability and
19
capacity with ours.
20
that it may really be challenging to meet that, and so
21
that's one of our biggest concerns.
22
And right now it's hard to predict if
And so that's one of the
And sometimes I do kind of predict
On the disturbance monitoring equipment side, we
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haven't gotten a lot of concerning feedback about the
2
availability of that, but maybe a lot of people haven't
3
started asking about it yet, so we don't really see a
4
lot of big concerns there.
5
to kind of get going and going out of the gates, we are
6
concerned that just from just bottleneck of services is
7
going to be a challenge.
8
MR. YEUNG:
9
to add to that?
10
MR. HAKE:
But once everything starts
Supply chain issues.
Yeah.
Andy, anything
So I think I agree with pretty
11
much everything that was just said.
12
the phased-in implementation for PRC-028.
13
that's very, very important.
14
during the first question that I personally believe
15
that the design portion shouldn't be separated from the
16
performance portion.
17
to be separate and should also be contingent on the
18
PRC-028 information.
19
We're a big fan of
I think
I made the point earlier
I don't see that needing to be --
And then the last part I'll mention here is on the
20
newly-revised PRC-038 implementation plan.
21
personally, I think that the link there to PRC-029 is
22
important.
Again,
I'm not sure how much we can discuss that
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today, but just putting that out there that, again, I
2
view all three standards as being somewhat sequential,
3
and I'm not entirely understanding why that revision
4
needs to be made after it was already approved.
5
MR. GUGEL:
Yeah, Rhonda, if I could pull on a
6
thread of something you mentioned earlier because it's
7
not anything that I had considered.
8
things in PRC-028, 029, and 030 that would cause
9
changes to your FAC-008 policy?
10
MS. JONES:
What are the
Well, like, when we talk about some of
11
the auxiliary equipment that, these changes that we're
12
making, if PRC-029, the curves are approved as
13
proposed, we think about some of the safety concerns
14
with the equipment down the line.
15
of that comes in when we're looking at the transformers
16
and stuff like that.
17
scenarios that they showed, it's like, well, wow, I'm
18
not only worried about the actual inverter itself, but
19
worried about some of the other auxiliary equipment in
20
that regard when you look at it from a scenario
21
perspective.
22
MR. GUGEL:
So that's where kind
Okay.
In certain events, in the
Yeah, I just -- I mean, the
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time frames that you're talking about, let's assume
2
that, you know, that the curves in PRC-029 stay the way
3
that they are.
4
most of the auxiliary equipment you'd be talking about,
5
especially when you're talking about transformers, CTs,
6
PTs, breakers and switches, seconds is not going to be
7
enough for that to heat up and cause any kind of -- I
8
don't think, at least in my experience, wouldn't be
9
enough to change a rating for any of those.
You know, the thermal constraints for
Now, if it
10
was extended, protracted, maybe, out for 15 to 20
11
minutes, which is not something we'd really be talking
12
about here, then I could see how that could be
13
affected.
14
figure out where it would change a -- that short-term
15
thing would change some sort of a rating for your
16
facility that isn't already taken into account in your
17
existing FAC-008 process.
18
But I'm struggling a little bit trying to
MS. JONES:
Yeah, that's something I'm
(Off mic) probably spent years on, but
19
definitely, that's something that came up about the
20
safety of the equipment and its ability to react, and
21
how it just can have that domino effect down the line.
22
MR. YEUNG:
Okay.
Manish, your comments, and if
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you can throw in a joke, it'd be appreciated.
MR. PATEL:
I'm running out of them.
So I'm going
3
to take a slightly different way to answer this.
4
so, you know, PRC-023 transmission, really loadability
5
standard.
PRC-025, generator relay loadability,
6
standard.
PRC 26, stable power swing standard.
7
those standards, when they were written, either
8
concurrently or immediately after, there was a document
9
produced either by the Standard Drafting Team or some
And
All
10
other technical committee or working group at NERC that
11
shows how to do calculations so that, you know, people
12
know how to meet the requirements of the standard,
13
right?
14
PRC-024, there is actually a document that -- out
15
there that shows three methods to do calculation for
16
converting voltage from high side of the main power
17
transformer, the generator step of transformer, to
18
synchronous machine terminals.
19
so, some solar developers came to say, well, you have a
20
document that shows calculations for synchronous
21
machines, not for, you know, solar plants.
22
Protection Working Group -- I work with them -- we put
And three years ago or
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together a white paper that shows one method that, as I
2
mentioned earlier this morning, that hopefully will get
3
approved by RSTC.
4
What I'm trying to say with all that back story is
5
PRC-029, it's a Ride-through standard.
6
framework out there to show a sample method to evaluate
7
your plan with and show that either it meets or does
8
not meet the Ride-through requirements, right?
9
think as we think about implementation plan, we need to
There is no
So I
10
think about the Joe Smith out there working on putting
11
together documentation to show compliance.
12
have or she has tools and calculation methodologies to
13
go along, right?
14
assuming that the standard gets filed, approved by FERC
15
early next year, then within one year, so first quarter
16
or second quarter of 2026, we are looking at fully
17
enforced standard, right?
18
we provided tools, methodologies to the industry that
19
can be followed and then that can be applied to this
20
thousand BES and then, in another nine months or so,
21
non-BES IBRs needs to be fully enforced.
22
calculations be done in some of this?
Does he
As written the implementation plan,
Do we -- do we have -- have
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You still need to go back to your OEMs, right, get
2
some information that might be necessary to show
3
compliance or seek exemptions and all that stuff.
4
think -- I think we need to about some of those things
5
when we talk about implementation plan.
6
any comment on PRC-028 implementation plan.
7
chair of the Standard Drafting Team, and as I said, we
8
have done best possible.
9
slightly different in nature, but I think when we think
So I
I don't have
I'm a
And I think PRC-030 is
10
about PRC-029 implementation plan, we need to be very
11
careful that we provide industry time and tools, right?
12
There is not a single literature document out there
13
that shows this is how you will evaluate Ride-through
14
capability.
15
regulatory standard, right?
16
methodology out there, I think.
17
Ride-through, this is first-of-a-kind
MR. YEUNG:
18
029, Manish.
19
anything to add?
There is no tools in
So we should've made you chair of PRC-
There wouldn't be a question.
20
MS. CALDERON:
21
MR. YEUNG:
22
new generators.
Jamie,
No, not on that question.
Okay.
So the next question is about
As mentioned, we also now have a SubScheduling@TP.One
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Category 2 type of registration that's going to be
2
under compliance for these standards as well.
3
NERC is expanding their registration criteria for the
4
GOs, how should companies approach the integration of
5
new assets or changes in ownership to ensure seamless
6
compliance, and what are there -- what are the key
7
considerations to keep in mind?
8
heard some of the things about, you know, tools, right,
9
especially these new players, as you said, the plain
10
Joes who have never been subjected to noncompliance.
11
MS. CALDERON:
So since
I think we already
Well, if I may expand on that, the
12
impetus for this question as well is we see a transfer
13
in ownership much more with a lot of the smaller IBR
14
than we're seeing with, like, conventional generation
15
where whole companies come and go.
16
quickly we have foreign-owned investors, and there's a
17
lot of interchange between some of this ownership with
18
IBR that we don't see traditionally.
19
additional layer of complication to this question then,
20
I think, is why we wanted to bring it up to the panel.
21
22
MR. HAKE:
It seems very
So there's an
Yeah, so I'll start again.
this is a fun challenge for sure.
Scheduling@TP.One
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This is --
So I guess what I'll
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do is just explain a little bit about how AES has kind
2
of attacked this, at least very, very early stages, to
3
be clear.
4
So we've come up with our list of potential new
5
Category 2 sites, right, based on all the data that we
6
have on our operating fleet, begun the effort of
7
gathering data in the field.
8
going to be a tremendous resource drain and constraint
9
on us in order to get this information.
We believe that it's
It's not
10
trivial.
11
super firm understanding of what exactly are we going
12
to have to do for these Category 2 sites, we figure we
13
can at least get some stuff started.
14
going to need that data no matter which standards
15
apply.
16
So even though, currently, we don't have a
You know, we're
And then to more directly address the question
17
about change of ownership for projects or how are we
18
now treating these Category 2 projects, especially new
19
ones that are coming up, and it might sound like a bit
20
of a simple answer, but, essentially, what we're doing
21
is treating them the same way that we do our Category 1
22
projects.
So again, because we don't necessarily know
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specifically which standards will apply, we are taking
2
a conservative approach and assuming it's going to be
3
most of them, if not all of them.
4
It does raise a lot of concerns and challenges in
5
working with our contractors trying to figure out what
6
is going to happen.
7
uncertainty just the same way that we don't, but that's
8
essentially what AES Clean Energy, our approach has
9
been thus far.
You know, they don't like
And we're certainly eager and awaiting
10
additional information so that we can, you know,
11
continue to plan and make sure, again, touching on the
12
resource availability point, that we have all the
13
people in the right places in order to actually make
14
this happen.
15
MS. JONES:
I echo -- I echo that process very
16
similar to how we do it in our shop.
17
we have about definitely 10 or 12 that'll come into --
18
under Category 2, and we just kind of stress test them
19
under the most extreme scenario.
20
the curves will come in a little bit, but nonetheless,
21
we just try to, in our shop with our NERC readiness
22
process, is try to understand now, well, what do we
Scheduling@TP.One
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Now, our hope is that
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need to do to get these facilities ready to be able to
2
demonstrate compliance, and it's just starting early
3
and trying to figure it out.
4
And we do have one or two cases where the vendor
5
is no longer there and just trying to, on our own, be
6
able to substantiate their effectiveness to the grid,
7
which we think is most important, and being able to
8
show how they continue to support grid reliability in
9
the absence maybe of some of that information because
10
11
the OEM is no longer around.
MR. GUGEL:
I like what I'm hearing, I mean, and I
12
think that's an excellent approach for folks to be
13
taking.
14
hands, hopefully there's a communication that occurs to
15
let folks know, hey, by the way, are you registered
16
with NERC if you're -- if you're selling an existing
17
asset or changing it, and if not, you might want to
18
reach out because the world's about to change.
19
yeah, raising that awareness, too, it would help -- it
20
would help us and help them, I think, entirely to make
21
sure that we've got awareness raised on those areas.
22
You know, the fortunate thing is we don't register
The other thing is that as assets change
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assets, we register entities, so once you're in, you're
2
in and, and you're in the know, if you will, so yeah,
3
but the approach that y'all are taking I think is
4
really good.
5
And then just a reminder that since these are, you
6
know, non-BES assets, standards would only be
7
applicable as they're changed or as, you know,
8
definitions kind of change in that area.
9
to be a process of standards development as each one of
So it's going
10
-- each standard is modified to see whether or not
11
these non-BES assets are included or not.
12
MR. PATEL:
So I don't have much to add to what
13
Howard said.
14
thought that came to mind is, you know, when you sell
15
your home, you have to -- you have to sign this
16
disclaimer about the status of the home, what's in it.
17
If something's broken, you have to declare it and all
18
that stuff.
19
checklist out there that someone can put together that
20
one owner gives to another owner, then the ownership
21
changes, and, you know, let the new owner become aware
22
of what they're getting into.
When I read this question, the raw
I think -- I think there might be a
I don't have much to add
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here.
2
those entities who play in this non-BES assets world
3
need to catch up to the reality that NERC standards
4
would apply to those assets now.
5
I think it's an administrative process, but all
MR. YEUNG:
-- communication for the new owners,
6
and, of course, NERC has already a plan for registering
7
these new owners, too.
8
9
The next question is a little bit maybe kind of -kind of going back to some of the things that already
10
been said, so I'm going to revise it a little bit.
11
question is, how does supply chain issues impact the
12
timely implementation of these new standards,
13
particularly in terms of retrofitting existing or new
14
installs, and what proactive measures can be taken to
15
mitigate these potential risks?
The
16
And I think we are over these past couple of days,
17
we've heard a lot about the PRC-029 impacts of these --
18
implementation and how the supply chain might impact
19
that.
20
two standards, 028 and 030, and, Manish, I think you
21
already opined on that a little bit, particularly,
22
again, this is about a lot of new Category 2 assets
So maybe kind of talk more about maybe the other
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that probably don't have any type of this equipment
2
presently.
3
MR. PATEL:
That is true for PRC-028.
It is very
4
likely that non-BES IBRs do not have all necessary
5
equipment.
6
recording as required by the standard, but not all
7
recordings that the standard requires.
8
require them to -- actually, if they don't have their
9
own engineering staff, first of all, go and find an
They may have some that can do some
This will
10
engineering consultant who can help them, right, design
11
the DME equipment, and then go and find folks who can
12
actually go into the substation and install it, right?
13
So it's going to be quite a bit of work.
14
In some cases they will have to talk to IBR unit
15
OEMs because the standard requires SCR data from the
16
inverters or the wind turbine generators.
17
have to go and talk to the OEMs about the capabilities
18
of that particular, you know, vintage of equipment that
19
they have in their asset.
20
work required, and I think that's why, as I said
21
earlier, the Standard Drafting Team, you know,
22
respecting the directive of the Order 901 in terms of
So they will
So there is quite a bit of
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when the standard needs to be fully enforced, still
2
went ahead and offered a framework to seek extension,
3
right, because again, I can draw up DME equipment right
4
here on my notepad in matter of five minutes.
5
another thing to actually go and get it installed in
6
the substation.
7
MR. YEUNG:
Howard, any thoughts?
8
MR. GUGEL:
Yeah.
9
add.
It's
I don't really have anything to
I'm not sure that, from our perspective, we
10
really understand the supply chain issue there.
11
think that, as it's mentioned before, you know, volume
12
is going to play in -- come into play here, and the
13
fact that you've got, you know, a significant number of
14
folks that are having to procure new equipment may
15
bring that into play and may cause a supply chain
16
issue.
17
I do
I could be totally wet on this and some folks may
18
be able to straighten me out on this later, but I think
19
one advantage that these units have over maybe the
20
traditional synchronous units are that they're already
21
sampling a lot of information.
22
bringing a lot of data in to do all the monitoring
They're already
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that's necessary internally.
2
the fact that they don't have to install some
3
additional inputs might be an advantage, but you're
4
still going to have to have that external logging
5
equipment there that would be able to pull that
6
information in.
7
little bit easier, there's still a lot of stuff that
8
has to occur and would be impacted by supply chain.
9
MS. JONES:
So it may be, you know,
So while one part of it may be a
Nothing new to add with supply chain.
10
I think we've kind of talked about it with just the
11
volume and not knowing that, and just hope that we're
12
at the front of the line is what I strive for when we
13
start to request this equipment.
14
know, I think the other thing that we kind of think
15
about with supply chain is not just equipment.
16
of the things that kind of came up in our analysis is
17
the ability for this equipment to record all this data
18
and what does that mean for additional kind of
19
capacity, and should we be looking at that as far as
20
something else to kind of consider as far as managing
21
and storing that data is something also, too, came up
22
in some of our conversations.
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But nonetheless, you
But one
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MR. HAKE:
Yeah, I don't have too much more to add
2
on this one.
3
again that in some cases, OEMs are out of business, so,
4
effectively, the supply chain does not exist.
5
early enough in the process that we haven't encountered
6
any specific supply chain issues with particular
7
equipment.
8
concerns that there's a whole lot of companies out
9
there that are going to be requesting the same thing,
I think that -- you know, I'll mention
We're
But, you know, we, of course, share similar
10
at the same time, on the same timeline.
11
very concerning, right, again, from equipment and,
12
again, from a resource availability standpoint
13
And that's
I think one thing that I learned yesterday that I
14
perhaps didn't appreciate previously is that this
15
equipment is wildly complicated, hearing from the OEMs
16
about how, you know, even just a single turbine is a
17
system of systems with auxiliary equipment.
18
of stuff that, again, everybody is going to be
19
requesting to upgrade and have updated at the same time
20
on a short timeline.
21
MR. GUGEL:
22
It's a lot
I could add just one thing because it
just came to mind, too.
I'm going to take an
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opportunity here to put in a little bit of a plug.
2
think if you're not already a member of some sort of a
3
trade organization, it would really be helpful in that
4
-- in that aspect.
5
so it would be good to join up with some other trade
6
organization, get some of the collective thoughts that
7
are there, and work together towards some of those
8
solutions because sometimes working by yourself, you
9
might come up with something, but as a community, if
I
So there's power in community, and
10
you come up with a solution, there's kind of the power
11
that could occur there.
12
you know, we've also got the Generator Forum that would
13
be an excellent source for you also there.
14
know, between the forums and the trade organizations, I
15
think there's a wealth of information that can be
16
tapped there as you get involved in those things.
17
just -- it was kind of my opportunity to kind of say
18
look for those also.
19
MS. CALDERON:
And yeah, Mark's reminded me,
But, you
So
So we've talked a bit about
20
installation of equipment, supply chain issues,
21
testing, and all of that.
22
about root cause analysis and being able to diagnose
PRC-030 also has that piece
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the fault recorder data to be able to diagnose root
2
cause.
3
analysis that needs to be proactively addressed as
4
well.
5
either onsite engineer or contractors, like, set up or
6
consultants set up to be able to do that type of
7
analysis because there will be a time limit once it's
8
being triggered and that request for the analysis is
9
being triggered, and it's a very specialized skillset.
10
11
And that's an entirely different form of
I would suggest making sure that you've got
So that's something else to keep in mind.
MS. JONES:
And that's a good point that you bring
12
up, Jamie, because part of our -- in our planning
13
efforts is kind of being able to design and how do we
14
maximize the filtering of that data to help us quickly
15
support a root cause analysis.
16
transparent, you know, we've kind of recommended we
17
need to build a program just around root cause
18
evaluation.
19
It's not just this casual task of someone just flips
20
through the paper and says what's happened, but you
21
actually have to tell the story and substantiate it,
22
and then talk through remediation and mitigation if
And to be just
It's its own program in and of itself.
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that's the case.
And so in our shop, we've talked about the need to
3
maybe carve out, for PRC-030, its own program.
4
a lot with our data analytics team, we work a lot with
5
our engineering team and our compliance professionals
6
to kind of bring that together, but we look at the
7
volume and the number of faults that's happened.
8
too, you have to think about your workforce and the
9
FTEs that are going to be needed to kind of support
10
11
We work
Also,
that, also.
MR. HAKE:
Yeah, that's a really good point there,
12
and I would like to add, also, that the way that we're
13
currently interpreting PRC-029, in some of the
14
measures, it talks about retention of actual
15
performance data to demonstrate compliance with these
16
performance requirements.
17
to have to do a similar type of effort every single
18
time an inverter trips offline.
19
discussion earlier about the Ride-through definition,
20
and we're optimistic that that can be clarified to try
21
and mitigate some of those concerns.
22
similar to your point on PRC-030, there's also going to
So, in effect, we are going
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But I think
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be a substantial amount of expertise and resources and
2
effort involved with that, right?
3
trips, we have to evaluate it versus the Ride-through
4
requirements.
5
MR. GUGEL:
Yeah.
Every time something
The only thing I would add is I
6
think if you've already got a team looking at PRC-024
7
and any mis-operations, they're already kind of
8
involved in that RCA thought.
9
them to maybe provide some information or some help to
And if you can draw on
10
look into your inverter trips, that would be really
11
good, too.
12
MR. HAKE:
13
point, Howard.
14
currently, we're looking at a significantly larger
15
volume than we would for PRC-024, so PRC-024 mis-
16
operations.
17
personally, they don't happen very often, so it's much
18
easier to deal with.
19
MR. GUGEL:
20
Yeah, I think that's a really good
The one distinction I would draw is,
Again, not speaking just for AES, just
Yeah.
You just need to clone them,
right?
21
(Laughter.)
22
MR. HAKE:
Exactly.
Problem solved.
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We have one more question for this
2
panel.
3
some of the things we've mentioned earlier about
4
testing and verification to whether or not you meet
5
these requirements, particularly 029 requirements.
6
what are some of the most challenging aspects of
7
testing and verification in the context of these new
8
standards -- 028, 029, or 030 -- probably you're going
9
to be talking about 029 -- and especially in the case
I'm just going to dig a little bit deeper into
So
10
that you're going to have this mix, right, of existing,
11
new retrofitted, it's going to be a changing landscape
12
in your fleet.
13
challenges to testing and verification, and how do you
14
ensure that testing protocols are robust now to meet
15
these requirements and avoid, as little as possible,
16
delays?
17
MR. HAKE:
So what's going to be some of those
So I'm not sure I have the answer for
18
that one.
19
are the -- some of the challenges we've talked about in
20
modeling, right?
21
verifying performance on the design side, the model has
22
to come first.
The first thing that comes to mind, though,
So when we -- when we talk about
And, you know, as discussed at length
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here the last couple of days, getting all of that
2
information is a major challenge, particularly for
3
legacy products.
4
back to the design cycle comment, in the short to
5
medium, even long term, we're going to have a similar
6
challenge.
7
run the tests, we can't demonstrate performance
8
requirements or compliance with them.
9
But even moving forward, again, going
And if we don't have the model in order to
MS. JONES:
Just add to that, you know, definitely
10
trying to nail down the modeling is going to be a --
11
you know, a work in process.
12
that came up in our shop was, is there just like this
13
consensus testing standard that exists on how testing
14
should be performed?
15
was to be developed, who is best to develop it that we
16
can have a shared approach at how we do testing, if not
17
just defining testing.
18
But one of the things
And if that kind of a standard
If I was a regulator and everybody had to define
19
their own testing, it could really get kind of
20
squirrely there.
21
but that's one of the questions that we're -- that
22
we've been talking about internally, what is that
But we don't have the answer to it,
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consistent standard of testing that we can adopt and
2
apply across the board and across equipment type?
3
that's something that we are still looking to kind of
4
learn more of, and we think that would help to simplify
5
things versus developing our own, this other entity
6
develops their own, and it's just everybody has their
7
own way of testing it, and do we -- are we achieving
8
the same objectives?
9
recommendations is to get that kind of consistent
10
standard of testing.
11
MR. GUGEL:
And
But that's one of our
Yeah, I would agree.
I think that's a
12
-- that's an area to concentrate on.
13
machines all struggled through that when we first went
14
through the MOD standards to try to figure out how to
15
do their real and reactive power output verifications
16
and their model verifications.
17
-- that the inverter-based resources have such an
18
additional complexity to their operation, that it is
19
going to take some specialized folks to set up those
20
testing procedures.
21
22
MR. PATEL:
The synchronous
And I think that these
I agree.
So this is also kind of only a
question for really PRC-029 disturbance monitoring
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equipment.
2
We know how to commission tests.
3
unique, very specific criteria in R1.
4
come up with process, you know, to honor that.
We have been installing for a long time.
PRC-030 is kind of
I think we can
5
So then PRC-029, we are not going to apply a 230
6
kV fault for 160 millisecond to test plant is able to
7
Ride-through or not, right?
8
testing, solar inverter, or container testing wind
9
turbine generator.
So this begins from lab
I don't even know what to think
10
about HVDC terminals.
11
capacity.
12
out there that says these are some of the tests that
13
you need to run on your IBR units, right -- the solar
14
inverters, the wind turbine generators, the HVDC
15
converters.
16
and then use the models at the plant level, and then a
17
simulation engineer like me can apply 230 kV fault all
18
day every day of whatever time duration, right?
19
They're a thousand megawatt in
But there has to be some sort of guidance
Somehow convert those tests into models
But this is what I meant earlier that -- we wrote
20
the standard.
21
here in next couple of months, and then how to show
22
compliance with the standard, it's a big task.
It will get done in one form or another
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begins with lab testing of equipment and then, you
2
know, some sort of model-based verifications.
3
there is a -- there is a need to develop framework for
4
all this work.
5
listening "IEEE," but some of that work is being
6
carried out in IEEE 2800.2 Working Group.
7
time to develop some of those things.
8
9
And
Some of that, I know we're all tired of
It takes
We have been talking with some OEMs, you know.
Testing for MVA battery energy storage inverter is very
10
different than testing a 12-megawatt wind turbine
11
generator in a container which is actually connected to
12
the system, right?
13
testing.
14
understand well, but, you know, a lot of things go on
15
what can be tested, what cannot be tested, and then
16
somehow bring it all into a simulation world and show
17
that the plant was designed.
18
have a confidence before we go commercial operation
19
that the plant will Ride-through, right?
20
disturbances, right?
21
remains in putting together a framework for test and
22
verification of Ride-through standard.
There are many different ways of
Now, I'm talking about things that I don't
If I was a GO, I want to
All system
So I think there is a lot of work
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MR. YEUNG:
Okay.
2
MR. GUGEL:
If only there was a research institute
Well, thank you.
Go ahead.
3
for the electric power area, there might be a way for
4
this to happen.
5
(Laughter.)
6
MR. GUGEL:
That was my attempt at humor, by the
MR. YEUNG:
-- some questions.
7
8
9
10
11
way.
start in the room for this panel.
We're going to
Any questions?
Scott?
MR. KARPIEL:
Scott Karpiel of SMA America.
Just
12
curious to understand, considering some of the hurdles
13
and issues, concerns with supply chain costs, transfer
14
of ownership -- let's see -- the costing of upgrades,
15
testing, modeling, you know, it all kind of stacks up.
16
At some point, there's diminishing returns on that
17
investment.
18
possibility that a plant or an asset would be
19
decommissioned, and, if so, how would that affect
20
transmission in planning?
21
22
Curious to understand if there's a
MR. GUGEL:
question.
I'm not sure I understand the
Can you elaborate just a little bit more on
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that?
MR. KARPIEL:
Sure.
So if I'm an owner, which I'm
3
not, right, there's a financial commitment.
4
return on the investment that I'm going to have to make
5
to bring this asset up to current code and standard.
6
If I were to deem that it wasn't worth my investment to
7
do that and I decided to shut the plant down,
8
decommission the plant, curious to understand how that
9
would affect the network from a planning standpoint,
There's a
10
from an operational standpoint.
11
there's a real possibility, especially for some of the
12
smaller asset owners, that they may decide to just
13
throw their hands up and close down the plant or
14
decommission the plant.
15
MR. GUGEL:
You know, I think
Yeah, that goes back to something we
16
had mentioned earlier that definitely do not want that
17
perverse incentive there.
18
need is a retirement of additional capacity that's out
19
there, but we do need the capacity that's there to act
20
reliably.
21
will be the ones that will be looking at this, in my
22
opinion, and if there's a decision made to retire, they
You know, the last thing we
So, you know, the reliability coordinators
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would be able to look at that and see what the overall
2
reaction to the system would be on that.
3
you know, that's going to be a decision that's based on
4
the owner of that asset and then, you know, the
5
reliability coordinator, looking at all the reliability
6
for the area.
7
But again,
Just my thoughts on that.
MS. CALDERON:
I would -- I would add that there's
8
substantial precedent for this type of business
9
decision just when retrofitting units, like carbon
10
capture, that was putting baghouses on coal units.
11
There's a whole lot of history with having to do some
12
form of retrofitting or upgrades.
13
the business of having generation.
14
MR. HAKE:
Yeah.
That's just part of
So I guess what I would add here
15
is, putting my personal opinion hat on, I don't know
16
that AES Clean Energy, we have not gone through a
17
detailed analysis to say X number of our plants will be
18
decommissioned.
19
it's a very valid and real concern, especially for
20
plants that are older, right?
21
potentially the less ROI we're getting, the more we
22
have to spend on, it begins to not make sense very
What I would say, though, is I think
The older the plant,
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quickly.
2
think it's a -- it's a really good point to make.
3
So I -- so I appreciate the question.
MS. JONES:
I
This is Rhonda's, not Invenergy's.
I
4
feel that the -- there's still a very strong argument
5
that the IBRs, even the ones that are, you know, quite
6
seasoned, still have an effective role in grid
7
stability, even not being upgraded to the latest and
8
greatest, that they still play a role.
9
an interesting argument to hear that them being
And it would be
10
prematurely decommissioned is better for the grid than
11
them staying on and still helping grid reliability, and
12
I just -- I don't really -- I don't -- I don't really
13
see that case.
14
Definitely the goal is to optimize performance.
15
Definitely that's an ever-changing responsibility based
16
on grid conditions and dynamics, and you should be in a
17
position to optimize performance and how we're kind of
18
defining that now.
19
stronger case, personally, for proving with data that
20
the role that they serve now on the grid is still very
21
helpful overall to reliability versus not being on it.
22
And with some of the queue positions getting backed up
But I do still feel there is a
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and things taking longer to come online, you can't even
2
say, oh yeah, you're out of here, we have somebody
3
ready to replace you right away.
4
happen exactly like that.
5
question.
6
MR. HAKE:
The timing doesn't
So I appreciate the
And I would agree with, I think, your
7
premise at a high level.
8
back onto a comment that I made earlier is, if the grid
9
operators don't understand how that unit is going to
The one thing that I'd leaned
10
react and actually, you know, how during disturbances
11
or during extreme situations on the system what they
12
can expect to be on or off, there may be negative
13
reliability impacts in those areas as opposed to the
14
steady state issue.
So that -- all of that needs to be
15
taken into account.
And if an entity chooses to not
16
want to look into that issue, I'm not sure that that's
17
a benefit to reliability for them to hang on just for
18
the sake of hanging on, but I do think that somebody
19
does need to analyze that information.
20
MR. HAKE:
Yeah, I agree, and if I could just
21
offer one mitigating factor.
22
for existing BES units, they would already comply with
I think that, at least
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PRC-020.
2
totally off the wall doing crazy things, right?
So we're not talking about units that are
3
MS. JONES:
4
MR. MAJUMDER:
Right.
Rajat from GE Vernova.
So, Howard,
5
question to you.
6
saying that it's not being done, that somebody's not
7
looking into it, when you say the grid operator needs
8
to know what the unit are going to be doing?
9
isn't it something we are doing already?
What's the basis of that you were
I mean,
So why is it
10
being raised as a matter of concern?
11
going to be outlier where the models did not keep up to
12
the actual equipment behavior.
13
statement when we were working in Appendix G of 2800,
14
so I'm bringing it up again.
15
statement made that, oh, well, the models are not good.
16
It's not true.
17
rest of the thing, we are all going through Mod 26 and
18
27, not every other 26 and 27 shows models are matched.
There are always
And I did not made the
And there has been some
Yes, there has been some exception, but
19
MR. GUGEL:
20
MR. MAJUMDER:
Yeah.
So I'm just trying to sense your
21
concern that when you say that it's a reliability risk,
22
flagging that grid operator does not know how these
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equipments are going to behave.
MR. GUGEL:
So I would point to all of the reports
3
that we have on our system.
4
events that we've analyzed, we pointed back to grid
5
components that reacted in ways that both the
6
reliability coordinator, the transmission operator,
7
and, in many instances, the generator owner/operator
8
did not expect that to happen.
9
analysis was done into that, it was found out that
If you look at each of the
After a root cause
10
there were maybe some additional controls that were
11
installed on the plant that nobody was aware of, or
12
that the generator owner might've been aware of it, but
13
that information had not been translated to the
14
transmission operator or to the reliability
15
coordinator.
16
So if you -- if you look through all of -- that's
17
why I'm saying that our experience has been, over the
18
last seven to eight years, that disturbances that are
19
occurring on the grid are happening, and the
20
reliability coordinator and the transmission operator
21
is seeing things happen that they're not expecting.
22
And it's because these units, each time they come up,
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they're behaving in a little bit of a different way
2
than they have in the past.
3
happening is we'll fix one problem, you know, let's,
4
let's take Blue Cut Fire.
5
phase fault, bunch of units tripped out, found out that
6
that was an issue with sampling on frequency, got that
7
fixed.
8
out on a single line-to-ground fault for a different
9
control system that was in the same plant.
10
So we'll fix -- what's
We had an issue with three
A year later, had a bunch of other units trip
Until we do a deep dive and try to figure out what
11
those scenarios are, we're going to continue to see
12
grid perturbations that occur that are reliability
13
concerns that are small at this point, but when we get
14
to a 50-percent penetration, they're not going to be
15
small anymore, is my concern.
16
MR. MAJUMDER:
17
MR. GUGEL:
18
MR. MAJUMDER:
Yeah.
So that's why I'm raising -I fully agree with that, and that's
19
what I'm saying, that things has happened and even
20
there were repeat offender.
21
Odessa even not specifying anything when ERCOT went
22
ahead, and, you know, published the report, there were
I know that.
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plans/manufacturer who made a commitment to fix it, and
2
the second one came up and it was saying that it's
3
there.
4
So I fully understand.
But at the same time, let's not -- I'm just trying
5
to say that let's not think -- that thing has also
6
happened with synchronous machine.
7
synchronous machine out in the -- in the field, but the
8
excitation system model, if you look at it, there's
9
still rotation, you know, the slow rotary excitation
There are so many
10
system.
11
the issue is not only in IBR, so let's not think that
12
how it's going to be -- I'm not at all undermining the
13
necessity that you are establishing.
14
with that, but I'm just trying to say that please let
15
us not flag IBR fleets specifically for this issue.
16
This issue exists.
17
In real field, it's completely different.
MR. GUGEL:
So
I fully agree
So my qualification was just the
18
specific question that you asked me:
19
you calling out and saying that grid operators don't
20
know what's going on, and so that's why I was pointing
21
to the reports there.
22
synchronous generators?
Why, Howard, are
Do we see issues happening with
Yes.
Have we modified
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generation standards over the years to basically react
2
to that?
3
standpoint, a lot of the technology that's behind that
4
and the basis behind it is something that's been around
5
for 50, 60 years.
6
through that, understand the issues, and basically know
7
how that reacts on the grid.
8
9
Yes.
But from a synchronous generator
We've had the ability to kind of go
We're now introducing some new components at a
fascinating, incredibly fast rate of equipment that has
10
some great reliability benefits.
11
for that, but also has a potential to give us some
12
unknowns and put us in unknown operating states.
It has a potential
13
MR. YEUNG:
So, Howard --
14
MR. GUGEL:
We need to be in front of that as
15
16
opposed to -MR. YEUNG:
Howard, I'm going to interrupt a
17
little bit.
18
order, you know, so we need to move forward, and, you
19
know, implement the order, so absolutely important
20
arguments, but any more questions about implementation?
21
22
I think those are probably basis of the
MS. CASUSCELLI:
We have one online.
Is there an
effort underway for the design compliance and further
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performance compliance for PRC-029?
2
MS. CALDERON:
3
MS. CASUSCELLI:
Could you say that again?
I can repeat it.
Mentioned in
4
the panel was a technical document.
5
is there any effort underway for the design compliance
6
and for the performance compliance for PRC-029?
7
MR. PATEL:
Yeah.
Is there a way --
So I think -- I think that's
8
where I mentioned IEEE 2800.2, where we are trying to
9
put the framework where, you know, the equipment
10
actually gets tested, right?
11
inverters, the wind turbine generators, we understand
12
their capability.
13
we run the simulations on plant model to verify that
14
the plan will be able to Ride-through what the standard
15
requires.
16
IBR units, individual
We build the plant model, and then
There is no effort at the NERC level.
I think that was my point when I gave all the
17
examples of different PRC standards, right?
18
companion NERC document that shows how to do
19
calculations for 023, 025, 026, et cetera, standards,
20
and I think there is equal need.
21
here for a companion NERC document to PRC-029, but
22
maybe IEEE 2800.2 can serve that role where, you know,
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you pick up the framework, put together in that
2
document in compliance with, I'm going to start calling
3
2900.
Maybe it will become true.
4
(Laughter.)
5
MS. CALDERON:
Well, and to add in on that as
6
well, there's ongoing work within the IRPS and within
7
the RSTC work tackling those types of engineering
8
questions.
9
guidelines put out.
They've had power plant model validation
There's ongoing discussions within
10
those groups, and it seems like an opportune place to
11
bring those up.
12
really just did it or did it not meet the criteria
13
based off of the measured data.
14
pretty big distinction between those two and how you
15
approach compliance with those.
16
MR. YEUNG:
When it comes to performance, it's
So there'll be a
Any more questions?
17
questions on the internet or Slido?
18
a question or do you have a comment?
Any more
Todd, do you have
19
MR. BENNETT:
20
necessarily a comment.
21
the room, and, Amy, are we wrapped up online?
22
I don't think I have a question or
I wasn't seeing it either in
(Nonaudible response.)
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MR. BENNETT:
Okay.
So with that, thank you to
2
our panel.
3
to you.
4
That's our last panel of this Technical Committee.
Very in-depth discussion here.
Many thanks
So anyway, how about a round of applause?
5
(Applause.)
6
MR. BENNETT:
And why don't we get back together
7
here in 15 minutes, and we will review some Slido polls
8
and have some additional polls on PRC-2900.
9
(Break.)
10
MR. BENNETT:
Okay.
So it looks like we're
11
getting ready to start back up here for our last
12
session of the Technical Conference today.
13
this should go fairly quickly, but we have three
14
questions to poll to all the participants through
15
Slido, so if you need to, go ahead and join back in on
16
there.
17
here real quick just in case anybody needs to join.
18
I'm not sure, but I believe -- yes, Amy's going to have
19
three questions here, and here's the results of our --
20
of our previous one.
21
okay.
22
I think
I don't know if we can put the QR code back up
Oh, this is actually new, so,
So yeah.
MS. CASUSCELLI:
Yeah, Todd, that's the new one.
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Sorry.
MR. BENNETT:
So there's three questions here, and
3
I'm going to hand it over to Amy to kind of lead us
4
through this for the next few minutes.
5
MS. CASUSCELLI:
All right.
Yeah, thanks Todd.
6
So as Todd mentioned earlier, you know, we have a
7
series of questions.
8
and, you know, this is not a formal voting mechanism.
9
This is just meant to inform the Standards Committee
I believe there's three of them,
10
members' decisions in the next couple of days here on
11
the path forward for all of the things that we've been
12
talking about for the last day and a half.
13
So for this initial question here, based on the
14
conversation you heard today, and I want to make sure
15
that we differentiate here.
16
to legacy assets.
17
and frequency criteria follow that assures reliability
18
assets?
19
So I'm going to not narrate the entire -- the entire
20
moment here and just let us sit in silence as you all
21
consider and cast your votes.
22
This question is related
So what should the PRC-029 voltage
So just note that that is for legacy assets.
(Slido voting.)
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MS. CASUSCELLI:
All right.
So I think that we've
2
pretty well slowed down with our votes cast, so looks
3
like we've got an overwhelming response for that
4
question.
5
think we can move on to the next question.
6
Thanks for -- everybody, for your input.
All right.
I
So this question is the -- identical,
7
with the exception of this is for assets being brought
8
online in the future.
9
one, and this is future assets.
10
(Slido voting.)
11
MS. CASUSCELLI:
So only two options for this
Oh, okay.
So I think the -- for
12
those of you who are looking on the screen here in the
13
room, the bottom option is cut off, but it says, "adopt
14
voltage and frequency bands proposed in IEEE 2800."
15
(Continued Slido voting.)
16
MS. CASUSCELLI:
All right.
So it looks like we
17
have a -- an overwhelming opinion on that one as well.
18
So with that, I think we can -- we're ready to move on
19
to our next question, and this one is related to the
20
implementation plans.
21
22
UNIDENTIFIED SPEAKER:
a presentation for this.
Amy, I don't think we have
Are we putting the question
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in front of it?
2
MS. CASUSCELLI:
3
(Brief pause.)
4
MS. CASUSCELLI:
Okay.
Hold on.
All right.
It's coming.
I see
5
it in Slido.
6
the implementation for these new standards, in 25 words
7
or less, what should NERC provide more information on
8
to assist industry in preparation?
9
there's any penalty for going over 25 words, but --
There we go.
10
(Off mic comment.)
11
MS. CASUSCELLI:
12
Okay.
All right.
Oh, really?
So regarding
I don't think
Oh, it does cap.
Okay.
13
(Slido voting.)
14
MS. CALDERON:
All right.
Just a quick point of
15
clarity that, of course, that is 25 characters or less.
16
What we're going to do here is when this closes, we're
17
going to close it and reopen it with that image
18
removed, just so it's easier to see for -- at least for
19
the folks in the room.
20
(Continued Slido voting.)
21
MS. CASUSCELLI:
22
All right.
I think we've seen a
slowdown in responses, so I think we're ready to close
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it.
2
display the image, I think that would be helpful for
3
folks.
And if you could, yeah, Jamie, like you said,
4
(Brief pause.)
5
MR. BENNETT:
Okay.
So while we wait on the
6
results to be posted up here on the screen for everyone
7
to see, at least something that jumped out at me on
8
this was the term "compliance guidance."
9
larger in the middle.
So it was
That that means it got mentioned
10
a bit more than some of the other items.
11
one thing that I am glad about on compliance guidance
12
is there's not only one path.
13
organizations that have been approved to put documents
14
like that together and can be endorsed by NERC.
15
it's -- I don't think that's a deviation from the past,
16
so I think there's some real promise there.
17
word that I saw that wasn't quite as big as "compliance
18
guidance," but it makes me think of certainty, but it
19
was "implementation timing," you know, what to expect.
20
So, you know,
So there's multiple
So o
Another
So with that, maybe I can kind of segue into the
21
next part of what to expect after this technical
22
conference concludes.
So after we wrap up today, we'll
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take the feedback from these polls from the -- from the
2
conversations over the last couple days, and the NERC
3
Standards Committee, in conjunction with members from
4
NERC as well as some of the Drafting Team members that
5
are available, we'll get together and start redlining
6
the standard based on what we've learned.
7
not an infinite time to do that.
8
compressed.
9
probably conclude by the end of next week, you know.
So there's
It's pretty
So I would expect, you know, that to
10
So it's going to be a busy next six or seven days for a
11
group of people, but at that time, I believe that we'll
12
be able to have a revised standard that captures maybe
13
a slightly different path forward.
14
of that is an implementation plan that is with that,
15
and I believe that will help with the certainty.
16
But then also part
You know, both of these documents, I can't for
17
foretell what will be on them at this current point in
18
time.
19
the implementation plan will help with that, what to
20
expect, and, based on certain scenarios, what companies
21
should try to plan on, given that the standard's
22
approved.
But they will be out there and I believe that
If it's not approved, that's a whole
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different -- that's a different story.
2
conversation for today.
3
might help with what to approve and implementation
4
guidance.
5
today, and some of the -- you know, the history with
6
the multiple ballots going out to industry and
7
struggling to find consensus, this does seem like an
8
ideal candidate for some type of implementation
9
guidance.
10
That's not our
So anyway, I think that that
Based on the conversations that I've heard
So with this in front of us here, these are the
11
most popular feedback words from today.
12
"compliance guidance" in this poll, "timelines," "we've
13
anticipated timeline," "priorities."
14
of things that we've already touched on, but then I see
15
several words up there that we need to consider over
16
the next week.
17
else to add, but are there any other questions in here
18
about the path forward and what to expect over the next
19
few weeks?
20
So there's
So there's a lot
So with that, I don't have anything
Maybe something I can -- that I didn't touch on
21
is, I believe the draft standard as well as the
22
implementation plan posting to industry, we don't have
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a specific date yet, but be on the lookout for mid-
2
September, so somewhere in there.
3
processes to make it through for quality review and
4
drafting.
5
the amount of time for comment and ballot.
6
do have to have it concluded by the 30th, so the end of
7
the month.
8
is to give industry as much time as we possibly can but
9
still get the best product that we can with the limited
We still have some
After that, it also has not been agreed upon
However, we
So one thing that I'm trying to commit to
10
time that we have.
11
on this?
12
MS. JONES:
13
MR. BENNETT:
So with that, any parting questions
(Off mic question.)
So the question is balloting will
14
happen this month.
15
I'm hearing.
16
September, and then the timeline has not been released,
17
whether that will be five days, seven days, 10 days,
18
but, you know, somewhere kind of in there, but we have
19
to have it concluded by the 30th.
This will be posted for ballot in mid-
20
MS. JONES:
21
MR. BENNETT:
22
So that's what I'm -- that's what
(Off mic question.)
So the question is about comments
previously provided.
So the previous ballot is what
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you're referring?
2
MS. JONES:
3
MR. BENNETT:
4
(Off mic comments.)
5
MS. JONES:
(Off mic comment.)
Oh, for this conference.
So for the comments that were provided
6
or testimonies to support this Technical Conference, if
7
the team that's working on drafting the new ballot
8
decide to use some of that or borrow from it, if they
9
borrow it, will there be citations related to who they
10
borrowed it from?
11
MR. BENNETT:
So on that, and my NERC friends
12
here, correct me if I'm wrong, I have not heard any
13
response to responding to the comments that were
14
provided to support this Technical Conference.
15
comments and testimony that was provided to help with
16
this Technical Conference was for learning, for the
17
building of a -- an official record of what happened
18
with this for, you know, a potential future filing with
19
FERC, but then also to provide some metrics and inform
20
and to help us develop the agenda for today as well as
21
some of the follow-up questions for the agenda today.
22
So that's what that comment -- that's what those formal
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comments were used for at this point.
2
MS. JONES:
Okay.
3
with the Drafting Team.
4
be.
5
MS. CALDERON:
So they won't be probably used
I thought they would possibly
Yeah.
So the next steps is with
6
the Standards Committee.
7
Drafting Team and NERC staff to make revisions to the
8
standard, working together, putting together the
9
official memo.
We actually do have the
All of it's going to be used for the
10
record of development as well for the filings, so
11
decisions made that were based off of information that
12
was provided.
13
from the OEM, will be used to substantiate decisions
14
made in the filing with FERC.
We got a lot of substantial information
15
MS. JONES:
16
MR. BENNETT:
Thank you.
Okay.
17
looking around the room.
18
questions here.
19
have one more.
Thank you, Jamie.
20
MR. CONWAY:
Okay.
I'm
I don't see any final
With that -- oops, sorry.
We
Yeah, Kevin Conway, Western Power
21
Pool.
22
talked, I think, in the hallway quite a bit about it.
More of a comment about this forum.
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1
It would be nice if through our standards process we
2
engage in this type of process earlier, right?
3
many times, just like in this case here, we're already
4
down the road so far.
5
any major impact that we can make, but our -- with the
6
intent of trying to accelerate the development of these
7
standards based on Board direction or FERC direction,
8
these are helpful and these move the Drafting Team
9
faster, farther, and more effectively down the road.
10
MS. CALDERON:
Too
There's no course corrections of
-- going to speak on your behalf,
11
Soo Jin, on just everything you've been doing for
12
getting more of these, so I'll let you go ahead.
13
MS. KIM:
Probably to Levetra and Tiffany and
14
Kelsey's chagrin, I do think we're going to have a lot
15
more technical conferences, not just for the next
16
couple of milestones, but as you all know, there are
17
several other projects on the horizon.
18
extreme hot and cold weather temperature project that
19
is another directive that is due in December.
20
a webinar next Tuesday, so I'm going to put a little
21
plug in for that for all of the utility stakeholders
22
who are participating in that.
We have an
There's
I think the team has
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made some tremendous progress.
2
to present that.
3
tools from today that was very effective, and so
4
they're going to try to solicit a lot of technical
5
input next Tuesday for extreme hot, cold -- hot and
6
cold temperatures.
7
directives after that, as many of you know, we have
8
some directives with regards to extreme cold weather.
9
That one is also probably going to require some type of
10
11
I think they would like
They're going to borrow some of the
I do believe for the next
technical input.
We will have more of these events.
We did commit
12
to doing that.
13
will have that.
14
that we see on the horizon, high-priority projects,
15
things that require a lot of coordination where there's
16
major gaps in information that the team just did not
17
have at its fingertips, I do think that these events
18
are much more fruitful than I think many people imagine
19
when we first started down this path.
20
I cannot promise that every project
But for some of the major projects
So thank you again for your participation.
I will
21
commit that the Department is going to not just look at
22
this just from the standards perspective, but also on
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the engineering side.
2
technical conferences generally, even before we get to
3
some of the standards development steps.
4
MR. BENNETT:
We have talked about doing more
Okay.
Thank you Soo Jin.
And I
5
just wanted to say, I'm going to have -- I'm going to
6
ask Sue to say a few words here at the end, but I just
7
wanted to mention to everybody that, you know, this was
8
kind of a first of its kind, so thanks for bearing with
9
this as we made it through this.
We did learn that
10
some things worked really well, some probably could've
11
worked a little better, but it sounds like there'll be
12
more of this, and this was a learning event for
13
everybody, so thank you.
14
parting words?
15
MS. KELLY:
16
the benediction.
17
(Laughter.)
18
MS. KELLY:
I do.
And Sue, do you have any
I have been designated to give
So on behalf of the Board, I want to
19
thank everyone who participated in this technical
20
conference, both in person and online.
21
content rich experience, especially for, you know, a
22
laywoman like me, and I think I've learned a lot.
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It has been a
I
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also know a lot more about what I don't know which is,
2
I guess, also good.
3
of some of the pressure points and the fault lines
4
regarding the current draft of this standard, and I
5
think we have some ideas about how we might be able to
6
address those, which is great.
7
I think we all have a better idea
I want to thank NERC staff and the Standards
8
Committee, not only for what you've already done, but
9
the mission which you are about to undertake, effort
10
you're going to have to undertake to prepare the next
11
draft of this standard for ballot in an extremely
12
accelerated time frame as Todd just reviewed with you.
13
As Soo Jin noted this morning, we're operating under
14
tight time frames that were set both by FERC and by
15
Rule 321 if you care to go review that.
16
finish the balloting by September 30th, so everyone
17
involved is going to need to put their shoulder to the
18
wheel to make sure this happens.
19
And we do need to get it done.
We have to
I would note that
20
FERC has instructed us to get it done by a date
21
certain, and the Board intends -- we're going to do
22
that, but the need to finish this effort goes well
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beyond the administrative imperatives that we face.
2
NERC produced its first reliability guideline on these
3
issues back in 2018.
4
morning.
5
Howard pointed out this morning, we already have hours
6
in some regions where energy from embroider-based
7
resources are producing virtually all the energy on the
8
grid.
9
decade, it could be 50 percent of our capacity might be
I was reviewing that this
This drafting project commenced in 2020.
As
And the projections are that by the end of the
10
IBR based.
11
software and hardware changes that we heard about from
12
the OEMs yesterday are indeed accurate, then we need to
13
move swiftly now to establish new standards that will
14
ensure reliability going forward as we have many more
15
of these devices on our grid.
If the lead time estimates for the needed
16
So again, thank you for your time and attention so
17
far, and thank you for the additional work that you are
18
going to undertake to bring us to the finish line by
19
September 30th, and may you all have safe travel home.
20
Thank you.
21
(Applause.)
22
MR. BENNETT:
Okay.
So with that, I believe that
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we are adjourned for the day, so thanks again for
2
everyone's participation.
3
come.
4
5
Safe travels, and more to
(Whereupon, at 3:23 p.m., the Technical Conference
was concluded.)
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
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CERTIFICATE OF TRANSCRIBER
I, Charlene Williamson, do hereby certify that, to the best of my knowledge and belief, the
attached transcript is a true and accurate transcription of the indicated audio recording.
I further certify that I am neither attorney nor counsel for nor related nor employed by any
of the parties to the action; further, that I am not a relative or employee of any attorney or
counsel employed by the parties hereto or financially interested in this action.
9/9/2024
____________________
DATE
_____________________________________
Charlene Williamson
TRANSCRIBER
Technical Conference Day 2
WORD INDEX
<0>
0 153:15
01:31:07 86:21
02 21:15
023 208:19
024 91:3 93:6
025 208:19
026 208:19
028 38:21
165:6 172:7
184:20 193:8
028's 153:16
029 31:16 36:9,
14 37:3 38:21
46:4 88:17
89:17 100:17
102:14 103:10
116:21 135:10
137:17 147:7
154:4 172:7
174:8 178:18
193:5, 8, 9
030 38:21
66:21 116:2
137:13 147:7
154:7 156:3
172:7 174:8
184:20 193:8
<1>
1 7:5 146:21
180:21
1:00 140:21
141:8
10 36:22
113:12 130:4
136:2, 14 138:4
139:4 181:17
217:17
9/5/2024
Page 1
10-percent
128:13, 15
10-plus 16:10
42:15
11 121:17 125:9
11:05 114:17
11:15 114:18
116 7:19
12 151:21
154:21 155:1
181:17
120 125:17
125 7:20
12-megawatt
197:10
13,700 36:20
14 7:9 36:20
142 8:9
15 7:14 59:7
68:6 130:4
142:7 150:15
175:10 210:7
150 36:20
152 8:13
1547 88:3, 9, 13
89:10
157 8:16
160 196:6
1920 41:10
198 8:17
1st 143:11
144:7 148:11
149:14 150:2, 9
152:18
<2>
2 7:5 8:7 9:7
41:19 47:12
61:6 68:21
136:12, 13
142:3 146:15,
22 147:4 149:3
150:19 151:2
152:12, 14
179:1 180:5, 12,
18 181:18
184:22
20 68:6 96:18
128:14, 16
131:21 136:2,
13 138:4 145:8
175:10
200 42:22 43:1
105:11 131:7
2000 96:7
2000s 37:1 49:7
2005 50:22 96:7
2007 21:14
2018 224:3
2020 224:4
2020-02 7:19
115:15 151:16
2023 41:9
2023-02 154:2
2024 1:13
2025 150:2
2026 150:8, 9,
22 151:8 177:16
2027 143:11
152:13, 18
2030 40:11
149:14, 20
150:13, 14 161:6
2040 40:11
2050 44:6
66:22 76:17
78:4 79:13
21 88:4
211 8:18
212 8:20
213 8:21
Scheduling@TP.One
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214 9:1
22 37:7
222 9:2
225 9:3
230 196:5, 17
25 17:13 76:21
213:6, 9, 15
26 176:6
203:17, 18
27 36:19 42:12,
18 203:18
2800 17:1
31:17 36:9, 15
37:12 42:1, 17
43:9, 19, 20
44:14, 22 45:16,
22 47:15 51:2
56:17 60:14
61:13, 19 75:12,
17 77:18 79:18
87:21 88:1, 20
89:9, 13, 16
90:9, 14, 22
101:17 102:14
105:9 111:22
112:4 120:17
127:15 138:17
203:13 212:14
2800.2 197:6
208:8, 22
2800-2022 14:19
27:18
2800's 122:15
2900 89:16
209:3
298 131:8
<3>
3 36:13, 19
41:17 49:16
3:23 225:4
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30th 13:15, 17
217:6, 19
223:16 224:19
31st 144:8
321 12:5, 16
13:13 223:15
<4>
4 36:19 49:15
52:13 136:2
138:4
4.5 42:18
<5>
5 1:13 123:15
136:13
50 26:10
145:22 146:2
149:7, 11 207:5
224:9
500 47:12, 13
50-percent
205:14
<6>
6 42:11 49:16
123:20
6,000 105:9
6,400 42:19
60 81:5 207:5
66 37:5, 8
<7>
7 123:20 147:1,
4
70 172:10
75 162:16
<8>
8 124:7, 8
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80 129:11
800 165:16
80-plus 172:11
85 7:15 162:19
<9>
9 7:6, 7 124:13
9,000 42:14
105:7
9:01 1:14
90 127:16
130:8 131:12
162:19
901 41:9 165:8,
20 185:22
90s 49:5
95 103:7 130:9
131:12
98 96:8
99 25:7 96:8
a.m 1:14
ABDOLLAHY
2:2
ability 68:8
72:21 120:19
121:1, 4 149:16,
18 152:4
171:18 175:20
187:17 207:5
able 20:7 23:11
24:15 38:15, 22
48:10, 22 50:7
61:20 63:15
64:5 67:3, 18
70:2 73:17
77:16 80:10
89:1 93:17
94:12 96:10, 15
107:1 109:2, 7
114:3 117:11
128:4 130:3, 22
142:10 144:21
147:11, 12, 13
148:1 149:20
151:14 152:9
169:7 182:1, 6,
7 186:18 187:5
189:22 190:1, 6,
13 196:6 200:1
208:14 215:12
223:5
abnormal
120:13
absence 182:9
absolute 53:12
Absolutely 24:5
40:5 102:12
128:10 129:1,
17 138:7 160:3
163:20 207:19
absorbed 25:8
accelerate 43:22
104:18 220:6
accelerated
223:12
access 147:18
accommodate
18:16
accomplish
144:1
accomplished
10:1
account 12:20
18:21 24:12
25:19 26:6
48:3 50:8
112:6, 13
132:11 133:13,
16 175:16
202:15
Scheduling@TP.One
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accountability
100:11
accountable
51:6 155:17
accounted 50:11
accounting
110:3
accurate 224:12
accurately 53:20
ACE 139:6
achievable 46:1
achieve 147:22
achieved 133:4
achieving 195:7
acknowledged
160:6
ACOSTA 3:2
ACP 5:5
acquiring
170:20
acquisition
135:3
act 199:19
action 171:12
active 115:21
129:7, 20 132:8,
9, 12
activities 85:14
actual 23:3
38:9 66:10
117:21 166:10
174:18 191:14
203:12
ADAM 2:16
adapt 134:7
add 9:13, 19
27:14, 17 73:2
80:1, 8 89:20
91:1 98:16
100:10 101:6
122:17 129:21
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Technical Conference Day 2
133:20 134:9
155:22 163:15
166:14 168:14
173:9 178:19
183:12, 22
186:9 187:9
188:1, 21
191:12 192:5
194:9 200:7, 14
209:5 216:17
added 76:10
124:17 125:6
130:7
adding 119:12
122:8, 9, 12
132:19 133:2
addition 26:8
36:11, 22 44:11
140:12
additional 67:22
77:11 78:7, 21
109:5 114:12
117:18 141:3, 6
179:19 181:10
187:3, 18
195:18 199:18
204:10 210:8
224:17
address 12:16
65:14 97:10
170:9, 14
180:16 223:6
addressed 13:10
26:3 62:5
170:7 190:3
addressing 12:7
adds 124:2
143:20
adequacy 83:11
adequate 95:2
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adhered 144:12
adjourned 225:1
Adjournment
9:3
administrative
184:1 224:1
admirable
120:17
adopt 195:1
212:13
adopting 101:17
adoption 13:19
advance 147:14
advantage 56:2
61:22 81:6
113:4 186:19
187:3
advantages 80:7,
12 81:12
advice 11:13
advisement
101:21
advocate 86:3
advocating
208:20
AEC 2:13 7:6
9:1
AES 3:16, 20
5:10, 19 8:14
102:15 158:3
180:1 181:8
192:16 200:16
affect 198:19
199:9
afternoon 140:9
141:10, 15 158:5
AGENDA 7:1, 2
8:3, 4 10:16
14:5 141:4
218:20, 21
aging 47:8
agnostic 21:20
43:15
ago 21:15 22:4
35:4 49:22
64:11 87:17, 21
89:7 95:12
176:18
agree 39:3
57:12 65:19
67:17 77:19, 21
89:22 90:5
92:10 105:19
137:11 173:10
195:11, 20
202:6, 20
205:18 206:13
Agreed 93:4
137:4 217:4
ahead 116:22
119:7 161:14
186:2 198:1
205:22 210:15
220:12
AHLSTROM
2:3 7:14 15:15
36:6 42:6 53:1
54:11 61:9
76:10 80:17, 20
85:9 89:22
91:7 93:4
103:14 105:4, 6
AHMAD 2:4
aimed 29:13
air 107:12
AL 4:16
alert 101:7
ALEX 5:11
7:10 11:10
14:9 15:6
26:18 32:4, 15
Scheduling@TP.One
www.TP.One
65:5 82:14
Alex's 87:8
ALFANO 2:5
AL-HADIDI
2:6 7:18
115:16 130:17
131:4, 18
132:22 133:17
136:11, 16
137:1, 11, 18, 20
138:7
align 132:20
133:1 153:8
155:4, 5
Alison 10:20
all-encompassing
118:2
Alliant 4:4
allocate 113:20
allow 17:1
23:11 65:1
127:9 132:13
allowed 52:15
86:3 87:18
164:3
allows 63:6, 20
64:16 65:7
86:14 94:1
166:6
alluded 18:8
19:2 20:15
29:6 52:13
61:7 80:20
alluding 145:7
alternate 85:22
America 35:19
36:1 45:1
198:11
AMERICAN
1:5 2:15 4:19
Americas 5:2
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Technical Conference Day 2
amount 11:4, 12
12:2 13:1, 4
19:9 20:21
30:1 46:1, 8
60:11 62:14
68:19 104:3
105:16 136:14
192:1 217:5
AMY 2:19
11:22 209:21
211:3 212:21
Amy's 210:18
analyses 34:9
54:3
analysis 15:20,
22 19:5, 6 30:2
32:11 36:17
42:10 45:6
46:18 53:16
60:4 75:22
98:3 155:8
162:3 170:12
187:16 189:22
190:3, 7, 8, 15
200:17 204:9
analytics 154:4
191:4
analyze 202:19
analyzed 204:4
and/or 149:18
ANDREW 3:11
ANDY 3:19
172:2 173:8
answer 26:5
29:4 44:19
46:17 73:8
103:16 128:7
136:4, 5 138:5
176:3 180:20
193:17 194:20
9/5/2024
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answering 47:9
answers 29:1
ANTHES 2:7
7:18 115:6, 12
116:6 121:22
127:20 128:6
132:3 134:11
135:1 138:20
139:1, 11, 13, 18,
20, 22 140:3, 6
anticipate
166:17
anticipated
216:13
anybody 16:17
210:17
anymore 58:17,
22 59:2 108:17
205:15
anyway 89:6
116:3 210:3
216:2
appears 138:17
Appendix
203:13
Applause 14:1
114:14, 16
210:3, 5 224:21
applicable
124:1 143:13
148:9 150:20
151:22 155:2
183:7
application
18:17 92:1
applied 30:9
91:12 177:19
applies 76:13, 16
apply 48:4
78:7 180:15
181:1 184:4
195:2 196:5, 17
applying 119:2
appreciate
51:21 111:17
188:14 201:1
202:4
appreciated
11:1 176:1
approach 90:14
116:14 179:4
181:2, 8 182:12
183:3 194:16
209:15
appropriate
63:15 99:19
119:5, 10
appropriately
63:17
approval 100:2
143:12, 13
147:20 148:12
approve 216:3
approved 146:6
148:12, 14
170:8 171:4
174:4, 12 177:3,
14 214:13
215:22
approves 146:1
approving
148:10 152:1
154:22 155:3
approximately
47:12
April 148:10, 11
AQUINO 2:8
archive 49:7
area 25:3
91:20 183:8
Scheduling@TP.One
www.TP.One
195:12 198:3
200:6
areas 45:19
71:20 102:3
182:21 202:13
Arevon 3:22
138:13
argue 131:19
argued 43:3, 9,
15
argument 90:11
201:4, 9
arguments
207:20
ARISTIDES
4:15
ARNE 4:6
58:5 93:14
articulate
162:12 169:7, 18
asked 67:6
76:15 206:18
asking 12:10
27:16 66:13
67:11 98:3
113:22 173:3
as-of-day 145:13
aspect 74:16
84:5 189:4
aspects 19:14
21:7 24:15
27:22 51:1
73:16 122:15
153:1 193:6
assembled 15:3
assess 52:18
64:10
assessing 128:20
assessment
102:10 168:16
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Technical Conference Day 2
asset 145:13
171:1 181:16
182:17 185:19
198:18 199:5,
12 200:4
assets 50:21
51:16 54:4
90:1 150:19
151:2, 13 162:7
170:22 179:5
182:13 183:1, 6,
11 184:2, 4, 22
211:16, 18
212:7, 9
assigned 110:1
assist 213:8
associated 39:19
Associates 2:2
Association 2:5
3:7 4:19
assume 175:1
assuming 101:4
104:21 148:12
177:14 181:2
assumption
111:22 168:11
assured 13:8
assures 211:17
Attachment
41:19 47:12
61:6
attacked 180:2
attempt 117:4
119:19, 21 198:6
attempted 120:9
attempting 61:5
63:10 64:9
121:7
attention 224:16
attestations
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100:12
auditors 69:19
authorities
143:17
authority
143:12, 14
152:1 155:2
166:8
authority's
148:9
auxiliaries 21:9
30:5 58:8 74:2,
9, 11
auxiliary 174:11,
19 175:4 188:17
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BABIK 2:9
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Scheduling@TP.One
www.TP.One
67:5, 14 72:15
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
137:2 145:12,
13 146:18
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200:3 201:15
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Scheduling@TP.One
www.TP.One
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73:10 150:14
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Blue 205:4
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
Board 4:3, 12
12:5 13:18
18:4 35:8
54:16 73:22
106:16 167:12
195:2 220:7
222:18 223:21
Bob 21:17, 18
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218:10
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172:13 173:6
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114:19 210:9
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190:11 191:6
197:16 199:5
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bringing 146:15
186:22 203:14
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brings 30:5
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Scheduling@TP.One
www.TP.One
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77:12 113:16
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
172:15, 19
187:19 196:11
199:18, 19 224:9
capitalize 139:16
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140:1, 4
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CASUSCELLI
2:19 97:21
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www.TP.One
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11:22 14:7, 13
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
114:11 157:9
158:14
CHARLIE 2:22
chart 143:21
cheaper 54:20
check 52:5
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Chicago 158:9
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82:22
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2:11
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213:15
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110:1
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Clean 3:20
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105:22 158:3
181:8 200:16
cleanly 160:19
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clear 97:16
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closer 163:3, 9
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Closing 8:22
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co-chair 115:16
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codes 35:17, 21
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220:18 221:5, 6,
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Scheduling@TP.One
www.TP.One
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35:5
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199:3 206:1
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
Committee 1:9
9:18 14:14
97:4 101:20
102:9 111:15
112:6, 12 114:6
158:16 176:10
210:4 211:9
215:3 219:6
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Company 2:15,
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compared 22:20
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81:7 100:8
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159:15
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47:17 48:7
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90:7, 19 91:17
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106:17 108:16
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151:18
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comprehensive
116:18
Scheduling@TP.One
www.TP.One
compressed
215:8
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135:12 136:21
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113:9
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158:18
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195:12
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125:19 137:22
156:18 161:12
170:13 172:6,
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
21 173:4
174:13 181:4
188:8 191:21
198:13 205:13
conclude 13:14,
17 81:15 215:9
concluded 217:6,
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176:8
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Conference
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conferences
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197:18
configuration
125:11
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configurations
36:21
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conforming
154:10, 13
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167:12
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82:9, 12
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155:10 215:3
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Consensus 8:21
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consistency
150:18
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Consortium
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92:15 175:3
construct 67:20
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66:16 69:3
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Scheduling@TP.One
www.TP.One
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11:10
Control 100:3
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149:18 166:4
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
205:9
controls 204:10
conventional
56:5 76:14
77:15 78:9
80:13, 22 90:5
179:14
conventionals
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9/5/2024
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(800.367.3376)
Technical Conference Day 2
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Page 13
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
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20:10 120:4
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123:13
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9/5/2024
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(800.367.3376)
Technical Conference Day 2
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(800.367.3376)
Technical Conference Day 2
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9/5/2024
Page 16
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
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9/5/2024
Page 17
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(800.367.3376)
Technical Conference Day 2
179:9 180:18
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9/5/2024
Page 18
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
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(800.367.3376)
Technical Conference Day 2
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
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(800.367.3376)
Technical Conference Day 2
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(800.367.3376)
Technical Conference Day 2
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(800.367.3376)
Technical Conference Day 2
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134:2 161:6
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
hurdles 198:12
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hurt 24:21
HUSAM 2:6
7:18 115:7, 16
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
improvements
54:20
inability 28:18
inaudible 86:21
incentive 199:17
incentives 77:8
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110:2
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138:1
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38:1
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indexing 117:12
individual 22:15
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industrial 48:3
Industries 2:5
industry 15:5
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www.TP.One
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35:19 46:17
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
interconnectivity
29:12
interest 79:6
interesting 201:9
internal 113:15
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172:17 187:1
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7:5 20:5
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
JOHN 2:9 5:12
JOHNNY 2:18
join 189:5
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www.TP.One
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(800.367.3376)
Technical Conference Day 2
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
level 23:2
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92:9 100:19
101:16 130:8
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(800.367.3376)
Technical Conference Day 2
looks 89:4
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Luncheon 141:7
lunchtime 140:8
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4:10 7:13
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magnitude 17:4
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160:20 176:16
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Management
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Scheduling@TP.One
www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
Matevosyan
32:3 82:14, 21
matter 19:9
58:6, 11 180:14
186:4 203:10
maximization
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measure 142:11
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measured
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www.TP.One
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minute 64:11
minutes 116:2
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
186:4 210:7
211:4
mis 192:15
misleading 80:3
mis-operations
192:7
missing 75:20
168:4
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800.FOR.DEPO
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Technical Conference Day 2
35:15, 20, 22
38:14 45:2, 13
46:13, 16, 21
52:22 57:20
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non-negotiable
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Nope 26:20
800.FOR.DEPO
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Technical Conference Day 2
normal 123:2
125:5 127:11
NORTH 1:5
35:19 36:1 45:1
notch 9:15
note 81:15
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nuts 110:17, 18
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nutshell 67:11
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www.TP.One
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800.FOR.DEPO
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Technical Conference Day 2
173:4 183:1
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Technical Conference Day 2
119:16 152:19
184:5, 7 199:12
ownership
179:5, 13, 17
180:17 183:20
198:14
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paper 12:20
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penetration
67:1 205:14
penetrations
40:10
people 10:7, 14,
21 12:9 72:5,
22 89:15
103:15, 19
125:16 134:14
136:18 151:4, 7
173:2 176:11
181:13 215:11
221:18
percent 25:7
26:11 37:5, 8
79:13 82:1
103:7 127:16
129:6, 11 130:9
131:3, 12, 21
136:2, 13, 14, 19
138:4 145:8, 11,
22 146:2 149:7,
12, 13 150:13
224:9
percentage
110:12, 14
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
percentages
53:11 146:21
perfect 115:7
perfectly 90:21
perform 49:11
50:11 53:9
70:2 72:3, 5
95:19 96:15
136:5, 6 137:15,
16 138:6 163:5
performance
19:1, 17 21:12
22:13, 15 63:1
67:10 69:14
73:9, 12 82:13
83:4 91:9 93:2
108:8 112:2, 8
116:21 117:18,
20 118:2 121:9
133:22 135:5, 6
153:14 155:7,
18 160:9, 17
163:4 173:16
191:15, 16
193:21 194:7
201:14, 17
208:1, 6 209:11
performancebased 153:3, 7,
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performed
136:6 137:15
194:14
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48:8 54:2
59:14 71:5
72:3 153:20
171:18
performs 98:14
period 56:12
123:2 125:4
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126:20 143:11,
19
person 11:7
222:20
personal 69:16
160:15 164:1
200:15
personally
65:20 173:14,
21 192:17
201:19
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29:16 34:15
58:4 72:18
103:4 161:19
170:3 174:21
186:9 221:22
perturbations
120:14 139:6, 7
205:12
perverse 199:17
phase 150:1
205:5
phased-in
142:15 144:2
145:6, 20
148:18 149:6
152:22 173:12
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44:7 59:6, 16
68:5, 9, 12
151:19 165:2
189:21
pieces 16:1
48:4 64:6
68:14 73:16
152:3
pinch 39:10
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PITTS 5:3
place 29:18
36:3 39:2, 14
49:6 63:6
66:22 69:9
84:19 144:6
163:14 170:8
209:10
placed 35:1
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72:2 181:13
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61:12 76:2
142:12, 19
144:2 145:3, 12
149:7 152:22
153:9, 15
154:12 166:3, 5,
8 173:20 177:7,
9, 13 178:5, 6,
10 181:11
184:6 208:14
215:14, 19, 21
216:22
planned 39:13
planner 128:17
planners 62:21
67:8 72:14
78:12 88:22
planning 39:7, 9,
11 40:9, 16
41:6 46:21
75:5, 21 81:22
85:12 148:2
162:1 167:22
Scheduling@TP.One
www.TP.One
190:12 198:20
199:9
Plans 8:8, 11, 21
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160:6 164:2, 5
212:20
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er 206:1
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18:14 19:2, 8
56:21 61:5
63:2, 10, 14
64:2 77:9
95:15, 18 99:22
100:19 103:21
104:3 105:12
109:16 118:17
123:9, 15, 20
124:4, 8, 14, 22
125:9, 14
126:11 130:13,
15 135:22
136:5, 6, 13
137:14, 15
138:6 164:19
166:1 196:6, 16
197:17, 19
198:18 199:7, 8,
13, 14 200:20
204:11 205:9
208:12, 13 209:8
plant-by-plant
16:7
plants 16:14
33:18, 20 36:18,
20 73:13 74:1,
2 77:1, 10
107:16 162:16,
19 165:12, 15,
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
17 176:21
200:17, 20
plate 79:18
platforms 82:7,
8
play 17:22
184:2 186:12,
15 201:8
players 179:9
please 13:9
114:22 116:11
117:6, 16 118:5
120:8, 15
121:14 141:22
142:18 143:6
145:5 148:3, 17
156:18 157:13
158:1 206:14
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189:1 220:21
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90:22
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point 18:13
19:22 26:5, 9
28:13 29:12, 22
33:19 44:8
45:12, 15 51:22
64:11 67:18
68:1, 8, 12 69:3,
8, 13 72:17
75:14, 15 76:2
80:6 83:11
91:2, 7 94:4
95:4, 20 99:10,
14 101:22
103:6, 12
106:17 108:14
110:16, 21
112:8, 10, 18
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113:10 136:8
140:8, 17
153:20 155:20
160:20 167:15,
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190:11 191:11,
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198:16 201:2
204:2 205:13
208:16 213:14
215:17 219:1
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76:18 78:20
204:4 224:5
pointing 206:20
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38:7 39:10
46:7 90:12
91:4 92:8
112:8 132:4
146:18 160:4
223:3
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174:9
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141:12, 15
210:14 216:12
Polling 8:18, 19,
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210:7, 8 215:1
POM 100:9
Pool 2:21 5:22
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107:2 158:15
219:21
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141:16 144:3
160:9 173:15, 16
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48:21 169:19
171:17 201:17
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198:18 199:11
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28:5, 8, 11
43:22 120:10
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157:17 169:8
178:8 193:15
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217:8 219:3
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217:15
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180:4 184:15
207:10, 11
218:18
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46:5 54:3 71:7
92:21 93:8
95:12 152:8
200:21
Power 2:21 3:7,
9, 17, 18 4:14,
18, 19, 22 5:22
14:13 23:22
24:9 33:18
Scheduling@TP.One
www.TP.One
64:14 72:20
73:22 74:3, 4
83:19 84:16
100:6 118:17
119:19 120:1, 3,
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128:14, 16
129:8, 11, 20
131:1 132:8, 9,
12 140:3
158:12, 15
162:15 176:6,
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195:15 198:3
209:8 219:20
powerful 89:15
powerproducing
122:20
practical 15:12
23:3 24:18, 19
25:2, 12, 19
26:7 107:4
131:20 165:21
167:4
practicality
111:5 135:17
practice 41:7
practices 39:13
167:4
PRC 38:20
46:3 88:16
89:16 93:5
103:9 135:9
137:12, 16
154:6 170:6
176:6 178:17
208:17
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
PRC-002 138:8,
10
PRC-020 203:1
PRC-023 176:4
PRC-024 14:19
21:13 37:13
42:2, 22 43:12,
17 45:5 47:15
51:3 60:13
79:18 87:16
88:19 89:5, 8, 9
90:1, 21 92:6,
13 93:1, 5
100:17 105:2,
11 138:8
151:18 163:8
176:14 192:6, 15
PRC-025 176:5
PRC-028 135:2,
9 144:18
145:22 146:3
147:7 148:4, 18
149:5, 13, 16
151:10 153:9,
10 155:6 156:5
164:21 166:6, 9
173:12, 18
174:8 178:6
185:3
PRC-028-1
159:16
PRC-028's 145:2
PRC-029 8:18,
19 14:7 15:2
27:3, 6, 12, 16,
18 32:6 33:14
35:2 37:7
41:20 42:8
44:14, 21 46:9
47:14, 17 60:13
61:7, 13 63:4
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69:6, 12 76:5
86:13 87:2, 10
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117:21 128:13,
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167:17 171:17
173:21 174:12
175:2 177:5
178:10 184:17
191:13 195:22
196:5 208:1, 6,
21 211:16
PRC-029-1 7:9
159:16
PRC-029's 155:5
PRC-030
116:19 128:11
135:3, 7, 9, 13,
16, 17, 20 136:3
137:8 138:2
154:3, 12 159:3
178:8 189:21
191:3, 22 196:2
PRC-030/defined
132:21
PRC-030's
154:11
PRC-031 159:17
PRC-038 173:20
PRC-2900 210:8
pre 124:11
125:10
precedent 200:8
predict 78:4
172:13, 19
predictability
38:21 39:4
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38:14
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119:18 120:1
129:19 130:3, 13
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201:10
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148:2 213:8
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223:10
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115:8, 19 221:2
Presentation
7:16 8:7 32:17
87:8 115:10
140:10 212:22
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36:7 47:8
98:20 144:1
164:2 173:10
209:14 212:2
215:7
Scheduling@TP.One
www.TP.One
prevent 134:20
159:22
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153:5 163:1
210:20 217:22
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63:12 167:10
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110:21 144:5
147:20 151:2, 7
priorities 216:13
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107:19 113:11
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113:18 114:2
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162:7
privy 54:1
proactive
161:20 162:5
184:14
proactively
190:3
probably 15:10
21:1 30:4
40:22 48:2
49:4 51:18
60:21 62:5
64:21, 22 66:1
73:1, 3 76:3
78:6 95:5 96:8
98:16 125:16
129:16 139:4
148:10, 11
158:21 159:5
161:20 162:8,
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
19 170:22
175:18 185:1
193:8 207:17
215:9 219:2
220:13 221:9
222:10
problem 25:13
46:12 55:15
73:7 82:22
192:22 205:3
problematic
172:6
problems 41:12
75:14, 19 79:7
85:16 166:11
procedures
195:20
process 13:6, 11,
18 17:3 19:22
21:17 30:22
54:15 55:14
56:9, 15, 17
57:5 59:21
62:10 63:5
75:12, 16 90:14,
22 94:5, 8 96:1,
8 97:7, 17
100:22 101:7, 9,
12 102:12
106:14 110:9
111:16 113:1
116:8 117:8
121:12 126:16,
18 146:13, 19
147:4, 5 151:9
175:17 181:15,
22 183:9 184:1
188:5 194:11
196:4 220:1, 2
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processes 17:8
19:19 75:21
217:3
procure 161:21
165:4 186:14
produce 134:4
produced 176:9
224:2
producing
94:17 125:1
131:6 224:7
product 20:5,
11, 20 55:7, 8
61:12 93:18, 19
100:14 217:9
production
55:13, 21 61:21
132:11 169:10
products 18:18
19:5 20:3, 4
41:22 62:3, 16
194:3
professionals
191:5
profiles 30:15
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program 147:14
190:17, 18 191:3
progress 11:19
221:1
prohibit 129:1,
17
prohibited
128:10
project 12:8
14:15 151:16,
18 154:2
162:15 220:18
221:12 224:4
projections 26:9
224:8
Projects 14:16
49:3, 4 83:10
158:8 170:21
172:11 180:17,
18, 22 220:17
221:13, 14
promise 214:16
221:12
proposed 44:21
46:3, 9 87:3
99:14 116:9
118:1, 15
121:17 123:4,
18 172:6, 16
174:13 212:14
protection 30:9
74:6, 9 87:11
91:10 92:8
98:1, 7, 10, 11
100:2, 16
110:11 112:7,
21 115:13
176:22
protections 36:3
protocols 193:14
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175:10
prove 95:2
96:1 97:6
proven 167:4
provide 53:16
63:21 70:15, 17
97:19 100:12
103:21 104:19,
21 105:18
109:2, 16
112:22 131:2,
15 146:11
156:15 178:11
192:9 213:7
218:19
Scheduling@TP.One
www.TP.One
provided 9:17
11:13 25:22
26:15, 16 53:3
63:2 103:2
104:22 177:18
217:22 218:5,
14, 15 219:12
provides 44:5
166:3
providing 38:21
72:19 102:2
105:5
provinces 35:17
provincial
143:16
proving 94:9
201:19
PT 165:1
PTs 175:6
Public 4:19
13:6 94:2 154:7
published
205:22
pull 58:9 59:8
94:19 141:9
174:5 187:5
pulled 165:16
pulls 104:9
purpose 35:15,
22 59:12, 13, 18
push 71:14, 15
136:17
put 10:7, 9
11:11 12:3
16:15 35:3
45:16 50:22
57:11 69:9, 10
71:11 77:4
90:9 91:16
93:5 96:6
104:17, 20
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
108:21 125:16
138:3 139:3
157:15 176:22
183:19 189:1
207:12 208:9
209:1, 9 210:16
214:13 220:20
223:17
putting 10:15
108:15 117:4
128:22 143:20
155:15 170:8
174:1 177:10
197:21 200:10,
15 212:22 219:8
Q&A 7:8, 15, 20
8:17
QIUSHI 5:19
QR 210:16
qualification
206:17
qualified 116:3
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quantified 24:1
quantify 41:21
74:18 136:12
quantifying
42:5 73:7
quantitative
141:18
quantity 113:14
quarter 146:7, 8,
10 148:8, 12, 13,
15 154:21
155:1 177:15, 16
Quebec 35:10
question 15:7,
11 18:9 19:12
21:3 26:19
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27:4, 11, 16
29:13 30:6
32:15 36:13
37:20 41:15, 17
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22 61:1, 3
65:22 66:6, 9,
14 67:11 70:6
76:10, 11, 13, 16
77:19 78:10, 18
86:2 89:4
93:12 94:3
99:13, 18 103:1,
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107:18 109:20
111:17 131:11
138:12 159:15
164:9 166:13,
15, 16 173:14
178:18, 20, 21
179:12, 19
180:16 183:13
184:8, 11 193:1
195:22 198:22
201:1 202:5
203:5 206:18
209:18, 19
211:13, 15
212:4, 5, 6, 19,
22 217:12, 13,
20, 21
questionnaires
111:20
questions 13:2
26:4, 19 32:22
52:8 61:2 66:9
69:6 85:21, 22
97:22 102:4
115:9 132:19
134:19 137:21
154:6 156:13,
17, 20, 22
157:19 194:21
198:8, 9 207:20
209:8, 16, 17
210:14, 19
211:2, 7 216:17
217:10 218:21
219:18
question's 66:13
166:21
queue 55:18
68:19 69:4
114:2 201:22
quick 38:6
99:16 138:12
147:10 210:17
213:14
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80:10, 11
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90:10, 11
104:15 179:16
190:14 201:1
210:13
Quinn 82:15
QUINT 5:4
quirks 80:22
quite 14:17
15:1 23:7
37:15 42:10, 15
51:1 63:9
76:15 101:7
185:13, 19
201:5 214:17
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quotes 37:17
107:12
Scheduling@TP.One
www.TP.One
R1 150:8 196:3
R2 154:15
R3 119:18
132:7 133:21
R7 150:9
raise 156:18
181:4
raised 102:3
182:21 203:10
raising 182:19
205:17
RAJAT 4:11
203:4
rambled 65:15
ramping 39:20
132:6
RAMSEY 5:5
rate 47:20, 22
48:9, 14 49:12
70:19 207:9
rating 175:9, 15
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raw 183:13
RC 130:7, 20
RCA 192:8
reach 13:9
113:7 156:13
182:18
reaching 21:1
113:22
react 80:9
175:20 202:10
207:1
reacted 204:5
reaction 200:2
reactive 195:15
reacts 207:7
read 66:11
118:6 120:18
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
121:18 126:8
130:21 134:11
139:1 183:13
readiness 181:21
reading 115:18
118:12
ready 161:19
162:16 172:11
182:1 202:3
210:11 212:18
213:22
real 32:17
33:12 38:6
39:10 42:3
65:3 74:15
76:12 84:1
85:15 94:3
97:1 99:16
111:15 119:14,
19 128:14, 16
158:22 195:15
199:11 200:19
206:10 210:17
214:16
realistically
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reality 19:18
43:11 56:2
107:5 168:20
184:3
realize 165:20
realized 29:20
165:11
realizing 41:2
57:17 166:10
really 9:22
10:6 17:14, 17
19:10 20:16, 21
21:4 24:14, 16
25:1 29:16
32:16 33:7, 11,
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160:13, 18
161:8, 22 162:1,
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169:17 170:15,
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173:3 175:11
176:4 183:4
186:8, 10 189:3
191:11 192:10,
12 194:19
195:22 201:2,
12 209:12
213:11 222:10
realm 92:22
reason 29:3
43:19 78:13
79:8 87:1
113:16, 17, 18
126:13 129:3
133:19, 21
134:7 138:2
145:20 146:17
reasonable
16:22 22:2
45:15 46:1
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134:20 152:18
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77:8 87:2
120:21 127:14
REBECCA 2:10
rebut 122:1
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Recap 7:5
recapped 157:14
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81:16
recognized
159:5
recognizing
83:14
recommend
102:20 108:11,
14 159:17
recommendations
195:9
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190:16
re-contract 77:4
reconvene
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record 97:3
187:17 218:17
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recorded 135:8
recorder 190:1
Scheduling@TP.One
www.TP.One
recording 135:8
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recordings 185:7
recover 127:15,
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recovery 81:6
123:2 125:5, 13
red 76:12
redesign 16:4
redlining 215:5
redrafting
108:12
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reduction
128:14, 16
reduplicating
135:11
REEDY 5:6
reevaluate
19:22 30:19
58:20 106:10, 12
refer 117:12
reference 117:3
124:13 157:17
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120:16
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160:21 218:1
refers 166:22
regard 36:8
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75:12 162:5
169:13, 19
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167:19 213:5
223:4
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
regards 10:5
12:16 13:2
221:8
regime 59:8
region 36:2
regional 144:13
156:14, 19
regions 36:2
224:6
register 182:22
183:1
registered
182:15
registering
184:6
registrants
150:22
registration
146:14 150:21
151:4 152:16
179:1, 3
regulated 78:13
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194:18
regulators 85:7
regulatory 25:1
85:17 158:11
178:15
related 62:8
166:16 211:15
212:19 218:9
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relative 18:7, 17
20:12 22:3, 5,
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39:21 44:22
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relatively 54:9
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relay 176:5
released 217:16
relevant 72:5
RELIABILITY
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24:8, 11 25:4
26:6, 14 34:8
38:13 43:6
48:8 51:12, 14
64:10, 14 67:16
71:17 72:14
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Remarks 8:22
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Renewable 2:11
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Renewables
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Scheduling@TP.One
www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
153:13 164:19
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47:11 63:3
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requiring 127:21
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Research 4:22
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reserve 51:18
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resolution
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resolve 33:11
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Scheduling@TP.One
www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
45:9 46:22
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Scheduling@TP.One
www.TP.One
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RYAN 5:4
82:15
800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
safe 224:19
225:2
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Scheduling@TP.One
www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
settings 100:5, 8,
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
slowdown
213:22
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
SRINIVAS 3:22
138:13
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84:4 176:6
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198:15
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
Steps 8:22
219:5 222:3
sticking 90:21
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40:8
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www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
86:3 95:9 98:5,
8 99:9 100:4
101:3 107:15
108:2 109:6, 8
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56:18
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159:21
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Scheduling@TP.One
www.TP.One
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
175:1, 4, 5, 11
193:9 194:22
197:8, 13 203:1
211:12
talks 97:9
191:14
tapped 189:16
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
132:4 160:14
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800.FOR.DEPO
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Technical Conference Day 2
183:14 192:8
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
translated
204:13
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2:15 38:13
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800.FOR.DEPO
(800.367.3376)
Technical Conference Day 2
uncertainty
28:4, 17 29:2
39:21 48:19
50:14 167:13
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15:17 17:8
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Exhibit H
Summary of Issues and Alternatives Considered Memo
RELIABILITY | RESILIENCE | SECURITY
To:
NERC Board of Trustees and Stakeholders
From:
NERC Staff and Representatives from the Standards Committee
Re:
Summary of Issues and Alternatives Considered, Proposed Reliability Standard PRC-029-1
(Frequency and Voltage Ride-through Requirements for Inverter-based Resources)
September 24, 2024
Date:
In Order No. 901, the Federal Energy Regulatory Commission (“FERC”) directed the development of new or
revised Reliability Standards to address certain reliability issues related to inverter-based resources
(“IBRs”), including IBR ride-through performance. 1 To address the IBR ride-through directives, Project 202002 Modifications to PRC-024-4 initiated development of proposed Reliability Standard PRC-029-1
(Frequency and Voltage Ride-through Requirements for Inverter-based Resources). However, proposed
Reliability Standard PRC-029-1 has failed to pass ballot through the usual standard development process.
Section 321 of the NERC Rules of Procedure allows the NERC Board of Trustees to take special actions when
a ballot pool has failed to approve a proposed Reliability Standard that contains a provision to adequately
address a specific matter identified in a directive issued by an Applicable Governmental Authority. The NERC
Board of Trustees took such action for the proposed PRC-029-1 standard at its August 2024 meeting. 2
Consistent with Section 321.2 of the NERC Rules of Procedure, the Standards Committee and NERC staff
convened a technical conference from September 4-5, 2024 to discuss the issues surrounding the FERC
Order No. 901 directives, including whether or not the proposed Reliability Standard PRC-029-1 is just,
reasonable, not unduly discriminatory or preferential, in the public interest, helpful to reliability, practical,
technically sound, technically feasible, and cost-justified. This memorandum discusses the issues, an
analysis of alternatives considered, and other appropriate matters.
Background
On October 19, 2023, the Commission issued Order No. 901 directing the development of new or revised
Reliability Standards to address reliability issues associated with the growth of IBRs on the Bulk-Power
Reliability Standards to Address Inverter-Based Resources, Order No. 901, 185 FERC ¶ 61,042, Docket No. RM22-12-000 (Oct. 19,
2023) [hereinafter Order No. 901]. Available here.
1
2
NERC Board of Trustees, Minutes of the August 15, 2024, available here.
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
RELIABILITY | RESILIENCE | SECURITY
System. 3 The Commission directed NERC to develop new or revised Reliability Standards addressing IBR
reliability issues as follows:
1) IBR disturbance monitoring data sharing and post-event performance validation 4 and ridethrough performance requirements 5 by November 4, 2024;
2) IBR data and model validation 6 by November 4, 2025; and
3) planning and operational studies 7 for IBRs by November 4, 2026.
The Commission also directed NERC to develop and submit a work plan to develop new and revised
Reliability Standards to address these issues in accordance with the specified timeframe. 8
On January 17, 2024, NERC submitted its Order No. 901 Work Plan, 9 which consists of key milestones to
meet the Commission’s directives by the filing deadlines mentioned above. Milestone 2, in progress,
focuses on the development of Reliability Standards to address disturbance monitoring, performancebased ride-through requirements and post-event performance validation for registered IBRs by November
4, 2024.
The Reliability Standards being proposed to address Milestone 2 of FERC Order 901 are being developed
through the following projects:
•
Project 2020-02 Modifications to PRC-024 (Generator Ride-through),
•
Project 2021-04 Modifications to PRC-002,
•
Project 2023-02 Analysis and Mitigation of BES Inverter-Based Resource Performance Issues
As of this writing, Projects 2021-04 and 2023-02 are on track for timely completion through the usual NERC
standard development process. Project 2020-02, addressing generator ride-through directives from Order
No. 901, is the subject of special Board action under Section 321.
Specifically, proposed Reliability Standard PRC-029-1 (Frequency and Voltage Ride-through Requirements
for Inverter-based Resources) is a draft standard designed to establish capability-based and performancebased ride-through requirements for IBRs during grid disturbances, to address the Commission directives
from Order No. 901. The draft standard failed to achieve consensus from the Registered Ballot Body over
3
See Order No. 901, supra, at PP 229.
4
See id. at PP 66-109 (discussing directives related to data sharing requirements).
5
See id. at PP 178-211 (discussing directives related to performance requirements).
6
See id. at PP 110-161 (discussing directives related to data and model validation requirements).
7
See id. at PP 162-177 (discussing directives related to planning and operational studies requirements).
8
See id. at P 222.
Informational Filing of the North American Electric Reliability Corporation Regarding the Development of Reliability Standards
Responsive to Order No. 901, (Docket No. RM22-12-000) (2024) [hereinafter Order No. 901 Work Plan].
9
RELIABILITY | RESILIENCE | SECURITY
multiple ballots, the latest of which occurred between August 2, 2024 to August 12, 2024. This called into
question whether development would be completed by FERC’s filing deadline of November 4, 2024.
As a result, the NERC Board of Trustees initiated the use of Section 321 at its August 15, 2024 meeting.
Under this special authority, the Board directed the Standards Committee to work with NERC Staff to
convene a technical conference to gather input from industry to address the outstanding issues and revise
PRC-029-1. This memorandum describes the issues that led to the technical conference convening and the
alternative solutions that were considered. The proposed PRC-029-1 standard has been revised using input
from the technical conference and is submitted for stakeholder ballot. This process must be completed
within 45 days of being initiated, which is September 30, 2024. If the re-balloted proposed Reliability
Standard achieves at least an affirmative 60% majority vote of the weighted Segment votes cast, then the
Board may consider it for adoption under Section 321.
Order No. 901 Directives for Ride-through
In Order No. 901, the Commission cites to multiple event reports as the reason that IBRs should have
Reliability Standards for 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. 10 Below you will find the Commission’s specific directives on
how IBRs should ride-through disturbances and how exceptions should be applied to certain IBRs. Finding
consensus around these directives were a part of the main issues addressed during the technical
conference.
“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 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.” 11
“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
10
See Order No. 901 at PP 190.
11
See id.
RELIABILITY | RESILIENCE | SECURITY
modify their coordinated protection and control settings to meet the requirements without physical
modification of the IBRs’ equipment.” 12
Summary of Issues and Alternatives Considered
The technical conference took place on September 4-5, 2024, and focused on unresolved issues raised by
stakeholders raised during the PRC-029-1 comment periods. Specifically, the technical conference focused
on: (1) the proposed definition of “Ride-through”; (2) the proposed criteria for frequency ride-through
performance; and (3) the feasibility of allowing hardware-based exemptions from the frequency ridethrough requirements, similar to the voltage ride-through exemption FERC directed NERC to consider in
Order No. 901. 13 These issues, and the alternatives considered, are discussed below.
Ride-Through Definition
The most recent Standard Authorization Request for Project 2020-02 included direction to the drafting
team to define the term “ride-through” as necessary. During the development of Milestone 2 projects, a
definition for “ride-through” was considered by the drafting teams of both PRC-029 and PRC-030 as both
Reliability Standards leverage the term to refer to acceptable performance criteria outlined in PRC-029. Per
the Standards Process Manual (NERC Rules of Procedure Appendix 3A), definitions themselves may not
include statements of performance requirements. As such, the specific performance requirements and
measures to demonstrate ride-through are to be found within the Requirements and Attachments of PRC029-1. References to “Ride-through criteria” in PRC-030-1, allow for those additional analytics to include
further evaluations with PRC-029-1 Ride-through performance requirements as appropriate while
preventing duplication of those performance requirements in different Reliability Standards.
Comments from Draft 3 of PRC-029-1 concerning the proposed definition of “Ride-through” were reviewed.
In the previously proposed definition, many stakeholders argued that the proposed definition was too
broad and ambiguous, particularly with the inclusion of phrases like “entire” and “in its entirety.” Those
stakeholders recommended revisions to clarify the definition and ensure it aligns better with IEEE Std
2800™, IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs)
Interconnecting with Associated Transmission Electric Power Systems. 14 The Draft 3 proposed definition of
“Ride-through” was discussed at the technical conference and presented on by a member of the original
drafting team. 15 The Draft 3 definition was presented as follows: “The entire plant/facility remaining
connected to the Bulk Power System and continuing in its entirety to operate through System
Disturbances.”
As part of the presentation, ten (10) alternative definitions were presented as proposed by commenters
during the previous rounds of ballot and formal comment. After the presentation, four (4) of the most
12
13
14
See Order No 901 at PP 193.
See Order No 901 at PP 199.
Hereinafter referred to as “IEEE 2800-2022”.
See “Outlining Objectives of a Ride-through Definition” of posted Standards Committee and NERC Ride-through Technical
Conference material; page 94/129.
15
RELIABILITY | RESILIENCE | SECURITY
distinct definitions were opened to technical conference attendees as a straw poll to gauge overall industry
preference. When asked “Which of the following proposed definitions for Ride-through do you think is most
correct?”:
•
•
•
•
68% voted in favor of the “Ability to withstand voltage or frequency disturbances inside defined
limits and to continue operating as specified.”;
16% voted in favor of “The plant/facility remaining connected to the Bulk Power System and
continuing to operate through System Disturbances as defined in applicable reliability standards.”;
12% voted in favor of “The entire plant/facility remaining connected to the Bulk Power System and
continuing in its entirety to operate through System Disturbances.”; and
4% voted in favor of “The plant/facility shall remain connected and in service, maintaining the predisturbance equipment configuration in operation, throughout the entirety of the system
disturbance and recovery.”
Following the technical conference, NERC staff, Standards Committee representatives, some members of
the drafting team, and FERC staff met to discuss the results of the straw poll as well as previously reviewed
material. Based on that discussion, language in the preferred definition such as “ability to withstand”,
“defined limits” and “as specified” were unclear and were inherently challenging for use in a definition that
must be leveraged by multiple Reliability Standards. It was determined that the final draft would proceed
with the 2nd most preferred definition, with slight modifications to remove usage of other defined terms
that had an embedded usage of the Bulk Electric System defined term. The final definition as proposed in
Draft 4 of PRC-029-1 is as follows: “The plant/facility remains connected and continues to operate through
voltage or frequency system disturbances.”
Proposed Criteria for Frequency Ride-Through Performance
As described in the Project 2020-02 Standard Authorization Request and assigned directives from Order No.
901, the drafting team was tasked with developing new or modified Reliability Standards to assure a
performance-based approach to generator ride-through. This scope included requirements that generating
resources shall ride-through grid disturbances and include quantitative measures on expectations for ridethrough that address all possible causes of tripping and power reductions from generating resources
(particularly generator, turbine, inverter, and all plant-level protection and controls).
The proposed new Reliability Standard PRC-029-1 requires generator owners of IBR to both design and
operate their IBR plants to ride-through voltage and frequency system disturbances. Requirement R3 and
Attachment 2 of PRC-029-1 define the quantitative frequency ride-through criteria by use of measured
frequency magnitude and time duration of sustaining that magnitude for all conditions. As discussed during
the development of PRC-029-1, many stakeholders commented in previous ballots a preference to leverage
those quantitative values as currently established in IEEE 2800-2022.
Frequency ride-through criteria was a prominent discussion of the technical conference. Members of the
drafting team presented on the decisions made during the development of these criteria during the
technical conference. 16 The presentation explained that the voltage and frequency ride-through zones
See “Review of Voltage and Frequency Ride-through Criteria in PRC-029-1” of posted Standards Committee and NERC Ride-through
Technical Conference material; page 47/129.
16
RELIABILITY | RESILIENCE | SECURITY
proposed in Draft 3 of the standard were based on the IEEE 2800-2022 no-trip zones and were established
in view of drafting team member experience with frequency excursions in planning and operations. The
drafting team also stated the proposed frequency criteria were reasonable and were practical limits of IBR
frequency tolerances, inclusive of adequate margins for worst-case conditions.
Following the presentation by the drafting team, NERC staff presented on voltage and frequency Ridethrough evaluations taken from recent NERC disturbance reports and the report results from the March
2023 Level 2 Alert. 17 The NERC presentation stressed balancing Bulk Power System needs with reasonable
criteria that account for technical capabilities of currently designed equipment. NERC also highlighted a
continued need to coordinate messaging during the design and interconnection phases of new IBR to have
protection and controller equipment set in accordance with the hardware capability of the IBR rather than
only in relation to minimum values established in NERC Reliability Standards.
Two panels regarding frequency criteria were held during the technical conference. The first panel included
representatives of various IBR original equipment manufacturers, and the second panel included other
members of industry. 18 Discussions from both panels highlighted the following key issues: 19
•
•
•
Many IBR designed before 2014 would be unable to meet frequency Ride-through magnitude and
duration criteria proposed in Attachment 2 of Draft 3. It was estimated by one panelist that
approximately 20 GW of installed capacity would not be able to meet the criteria, indicating
significant challenges for legacy IBR without substantial hardware replacement and redesign.
Many IBR had not been designed to meet a rate of change of frequency (RoCoF) of 5 Hz per second.
Of concern from the panelist was the technical basis for determining the need for a 5 Hz RoCoF did
not include a study or more thorough evaluation of potential system strength benefits and that
different parts of the Bulk Power System have not been demonstrated to require it.
Recent event reports presented by NERC were all related to voltage excursions, potentially
indicating that frequency-based disturbances were less likely to occur. Some panelists contended
that this potential lower likelihood of experiencing a frequency event did not align with the
expansion of frequency criteria beyond those currently established in IEEE 2800-2022.
After the panels of this topic, two straw polls were opened for attendees of the Ride-through technical
conference to provide their feedback for consideration regarding “legacy” IBR and future IBR.
When attendees were asked “Based on the conversation you heard today from our panels, for legacy assets,
what should PRC-029 voltage and frequency criteria follow that assures reliability and is reasonable for
industry?”:
•
64% voted in favor of “Maintain PRC-024 criteria for IBR”;
See “Review of Voltage and Frequency Ride-through” of posted Standards Committee and NERC Ride-through Technical Conference
material; page 67/129.
17
See “Panel Discussion: Original Equipment Manufacturer Perspectives on Voltage and Frequency Ride-through Criteria” of posted
Standards Committee and NERC Ride-through Technical Conference material; pages 85/129 and 86/129.
18
See Day 1 Recording and Transcript of the Standards Committee & NERC Ride-through Technical Conference; Project 2020-02
Modifications to PRC-024 (Generator Ride-through) Related Files; posted September 18, 2024.
19
RELIABILITY | RESILIENCE | SECURITY
•
•
29% voted in favor of “Adopt voltage and frequency bands proposed in IEEE 2800-2022”; and
6% voted in favor of “Retain currently proposed PRC-029 criteria”.
When attendees were asked “Based on the conversation you heard today from our panels, for assets being
brought online in the future, what should PRC-029 voltage & frequency criteria follow that assures reliability
and is reasonable for industry?”:
•
•
90% voted in favor of “Adopt voltage and frequency bands proposed in IEEE 2800-2022”; and
10% voted in favor of “Retain currently proposed PRC-029 criteria”.
Following the technical conference, NERC staff, Standards Committee representatives, some members of
the drafting team, and FERC staff met to discuss the results of the straw polls as well as previously reviewed
material. The team discussed that the term “legacy assets”, as used during the technical conference, aligned
with the date for seeking potential exemption within PRC-029-1; meaning those IBR that were “in-service”
by the effective date of PRC-029-1. While respondents at the technical conference did vote more favorably
to retaining existing PRC-024 criteria for legacy assets, other information submitted by commenters and
highlighted during the panel of original equipment manufacturers, indicated that a significant majority of
IBR have been designed to meet IEEE 2800-2022 values. 20, 21
Additional information provided during the NERC staff presentation 22 identified that many IBR were still
being designed and installed without setting their protection and controls in accordance with their physical
capabilities. Due to a concern of lowering the bar of performance by requiring that IBR perform less than
what the significant majority of IBR are being designed and manufactured to, it was determined that the
proposed standard should not align with previous PRC-024-3 criteria.
Based on the more clearly understood hardware-based capability limitation established due to manufacture
design for a significant amount of installed IBR, there was a reliability concern to proceed with Draft 3 PRC029-1 frequency criteria as that same amount of IBR could necessitate disconnection and retrofitting in
order to comply. It was also identified that the potential disconnection of a large amount of installed IBR
capacity did not substantially outweigh unstudied reliability benefits potentially resulting from setting
frequency ride-through bands wider than those established in IEEE 2800-2022 and overwhelmingly
identified by manufacturers during our comment review when designing IBR throughout the past decade.
Due to these reliability concerns, the frequency criteria in Attachment 2 of the draft has been adjusted to
align with those values in IEEE 2800-2022.
Feasibility of Hardware-Based Exemptions from Frequency Ride-Through Requirements
Potential hardware-based exemptions were discussed during each formal comment period of PRC-029-1,
with a significant majority of commenters supporting some exemptions from frequency ride-through
See Industry Submitted Comments for the Standards Committee & NERC Ride-through Technical Conference; Project 2020-02
Modifications to PRC-024 (Generator Ride-through) Related Files; posted September 2024.
20
See Day 1 Recording and Transcript of the Standards Committee & NERC Ride-through Technical Conference; Project 2020-02
Modifications to PRC-024 (Generator Ride-through) Related Files; posted September 18, 2024.
21
See “Review of Voltage and Frequency Ride-through” of posted Standards Committee and NERC Ride-through Technical Conference
material; page 67/129.
22
RELIABILITY | RESILIENCE | SECURITY
criteria for legacy IBR. The drafting team and industry were advised that Order No. 901 only included and
only allowed for exemptions of voltage ride-through performance requirements, based on the following
discussion of allowable exemptions within the order:
“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.” 23
“Further, we direct NERC to ensure that any such exemption would be applicable for only existing
equipment that is unable to meet voltage ride-through 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.).” 24
While the order spoke only to exemptions from voltage ride-through requirements and was silent regarding
any exemptions for frequency ride-through criteria, industry continued to identify that there was a need to
include such exemptions in PRC-029-1. It was determined that the details shared leading up to and during
the technical conference provided clarity as well as a more substantiated basis for why hardware-based
exemptions of frequency ride-through criteria was needed.
Prior to the technical conference, NERC solicited comments from industry as well as original equipment
manufacturers. 25 In particular, any information on hardware-based limitations that would prevent IBR from
meeting the proposed frequency criteria within PRC-029-1 was requested. 21 individual comments were
received including six (6) from different original equipment manufacturers of IBR. NERC and representatives
from the Standards Committee reviewed the submitted material and confirmed that IBR are being designed
by original equipment manufacturers to be able to meet those voltage and frequency ride-through curves
established in IEEE 2800-2022. As Draft 3 of PRC-029-1 proposed frequency criteria were beyond those
established in IEEE 2800-2022, there was a concern that IBR would not be able to meet those proposed
frequency criteria as IBR capability limits were hardware-based and inherent to a manufacturer’s design.
While many comments received during the formal comment periods stressed a desire to align PRC-029-1
with IEEE 2800-2022, there was little differentiation between comments that sought to leverage other
industry volunteer guidelines that have been significantly adopted with those comments that sought
exemptions due to the fact that manufacturers are designing IBR capabilities to the IEEE 2800-2022 values.
Moreover, comments submitted by manufacturers provided a better understanding and approximation of
what percentage of the installed fleets of IBR would be unable to meet PRC-029-1 frequency criteria. While
additional information regarding specific amounts of affected IBR is still sought by NERC, from the
23
See id. at P 153.
24
See id. at P 153.
See Standards Committee and NERC Ride-through Technical Conference; Conference Details; publicly announced August 21, 2024;
https://www.nerc.com/pa/Stand/Documents/SC_and_NERC%20Ride-through_Technical_Conference_Details_08212024.pdf
25
RELIABILITY | RESILIENCE | SECURITY
information provided, it appears that a significant percentage of IBR 26 – specifically Type 3 wind turbine
facilities – would need to retrofit to avoid noncompliance with PRC-029-1 as proposed in Draft 3.
The technical conference included a panel discussion on frequency exemptions. Panelists discussed various
challenges related to legacy IBR, such as difficulties obtaining more detailed information on equipment
capabilities; specifically for manufacturers who are no longer in business and for IBR that are no longer
supported by the manufacturer. In such instances, additional time and cost would be expected to conduct
more detailed capability testing. Other concerns raised included the possibility that manufacturers would
not be willing to provide design or hardware limitation documentation should they identify the information
to be proprietary information. Other discussions substantiated information received during the solicitation
of comments for the conference and provided more clarity as to the alignment of the IEEE 2800-2022 curves
with inherent capability limitations. 27
Following the technical conference, NERC staff, Standards Committee representatives, some members of
the drafting team, and FERC staff met to discuss the discussions during the conference as well as previously
reviewed material. Based on the more clearly understood hardware-based capability limitation established
due to manufacture design for a significant amount of installed IBR, there was a reliability concern to
proceed with no potential for hardware-based limitations for frequency criteria, as that same amount of
IBR could necessitate disconnection and retrofitting to comply.
It was determined that this potential disconnection of a large amount of installed IBR capacity
overwhelmingly indicated a reliability need to allow for a documented and limited set of exemptions for
IBR from voltage and frequency ride-through criteria. In light of this reliability concern, Requirement R4 of
PRC-029-1 has been modified to allow for a documented, and limited set of exemptions for IBR from
frequency criteria. Further modifications were made to allow Generator Owners to exclude information
considered to be proprietary from submittals to anyone other than the Compliance Enforcement Authority,
to facilitate the sharing of requisite information from manufacturers.
Conclusion
After following the process described in Section 321 of the NERC Rules of Procedure, as directed by the
NERC Board of Trustees at the August 15, 2024 meeting, proposed Reliability Standard PRC-029-1 has been
revised to: include revised definition for the new proposed term “Ride-through”, align frequency ridethrough criteria with IEEE 2800-2022 values, allow for a limited documented set of exemptions for
hardware-based limitations for frequency ride-through criteria, and to allow Generator Owners to only
share information deemed by the original equipment manufacturer as proprietary with the Compliance
Enforcement Authority..
These revisions in proposed Reliability Standard PRC-029-1 reflect a fulsome consideration of the technical,
reliability, and implementation considerations raised in the underlying development proceeding and during
Analysis of the data collected through NERC’s Level 2 Alert: Industry Recommendation for IBR Performance Issues showed that the
number of resources that are not able to meet PRC-029 Draft 3 is approximately double when compared to those same resources ability to
comply with the updated criteria in PRC-029 Draft 4 which align with IEEE 2800-2022. Information submitted through the comment period
and the technical conference discussions indicated that this ratio would be higher for wind resources, specifically Type 3 wind.
26
See Day 2 Recording and Transcript of the Standards Committee & NERC Ride-through Technical Conference; Project 2020-02
Modifications to PRC-024 (Generator Ride-through) Related Files; posted September 18, 2024.
27
RELIABILITY | RESILIENCE | SECURITY
the technical conference, with the intent of addressing the Order No. 901 directives in a manner that is just,
reasonable, not unduly discriminatory or preferential, in the public interest, helpful to reliability, practical,
technically sound, technically feasible, and cost-justified.
RELIABILITY | RESILIENCE | SECURITY
Exhibit I
Standard Drafting Team Roster
RELIABILITY | RESILIENCE | SECURITY
Standard Drafting Team Roster
Project 2020-02 Modifications to PRC-024 (Generator Ride-through)
Name
Entity
Chair
Xiaoyu Wang (Shawn)
Enel North America
Vice Chair
Husam Al-Hadidi
Manitoba Hydro
Members
John B. Anderson
Xcel Energy
Joel Anthes
Pacific Gas and Electric
Johnny C. Carlisle
Southern Company Services, Inc
Rajat Majumder
Ørsted North America
Robert J. O’Keefe
American Electric Power (AEP)
Alex Pollock
AMSC
Ebrahim Rahimi
California ISO
Fabio Rodriguez
Duke Energy Florida
Kenneth Silver
8minute Solar Energy
Ovidiu Vasilachi
Independent Electricity System Operator (IESO)
John Zong
Electric Power Engineers
Pamela Hunter
Southern Company
Anthony Westenkirchner
Evergy
Jamie Calderon – Manager of
Standards Development
North American Electric Reliability Corporation
PMOS Liaisons
NERC Staff
RELIABILITY | RESILIENCE | SECURITY
Name
Lauren Perotti – Legal
Entity
North American Electric Reliability Corporation
Drafting Team Roster
Project 2020-02 Project 2020-02 Modifications to PRC-024 (Generator Ride-through) | November 2023
2
| File Type | application/pdf |
| Author | Phillip Yoffe |
| File Modified | 2024-11-04 |
| File Created | 2024-11-04 |