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pdfUNITED 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
PRC-026-1
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate General Counsel
William H. Edwards
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
December 31, 2014
TABLE OF CONTENTS
I.
Notices and Communications ................................................................................................. 3
II.
Summary ................................................................................................................................. 3
III. Technical Overview ................................................................................................................ 6
1.
Stable Power Swings .................................................................................................... 6
2.
Protection System Attributes Related to Power Swings ............................................... 7
IV. 2003 Blackout and Regulatory History................................................................................... 8
A.
2003 Blackout .................................................................................................................. 8
B.
Regulatory History ........................................................................................................... 9
V.
1.
Order No. 733 ............................................................................................................... 9
2.
Order No. 733-A ......................................................................................................... 11
3.
Order No. 733-B ......................................................................................................... 12
4.
NERC Informational Filing ........................................................................................ 12
NERC Activity to Address the Directive .............................................................................. 14
A.
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings ........................ 14
B.
PSRPS Report ................................................................................................................ 15
1.
2003 Blackout Comments .......................................................................................... 16
2.
Dependability vs. Security .......................................................................................... 16
3.
Recommendations for the Design of a Reliability Standard ...................................... 18
VI. Justification for Approval ..................................................................................................... 18
A.
NERC’s Approach to Meet the Directive ...................................................................... 19
B.
Proposed Reliability Standard PRC-026-1..................................................................... 25
C.
1.
Purpose and Reliability Benefit of Proposed PRC-026-1 .......................................... 25
2.
Applicable Entities ..................................................................................................... 26
3.
Requirement R1 .......................................................................................................... 32
4.
Requirement R2 .......................................................................................................... 34
5.
Requirements R3 and R4 ............................................................................................ 39
Enforceability of Proposed Reliability Standards .......................................................... 40
VII. CONCLUSION ..................................................................................................................... 40
Exhibit A
Proposed Reliability Standard PRC-026-1
i
TABLE OF CONTENTS
Exhibit B
Implementation Plan
Exhibit C
Order No. 672 Criteria
Exhibit D
Consideration of Issues and Directives
Exhibit E
NERC System Protection and Control Subcommittee: Protection System
Response to Power Swings
Exhibit F
Analysis of Violation Risk Factors and Violation Severity Levels
Exhibit G
Summary of Development History and Complete Record of Development
Exhibit H
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
PRC-026-1
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”)1 and Section 39.52 of the
Federal Energy Regulatory Commission’s3 (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”)4 hereby submits proposed Reliability
Standard PRC-026-1 (Relay Performance During Stable Power Swings) (Exhibit A) in response
to the Commission’s directive in Order No. 7335 to develop a Reliability Standard addressing
undesirable relay operation due to stable power swings.6 NERC requests that the Commission
approve the proposed Reliability Standard as responsive to the directive and find that it is just,
1
16 U.S.C. § 824o (2012).
18 C.F.R. § 39.5 (2014). Section 39.5(a) of the Commission’s regulations requires the ERO to file with the
Commission for its 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 should be
made effective. Id.
3
By enacting the Energy Policy Act of 2005, 16 U.S.C. § 824o (2012), Congress entrusted the Commission
with the duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk-Power System, and
with the duties of certifying an Electric Reliability Organization (“ERO”) that would be charged with developing
and enforcing mandatory Reliability Standards, subject to Commission approval.
4
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).
5
Transmission Relay Loadability Reliability Standard, Order No. 733, 130 FERC ¶ 61,221 (2010) (“Order
No. 733”); order on reh’g and clarification, Order No. 733-A, 134 FERC ¶ 61,127 (2011) (“Order No. 733-A”);
clarified, Order No. 733-B, 136 FERC ¶ 61,185 (2011) (“Order No. 733-B”).
6
Order No. 733 at P 152.
2
1
reasonable, not unduly discriminatory or preferential, and in the public interest.7 NERC also
requests approval of: (i) the Implementation Plan (Exhibit B) for the proposed Reliability
Standard; and (ii) the associated Violation Risk Factors (“VRFs”) and Violation Severity Levels
(“VSLs”) (Exhibits A and F). The NERC Board of Trustees adopted proposed Reliability
Standard PRC-026-1 on December 17, 2014.8
As required by Section 39.5(a)9 of the Commission’s regulations, this petition presents
the technical basis and purpose of proposed Reliability Standard PRC-026-1,10 a summary of the
development history (Exhibit G), and a demonstration that the proposed Reliability Standard
meets the criteria identified by the Commission in Order No. 67211 (Exhibit C).
Below, NERC also provides the following information for background purposes prior to
providing the technical basis for NERC’s proposed Reliability Standard in Section VI:
1) a summary of the role of stable power swings in the August 14, 2003 blackout in
the United States and Canada (“2003 Blackout”) as originally provided by the
joint U.S.-Canada Task Force established to investigate the causes of the 2003
Blackout (“Task Force”);
7
Unless otherwise designated, capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards (“NERC Glossary of Terms”), available at
http://www.nerc.com/files/Glossary_of_Terms.pdf.
8
See Draft Minutes - Board of Trustees Meeting – Dec. 17, 2014, available at
http://www.nerc.com/gov/bot/Pages/Agenda-Highlights-and-Minutes-.aspx. Minutes for the December 17, 2014
conference call were not yet available at the time of filing. The agenda package for the meeting is available at the
same link.
9
18 C.F.R. § 39.5(a) (2014).
10
Pursuant to Section 215(d)(2) of the FPA, 16 U.S.C. § 824o(d)(2), and Section 39.5(c), 18 C.F.R. §
39.5(c)(1), 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.
11
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
2
2) a summary of the Order No. 733 regulatory proceeding in which the Commission
issued its directive; and
3) a summary of NERC’s informational filing12 (“Informational Filing”) in the Order
No. 733 proceeding, which clarified the role of stable power swings in the 2003
Blackout.
I.
Notices and Communications
Notices and communications with respect to this filing may be addressed to the
following:13
Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Associate General Counsel
William H. Edwards*
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
II.
Valerie L. Agnew*
Director of Standards
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
[email protected]
Summary
On March 18, 2010, in Order No. 733, the Commission approved Reliability Standard
PRC-023-1 (Transmission Relay Loadability) and directed NERC to develop a new Reliability
12
NERC Jul. 21, 2011 Informational Filing in Response to Order 733-A on Rehearing, Clarification, and
Request for an Extension of Time, Docket No. RM08-13-000, available at http://www.nerc.com/FilingsOrders/
us/NERC%20Filings%20to%20FERC%20DL/Informational_Filing_on_Order_733-A.pdf.
13
Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2014), to allow the inclusion
of more than two persons on the service list in this proceeding.
3
Standard that requires the use of protective relay systems that can differentiate between faults
and stable power swings and retirement, when necessary, of protective relay systems that cannot
meet this requirement.14 In its Notice of Proposed Rulemaking (“NOPR”) preceding its Order,15
the Commission cited the findings of the Task Force’s final report16 (“Final Blackout Report”)
on the causes of the 2003 Blackout.17 The Commission explained that the cascade during the
2003 Blackout was accelerated by zone 3/zone 2 relays that operated because they could not
distinguish between a dynamic, but stable power swing and an actual fault.18 The Commission
therefore directed NERC to develop a Reliability Standard addressing undesirable relay
operation due to stable power swings.19
Proposed Reliability Standard PRC-026-1 meets this directive from Order No. 733 by
helping to prevent the unnecessary tripping of Bulk Electric System Elements in response to
stable power swings. As explained in NERC’s Informational Filing20 and in detail in Section
IV.B below, the fourteen lines associated with the 2003 Blackout discussed in Order No. 733 and
in the Final Blackout Report by the Task Force did not trip due to stable power swings.
Nonetheless, it is important for power system reliability that protection systems are secure to
prevent undesired operation during stable power swings while allowing a dependable means to
separate the system in the event of an unstable power swing.
14
Order No. 733 at P 150.
Transmission Relay Loadability Reliability Standard, Notice of Proposed Rulemaking, 127 FERC ¶ 61,175
(2009) (“Order No. 733 NOPR”).
16
U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the
United States and Canada: Causes and Recommendations (Apr. 2004), available at http://energy.gov/sites/
prod/files/oeprod/DocumentsandMedia/BlackoutFinal-Web.pdf.
17
Order No. 733 NOPR at PP 52-54.
18
Order No. 733 at P 130.
19
Id. P 152.
20
Informational Filing at 4-5.
15
4
The proposed Reliability Standard aims to improve reliability by ensuring that relays are
expected to not trip in response to a stable power swing during non-Fault conditions in the
future. The proposed Reliability Standard requires at-risk Elements to be identified by the
Planning Coordinator and the respective Generator Owners and Transmission Owners to be
notified of the Elements. Generator Owners and Transmission Owners that apply loadresponsive protective relays (identified in Attachment A of the proposed Reliability Standard)
must determine whether their relays meet certain criteria (Attachment B of the proposed
Reliability Standard). Additionally, a subsequent determination must be made if the relays have
not been evaluated according to the Attachment B criteria in the last five calendar years for
Elements identified by the Planning Coordinator. This provides assurance that relays will
continue to be secure for stable power swings if any changes in system impedance occur. If
relays do not meet the proposed Attachment B criteria, the applicable Generator Owner and
Transmission Owner must develop and implement a Corrective Action Plan to modify the
Protection System so that the relays meet the criteria. The proposed Reliability Standard was
developed with input from the NERC Planning Committee’s System Protection and Control
Subcommittee (“SPCS”). The SPCS, with support from the System Analysis and Modeling
Subcommittee (“SAMS”), issued a report, Protection System Response to Power Swings21
(“PSRPS Report”), which provided technical information and recommendations for a proposed
Reliability Standard. The proposed Reliability Standard approach is consistent with those
recommendations.
Below, NERC provides a technical overview of stable power swings, background
information on the 2003 Blackout along with subsequent technical analysis, the regulatory
21
See Ex. E, NERC SPCS, Protection System Response to Power Swings, August 2013.
5
history of Order No. 733, a summary of the PSRPS Report, and justification for the approval of
the proposed Reliability Standard and its Requirements.
III.
Technical Overview
Provided below is a high-level technical overview of the general characteristics of stable
power swings and protection system attributes related to power swings to assist in understanding
the technical issues that will be discussed in the background material and in NERC’s
presentation of the proposed Reliability Standard. This information was developed by the SPCS
and adapted for this summary. The discussion is included in Appendices A and B of the PSRPS
Report in Exhibit E.22
1.
Stable Power Swings
The electric power grid, consisting of generators connected to loads via transmission
lines, is constantly in a dynamic state as generators automatically adjust their output to satisfy
real and reactive power demand. During steady‐state operating conditions, a balance exists
between the power generated and the power consumed. In the balanced system state, each
generator in the system maintains its voltage at an appropriate level for conditions on the system
and each machine’s internal machine rotor angle in relation to the other generators is dictated by
the dispatched power flows across the system.
Sudden changes in electrical power caused by power system faults, line switching,
generator disconnection, or the loss or connection of large blocks of load, disturb the balance
between the mechanical power into and the required electrical power output of generators. This
causes acceleration or deceleration of the generating units because the mechanical power input
responds more slowly than the generator electrical power. Such system disturbances cause the
22
Ex. E PSRPS Report, Appendix A at 25 and Appendix B at 29.
6
machine rotor angles of the generators to swing or oscillate with respect to one another in the
search for a new equilibrium state. During this period, power system Elements will experience
power swings. A power swing is “[a] variation in three phase power flow which occurs when the
generator rotor angle differences are advancing or retarding relative to each other in response to
changes in load magnitude and direction, line switching, loss of generation, faults, and other
system disturbances.”23 Swings can be stable or unstable, depending of the severity of the
disturbance.
In a stable power swing, the power system will return to a new equilibrium state where
the generator machine rotor angle differences are within stable operating range to generate power
that is balanced with the load. In an unstable power swing, the generation and load do not find a
balance and the machine rotor angles between generators or coherent groups of generators
continue to increase, eventually leading to loss of synchronism between generators or coherent
groups of generators. The location where loss of synchronism occurs is based on the physical
attributes of the system, such as, what generation and transmission is in service and the nature of
the disturbance. When synchronism is lost between areas, this is referred to as an out‐of‐step
condition.
2.
Protection System Attributes Related to Power Swings
To maintain the reliability of the Bulk-Power System, secure protective relay settings are
necessary to avoid relay operation during stable power swings and provide dependable tripping
for faults and unstable power swings. A Protection System is required to detect line faults and
trip appropriately. During power swing conditions where generation, transformer, and
See IEEE Power System Relaying Committee, Working Group D‐6, Power Swing and Out‐of‐Step
Considerations on Transmission Lines, at 6, available at http://www.pes-psrc.org/Reports/Power%20Swing%
20and%20OOS%20Considerations%20on%20Transmission%20Lines%20F..pdf.
23
7
transmission line protection should not operate, i.e., if the power swing is stable, the unnecessary
loss of power system Elements could exacerbate the power swing to the extent that a stable
swing becomes unstable. In this case, the relevant protective relays should be set to not operate
in response to the stable power swing condition. This may be achievable by use of a Protection
System immune to power swings, selection of the settings not susceptible to stable power
swings, or use of dedicated logic to block operation during power swings.
IV.
2003 Blackout and Regulatory History
A.
2003 Blackout
In the 2003 Blackout, large portions of the Midwest and Northeast United States and
Ontario, Canada, experienced an electric power blackout. Following the event, the Task Force
investigated the causes and how to reduce the possibility of future outages. The Task Force’s
work was divided into two phases:
•
Phase I: Investigate the outage to determine its causes and why it was not
contained.
•
Phase II: Develop recommendations to reduce the possibility of future outages
and minimize the scope of any that occur.24
In November 2003, the Task Force issued the Interim Blackout Report, describing its
investigation and findings and identifying the causes of the 2003 Blackout.25 In the Final
Blackout Report, the Task Force reaffirmed the findings stated in the Interim Blackout Report
that the initiating causes of the 2003 Blackout were: 1) lost functionality of critical monitoring
tools, resulting in loss of situational awareness of degraded conditions on the transmission
system; 2) inadequate management of tree growth on transmission line rights-of-way; 3)
24
See U.S.-Canada Power System Outage Task Force, Interim Report: Causes of the August 14th Blackout in
the United States and Canada at 1 (Nov. 2003) (“Interim Blackout Report”) (describing the work of the Task
Force), available at http://emp.lbl.gov/sites/all/files/interim-rpt-Aug-14-blkout-03.pdf.
25
Id.
8
inadequate diagnostic support for a reliability coordinator tools; and 4) that coordination between
reliability coordinators was ineffective. The Final Blackout Report indicated that fourteen lines
tripped by zone 2 and zone 3 relays “after each line overloaded.”26 The investigation team
concluded that because these zone 2 and 3 relays tripped after each line overloaded, these relays
were the common mode of failure that accelerated the geographic spread of the cascade.27 The
Task Force stated that “although the operation of zone 2 and 3 relays in Ohio and Michigan did
not cause the blackout, it is certain that they greatly expanded and accelerated the spread of the
cascade.”28
B.
Regulatory History
1.
Order No. 733
On March 18, 2010, the Commission issued Order No. 733, approving Reliability
Standard PRC-023-1 (Transmission Relay Loadability) and directing NERC to develop a new
Reliability Standard that requires the use of protective relay systems that can differentiate
between faults and stable power swings and retirement, when necessary, of protective relay
systems that cannot meet this requirement.29 The Commission found that undesirable relay
operation due to stable power swings is a specific matter that must be addressed by NERC and
that NERC’s standard must address this concern.30 In its determination, the Commission
reiterated the findings of the 2003 Blackout Task Force that the inability of zone 2 and zone 3
26
27
28
29
30
Final Blackout Report at 80.
Id.
Id. at 82.
Order No. 733 at P 150.
Id. at P 152.
9
relays to distinguish between a dynamic, but stable power swing and an actual fault contributed
to the cascade.31
Various entities submitted comments to the NOPR preceding Order No. 733.32 In its
comments, NERC stated that while it is possible to employ protection systems that are immune
from stable power swings, use of these systems should not be favored at the expense of
diminishing the ability of protective relays to dependably trip for faults or detect unstable power
swings. Other commenters argued that stable power swings were not the root cause of the
cascading outages. Entities stated, among other things, that relay performance during stable
power swings is outside the scope of relay loadability, that one company’s stability studies have
not identified any of its lines that would trip from stable power swings, and that PRC-023-1
indirectly addresses the Commission’s concern. One entity even argued that the Commission’s
directive would harm reliability by phasing out certain relays, leaving the electric system without
any reliable backup for transmission lines with failed communication or other equipment
failures, thereby exposing the system to faults that cannot be cleared and potentially resulting in
larger outages and/or equipment damage. Ultimately, the Commission was not persuaded,33
although the Commission did agree with one commenter that argued that “islanding” strategies
in conjunction with out-of-step34 blocking (or tripping)35 requirements should be considered in
the proposed Reliability Standard.
31
Id.
See Order No. 733 at PP 131-49.
33
See generally id. at PP 150-73.
34
An out-of-step condition is the same as an unstable power swing. See IEEE Power System Relaying
Committee, Working Group D‐6, Power Swing and Out‐of‐Step Considerations on Transmission Lines, at 4,
available at http://www.pes-psrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20
Transmission%20Lines%20F..pdf.
35
Out-of-step tripping schemes are designed to protect the power system during unstable conditions, isolating
generators or larger power system areas from each other with the formation of system islands, in order to maintain
stability within each island by balancing the generation resources with the area load. Id. at 24.
32
10
2.
Order No. 733-A
In response to the directive in Order No. 733 related to stable power swings, several
organizations sought rehearing. Requesters contended that the Commission’s directive is
ambiguous and that the record did not support issuance of the directive. Others, including
NERC, cautioned that the use of protection that differentiates between faults and stable swings
might result in less stability because of a decreased ability to identify unstable swings. NERC
also sought clarification that it can use its industry technical experts to appropriately address the
issue of stable power swings and that the directive was not intended to create an absolute
requirement to highlight a concern that other approaches might satisfy.
FERC issued Order No. 733-A on February 17, 2011, denying these requests for
rehearing and maintaining its position that a Reliability Standard to address stable power swings
is necessary for reliability of the Bulk-Power System.36 In that Order, the Commission
emphasized that it “did 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.”37 The Commission also clarified that it did not require an
across-the-board elimination of all zone 3 relays, but only the creation of a Reliability Standard
that addresses Protection Systems vulnerable to stable power swings (resulting from Category B
and Category C contingencies from the NERC Planning Standards in place at that time) that will
result in inappropriate tripping.38
36
Transmission Relay Loadability Reliability Standard, Order No. 733, 130 FERC ¶ 61,221 (2010); order on
reh’g and clarification, Order No. 733-A, 134 FERC ¶ 61,127 (2011).
37
Id. at P 11.
38
Order No. 733-A at P 107.
11
3.
Order No. 733-B
Various trade organizations requested rehearing on Order 733-A, again reemphasizing
their concern with the Commission’s directives related to the creation of a Reliability Standard to
address stable power swings. The requestors reiterated their concerns with the actions of the
Commission and asserted that the directives were based on either a faulty understanding of the
Final Blackout Report or an incorrect characterization of relay engineering. The requestors also
repeated arguments made in the proceeding.
The Commission issued Order No. 733-B on September 15, 2011. In that Order, the
Commission ruled that the issues raised had been addressed in both Order Nos. 733 and 733-A,
and that further clarification was not necessary.39
4.
NERC Informational Filing
After the issuance of Order No. 733-A, NERC submitted an Informational Filing to the
Commission addressing certain aspects of 2003 Blackout investigation relative to operation of
protective relays in response to stable power swings. Some of the clarifications in the NERC
Informational Filing were documented in the Final Blackout Report, while other clarifications
were based on unpublished findings of the blackout investigation team derived from detailed
analyses that occurred subsequent to the issuance of the Final Blackout Report.
Order 733-A discussed tripping of fourteen transmission lines to support the directive
pertaining to conditions in which relays misoperate due to stable power swings that were
identified as propagating the cascade during the 2003 Blackout. The NERC Informational Filing
clarified that all of these fourteen lines did not trip due to stable power swings. Ten of these
lines tripped by zone 2 and zone 3 relays after each line overloaded in response to the steady-
39
Order No. 733-B at P 12.
12
state loadability issue addressed by Reliability Standard PRC-023, while the last four lines
tripped in response to dynamic instability of the power system.
That detailed subsequent analysis confirmed that ten of the line trips occurring up to and
including the time of the initial trips of the Argenta – Battle Creek and the Argenta – Tompkins
345 kV lines occurred as a result of increasingly heavy line loading. NERC stated that the relays
on those lines reacted as though there was a fault in their protective zone when there was no
fault. Such behavior is related to the steady-state loadability issue addressed by Reliability
Standard PRC-023. Line trips following the initial trips of Argenta – Battle Creek and Argenta –
Tompkins lines were verified by those simulations and analysis of relay performance to be
associated with high-speed dynamic instability during the system collapse.
Although the fourteen line trips by zone 2 and zone 3 relays discussed in the Final
Blackout Report did not occur because of stable power swings, the Task Force did identify two
other transmission lines that tripped on zone 1 relays due to protective relay operation in
response to power swings.40 The Task Force identified these lines as the Homer City –
Watercure 345 kV line and the Homer City – Stolle Road 345 kV line. NERC explained in its
Informational Filing that as the dynamic instability propagated across the system, a system
separation occurred along the border between New York and the PJM Interconnection. Two
swings occurred between the two systems. The first swing occurred at approximately 16:10:39.5
corresponding with tripping of the Homer City – Watercure and Homer City – Stolle Road 345
kV transmission lines. The second swing occurred approximately four seconds later
corresponding with the New York-PJM separation completed by the Branchburg – Ramapo 500
kV trip. The Task Force performed a sensitivity analysis without tripping of the Homer City
40
Final Blackout Report at 89. Although NERC noted in its Informational Filing that these trips were due to
stable power swings, the Final Blackout Report does not use the term “stable” to describe the type of power swing.
13
lines to identify how the system performance might have been different if the line trips had not
occurred. The simulation demonstrates the two swings associated with the Homer City line trips
occurred on a stable power swing.
However, the simulations also indicated that the second swing between New York and
PJM would have resulted in a loss of synchronism between the two systems regardless of
whether the Homer City lines had tripped on the first swing. The simulation also indicated that
the sequence of events following separation of the New York and PJM systems would have
essentially the same end result, including the subsequent separations between New York and
New England, western and eastern New York, and Ontario and western New York.
Since the New York and PJM separation and subsequent system separations would have
occurred regardless of whether the Homer City – Watercure and Homer City – Stolle Road lines
tripped on the stable swing, NERC concluded that the Protection System operations on these
lines did not contribute significantly to the overall outcome of the 2003 Blackout.
However, NERC reiterated in the Informational Filing that Protection System operation
during stable power swings could negatively impact system reliability under different operating
conditions and that NERC supports the reliability objective associated with developing a
standard to address operation of protective relays in response to stable power swings.
V.
NERC Activity to Address the Directive
A.
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
To respond to the directives in Order No. 733, NERC initiated a three-phased Project
2010-13. Phase I focused on making specific modifications to PRC-023-1 identified in Order
No. 733. In Phase I, NERC developed Reliability Standard PRC-023-2, which was subsequently
14
approved by FERC in Order No. 759.41 In Phase II, NERC developed new Reliability Standard
PRC-025-1 to address generator relay loadability and aligning changes to the transmission
loadability standard resulting in PRC-023-3. The Commission approved PRC-023-3 and PRC025-1 in Order No. 799.42 Phase III of the Project focused on developing proposed Reliability
Standard PRC-026-1 to address the Commission’s concerns regarding undesirable protective
relay operations due to stable power swings.
B.
PSRPS Report
To support Project 2010-13.3, the SPCS, with support from the SAMS, developed the
PSRPS Report to promote understanding of the overall concepts related to the nature of power
swings; the effects of power swings on protection system operation; techniques for detecting
power swings and the limitations of those techniques; and methods for assessing the impact of
power swings on protection system operation. Based on its review of historical events,43
consideration of the trade‐offs between dependability and security, and recognizing the indirect
benefits of implementing the transmission relay loadability standard (PRC‐023), the SPCS
concluded that a NERC Reliability Standard to address relay performance during stable power
swings was not needed, and could result in unintended adverse impacts to Bulk‐Power System
reliability.
However, the SPCS provided recommendations for the creation of a Reliability Standard
in recognition of the Commission directive in the event NERC proceeded with development.
The proposed Reliability Standard developed by the standard drafting team is based on and is
41
Transmission Relay Loadability Standard, Order No. 759, 138 FERC ¶ 61,197 (2012).
Generator Relay Loadability and Revised Transmission Relay Loadability Reliability Standards, Order No.
799, 148 FERC ¶ 61,042 (2014).
43
As part of this assessment, the SPCS reviewed six of the most significant system disturbances that have
occurred since 1965 and concluded that operation of transmission line Protection Systems during stable power
swings was not causal or contributory to any of these disturbances. See PSRPS Report at 7-17.
42
15
consistent with the recommendations found in the PSRPS Report. The following summary of
the PSRPS Report provides the SPCS’s position on the role of stable power swings in the 2003
Blackout. NERC also provides an explanation by SPCS of the trade-off between dependability
and security, and a summary of the SPCS’s recommendations related to the creation of a
proposed Reliability Standard related to stable power swings.
1.
2003 Blackout Comments
With respect to the 2003 Blackout, the PSRPS Report stated that although it might be
reasonable, based on the Final Blackout Report, to conclude stable power swings was a causal
factor on August 14, 2003, subsequent analysis clarified the line trips that occurred prior to the
system becoming dynamically unstable were a result of steady‐state relay loadability. The SPCS
explained that the causal factors in these disturbances included weather, equipment failure, relay
failure, steady‐state relay loadability, vegetation management, situational awareness, and
operator training. However, the SPCS noted that while tripping on stable swings was not a
causal factor, unstable swings caused system separation during several of these disturbances.
Therefore, it is possible, according to the SPCS, that the scope of some events may have been
greater without dependable tripping on unstable swings to physically separate portions of the
system that lost synchronism.
2.
Dependability vs. Security
The PSRPS Report explained that secure and dependable operation of protection systems
are both important to power system reliability. A summary of the SPCS discussion of the tradeoffs between dependability and security is provided to explain why the SPCS recommended an
approach in a draft standard that favors dependability over security. The SPCS stated that to
support power system reliability, it is desirable that protection systems are secure to prevent
16
unnecessary operation during stable power swings. It also is desirable to provide dependable
means to separate the system in the event of an unstable power swing. The PSRPS Report
continued that while methods for discriminating between stable and unstable power swings have
improved over time, ensuring both secure and dependable operation for all possible system
events remains a challenge.
The SPCS cautioned that the directive in Order No. 733 is focused on protective relays
operating unnecessarily due to stable power swings and that it is important, in the process of
achieving this goal, not to decrease the ability to dependably identify unstable power swings and
separate portions of the system that have lost synchronism. The SPCS continued that application
of protection systems that can discriminate between fault and power swing conditions at
locations where the system may be prone to unstable power swings does not provide a
dependable means of separating portions of the system that lose synchronism. Where this
occurs, it would be necessary to install out‐of‐step protection to initiate system separation, which
reintroduces the need to discriminate between stable and unstable power swings. The SPCS
stated that a lack of dependability is more likely to result in an undesirable outcome. For
example, with an unstable power swing, a failure to trip will result in portions of the system
slipping poles44 against each other and resultant increased equipment stress and an increased
probability of system collapse.
44
A pole slip is a condition whereby a generator, or group of generators, terminal voltage angles (or phases)
go past 180 degrees with respect to the rest of the connected power system. IEEE Power System Relaying
Committee, Working Group D‐6, Power Swing and Out‐of‐Step Considerations on Transmission Lines, July 2005,
available at http://www.pes-psrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20
Transmission%20Lines%20F..pdf.
17
3.
Recommendations for the Design of a Reliability Standard
While the SPCS recommended that a Reliability Standard is not needed, the SPCS
recognized the directive in FERC Order No. 733 and the NERC Standards Committee request for
research to support Project 2010‐13.3. The SPCS explained that two options exist for developing
requirements for secure operation of protection systems during power swings: (i) develop
requirements applicable to protection systems on all circuits, or (ii) identify the circuits on which
a power swing may affect protection system operation and develop requirements applicable to
protection systems on those specific circuits, similar to the approach used in standard PRC-023.
The SPCS stated that an approach covering each circuit would be a significant effort with
varying results that are dependent on the system topology and the assumptions specified for the
analysis.
As a result, the SPCS recommended that if a standard is developed, the most effective
and efficient use of industry resources would be to limit applicability to protection systems on
circuits where the potential for observing power swings has been demonstrated through system
operating studies, transmission planning assessments, event analyses, and other studies that have
identified locations at which a system separation may occur. The SPCS also proposed, as a
starting point for a standard drafting team, criteria to determine the circuits to which the standard
should be applicable, as well as methods that entities could use to demonstrate that protection
systems on applicable circuits are set appropriately to mitigate the potential for operation during
stable power swings.
VI.
Justification for Approval
Proposed Reliability Standard PRC-026-1 is responsive to the Commission’s directive in
Order No. 733 and is just, reasonable, not unduly discriminatory or preferential, and in the public
18
interest. As discussed below and specifically in Exhibit C, the proposed Reliability Standard
satisfies the Commission’s criteria in Order No. 672. The following section explains NERC’s
development of its alternative45 approach to the Commission’s suggested direction for the
proposed Reliability Standard. It also explains the purpose and benefit of proposed Reliability
Standard PRC-026-1 to reliability and provides a description of and the technical basis for the
proposed Requirements. Finally, this section includes a discussion of the enforceability of the
proposed Reliability Standard.
A.
NERC’s Approach to Meet the Directive
As noted above, the fourteen lines associated with the 2003 Blackout discussed in Order
No. 733 did not trip due to stable power swings. NERC explained in its Informational Filing that
ten of these lines tripped in response to the steady-state loadability issue addressed by Reliability
Standard PRC-023, while the last four lines tripped in response to dynamic instability of the
power system. However, as noted in NERC’s Informational Filing, two other transmission lines
tripped due to protective relay operation in response to stable power swings. Analysis showed
that had these relays not tripped on the initial stable power swings, the next power swings would
have been unstable and tripped the relays. As a result, not tripping in response to the stable
power swings, which is the focus of the Commission’s directive, would not have arrested the
collapse of the Bulk-Power System during the 2003 Blackout.
In Order No. 733-B, which came after NERC’s Informational Filing, the Commission
again reaffirmed its prior directive when challenged on the technical justification for the
45
As clarified in Order No. 733-A, the Commission states that its directive is for the creation of a Reliability
Standard that addresses Protection Systems vulnerable to stable power swings that will result in inappropriate
tripping. Order No. 733-A at P 107. NERC’s proposed Reliability Standard is directly responsive to the
Commission’s directive, as clarified. As a result, NERC is not necessarily proposing its Reliability Standard as an
“equally effective and efficient alternative” to the Commission’s suggested approach to employ specific relays that
can differentiate between faults and stable power swings to meet the Commission’s concern.
19
directive related to stable power swings. In its determination, the Commission cited the tripping
of the Homer City – Watercure and Homer City – Stolle Road 345 kV transmission lines due to
protective relay operation in response to stable power swings as justification for reaffirming its
original Order No. 733 directive in response to technical challenges by trade associations.46
While the technical justification for the directive has been questioned by the follow-up analysis
to the Final Blackout Report, in its filings in the Order No. 733 proceeding, NERC did
acknowledge the Commission’s concern that protection system operation during stable power
swings could negatively impact system reliability under different operating conditions. NERC
continues to hold that it remains important for power system reliability that protection systems
are secure to prevent undesired operation during stable power swings and to provide dependable
means to separate the system in the event of an unstable power swing.
In response to the Commission’s directive, this proposed Reliability Standard improves
reliability by ensuring that relays are expected to not trip in response to stable powers swing
during non-Fault conditions in the future. The standard drafting team based the development of
the proposed Reliability Standard on the recommended approach provided in the PSRPS Report
to meet the directive.
The PSRPS Report recommended the following criteria in establishing the applicability
of the Reliability Standard to limit applicability to only those transmission lines on which
protective relays are most likely to be challenged during stable power swings: (i) lines
terminating at a generating plant, where a generating plant stability constraint is addressed by an
operating limit or Special Protection System (SPS) (including line‐out conditions), (ii) lines that
are associated with a System Operating Limit (SOL) that has been established based on stability
46
Order No. 733-B at P 72, n.108.
20
constraints identified in system planning or operating studies (including line‐out conditions), (iii)
lines that have tripped due to power swings during system disturbances, (iv) lines that form a
boundary of the Bulk Electric System that may form an island, and (v) lines identified through
other studies, including but not limited to, event analyses and transmission planning or
operational planning assessments.47 The standard substantively adopted the five criteria above as
recommended by the PSRPS Report, adding generator and transformer Elements in addition to
transmission lines and limited the fifth criteria to transmission Planning Assessments.
Operational planning assessments were not included as a criteria for identifying Elements
because addressing at-risk Elements should be performed in the planning horizon through
Planning Assessments by the Planning Coordinator which has a wide-area view of the system,
and where corrective actions can be identified and implemented before entering the operating
timeframe. Operations planning assessments are generally performed in the operations horizon
by the Reliability Coordinator. In addition, event analyses were not included because actual
disturbances and the event analyses are typically addressed by the owners of the applicable
Elements, not the Planning Coordinator.
The standard drafting team agreed with the PSRPS Report that focusing the applicability
of the standard to Elements meeting a select set of criteria provides a number of benefits. For
example, the efforts of the applicable entities is more focused on the Elements having the
greatest risk of being challenged by power swings. The PSRPS Report further suggested that
certain entities could use the focused criteria in creating the possibility to include dynamic
simulations assessing a greater number of fault types and system configurations; however, the
standard drafting team implemented the following alternative approach.
47
PSRPS Report at 21.
21
The PSRPS Report acknowledged that it may be possible, subject to relay model
availability, to model specific relay settings in the dynamic simulation software, to more
precisely identify the likelihood of a stable swing entering the relay characteristic. Although
precise for the contingency under study, the standard drafting team determined that performing
such dynamic simulations would be burdensome, highly variable and dependent on the
contingency selected by the planner. As an alternative approach to dynamic simulations to
produce the apparent impedance for relay owners, the standard requires that the owners of loadresponsive protective relays to evaluate their relay characteristics to specific criteria provided in
Attachment B of the proposed Reliability Standard. This method provides a consistent approach
for determining whether the relay for an identified Element is at-risk to tripping in response to a
stable power swing. If the relay is at-risk, the relay owner is required to develop and implement
a Corrective Action Plan to modify the Protection System so that the relays meet the criteria and,
therefore, are expected to not trip in response to stable power swings during non-Fault
conditions.
The SPSC Report further recommended that each facility owner to document its basis for
applying protection to each of its applicable Elements (as identified above), and provide this
information to its Reliability Coordinator, Planning Coordinator, and Transmission Planner.
Furthermore, subsequent requirements should include all entities responsible for assessing
dynamic performance of the Bulk‐Power System.48 The Reliability Coordinator has
responsibility for operating studies and the Planning Coordinator and Transmission Planner have
responsibility for transmission Planning Assessments. Although this approach increases
communication among entities, it adds unnecessary requirements to achieve the purpose of the
48
PSRPS Report at 22.
22
proposed Reliability Standard. The proposed Reliability Standard’s approach of notifying the
owners of protective relays for Elements meeting specific criteria is the most efficient and
effective manner to ensure at-risk protective relays are evaluated, and where necessary, modified
such that the relays are expected to not trip in response to stable power swings during non-Fault
conditions.
Islanding strategies, as directed by Order No. 733,49 were considered during the
development of the proposed standard. The standard drafting team determined that islanding
strategies are not an appropriate method to meet the purpose and intent of the proposed standard.
For example, islanding strategies are developed to isolate the system from unstable power
swings, which is not prohibited under the proposed standard. The proposed standard’s intent is
to ensure that load-responsive protective relays are expected to not trip in response to stable
power swings during non-Fault conditions, while maintaining dependable fault detection and
dependable out-of-step tripping (if out-of-step tripping is applied at the terminal of the BES
Element).
NERC’s proposed Reliability Standard is directly responsive to the specific matter the
Commission directed NERC to address in Order No. 733 — to develop a Reliability Standard
addressing undesirable relay operation due to stable power swings.50 However, the proposed
Reliability Standard includes an alternative to the Commission’s approach to require “the use of
protective relay systems that can differentiate between faults and stable power swings and, when
necessary, phases out protective relay systems that cannot meet this requirement.”51
49
50
51
Order No. 733 at P 162.
Id. P 153.
Id. P 150.
23
The proposed Reliability Standard appropriately narrows the applicable Facilities to
generator, transformer, and transmission line Bulk Electric System Elements identified by the
Planning Coordinator using specific criteria for determining which Bulk Electric System
Elements could be at-risk to power swings, similar to the criteria used determine the applicability
of PRC-023, and by the Generator Owner and Transmission Owner upon becoming aware of
Bulk Electric System Elements that actually trip in response to power swings. Additionally, the
Applicability section of the proposed Standard only includes those protective systems that are
not immune to operating in response to power swings. This includes load-responsive protective
relays associated with backup protection for the applicable Element meeting the proposed
Reliability Standard’s criteria, without regard to the various zones of protection, when the relay
has an intentional time delay of less than 15 cycles or no time delay (i.e., instantaneous).
The standard drafting team did not adopt the Commission’s approach requiring the use of
protective relay systems that can differentiate between faults and stable power swings and, when
necessary, phasing out protective relay systems that cannot meet this requirement. Given the
relative risks associated with a lack of dependable operation for unstable power swings and the
lack of secure operation for stable swings, it is generally preferable to emphasize dependability
over security when it is not possible to ensure both for all possible system conditions.
Prohibiting use of certain types of relays, such as those protective relay systems that cannot
differentiate between faults and stable power swings, may have unintended negative outcomes
for Bulk‐Power System reliability. It is important to note that NERC’s proposed Reliability
Standard does not restrict or discourage entities from employing any technically viable solutions.
This is evident in development of a Corrective Action Plan in Requirement R3 that allows the
protective relay owner to either modify the existing Protection System to meet the Attachment B
24
criteria or to exclude the existing Protection System under Attachment A by applying power
swing blocking supervision to relay functions. The protective relay owner has the option to
replace the protection system with protective functions that are immune to power swings. This
approach also addresses the comment, summarized above, in the Order No. 733 proceeding that
stated phasing out certain relays would leave the electric system without any reliable backup for
transmission lines, thereby exposing the system to faults that cannot be cleared and potentially
result in larger outages and/or equipment damage.
B.
Proposed Reliability Standard PRC-026-1
1.
Purpose and Reliability Benefit of Proposed PRC-026-1
The purpose of proposed Reliability Standard PRC-026-1 is “[t]o ensure that loadresponsive protective relays are expected to not trip in response to stable power swings during
non-Fault conditions.” The reliability goal of the proposed Reliability Standard is to reduce or
eliminate unnecessary tripping of Bulk Electric System Elements in response to stable power
swings. The proposed Reliability Standard requires at-risk Elements to be identified using
specific criteria by the Planning Coordinator and the respective Generator Owners and
Transmission Owners to be notified of the Elements. Generator Owners and Transmission
Owners that apply load-responsive protective relays (identified in Attachment A of proposed
PRC-026-1) must determine whether their relays meet certain criteria (Attachment B of proposed
PRC-026-1), if the relays had not been evaluated according to the Attachment B criteria in the
last five calendar years. This ensures that relays will continue to be secure for stable power
swings if any changes in system impedance occur. Additionally, if a Generator Owner or
Transmission Owner identifies an Element as having tripped in response to a power swing, it
25
must determine whether the relays meet the Attachment B criteria regardless of any previous
evaluation using the criteria.
If relays do not meet the Attachment B criteria, the applicable Generator Owner and
Transmission Owner must develop and implement a Corrective Action Plan to modify the
Protection System so that the relays meet the criteria. Actions could include changes in relay
settings, modification of the Protection System to meet the criteria, replacement of the Protection
System to meet the criteria, or modification of the Protection System to exclude the relay from
the coverage of the proposed Reliability Standard according to exclusions in the proposed
Attachment A. Below, NERC provides an in-depth discussion the proposed Reliability Standard.
NERC notes that while some information is included below, the standard drafting team has
included extensive Application Guidelines within the proposed Reliability Standard, which
provide additional detail and examples to assist the Commission in its evaluation of the proposed
Reliability Standard (see Exhibit A).
2.
Applicable Entities
4.1. Functional Entities:
4.1.1 Generator Owner that applies load-responsive
protective relays as described in PRC-026-1 – Attachment
A at the terminals of the Elements listed in Section 4.2,
Facilities.
4.1.2 Planning Coordinator.
4.1.3 Transmission Owner that applies load-responsive
protective relays as described in PRC-026-1 – Attachment
A at the terminals of the Elements listed in Section 4.2,
Facilities.
4.2. Facilities: The following Elements that are part of the Bulk
Electric System (BES):
4.2.1 Generators.
4.2.2 Transformers.
4.2.3 Transmission lines.
26
The proposed PRC-026-1 is applicable to Planning Coordinators. This inclusion is
consistent with the recommendations in the PSRPS Report. The PSRPS Report also suggested
inclusion of the Reliability Coordinator and Transmission Planner. The standard drafting team
did not include these entities in the proposed Reliability Standard’s Applicability. The standard
drafting team determined that a single entity, the Planning Coordinator, should be the source for
identifying Elements according to Requirement R1. A single source will insure that multiple
entities will not identify Elements in duplicate, nor will one entity fail to provide an Element
because it believes the Element is being provided by another entity. The Planning Coordinator
has, or has access to, the wide-area model(s), which may be used to identify Elements according
to the criteria in Requirement R1.
Use of the Planning Coordinator as the single identifying entity is also consistent with the
NERC Functional Model.52 Under the NERC Functional Model, Planning Coordinators work
through a variety of mechanisms to conduct facilitated, coordinated, joint, centralized, or
regional planning activities to the extent that all network areas with little or no ties to others’
areas, such as interconnections, are completely coordinated for planning activities. The Planning
Coordinator coordinates and collects data for system modeling from Transmission Planners and
other Planning Coordinators, and coordinates plans with Reliability Coordinators and other
Planning Coordinators on reliability issues. Additionally, the Planning Coordinator collects
information including Transmission facility characteristics and ratings from the Transmission
Owners and Transmission Planner in addition to performance characteristics and capabilities of
generator units from Generator Owners. Planning Coordinators submit and coordinate the plans
52
See NERC Reliability Functional Model: Function Definitions and Functional Entities, Version 5, available
at http://www.nerc.com/pa/Stand/Functional%20Model%20Archive%201/Functional_Model_V5_Final_
2009Dec1.pdf.
27
for the interconnection of facilities to the Bulk Electric System, which are under the purview of
the proposed Requirement R1 criteria, within its Planning Coordinator area with Transmission
Planners and adjacent Planning Coordinator areas. The proposed Requirement R1 criteria
include conditions related to identified System Operating Limits determined by the Planning
Coordinator pursuant to Requirement R3 in Reliability Standard FAC-014-2 (Establish and
Communicate System Operating Limits).
The Transmission Planner develops a long-term (generally one year and beyond) plan for
the reliability (adequacy) of the Bulk Electric System within a Transmission Planner area and
coordinate their plans with the adjoining Transmission Planners to assess impact on or by those
plans at a localized level whereas the Planning Coordinator coordinates at a regional level.
Although the Transmission Planner generally maintains transmission system models (steady
state, dynamics, and short circuit) to evaluate Bulk Electric System performance, which would
be used to identify Elements under the proposed Requirement R1 criteria, the Planning
Coordinator also has this ability or has the access to obtain the necessary information to perform
the identification of Elements according to the proposed Requirement R1 criteria.
The Reliability Coordinator maintains the Real-time operating reliability of its Reliability
Coordinator Area and includes situational awareness of its neighboring Reliability Coordinator
Areas. Because of the Real-time operating nature of the Reliability Coordinator function, it
receives operational plans from Balancing Authorities and transmission and generation
maintenance plans from Transmission Owners and Generator Owners, respectively, for
reliability analysis. Although the PSRPS Report recommended the inclusion of operating studies
(e.g., Operational Planning Analysis) in connection with its recommendation to include the
Reliability Coordinator in the approach to the standard, the standard drafting team determined
28
that operating studies are not necessary because the Planning Coordinator is in the best position
to identify at-risk Elements.
The proposed Reliability Standard is also applicable to Generator Owners and
Transmission Owners that apply load-responsive protective relays as described in PRC-026-1 –
Attachment A at the terminals of Bulk Electric System generators, transformers, and
transmission lines, as listed in Section 4.2, Facilities. The standard drafting team also considered
the Distribution Provider for inclusion in the proposed Reliability Standard as an applicable
entity; however, this entity, by functional registration, would not own generators, transmission
lines, or transformers other than load serving. Under the Functional Model, the Distribution
Provider would be registered as a Generator Owner when it owns Bulk Electric System
generators or generator step-up (GSU) transformers or registered as a Transmission Owner when
it owns Bulk Electric System transformers (i.e., related to transmission operation) or
transmission lines.
According to Attachment A, proposed PRC-026-1 applies to any protective functions that
could trip instantaneously or with a time delay of less than 15 cycles on load current (i.e., “loadresponsive”) including, but not limited to: (1) phase distance; (2) phase overcurrent; (3) out-ofstep tripping; and (4) loss-of-field. The proposed Reliability Standard addresses relays that trip
instantaneously (without an intentional time delay) regardless of the zone of protection and those
relays with a time delay less than 15 cycles.
Load-responsive protective relays that are set to trip instantaneously (without an
intentional time delay) are applicable to the Standard and any relay where an entity may have a
slight time delay which would not eliminate the susceptibility to power swings. In order to
address this additional susceptibility, the standard drafting team developed a conservative time
29
delay threshold value of 15 cycles (0.25 seconds) so that any applicable load-responsive
protective relay set with a time delay of 15 cycles or greater may be excluded from the
Applicability of the standard.
The 15 cycle or 0.25 second time delay is representative of an expected power swing
having a slow slip rate of 0.67 Hertz (Hz) and is the average time that a stable power swing with
that slip rate would enter the relay’s characteristic, reverse direction, and then exit the
characteristic before the time delay expired. The standard drafting team recognizes that the
trajectory of a stable power swing is not constant (e.g., must slow when reversing direction). In
consideration of this effect, a constant slip rate of 0.67 Hz as proposed by the standard assumes
that the angle of the power swing begins at 90 degrees (see e.g., Equation 1 of the proposed
Reliability Standard’s Application Guidelines) as a determination of the time delay (i.e., zone
timer).
A power swing having a slower slip rate of 0.25 Hz (e.g., slower than 0.67 Hz) would
increase the risk to tripping, the following is an example of a transmission relay set according to
the transmission relay loadability standard using maximum power transfer (e.g., 90 degree
system angle). A relay set to comply with the transmission loadability standard (i.e., PRC-023-3,
Requirement R1, Criteria 3, Bullet 2 ) using maximum power transfer would have a system angle
beginning at 108.8 degrees (due to the 115% multiplier) and a calculated zone timer of 14.9
cycles based upon Equation 1 (zone timer) of the proposed standard’s Application Guidelines.
Therefore, in this example, a relay that is set 15 cycles or greater (i.e., not applicable to the
standard), when challenged by a power swing with a constant slip rate of 0.67 Hz (i.e., the basis
for 15 cycles) or a slower power swing with a slip rate of 0.25 Hz (not the constant 0.67 Hz),
would achieve the reliability goal of the standard and be expected to not trip in response to the
30
stable power swing. However, any relay with a time delay of less than 15 cycles, which is based
on a power swing with a constant 0.67 Hz slip rate, is subject to the standard, and the entity
would be required to evaluate its load-responsive protective relays to determine whether the
relay meets the proposed Attachment B criteria.
Furthermore, the proposed Reliability Standard requires that relays set with a time delay
of less than 15 cycles meet the proposed Standard’s criteria for a system separation angle of at
least 120 degrees. Any relay applicable to the standard that meets the 120 degree criteria, which
is the industry-accepted maximum system separation angle from which a stable power swing
would be recoverable, along with the conditions and additional criteria listed in Attachment B,
would be expected to not trip in response to a stable power swing. Any power swing subject to a
system separation angle greater than 120 degrees is presumably unstable and beyond the scope of
the proposed standard.
A time delay threshold of 15 cycles is not intended to characterize the slip rate of all
power swings, but to address potential issues with limiting only instantaneous relays and relays
with short time delays to the Applicability of the proposed standard while remaining cognizant of
concerns raised in the PSRPS Report about potential trade‐offs between dependability and
security, and recognizing the indirect benefits of implementing the transmission relay loadability
standard (PRC‐023).
As noted above, proposed Attachment A provides clarity on which load-responsive
protective relay functions are applicable. Attachment A also includes a list of those protective
relay functions that are not applicable. Non-applicable relay functions include those functions
that are either immune to power swings, block power swings, or prevent non-immune protective
function operation due to supervision of the function.
31
3.
Requirement R1
R1. Each Planning Coordinator shall, at least once each calendar
year, provide notification of each generator, transformer, and
transmission line BES Element in its area that meets one or more
of the following criteria, if any, to the respective Generator Owner
and Transmission Owner: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
Criteria:
1. Generator(s) where an angular stability constraint exists
that is addressed by a System Operating Limit (SOL) or a
Remedial Action Scheme (RAS) and those Elements
terminating at the Transmission station associated with the
generator(s).
2. An Element that is monitored as part of an SOL
identified by the Planning Coordinator’s methodology1
based on an angular stability constraint.
3. An Element that forms the boundary of an island in the
most recent underfrequency load shedding (UFLS) design
assessment based on application of the Planning
Coordinator’s criteria for identifying islands, only if the
island is formed by tripping the Element due to angular
instability.
4. An Element identified in the most recent annual Planning
Assessment where relay tripping occurs due to a stable or
unstable2 power swing during a simulated disturbance.
Proposed Requirement R1 requires the Planning Coordinator to provide notification to
the Generator Owner or Transmission Owner of each Bulk Electric System generator,
transformer, and transmission line Element in its area that meets one or more of the four criteria
listed in Requirement R1. These criteria along with examples are discussed in the Application
Guidelines in the proposed Reliability Standard and are consistent with the recommendations in
the PSRPS Report. The identification of Elements is derived from annual Planning Assessments
pursuant to the transmission planning (i.e., “TPL”) and other NERC Reliability Standards (e.g.,
32
PRC-006). The proposed Reliability Standard does not mandate any other assessments to be
performed by the Planning Coordinator. The required notification is cycled on a calendar year
basis to the respective Generator Owner and Transmission Owner to align with the completion of
the annual Planning Assessments. The Planning Coordinator will continue to provide
notification of Elements on a calendar year basis even if a study is performed less frequently
(e.g., PRC-006 – Automatic Underfrequency Load Shedding, which is five years) and has not
changed. The proposed Reliability Standard would also allow for the use of studies from a prior
year in determining the necessary notifications pursuant to Requirement R1.
The first criterion identifies generator(s) where an angular stability constraint exists that
is addressed by a System Operating Limit or a Remedial Action Scheme and those Elements
terminating at the Transmission station associated with the generator(s).
The second criterion identifies Elements that are monitored as a part of an established
System Operating Limit based on an angular stability limit regardless of the outage conditions
that result in the enforcement of the System Operating Limit.
The third criterion identifies Elements that form the boundary of an island within an
underfrequency load shedding (“UFLS”) design assessment. The criterion applies to islands
identified based on application of the Planning Coordinator’s criteria for identifying islands,
where the island is formed by tripping the Elements based on angular instability. The criterion
applies if the angular instability is modeled in the UFLS design assessment, or if the boundary is
identified “off-line” (i.e., the Elements are selected based on angular instability considerations,
but the Elements are tripped in the UFLS design assessment without modeling the initiating
angular instability). In cases where an out-of-step condition is detected and tripping is initiated
at an alternate location, the criterion applies to the Element on which the power swing is
33
detected. The criterion does not apply to islands identified based on other considerations that do
not involve angular instability, such as excessive loading, Planning Coordinator area boundary
tie lines, or Balancing Authority boundary tie lines.
The fourth criterion identifies Elements in the most recent annual Planning Assessment
where relay tripping occurs due to a stable or unstable power swing during a simulated
disturbance. The intent is for the Planning Coordinator to include any Element(s) where relay
tripping was observed during simulations performed for the most recent annual Planning
Assessment associated with the transmission planning TPL-001-4 Reliability Standard.
Elements where relay tripping occurs due to an unstable power swing have been included in this
criterion as a method of determining which Elements are susceptible and should be identified.
An Element that trips on an unstable power swing is most likely subjected to other stable power
swings that may challenge the Protection System. By identifying these Elements, an entity can
then evaluate its load-responsive protective relays applied on these Elements according to the
Attachment B criteria. If those relays do not meet the criteria, the entity would develop a
Corrective Action Plan to modify the Protection System so that the relays meet the criteria and
therefore, expected to not trip in response to stable power swings during non-Fault conditions.
4.
Requirement R2
R2. Each Generator Owner and Transmission Owner shall:
[Violation Risk Factor: High] [Time Horizon: Operations
Planning]
2.1 Within 12 full calendar months of notification of a BES
Element pursuant to Requirement R1, determine whether its
load-responsive protective relay(s) applied to that BES
Element meets the criteria in PRC-026-1 – Attachment B
where an evaluation of that Element’s load-responsive
protective relay(s) based on PRC-026-1 – Attachment B
criteria has not been performed in the last five calendar
34
years.
2.2 Within 12 full calendar months of becoming
aware[FN4] of a generator, transformer, or transmission
line BES Element that tripped in response to a stable or
unstable[FN5] power swing due to the operation of its
protective relay(s), determine whether its load-responsive
protective relay(s) applied to that BES Element meets the
criteria in PRC-026-1 – Attachment B.
[FN4] Some examples of the ways an entity may become aware of a power
swing are provided in the Guidelines and Technical Basis section, “Becoming
Aware of an Element That Tripped in Response to a Power Swing.”
[FN5] An example of an unstable power swing is provided in the Guidelines and
Technical Basis section, “Justification for Including Unstable Power Swings in
the Requirements section of the Guidelines and Technical Basis.”
Proposed Requirement R2 requires the Generator Owner and Transmission Owner to
evaluate its load-responsive protective relays, that are within the scope of the proposed
Reliability Standard (see Section VI.B.2 above) and meet the conditions in Part 2.1 and 2.2, to
ensure that they are expected to not trip in response to stable power swings during non-Fault
conditions. The Generator Owner or Transmission Owner must evaluate the relay to determine
whether it meets the criteria provided in Attachment B. The Generator Owner or Transmission
Owner, as the protective relay owner, is in the best position to determine whether its loadresponsive protective relays meet the PRC-026-1 – Attachment B criteria. Proposed PRC-026-1,
Attachment B establishes two criteria, A and B, to measure whether each load-responsive
protective relay is set so that protective relays are expected to not trip in response to stable power
swings during non-Fault conditions.
The proposed Attachment B, Criterion A requires that impedance-based relays used for
tripping be expected to not trip for a stable power swing, when the relay characteristic is
completely contained within the unstable power swing region (see proposed Reliability Standard,
35
Figures 1 and 2). The unstable power swing region is formed by the union of three shapes in the
impedance (R-X) plane. These shapes include:
(1) a lower loss-of-synchronism circle based on a ratio of the sending-end to receivingend voltages of 0.7;
(2) an upper loss-of-synchronism circle based on a ratio of the sending-end to receivingend voltages of 1.43;
(3) a lens that connects the endpoints of the total system impedance (with the parallel
transfer impedance removed) bounded by varying the sending-end and receiving-end voltages
from 0.0 to 1.0 per unit.
This must occur while maintaining a constant system separation angle across the total system
impedance where:
(i) the evaluation is based on a system separation angle of at least 120 degrees, or
an angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120 degrees;
(ii) all generation is in service and all transmission BES Elements are in their
normal operating state when calculating the system impedance; and
(iii) the saturated (transient or sub-transient) reactance is used for all machines.
The sending-end and receiving-end source voltages are varied from 0.7 to 1.0 per unit to
form the lower and upper loss-of-synchronism circles. The ratio of these two voltages is used in
the calculation of the loss-of-synchronism circles, and result in a ratio range from 0.7 to 1.43 as
shown in Equations 2 and 3 of the proposed standard’s Application Guidelines. The internal
generator voltage during severe power swings or transmission system fault conditions will be
greater than zero due to voltage regulator support. The voltage ratio of 0.7 to 1.43 is more
36
conservative than the lower bound voltage of 0.85 per unit voltage used in the PRC-023-3 and
PRC-025-1 relay loadability NERC Reliability Standards. A ±15% internal generator voltage
range is a conservative voltage range for calculation of the voltage ratio used to calculate the
loss-of-synchronism circles. For example, the voltage ratio using these voltages would result in
a ratio range from 0.739 to 1.353 as shown in Equations 4 and 5 of the proposed standard’s
Application Guidelines. The lower ratio of 0.739 rounded down to 0.7 to be more conservative.
Similarly, Criterion B is used for overcurrent-based relays when the pickup of an
overcurrent relay element used for tripping is above the calculated current value (with the
parallel transfer impedance removed) for the conditions where the relay is:
(i) evaluated based on a system separation angle of at least 120 degrees, or an angle less
than 120 degrees, where a documented transient stability analysis demonstrates that the expected
maximum stable separation angle is less than 120 degrees;
(ii) all generation must be in service and all transmission BES Elements in their normal
operating state when calculating the system impedance;
(iii) the saturated (transient or sub-transient) reactance is used for all machines; and
(iv) the sending-end and receiving-end voltages at 1.05 per unit.
The 1.05 per unit generator voltage is used to establish a minimum pickup current value
for overcurrent relays that are set below 15 cycle time delay for both the sending and receiving
end using the 120 degree system separation angle criteria.
Generator Owners and Transmission Owners must evaluate applicable relays that meet
either of the two conditions in Part 2.1 and 2.2. Under Part 2.1, once a Generator Owner or
Transmission Owner is notified of Elements pursuant to Requirement R1, it has 12 full calendar
months to determine if each Element’s load-responsive protective relays meet the PRC-026-1 –
37
Attachment B criteria, if the determination according to Attachment B criteria has not been
performed in the last five calendar years. Additionally, under Part 2.2, each Generator Owner
and Transmission Owner, that becomes aware of a generator, transformer, or transmission line
BES Element that tripped in response to a stable or unstable power swing due to the operation of
its protective relay(s) must perform the same evaluation according to the PRC-026-1 –
Attachment B criteria within 12 full calendar months. There is no re-evaluation interval for
actual tripping in response to a stable or unstable power swing because each occurrence must be
evaluated to ensure that system impedance has not changed or that some other issue is not
present. The purpose of Part 2.2 is to initiate action by the Generator Owner and Transmission
Owner when it becomes aware of a known stable or unstable power swing and it resulted in the
entity’s Element tripping.
The phrase “becoming aware” is used in the proposed Requirement R2, Part 2.2 to not
overburden entities by requiring a determination of whether a power swing was present for every
Element trip. The identification of power swings will generally be associated with large events
and revealed during an analysis of the event. This event analysis could include internal analysis
conducted by the entity, the entity’s Protection System review following a trip, or a larger scale
analysis by other entities. Event analysis could include involvement by the entity’s Regional
Entity, and in some cases NERC. Given the expected infrequency of Elements tripping in
response to a stable power swing afforded by the benefits of the application of PRC-023, the
standard drafting team determined that requiring an evaluation following a known power swing
trip, in addition to the evaluation of Elements identified in proposed Requirement R1, provides
the requisite coverage recommended by the PSRPS Report to meet the reliability purpose of the
38
proposed Reliability Standard and directive in an efficient manner without significant burden to
applicable entities.
5.
Requirements R3 and R4
R3. Each Generator Owner and Transmission Owner shall, within
six full calendar months of determining a load-responsive
protective relay does not meet the PRC-026-1 – Attachment B
criteria pursuant to Requirement R2, develop a Corrective Action
Plan (CAP) to meet one of the following: [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]
• The Protection System meets the PRC-026-1 –
Attachment B criteria, while maintaining dependable fault
detection and dependable out-of-step tripping (if out-ofstep tripping is applied at the terminal of the BES
Element); or
• The Protection System is excluded under the PRC-026-1
– Attachment A criteria (e.g., modifying the Protection
System so that relay functions are supervised by power
swing blocking or using relay systems that are immune to
power swings), while maintaining dependable fault
detection and dependable out-of-step tripping (if out-ofstep tripping is applied at the terminal of the BES
Element).
R4. Each Generator Owner and Transmission Owner shall
implement each CAP developed pursuant to Requirement R3 and
update each CAP if actions or timetables change until all actions
are complete. [Violation Risk Factor: Medium][Time Horizon:
Long-Term Planning]
To achieve the stated purpose of this standard, which is to ensure that load-responsive
protective relays are expected to not trip in response to stable power swings during non-Fault
conditions, the applicable entity is required to implement any CAP developed pursuant to
Requirement R3 such that the Protection System will meet PRC-026-1 – Attachment B criteria or
can be excluded under the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection
System so that relay functions are supervised by power swing blocking or using relay systems
39
that are immune to power swings), while maintaining dependable fault detection and dependable
out-of-step tripping (if out-of-step tripping is applied at the terminal of the Bulk Electric System
Element). Protection System owners are required in the implementation of a CAP to update it
when actions or timetable change, until all actions are complete. Accomplishing this objective is
intended to reduce the occurrence of Protection System tripping during a stable power swing,
thereby improving reliability and minimizing risk to the Bulk Electric System.
C.
Enforceability of Proposed Reliability Standards
The proposed Reliability Standard PRC-026-1 includes Measures that support each
Requirement to help ensure that the Requirements will be enforced in a clear, consistent, nonpreferential manner and without prejudice to any party. The proposed Reliability Standard also
includes VRFs and VSLs for each Requirement. The VRFs and VSLs for the proposed
Reliability Standard comport with NERC and Commission guidelines related to their assignment.
A detailed analysis of the assignment of VRFs and the VSLs for proposed PRC-026-1 is
included as Exhibit E.
VII.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve:
•
the proposed Reliability Standard in Exhibit A;
•
the other associated elements in the Reliability Standard in Exhibit A including the VRFs
and VSLs (Exhibits A and F); and
•
the Implementation Plan, included in Exhibit B.
Respectfully submitted,
/s/ William H. Edwards
40
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate General Counsel
William H. Edwards
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
Date: December 31, 2014
41
Exhibit A
Proposed Reliability Standard PRC-026-1
PRC-026-1 — Relay Performance During Stable Power Swings
A. Introduction
1. Title:
Relay Performance During Stable Power Swings
2. Number:
PRC-026-1
3. Purpose:
To ensure that load-responsive protective relays are expected to not trip in
response to stable power swings during non-Fault conditions.
4. Applicability:
4.1.
4.2.
Functional Entities:
4.1.1
Generator Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
4.1.2
Planning Coordinator.
4.1.3
Transmission Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
Facilities: The following Elements that are part of the Bulk Electric System
(BES):
4.2.1
Generators.
4.2.2
Transformers.
4.2.3
Transmission lines.
5. Background:
This is the third phase of a three-phased standard development project that focused on
developing this new Reliability Standard to address protective relay operations due to
stable power swings. The March 18, 2010, Federal Energy Regulatory Commission
(FERC) Order No. 733 approved Reliability Standard PRC-023-1 – Transmission Relay
Loadability. In that Order, FERC directed NERC to address three areas of relay loadability
that include modifications to the approved PRC-023-1, development of a new Reliability
Standard to address generator protective relay loadability, and a new Reliability Standard
to address the operation of protective relays due to stable power swings. This project’s
SAR addresses these directives with a three-phased approach to standard development.
Phase 1 focused on making the specific modifications from FERC Order No. 733 to PRC023-1. Reliability Standard PRC-023-2, which incorporated these modifications, became
mandatory on July 1, 2012.
Phase 2 focused on developing a new Reliability Standard, PRC-025-1 – Generator Relay
Loadability, to address generator protective relay loadability. PRC-025-1 became
mandatory on October 1, 2014, along with PRC-023-3, which was modified to harmonize
PRC-023-2 with PRC-025-1.
Phase 3 focuses on preventing protective relays from tripping unnecessarily due to stable
power swings by requiring identification of Elements on which a stable or unstable power
swing may affect Protection System operation, assessment of the security of loadPage 1 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
responsive protective relays to tripping in response to only a stable power swing, and
implementation of Corrective Action Plans (CAP), where necessary. Phase 3 improves
security of load-responsive protective relays for stable power swings so they are expected
to not trip in response to stable power swings during non-Fault conditions while
maintaining dependable fault detection and dependable out-of-step tripping.
6. Effective Dates:
Requirement R1
First day of the first full calendar year that is 12 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 12 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
Requirements R2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 36 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
Page 2 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
B. Requirements and Measures
R1. Each Planning Coordinator shall, at least once each calendar year, provide notification
of each generator, transformer, and transmission line BES Element in its area that
meets one or more of the following criteria, if any, to the respective Generator Owner
and Transmission Owner: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
Criteria:
1. Generator(s) where an angular stability constraint exists that is addressed by a
System Operating Limit (SOL) or a Remedial Action Scheme (RAS) and those
Elements terminating at the Transmission station associated with the generator(s).
2. An Element that is monitored as part of an SOL identified by the Planning
Coordinator’s methodology1 based on an angular stability constraint.
3. An Element that forms the boundary of an island in the most recent
underfrequency load shedding (UFLS) design assessment based on application of
the Planning Coordinator’s criteria for identifying islands, only if the island is
formed by tripping the Element due to angular instability.
4. An Element identified in the most recent annual Planning Assessment where relay
tripping occurs due to a stable or unstable2 power swing during a simulated
disturbance.
M1. Each Planning Coordinator shall have dated evidence that demonstrates notification of
the generator, transformer, and transmission line BES Element(s) that meet one or
more of the criteria in Requirement R1, if any, to the respective Generator Owner and
Transmission Owner. Evidence may include, but is not limited to, the following
documentation: emails, facsimiles, records, reports, transmittals, lists, or spreadsheets.
1
NERC Reliability Standard FAC-014-2 – Establish and Communicate System Operating Limits, Requirement R3.
2
An example of an unstable power swing is provided in the Guidelines and Technical Basis section, “Justification
for Including Unstable Power Swings in the Requirements section of the Guidelines and Technical Basis.”
Page 3 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
R2. Each Generator Owner and Transmission Owner shall: [Violation Risk Factor: High]
[Time Horizon: Operations Planning]
2.1 Within 12 full calendar months of notification of a BES Element pursuant to
Requirement R1, determine whether its load-responsive protective relay(s)
applied to that BES Element meets the criteria in PRC-026-1 – Attachment B
where an evaluation of that Element’s load-responsive protective relay(s) based
on PRC-026-1 – Attachment B criteria has not been performed in the last five
calendar years.
2.2 Within 12 full calendar months of becoming aware3 of a generator, transformer,
or transmission line BES Element that tripped in response to a stable or unstable4
power swing due to the operation of its protective relay(s), determine whether its
load-responsive protective relay(s) applied to that BES Element meets the criteria
in PRC-026-1 – Attachment B.
M2. Each Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the evaluation was performed according to Requirement R2. Evidence
may include, but is not limited to, the following documentation: apparent impedance
characteristic plots, email, design drawings, facsimiles, R-X plots, software output,
records, reports, transmittals, lists, settings sheets, or spreadsheets.
R3. Each Generator Owner and Transmission Owner shall, within six full calendar months
of determining a load-responsive protective relay does not meet the PRC-026-1 –
Attachment B criteria pursuant to Requirement R2, develop a Corrective Action Plan
(CAP) to meet one of the following: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
•
The Protection System meets the PRC-026-1 – Attachment B criteria, while
maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the BES Element); or
•
The Protection System is excluded under the PRC-026-1 – Attachment A criteria
(e.g., modifying the Protection System so that relay functions are supervised by
power swing blocking or using relay systems that are immune to power swings),
while maintaining dependable fault detection and dependable out-of-step tripping
(if out-of-step tripping is applied at the terminal of the BES Element).
M3. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the development of a CAP in accordance with Requirement R3. Evidence
may include, but is not limited to, the following documentation: corrective action
plans, maintenance records, settings sheets, project or work management program
records, or work orders.
R4. Each Generator Owner and Transmission Owner shall implement each CAP developed
pursuant to Requirement R3 and update each CAP if actions or timetables change until
all actions are complete. [Violation Risk Factor: Medium][Time Horizon: Long-Term
Planning]
Page 4 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
M4. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates implementation of each CAP according to Requirement R4, including
updates to the CAP when actions or timetables change. Evidence may include, but is
not limited to, the following documentation: corrective action plans, maintenance
records, settings sheets, project or work management program records, or work orders.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention
The following evidence retention periods 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 CEA may ask an entity to provide other evidence to show that it was
compliant for the full time period since the last audit.
The Generator Owner, Planning Coordinator, and Transmission Owner shall keep
data or evidence to show compliance as identified below unless directed by its CEA
to retain specific evidence for a longer period of time as part of an investigation.
•
The Planning Coordinator shall retain evidence of Requirement R1 for a
minimum of one calendar year following the completion of the
Requirement.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirement R2 evaluation for a minimum of 12 calendar months following
completion of each evaluation where a CAP is not developed.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R2, R3, and R4 for a minimum of 12 calendar months
following completion of each CAP.
If a Generator Owner, Planning Coordinator, or Transmission Owner is found noncompliant, it shall keep information related to the non-compliance until mitigation
is complete and approved, or for the time specified above, whichever is longer.
3
Some examples of the ways an entity may become aware of a power swing are provided in the Guidelines and
Technical Basis section, “Becoming Aware of an Element That Tripped in Response to a Power Swing.”
4
An example of an unstable power swing is provided in the Guidelines and Technical Basis section, “Justification
for Including Unstable Power Swings in the Requirements section of the Guidelines and Technical Basis.”
Page 5 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3.
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure; “Compliance Monitoring and
Assessment Processes” 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.
1.4.
Additional Compliance Information
None.
Page 6 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
Table of Compliance Elements
R#
R1
Time
Horizon
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was less than or equal
to 30 calendar days
late.
Moderate VSL
High VSL
Severe VSL
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 90
calendar days late.
OR
The Planning
Coordinator failed to
provide notification
of the BES
Element(s) in
accordance with
Requirement R1.
Page 7 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
R#
R2
Time
Horizon
Operations
Planning
Violation Severity Levels
VRF
High
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was less than or equal
to 30 calendar days
late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 90
calendar days late.
OR
The Generator Owner
or Transmission
Owner failed to
evaluate its loadresponsive protective
relay(s) in accordance
with Requirement R2.
Page 8 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
R#
R3
R4
Time
Horizon
Long-term
Planning
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than six
calendar months and
less than or equal to
seven calendar
months.
Medium The Generator Owner
or Transmission
Owner implemented a
Corrective Action
Plan (CAP), but failed
to update a CAP when
actions or timetables
changed, in
accordance with
Requirement R4.
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than seven
calendar months and
less than or equal to
eight calendar
months.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than eight
calendar months and
less than or equal to
nine calendar months.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than nine
calendar months.
N/A
N/A
OR
The Generator Owner
or Transmission
Owner failed to
develop a CAP in
accordance with
Requirement R3.
The Generator Owner
or Transmission
Owner failed to
implement a
Corrective Action
Plan (CAP) in
accordance with
Requirement R4.
Page 9 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
Burdy, John, Loss-of-excitation Protection for Synchronous Generators GER-3183, General
Electric Company.
IEEE Power System Relaying Committee WG D6, Power Swing and Out-of-Step
Considerations on Transmission Lines, July 2005: http://www.pes-psrc.org/Reports
/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission%20
Lines%20F..pdf.
Kimbark Edward Wilson, Power System Stability, Volume II: Power Circuit Breakers and
Protective Relays, Published by John Wiley and Sons, 1950.
Kundur, Prabha, Power System Stability and Control, 1994, Palo Alto: EPRI, McGraw Hill,
Inc.
NERC System Protection and Control Subcommittee, Protection System Response to Power
Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf.
Reimert, Donald, Protective Relaying for Power Generation Systems, 2006, Boca Raton: CRC
Press.
Version History
Version
Date
1.0
TBD
2
November 13, 2014
Action
Effective Date
Change
Tracking
New
Adopted by NERC Board of
Trustees
Page 10 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment A
This standard applies to any protective functions which could trip instantaneously or with a time
delay of less than 15 cycles on load current (i.e., “load-responsive”) including, but not limited to:
•
•
•
•
Phase distance
Phase overcurrent
Out-of-step tripping
Loss-of-field
The following protection functions are excluded from Requirements of this standard:
•
•
•
•
•
•
•
•
•
•
•
Relay elements supervised by power swing blocking
Relay elements that are only enabled when other relays or associated systems fail. For
example:
o Overcurrent elements that are only enabled during loss of potential conditions.
o Relay elements that are only enabled during a loss of communications
Thermal emulation relays which are used in conjunction with dynamic Facility Ratings
Relay elements associated with direct current (dc) lines
Relay elements associated with dc converter transformers
Phase fault detector relay elements employed to supervise other load-responsive phase
distance elements (i.e., in order to prevent false operation in the event of a loss of potential)
Relay elements associated with switch-onto-fault schemes
Reverse power relay on the generator
Generator relay elements that are armed only when the generator is disconnected from the
system, (e.g., non-directional overcurrent elements used in conjunction with inadvertent
energization schemes, and open breaker flashover schemes)
Current differential relay, pilot wire relay, and phase comparison relay
Voltage-restrained or voltage-controlled overcurrent relays
Page 11 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
Criterion A:
An impedance-based relay used for tripping is expected to not trip for a stable power swing,
when the relay characteristic is completely contained within the unstable power swing region.5
The unstable power swing region is formed by the union of three shapes in the impedance (RX) plane; (1) a lower loss-of-synchronism circle based on a ratio of the sending-end to
receiving-end voltages of 0.7; (2) an upper loss-of-synchronism circle based on a ratio of the
sending-end to receiving-end voltages of 1.43; (3) a lens that connects the endpoints of the
total system impedance (with the parallel transfer impedance removed) bounded by varying
the sending-end and receiving-end voltages from 0.0 to 1.0 per unit, while maintaining a
constant system separation angle across the total system impedance where:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
5
Guidelines and Technical Basis, Figures 1 and 2.
Page 12 of 84
PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
Criterion B:
The pickup of an overcurrent relay element used for tripping, that is above the calculated
current value (with the parallel transfer impedance removed) for the conditions below:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
4. Both the sending-end and receiving-end voltages at 1.05 per unit.
Page 13 of 84
PRC-026-1 – Application Guidelines
Guidelines and Technical Basis
Introduction
The NERC System Protection and Control Subcommittee technical document, Protection System
Response to Power Swings, August 2013,6 (“PSRPS Report” or “report”) was specifically prepared
to support the development of this NERC Reliability Standard. The report provided a historical
perspective on power swings as early as 1965 up through the approval of the report by the NERC
Planning Committee. The report also addresses reliability issues regarding trade-offs between
security and dependability of Protection Systems, considerations for this NERC Reliability
Standard, and a collection of technical information about power swing characteristics and varying
issues with practical applications and approaches to power swings. Of these topics, the report
suggests an approach for this NERC Reliability Standard (“standard” or “PRC-026-1”) which is
consistent with addressing three regulatory directives in the FERC Order No. 733. The first
directive concerns the need for “…protective relay systems that differentiate between faults and
stable power swings and, when necessary, phases out protective relay systems that cannot meet
this requirement.”7 Second, is “…to develop a Reliability Standard addressing undesirable relay
operation due to stable power swings.”8 The third directive “…to consider “islanding” strategies
that achieve the fundamental performance for all islands in developing the new Reliability
Standard addressing stable power swings”9 was considered during development of the standard.
The development of this standard implements the majority of the approaches suggested by the
report. However, it is noted that the Reliability Coordinator and Transmission Planner have not
been included in the standard’s Applicability section (as suggested by the PSRPS Report). This is
so that a single entity, the Planning Coordinator, may be the single source for identifying Elements
according to Requirement R1. A single source will insure that multiple entities will not identify
Elements in duplicate, nor will one entity fail to provide an Element because it believes the
Element is being provided by another entity. The Planning Coordinator has, or has access to, the
wide-area model and can correctly identify the Elements that may be susceptible to a stable or
unstable power swing. Additionally, not including the Reliability Coordinator and Transmission
Planner is consistent with the applicability of other relay loadability NERC Reliability Standards
(e.g., PRC-023 and PRC-025). It is also consistent with the NERC Functional Model.
The phrase, “while maintaining dependable fault detection and dependable out-of-step tripping”
in Requirement R3, describes that the Generator Owner and Transmission Owner are to comply
with this standard while achieving its desired protection goals. Load-responsive protective relays,
as addressed within this standard, may be intended to provide a variety of backup protection
functions, both within the generating unit or generating plant and on the transmission system, and
6
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
7
Transmission Relay Loadability Reliability Standard, Order No. 733, P.150 FERC ¶ 61,221 (2010).
8
Ibid. P.153.
9
Ibid. P.162.
Page 14 of 84
PRC-026-1 – Application Guidelines
this standard is not intended to result in the loss of these protection functions. Instead, the
Generator Owner and Transmission Owner must consider both the Requirements within this
standard and its desired protection goals and perform modifications to its protective relays or
protection philosophies as necessary to achieve both.
Power Swings
The IEEE Power System Relaying Committee WG D6 developed a technical document called
Power Swing and Out-of-Step Considerations on Transmission Lines (July 2005) that provides
background on power swings. The following are general definitions from that document:10
Power Swing: a variation in three phase power flow which occurs when the generator rotor
angles are advancing or retarding relative to each other in response to changes in load
magnitude and direction, line switching, loss of generation, faults, and other system
disturbances.
Pole Slip: a condition whereby a generator, or group of generators, terminal voltage angles
(or phases) go past 180 degrees with respect to the rest of the connected power system.
Stable Power Swing: a power swing is considered stable if the generators do not slip poles
and the system reaches a new state of equilibrium, i.e. an acceptable operating condition.
Unstable Power Swing: a power swing that will result in a generator or group of generators
experiencing pole slipping for which some corrective action must be taken.
Out-of-Step Condition: Same as an unstable power swing.
Electrical System Center or Voltage Zero: it is the point or points in the system where the
voltage becomes zero during an unstable power swing.
Burden to Entities
The PSRPS Report provides a technical basis and approach for focusing on Protection Systems,
which are susceptible to power swings, while achieving the purpose of the standard. The approach
reduces the number of relays to which the PRC-026-1 Requirements would apply by first
identifying the BES Element(s) on which load-responsive protective relays must be evaluated. The
first step uses criteria to identify the Elements on which a Protection System is expected to be
challenged by power swings. Of those Elements, the second step is to evaluate each loadresponsive protective relay that is applied on each identified Element. Rather than requiring the
Planning Coordinator or Transmission Planner to perform simulations to obtain information for
each identified Element, the Generator Owner and Transmission Owner will reduce the need for
simulation by comparing the load-responsive protective relay characteristic to specific criteria in
PRC-026-1 – Attachment B.
10
http://www.pes-psrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission
%20Lines%20F..pdf.
Page 15 of 84
PRC-026-1 – Application Guidelines
Applicability
The standard is applicable to the Generator Owner, Planning Coordinator, and Transmission
Owner entities. More specifically, the Generator Owner and Transmission Owner entities are
applicable when applying load-responsive protective relays at the terminals of the applicable BES
Elements. The standard is applicable to the following BES Elements: generators, transformers, and
transmission lines. The Distribution Provider was considered for inclusion in the standard;
however, it is not subject to the standard because this entity, by functional registration, would not
own generators, transmission lines, or transformers other than load serving.
Load-responsive protective relays include any protective functions which could trip with or
without time delay, on load current.
Requirement R1
The Planning Coordinator has a wide-area view and is in the position to identify what, if any,
Elements meet the criteria. The criterion-based approach is consistent with the NERC System
Protection and Control Subcommittee (SPCS) technical document, Protection System Response to
Power Swings (August 2013),11 which recommends a focused approach to determine an at-risk
Element. Identification of Elements comes from the annual Planning Assessments pursuant to the
transmission planning (i.e., “TPL”) and other NERC Reliability Standards (e.g., PRC-006), and
the standard is not requiring any other assessments to be performed by the Planning Coordinator.
The required notification on a calendar year basis to the respective Generator Owner and
Transmission Owner is sufficient because it is expected that the Planning Coordinator will make
its notifications following the completion of its annual Planning Assessments. The Planning
Coordinator will continue to provide notification of Elements on a calendar year basis even if a
study is performed less frequently (e.g., PRC-006 – Automatic Underfrequency Load Shedding,
which is five years) and has not changed. It is possible that a Planning Coordinator could utilize
studies from a prior year in determining the necessary notifications pursuant to Requirement R1.
Criterion 1
The first criterion involves generator(s) where an angular stability constraint exists that is
addressed by a System Operating Limit (SOL) or a Remedial Action Scheme (RAS) and those
Elements terminating at the Transmission station associated with the generator(s). For example, a
scheme to remove generation for specific conditions is implemented for a four-unit generating
plant (1,100 MW). Two of the units are 500 MW each; one is connected to the 345 kV system and
one is connected to the 230 kV system. The Transmission Owner has two 230 kV transmission
lines and one 345 kV transmission line all terminating at the generating facility as well as a 345/230
kV autotransformer. The remaining 100 MW consists of two 50 MW combustion turbine (CT)
units connected to four 66 kV transmission lines. The 66 kV transmission lines are not electrically
joined to the 345 kV and 230 kV transmission lines at the plant site and are not subject to the
operating limit or RAS. A stability constraint limits the output of the portion of the plant affected
11
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%20
20/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Page 16 of 84
PRC-026-1 – Application Guidelines
by the RAS to 700 MW for an outage of the 345 kV transmission line. The RAS trips one of the
500 MW units to maintain stability for a loss of the 345 kV transmission line when the total output
from both 500 MW units is above 700 MW. For this example, both 500 MW generating units and
the associated generator step-up (GSU) transformers would be identified as Elements meeting this
criterion. The 345/230 kV autotransformer, the 345 kV transmission line, and the two 230 kV
transmission lines would also be identified as Elements meeting this criterion. The 50 MW
combustion turbines and 66 kV transmission lines would not be identified pursuant to Criterion 1
because these Elements are not subject to an operating limit or RAS and do not terminate at the
Transmission station associated with the generators that are subject to the SOL or RAS.
Criterion 2
The second criterion involves Elements that are monitored as a part of an established System
Operating Limit (SOL) based on an angular stability limit regardless of the outage conditions that
result in the enforcement of the SOL. For example, if two long parallel 500 kV transmission lines
have a combined SOL of 1,200 MW, and this limit is based on angular instability resulting from a
fault and subsequent loss of one of the two lines, then both lines would be identified as Elements
meeting the criterion.
Criterion 3
The third criterion involves Elements that form the boundary of an island within an underfrequency
load shedding (UFLS) design assessment. The criterion applies to islands identified based on
application of the Planning Coordinator’s criteria for identifying islands, where the island is
formed by tripping the Elements based on angular instability. The criterion applies if the angular
instability is modeled in the UFLS design assessment, or if the boundary is identified “off-line”
(i.e., the Elements are selected based on angular instability considerations, but the Elements are
tripped in the UFLS design assessment without modeling the initiating angular instability). In cases
where an out-of-step condition is detected and tripping is initiated at an alternate location, the
criterion applies to the Element on which the power swing is detected. The criterion does not apply
to islands identified based on other considerations that do not involve angular instability, such as
excessive loading, Planning Coordinator area boundary tie lines, or Balancing Authority boundary
tie lines.
Criterion 4
The fourth criterion involves Elements identified in the most recent annual Planning Assessment
where relay tripping occurs due to a stable or unstable12 power swing during a simulated
disturbance. The intent is for the Planning Coordinator to include any Element(s) where relay
tripping was observed during simulations performed for the most recent annual Planning
Assessment associated with the transmission planning TPL-001-4 Reliability Standard. Note that
relay tripping must be assessed within those annual Planning Assessments per TPL-001-4, R4,
12
Refer to the “Justification for Including Unstable Power Swings in the Requirements” section.
Page 17 of 84
PRC-026-1 – Application Guidelines
Part 4.3.1.3, which indicates that analysis shall include the “Tripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic or actual
relay models.” Identifying such Elements according to Criterion 4 and notifying the respective
Generator Owner and Transmission Owner will require that the owners of any load-responsive
protective relay applied at the terminals of the identified Element evaluate the relay’s susceptibility
to tripping in response to a stable power swing.
Planning Coordinators have the discretion to determine whether the observed tripping for a power
swing in its Planning Assessments occurs for valid contingencies and system conditions. The
Planning Coordinator will address tripping that is observed in transient analyses on an individual
basis; therefore, the Planning Coordinator is responsible for identifying the Elements based only
on simulation results that are determined to be valid.
Due to the nature of how a Planning Assessment is performed, there may be cases where a
previously-identified Element is not identified in the most recent annual Planning Assessment. If
so, this is acceptable because the Generator Owner and Transmission Owner would have taken
action upon the initial notification of the previously identified Element. When an Element is not
identified in later Planning Assessments, the risk of load-responsive protective relays tripping in
response to a stable power swing during non-Fault conditions would have already been assessed
under Requirement R2 and mitigated according to Requirements R3 and R4 where the relays did
not meet the PRC-026-1 – Attachment B criteria. According to Requirement R2, the Generator
Owner and Transmission Owner are only required to re-evaluate each load-responsive protective
relay for an identified Element where the evaluation has not been performed in the last five
calendar years.
Although Requirement R1 requires the Planning Coordinator to notify the respective Generator
Owner and Transmission Owner of any Elements meeting one or more of the four criteria, it does
not preclude the Planning Coordinator from providing additional information, such as apparent
impedance characteristics, in advance or upon request, that may be useful in evaluating protective
relays. Generator Owners and Transmission Owners are able to complete protective relay
evaluations and perform the required actions without additional information. The standard does
not include any requirement for the entities to provide information that is already being shared or
exchanged between entities for operating needs. While a Requirement has not been included for
the exchange of information, entities should recognize that relay performance needs to be
measured against the most current information.
Requirement R2
Requirement R2 requires the Generator Owner and Transmission Owner to evaluate its loadresponsive protective relays to ensure that they are expected to not trip in response to stable power
swings.
Page 18 of 84
PRC-026-1 – Application Guidelines
The PRC-026-1 – Attachment A lists the applicable load-responsive relays that must be evaluated
which include phase distance, phase overcurrent, out-of-step tripping, and loss-of-field relay
functions. Phase distance relays could include, but are not limited to, the following:
•
•
Zone elements with instantaneous tripping or intentional time delays of less than 15 cycles
Phase distance elements used in high-speed communication-aided tripping schemes
including:
Directional Comparison Blocking (DCB) schemes
Directional Comparison Un-Blocking (DCUB) schemes
Permissive Overreach Transfer Trip (POTT) schemes
Permissive Underreach Transfer Trip (PUTT) schemes
A method is provided within the standard to support consistent evaluation by Generator Owners
and Transmission Owners based on specified conditions. Once a Generator Owner or Transmission
Owner is notified of Elements pursuant to Requirement R1, it has 12 full calendar months to
determine if each Element’s load-responsive protective relays meet the PRC-026-1 – Attachment
B criteria, if the determination has not been performed in the last five calendar years. Additionally,
each Generator Owner and Transmission Owner, that becomes aware of a generator, transformer,
or transmission line BES Element that tripped in response to a stable or unstable power swing due
to the operation of its protective relays pursuant to Requirement R2, Part 2.2, must perform the
same PRC-026-1 – Attachment B criteria determination within 12 full calendar months.
Becoming Aware of an Element That Tripped in Response to a Power Swing
Part 2.2 in Requirement R2 is intended to initiate action by the Generator Owner and Transmission
Owner when there is a known stable or unstable power swing and it resulted in the entity’s Element
tripping. The criterion starts with becoming aware of the event (i.e., power swing) and then any
connection with the entity’s Element tripping. By doing so, the focus is removed from the entity
having to demonstrate that it made a determination whether a power swing was present for every
Element trip. The basis for structuring the criterion in this manner is driven by the available ways
that a Generator Owner and Transmission Owner could become aware of an Element that tripped
in response to a stable or unstable power swing due to the operation of its protective relay(s).
Element trips caused by stable or unstable power swings, though infrequent, would be more
common in a larger event. The identification of power swings will be revealed during an analysis
of the event. Event analysis where an entity may become aware of a stable or unstable power swing
could include internal analysis conducted by the entity, the entity’s Protection System review
following a trip, or a larger scale analysis by other entities. Event analysis could include
involvement by the entity’s Regional Entity, and in some cases NERC.
Information Common to Both Generation and Transmission Elements
The PRC-026-1 – Attachment A lists the load-responsive protective relays that are subject to this
standard. Generator Owners and Transmission Owners may own load-responsive protective relays
(e.g., distance relays) that directly affect generation or transmission BES Elements and will require
analysis as a result of Elements being identified by the Planning Coordinator in Requirement R1
Page 19 of 84
PRC-026-1 – Application Guidelines
or the Generator Owner or Transmission Owner in Requirement R2. For example, distance relays
owned by the Transmission Owner may be installed at the high-voltage side of the generator stepup (GSU) transformer (directional toward the generator) providing backup to generation
protection. Generator Owners may have distance relays applied to backup transmission protection
or backup protection to the GSU transformer. The Generator Owner may have relays installed at
the generator terminals or the high-voltage side of the GSU transformer.
Exclusion of Time Based Load-Responsive Protective Relays
The purpose of the standard is “[t]o ensure that load-responsive protective relays are expected to
not trip in response to stable power swings during non-Fault conditions.” Load-responsive, highspeed tripping protective relays pose the highest risk of operating during a power swing. Because
of this, high-speed tripping protective relays and relays with a time delay of less than 15 cycles are
included in the standard; whereas other relays (i.e., Zones 2 and 3) with a time delay of 15 cycles
or greater are excluded. The time delay used for exclusion on some load-responsive protective
relays is based on the maximum expected time that load-responsive protective relays would be
exposed to a stable power swing with a slow slip rate frequency.
In order to establish a time delay that distinguishes a high-risk load-responsive protective relay
from one that has a time delay for tripping (lower-risk), a sample of swing rates were calculated
based on a stable power swing entering and leaving the impedance characteristic as shown in Table
1. For a relay impedance characteristic that has a power swing entering and leaving, beginning at
90 degrees with a termination at 120 degrees before exiting the zone, the zone timer must be greater
than the calculated time the stable power swing is inside the relay’s operating zone to not trip in
response to the stable power swing.
Eq. (1)
> 2 ×
(120° −
ℎ
(360 ×
ℎ
) × 60
)
Table 1: Swing Rates
Zone Timer
(Cycles)
Slip Rate
(Hz)
10
1.00
15
0.67
20
0.50
30
0.33
With a minimum zone timer of 15 cycles, the corresponding slip rate of the system is 0.67 Hz.
This represents an approximation of a slow slip rate during a system Disturbance. Longer time
delays allow for slower slip rates.
Page 20 of 84
PRC-026-1 – Application Guidelines
Application to Transmission Elements
Criterion A in PRC-026-1 – Attachment B describes an unstable power swing region that is formed
by the union of three shapes in the impedance (R-X) plane. The first shape is a lower loss-ofsynchronism circle based on a ratio of the sending-end to receiving-end voltages of 0.7 (i.e., ES /
ER = 0.7 / 1.0 = 0.7). The second shape is an upper loss-of-synchronism circle based on a ratio of
the sending-end to receiving-end voltages of 1.43 (i.e., ES / ER = 1.0 / 0.7 = 1.43). The third shape
is a lens that connects the endpoints of the total system impedance together by varying the sendingend and receiving-end system voltages from 0.0 to 1.0 per unit, while maintaining a constant
system separation angle across the total system impedance (with the parallel transfer impedance
removed—see Figures 1 through 5). The total system impedance is derived from a two-bus
equivalent network and is determined by summing the sending-end source impedance, the line
impedance (excluding the Thévenin equivalent transfer impedance), and the receiving-end source
impedance as shown in Figures 6 and 7. Establishing the total system impedance provides a
conservative condition that will maximize the security of the relay against various system
conditions. The smallest total system impedance represents a condition where the size of the lens
characteristic in the R-X plane is smallest and is a conservative operating point from the standpoint
of ensuring a load-responsive protective relay is expected to not trip given a predetermined angular
displacement between the sending-end and receiving-end voltages. The smallest total system
impedance results when all generation is in service and all transmission BES Elements are modeled
in their “normal” system configuration (PRC-026-1 – Attachment B, Criterion A). The parallel
transfer impedance is removed to represent a likely condition where parallel Elements may be lost
during the disturbance, and the loss of these Elements magnifies the sensitivity of the loadresponsive relays on the parallel line by removing the “infeed effect” (i.e., the apparent impedance
sensed by the relay is decreased as a result of the loss of the transfer impedance, thus making the
relay more likely to trip for a stable power swing—See Figures 13 and 14).
The sending-end and receiving-end source voltages are varied from 0.7 to 1.0 per unit to form the
lower and upper loss-of-synchronism circles. The ratio of these two voltages is used in the
calculation of the loss-of-synchronism circles, and result in a ratio range from 0.7 to 1.43.
Eq. (2)
=
0.7
= 0.7
1.0
Eq. (3):
=
1.0
= 1.43
0.7
The internal generator voltage during severe power swings or transmission system fault conditions
will be greater than zero due to voltage regulator support. The voltage ratio of 0.7 to 1.43 is chosen
to be more conservative than the PRC-02313 and PRC-02514 NERC Reliability Standards where a
lower bound voltage of 0.85 per unit voltage is used. A ±15% internal generator voltage range was
chosen as a conservative voltage range for calculation of the voltage ratio used to calculate the
loss-of-synchronism circles. For example, the voltage ratio using these voltages would result in a
ratio range from 0.739 to 1.353.
13
Transmission Relay Loadability
14
Generator Relay Loadability
Page 21 of 84
PRC-026-1 – Application Guidelines
Eq. (4)
=
0.85
= 0.739
1.15
Eq. (5):
=
1.15
= 1.353
0.85
The lower ratio is rounded down to 0.7 to be more conservative, allowing a voltage range of 0.7
to 1.0 per unit to be used for the calculation of the loss-of-synchronism circles.15
When the parallel transfer impedance is included in the model, the division of current through the
parallel transfer impedance path results in actual measured relay impedances that are larger than
those measured when the parallel transfer impedance is removed (i.e., infeed effect), which would
make it more likely for an impedance relay element to be completely contained within the unstable
power swing region as shown in Figure 11. If the transfer impedance is included in the evaluation,
a distance relay element could be deemed as meeting PRC-026-1 – Attachment B criteria and, in
fact would be secure, assuming all Elements were in their normal state. In this case, the distance
relay element could trip in response to a stable power swing during an actual event if the system
was weakened (i.e., a higher transfer impedance) by the loss of a subset of lines that make up the
parallel transfer impedance as shown in Figure 10. This could happen because the subset of lines
that make up the parallel transfer impedance tripped on unstable swings, contained the initiating
fault, and/or were lost due to operation of breaker failure or remote back-up protection schemes.
Table 10 shows the percent size increase of the lens shape as seen by the relay under evaluation
when the parallel transfer impedance is included. The parallel transfer impedance has minimal
effect on the apparent size of the lens shape as long as the parallel transfer impedance is at least
10 multiples of the parallel line impedance (less than 5% lens shape expansion), therefore, its
removal has minimal impact, but results in a slightly more conservative, smaller lens shape.
Parallel transfer impedances of 5 multiples of the parallel line impedance or less result in an
apparent lens shape size of 10% or greater as seen by the relay. If two parallel lines and a parallel
transfer impedance tie the sending-end and receiving-end buses together, the total parallel transfer
impedance will be one or less multiples of the parallel line impedance, resulting in an apparent
lens shape size of 45% or greater. It is a realistic contingency that the parallel line could be outof-service, leaving the parallel transfer impedance making up the rest of the system in parallel with
the line impedance. Since it is not known exactly which lines making up the parallel transfer
impedance will be out of service during a major system disturbance, it is most conservative to
assume that all of them are out, leaving just the line under evaluation in service.
Either the saturated transient or sub-transient direct axis reactance may be used for machines in
the evaluation because they are smaller than the un-saturated reactances. Since saturated subtransient generator reactances are smaller than the transient or synchronous reactances, the use of
sub-transient reactances will result in a smaller source impedance and a smaller unstable power
swing region in the graphical analysis as shown in Figures 8 and 9. Because power swings occur
in a time frame where generator transient reactances will be prevalent, it is acceptable to use
saturated transient reactances instead of saturated sub-transient reactances. Because some short-
15
Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations,
April 2004, Section 6 (The Cascade Stage of the Blackout), p. 94 under “Why the Generators Tripped Off,” states,
“Some generator undervoltage relays were set to trip at or above 90% voltage. However, a motor stalls out at about
70% voltage and a motor starter contactor drops out around 75%, so if there is a compelling need to protect the
turbine from the system the under-voltage trigger point should be no higher than 80%.”
Page 22 of 84
PRC-026-1 – Application Guidelines
circuit models may not include transient reactances, the use of sub-transient reactances is also
acceptable because it produces more conservative results. For this reason, either value is acceptable
when determining the system source impedances (PRC-026-1 – Attachment B, Criterion A and B,
No. 3).
Saturated reactances are used in short-circuit programs that produce the system impedance
mentioned above. Planning and stability software generally use un-saturated reactances. Generator
models used in transient stability analyses recognize that the extent of the saturation effect depends
upon both rotor (field) and stator currents. Accordingly, they derive the effective saturated
parameters of the machine at each instant by internal calculation from the specified (constant)
unsaturated values of machine reactances and the instantaneous internal flux level. The specific
assumptions regarding which inductances are affected by saturation, and the relative effect of that
saturation, are different for the various generator models used. Thus, unsaturated values of all
machine reactances are used in setting up planning and stability software data, and the appropriate
set of open-circuit magnetization curve data is provided for each machine.
Saturated reactance values are smaller than unsaturated reactance values and are used in shortcircuit programs owned by the Generator and Transmission Owners. Because of this, saturated
reactance values are to be used in the development of the system source impedances.
The source or system equivalent impedances can be obtained by a number of different methods
using commercially available short-circuit calculation tools.16 Most short-circuit tools have a
network reduction feature that allows the user to select the local and remote terminal buses to
retain. The first method reduces the system to one that contains two buses, an equivalent generator
at each bus (representing the source impedances at the sending-end and receiving-end), and two
parallel lines; one being the line impedance of the protected line with relays being analyzed, the
other being the parallel transfer impedance representing all other combinations of lines that
connect the two buses together as shown in Figure 6. Another conservative method is to open both
ends of the line being evaluated, and apply a three-phase bolted fault at each bus to determine the
Thévenin equivalent impedance at each bus. The source impedances are set equal to the Thévenin
equivalent impedances and will be less than or equal to the actual source impedances calculated
by the network reduction method. Either method can be used to develop the system source
impedances at both ends.
The two bullets of PRC-026-1 – Attachment B, Criterion A, No. 1, identify the system separation
angles used to identify the size of the power swing stability boundary for evaluating loadresponsive protective relay impedance elements. The first bullet of PRC-026-1 – Attachment B,
Criterion A, No. 1 evaluates a system separation angle of at least 120 degrees that is held constant
while varying the sending-end and receiving-end source voltages from 0.7 to 1.0 per unit, thus
creating an unstable power swing region about the total system impedance in Figure 1. This
unstable power swing region is compared to the tripping portion of the distance relay
characteristic; that is, the portion that is not supervised by load encroachment, blinders, or some
other form of supervision as shown in Figure 12 that restricts the distance element from tripping
16
Demetrios A. Tziouvaras and Daqing Hou, Appendix in Out-Of-Step Protection Fundamentals and
Advancements, April 17, 2014: https://www.selinc.com.
Page 23 of 84
PRC-026-1 – Application Guidelines
for heavy, balanced load conditions. If the tripping portion of the impedance characteristics are
completely contained within the unstable power swing region, the relay impedance element meets
Criterion A in PRC-026-1 – Attachment B. A system separation angle of 120 degrees was chosen
for the evaluation because it is generally accepted in the industry that recovery for a swing beyond
this angle is unlikely to occur.17
The second bullet of PRC-026-1 – Attachment B, Criterion A, No. 1 evaluates impedance relay
elements at a system separation angle of less than 120 degrees, similar to the first bullet described
above. An angle less than 120 degrees may be used if a documented stability analysis demonstrates
that the power swing becomes unstable at a system separation angle of less than 120 degrees.
The exclusion of relay elements supervised by Power Swing Blocking (PSB) in PRC-026-1 –
Attachment A allows the Generator Owner or Transmission Owner to exclude protective relay
elements if they are blocked from tripping by PSB relays. A PSB relay applied and set according
to industry accepted practices prevent supervised load-responsive protective relays from tripping
in response to power swings. Further, PSB relays are set to allow dependable tripping of supervised
elements. The criteria in PRC-026-1 – Attachment B specifically applies to unsupervised elements
that could trip for stable power swings. Therefore, load-responsive protective relay elements
supervised by PSB can be excluded from the Requirements of this standard.
17
“The critical angle for maintaining stability will vary depending on the contingency and the system condition at
the time the contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is
marginal and 120 degrees is generally accepted as an appropriate basis for setting out‐of‐step protection. Given the
importance of separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a
proper balance between dependable tripping for unstable power swings and secure operation for stable power
swings.” NERC System Protection and Control Subcommittee, Protection System Response to Power Swings,
August 2013: http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20
SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf), p. 28.
Page 24 of 84
PRC-026-1 – Application Guidelines
Figure 1: An enlarged graphic illustrating the unstable power swing region formed by the union
of three shapes in the impedance (R-X) plane: Shape 1) Lower loss-of-synchronism circle,
Shape 2) Upper loss-of-synchronism circle, and Shape 3) Lens. The mho element characteristic
is completely contained within the unstable power swing region (i.e., it does not intersect any
portion of the unstable power swing region), therefore it meets PRC-026-1 – Attachment B,
Criterion A, No. 1.
Page 25 of 84
PRC-026-1 – Application Guidelines
Figure 2: Full graphic of the unstable power swing region formed by the union of the three
shapes in the impedance (R-X) plane: Shape 1) Lower loss-of-synchronism circle, Shape 2)
Upper loss-of-synchronism circle, and Shape 3) Lens. The mho element characteristic is
completely contained within the unstable power swing region, therefore it meets PRC-26-1 –
Attachment B, Criterion A, No.1.
Page 26 of 84
PRC-026-1 – Application Guidelines
Figure 3: System impedances as seen by Relay R (voltage connections are not shown).
Figure 4: The defining unstable power swing region points where the lens shape intersects the
lower and upper loss-of-synchronism circle shapes and where the lens intersects the equal EMF
(electromotive force) power swing.
Page 27 of 84
PRC-026-1 – Application Guidelines
Figure 5: Full table of 31 detailed lens shape point calculations. The bold highlighted rows
correspond to the detailed calculations in Tables 2-7.
Table 2: Example Calculation (Lens Point 1)
This example is for calculating the impedance the first point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (ES) leading
the receiving-end voltage (ER) by 120 degrees. See Figures 3 and 4.
Eq. (6)
=
∠120°
√3
Page 28 of 84
PRC-026-1 – Application Guidelines
Table 2: Example Calculation (Lens Point 1)
230,000∠120°
=
√3
= 132,791∠120°
Eq. (7)
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Positive sequence impedance data (with transfer impedance ZTR set to a large value).
= 2 + 10 Ω
Given:
=
Given:
= 4 + 20 Ω
= 4 + 20 Ω
× 10 Ω
Total impedance between the generators.
=
Eq. (8)
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20) × 10
(4 + 20) Ω + (4 + 20) × 10
=
Ω
Ω
= 4 + 20 Ω
Total system impedance.
=
Eq. (9)
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Total system current from sending-end source.
Eq. (10)
=
=
−
132,791∠120° − 132,791∠0°
(10 + 50 )Ω
= 4,511∠71.3°
The current, as measured by the relay on ZL (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (11)
=
×
+
Page 29 of 84
PRC-026-1 – Application Guidelines
Table 2: Example Calculation (Lens Point 1)
= 4,511∠71.3° ×
(4 + 20) × 10 Ω
(4 + 20) Ω + (4 + 20) × 10
Ω
= 4,511∠71.3°
The voltage, as measured by the relay on ZL (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (12)
=
−
×
= 132,791∠120°
− (2 + 10) Ω × 4,511∠71.3°
= 95,757∠106.1°
The impedance seen by the relay on ZL.
=
Eq. (13)
=
95,757∠106.1°
4,511∠71.3°
= 17.434 + 12.113 Ω
Table 3: Example Calculation (Lens Point 2)
This example is for calculating the impedance second point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (ES) at 70% of
the receiving-end voltage (ER) and leading the receiving-end voltage by 120 degrees. See
Figures 3 and 4.
Eq. (14)
=
=
∠120°
× 70%
√3
230,000∠120°
√3
× 0.70
= 92,953.7∠120°
Eq. (15)
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Positive sequence impedance data (with transfer impedance ZTR set to a large value).
= 2 + 10 Ω
Given:
Given:
=
= 4 + 20 Ω
= 4 + 20 Ω
× 10 Ω
Page 30 of 84
PRC-026-1 – Application Guidelines
Table 3: Example Calculation (Lens Point 2)
Total impedance between the generators.
=
Eq. (16)
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20) × 10
(4 + 20) Ω + (4 + 20) × 10
=
Ω
Ω
= 4 + 20 Ω
Total system impedance.
=
Eq. (17)
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Total system current from sending-end source.
Eq. (18)
=
=
−
92,953.7∠120° − 132,791∠0°
(10 + 50) Ω
= 3,854∠77°
The current, as measured by the relay on ZL (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (19)
=
×
+
= 3,854∠77° ×
(4 + 20) × 10 Ω
(4 + 20) Ω + (4 + 20) × 10
Ω
= 3,854∠77°
The voltage, as measured by the relay on ZL (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (20)
=
−
×
= 92,953∠120° − (2 + 10 )Ω × 3,854∠77°
= 65,271∠99°
The impedance seen by the relay on ZL.
Eq. (21)
=
Page 31 of 84
PRC-026-1 – Application Guidelines
Table 3: Example Calculation (Lens Point 2)
=
65,271∠99°
3,854∠77°
= 15.676 + 6.41 Ω
Table 4: Example Calculation (Lens Point 3)
This example is for calculating the impedance third point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (ER) at 70%
of the sending-end voltage (ES) and the sending-end voltage leading the receiving-end voltage
by 120 degrees. See Figures 3 and 4.
Eq. (22)
∠120°
=
√3
230,000∠120°
=
√3
= 132,791∠120°
Eq. (23)
=
=
∠0°
× 70%
√3
230,000∠0°
√3
× 0.70
= 92,953.7∠0°
Positive sequence impedance data (with transfer impedance ZTR set to a large value).
= 2 + 10 Ω
Given:
Given:
=
= 4 + 20 Ω
= 4 + 20 Ω
× 10 Ω
Total impedance between the generators.
Eq. (24)
=
(
(
=
×
+
)
)
(4 + 20) Ω × (4 + 20) × 10
(4 + 20) Ω + (4 + 20) × 10
Ω
Ω
= 4 + 20 Ω
Total system impedance.
Eq. (25)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Page 32 of 84
PRC-026-1 – Application Guidelines
Table 4: Example Calculation (Lens Point 3)
Total system current from sending-end source.
Eq. (26)
=
=
−
132,791∠120° − 92,953.7∠0°
(10 + 50) Ω
= 3,854∠65.5°
The current, as measured by the relay on ZL (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (27)
=
×
+
= 3,854∠65.5° ×
(4 + 20) × 10 Ω
(4 + 20) Ω + (4 + 20) × 10
Ω
= 3,854∠65.5°
The voltage, as measured by the relay on ZL (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (28)
=
−(
× )
= 132,791∠120°
− (2 + 10) Ω × 3,854∠65.5°
= 98,265∠110.6°
The impedance seen by the relay on ZL.
=
Eq. (29)
=
98,265∠110.6°
3,854∠65.5°
= 18.005 + 18.054 Ω
Table 5: Example Calculation (Lens Point 4)
This example is for calculating the impedance fourth point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (ES) leading
the receiving-end voltage (ER) by 240 degrees. See Figures 3 and 4.
Eq. (30)
=
=
∠240°
√3
230,000∠240°
√3
Page 33 of 84
PRC-026-1 – Application Guidelines
Table 5: Example Calculation (Lens Point 4)
= 132,791∠240°
Eq. (31)
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Positive sequence impedance data (with transfer impedance ZTR set to a large value).
= 2 + 10 Ω
Given:
=
Given:
= 4 + 20 Ω
= 4 + 20 Ω
× 10 Ω
Total impedance between the generators.
=
Eq. (32)
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20) × 10
(4 + 20) Ω + (4 + 20) × 10
=
Ω
Ω
= 4 + 20 Ω
Total system impedance.
=
Eq. (33)
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Total system current from sending-end source.
Eq. (34)
=
=
−
132,791∠240° − 132,791∠0°
(10 + 50 )Ω
= 4,511∠131.3°
The current, as measured by the relay on ZL (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (35)
=
×
+
= 4,511∠131.1° ×
(4 + 20) × 10 Ω
(4 + 20) Ω + (4 + 20) × 10
Ω
= 4,511∠131.1°
Page 34 of 84
PRC-026-1 – Application Guidelines
Table 5: Example Calculation (Lens Point 4)
The voltage, as measured by the relay on ZL (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (36)
−(
=
× )
= 132,791∠240°
− (2 + 10 ) Ω × 4,511∠131.1°
= 95,756∠ − 106.1°
The impedance seen by the relay on ZL.
=
Eq. (37)
=
95,756∠ − 106.1°
4,511∠131.1°
= −11.434 + 17.887 Ω
Table 6: Example Calculation (Lens Point 5)
This example is for calculating the impedance fifth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (ES) at 70% of
the receiving-end voltage (ER) and leading the receiving-end voltage by 240 degrees. See
Figures 3 and 4.
Eq. (38)
=
=
∠240°
× 70%
√3
230,000∠240°
√3
× 0.70
= 92,953.7∠240°
Eq. (39)
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Positive sequence impedance data (with transfer impedance ZTR set to a large value).
= 2 + 10 Ω
Given:
Given:
=
= 4 + 20 Ω
= 4 + 20 Ω
× 10 Ω
Total impedance between the generators.
Eq. (40)
=
(
(
×
+
)
)
Page 35 of 84
PRC-026-1 – Application Guidelines
Table 6: Example Calculation (Lens Point 5)
(4 + 20) Ω × (4 + 20) × 10
(4 + 20) Ω + (4 + 20) × 10
=
Ω
Ω
= 4 + 20 Ω
Total system impedance.
=
Eq. (41)
+
+
= (2 + 10 Ω) + (4 + 20 Ω) + (4 + 20 Ω)
= 10 + 50 Ω
Total system current from sending-end source.
Eq. (42)
=
=
−
92,953.7∠240° − 132,791∠0°
10 + 50 Ω
= 3,854∠125.5°
The current, as measured by the relay on ZL (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (43)
=
×
+
= 3,854∠125.5° ×
(4 + 20) × 10 Ω
(4 + 20) Ω + (4 + 20) × 10
Ω
= 3,854∠125.5°
The voltage, as measured by the relay on ZL (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (44)
=
−(
× )
= 92,953.7∠240°
− (2 + 10 ) Ω × 3,854∠125.5°
= 65,270.5∠ − 99.4°
The impedance seen by the relay on ZL.
Eq. (45)
=
=
65,270.5∠ − 99.4°
3,854∠125.5°
= −12.005 + 11.946 Ω
Page 36 of 84
PRC-026-1 – Application Guidelines
Table 7: Example Calculation (Lens Point 6)
This example is for calculating the impedance sixth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (ER) at 70%
of the sending-end voltage (ES) and the sending-end voltage leading the receiving-end voltage
by 240 degrees. See Figures 3 and 4.
Eq. (46)
∠240°
=
=
√3
230,000∠240°
√3
= 132,791∠240°
∠0°
Eq. (47)
=
× 70%
√3
230,000∠0°
=
× 0.70
√3
= 92,953.7∠0°
Positive sequence impedance data (with transfer impedance ZTR set to a large value).
Given:
= 2 + 10 Ω
= 4 + 20 Ω
= 4 + 20 Ω
Given:
=
× 10 Ω
Total impedance between the generators.
( ×
)
Eq. (48)
=
)
( +
(4 + 20) Ω × (4 + 20) × 10 Ω
=
(4 + 20) Ω + (4 + 20) × 10 Ω
= 4 + 20 Ω
Total system impedance.
= +
+
Eq. (49)
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Total system current from sending-end source.
−
=
Eq. (50)
132,791∠240° − 92,953.7∠0°
10 + 50 Ω
= 3,854∠137.1°
=
Page 37 of 84
PRC-026-1 – Application Guidelines
Table 7: Example Calculation (Lens Point 6)
The current, as measured by the relay on ZL (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (51)
=
×
+
= 3,854∠137.1° ×
(4 + 20) × 10 Ω
(4 + 20) Ω + (4 + 20) × 10
Ω
= 3,854∠137.1°
The voltage, as measured by the relay on ZL (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (52)
= −( × )
= 132,791∠240° − (2 + 10 ) Ω × 3,854∠137.1°
= 98,265∠ − 110.6°
The impedance seen by the relay on ZL.
Eq. (53)
=
98,265∠ − 110.6°
3,854∠137.1°
= −9.676 + 23.59 Ω
=
Page 38 of 84
PRC-026-1 – Application Guidelines
Figure 6: Reduced two bus system with sending-end source impedance ZS, receiving-end
source impedance ZR, line impedance ZL, and parallel transfer impedance ZTR.
Figure 7: Reduced two bus system with sending-end source impedance ZS, receiving-end
source impedance ZR, and line impedance ZL with the parallel transfer impedance ZTR removed.
Page 39 of 84
PRC-026-1 – Application Guidelines
Figure 8: A strong-source system with a line impedance of ZL = 20.4 ohms (i.e., the thicker red
line). This mho element characteristic (i.e., the blue circle) does not meet the PRC-026-1 –
Attachment B, Criterion A because it is not completely contained within the unstable power
swing region (i.e., the orange characteristic).
Figure 8 above represents a heavily-loaded system with all generation in service and all
transmission BES Elements in their normal operating state. The mho element characteristic (set at
137% of ZL) extends into the unstable power swing region (i.e., the orange characteristic). Using
the strongest source system is more conservative because it shrinks the unstable power swing
region, bringing it closer to the mho element characteristic. This figure also graphically represents
the effect of a system strengthening over time and this is the reason for re-evaluation if the relay
has not been evaluated in the last five calendar years. Figure 9 below depicts a relay that meets the
PRC-026-1 – Attachment B, Criterion A. Figure 8 depicts the same relay with the same setting
five years later, where each source has strengthened by about 10% and now the same mho element
characteristic does not meet Criterion A.
Page 40 of 84
PRC-026-1 – Application Guidelines
Figure 9: A weak-source system with a line impedance of ZL = 20.4 ohms (i.e., the thicker red
line). This mho element characteristic (i.e., the blue circle) meets the PRC-026-1 – Attachment
B, Criterion A because it is completely contained within the unstable power swing region (i.e.,
the orange characteristic).
Figure 9 above represents a lightly-loaded system, using a minimum generation profile. The mho
element characteristic (set at 137% of ZL) does not extend into the unstable power swing region
(i.e., the orange characteristic). Using a weaker source system expands the unstable power swing
region away from the mho element characteristic.
Page 41 of 84
PRC-026-1 – Application Guidelines
Figure 10: This is an example of an unstable power swing region (i.e., the orange characteristic)
with the parallel transfer impedance removed. This relay mho element characteristic (i.e., the
blue circle) does not meet PRC-026-1 – Attachment B, Criterion A because it is not completely
contained within the unstable power swing region.
Table 8: Example Calculation (Parallel Transfer Impedance Removed)
Calculations for the point at 120 degrees with equal source impedances. The total system current
equals the line current. See Figure 10.
Eq. (54)
=
=
∠120°
√3
230,000∠120°
√3
= 132,791∠120°
Page 42 of 84
PRC-026-1 – Application Guidelines
Table 8: Example Calculation (Parallel Transfer Impedance Removed)
Eq. (55)
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given impedance data.
= 2 + 10 Ω
Given:
=
Given:
= 4 + 20 Ω
= 4 + 20 Ω
× 10 Ω
Total impedance between the generators.
=
Eq. (56)
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20) × 10
(4 + 20) Ω + (4 + 20) × 10
=
Ω
Ω
= 4 + 20 Ω
Total system impedance.
=
Eq. (57)
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Total system current from sending-end source.
Eq. (58)
=
=
−
132,791∠120° − 132,791∠0°
10 + 50 Ω
= 4,511∠71.3°
The current, as measured by the relay on ZL (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (59)
=
×
+
= 4,511∠71.3° ×
(4 + 20) × 10 Ω
(4 + 20) Ω + (4 + 20) × 10
Ω
= 4,511∠71.3°
Page 43 of 84
PRC-026-1 – Application Guidelines
Table 8: Example Calculation (Parallel Transfer Impedance Removed)
The voltage, as measured by the relay on ZL (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (60)
=
−
×
= 132,791∠120°
− (2 + 10 Ω) × 4,511∠71.3°
= 95,757∠106.1°
The impedance seen by the relay on ZL.
Eq. (61)
=
=
95,757∠106.1°
4,511∠71.3°
= 17.434 + 12.113 Ω
Page 44 of 84
PRC-026-1 – Application Guidelines
Figure 11: This is an example of an unstable power swing region (i.e., the orange characteristic)
with the parallel transfer impedance included causing the mho element characteristic (i.e., the
blue circle) to appear to meet the PRC-026-1 – Attachment B, Criterion A because it is
completely contained within the unstable power swing region. Including the parallel transfer
impedance in the calculation is not allowed by the PRC-026-1 – Attachment B, Criterion A.
In Figure 11 above, the parallel transfer impedance is 5 times the line impedance. The unstable
power swing region has expanded out beyond the mho element characteristic due to the infeed
effect from the parallel current through the parallel transfer impedance, thus allowing the mho
element characteristic to appear to meet the PRC-026-1 – Attachment B, Criterion A. Including
the parallel transfer impedance in the calculation is not allowed by the PRC-026-1 – Attachment
B, Criterion A.
Page 45 of 84
PRC-026-1 – Application Guidelines
Table 9: Example Calculation (Parallel Transfer Impedance Included)
Calculations for the point at 120 degrees with equal source impedances. The total system current
does not equal the line current. See Figure 11.
Eq. (62)
∠120°
=
√3
230,000∠120°
=
√3
= 132,791∠120°
Eq. (63)
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given impedance data.
= 2 + 10 Ω
Given:
Given:
=
= 4 + 20 Ω
= 4 + 20 Ω
×5
= (4 + 20) Ω × 5
= 20 + 100 Ω
Total impedance between the generators.
Eq. (64)
=
(
(
=
(4 + 20) Ω × (20 + 100) Ω
(4 + 20) Ω + (20 + 100) Ω
×
+
)
)
= 3.333 + 16.667 Ω
Total system impedance.
Eq. (65)
=
+
+
= (2 + 10) Ω + (3.333 + 16.667) Ω + (4 + 20) Ω
= 9.333 + 46.667 Ω
Total system current from sending-end source.
Eq. (66)
=
=
−
132,791∠120° − 132,791∠0°
9.333 + 46.667 Ω
Page 46 of 84
PRC-026-1 – Application Guidelines
Table 9: Example Calculation (Parallel Transfer Impedance Included)
= 4,833∠71.3°
The current, as measured by the relay on ZL (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (67)
=
×
+
= 4,833∠71.3° ×
(20 + 100) Ω
(4 + 20) Ω + (20 + 100) Ω
= 4,027.4∠71.3°
The voltage, as measured by the relay on ZL (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (68)
=
−
×
= 132,791∠120°
− (2 + 10 Ω) × 4,833∠71.3°
= 93,417∠104.7°
The impedance seen by the relay on ZL.
Eq. (69)
=
=
93,417∠104.7°
4,027∠71.3°
= 19.366 + 12.767 Ω
Page 47 of 84
PRC-026-1 – Application Guidelines
Table 10: Percent Increase of a Lens Due To Parallel Transfer Impedance.
The following demonstrates the percent size increase of the lens characteristic for ZTR in
multiples of ZL with the parallel transfer impedance included.
ZTR in multiples of ZL
Percent increase of lens with equal EMF
sources (Infinite source as reference)
Infinite
N/A
1000
0.05%
100
0.46%
10
4.63%
5
9.27%
2
23.26%
1
46.76%
0.5
94.14%
0.25
189.56%
Page 48 of 84
PRC-026-1 – Application Guidelines
Figure 12: The tripping portion of the mho element characteristic (i.e., the blue circle) not
blocked by load encroachment (i.e., the parallel green lines) is completely contained within the
unstable power swing region (i.e., the orange characteristic). Therefore, the mho element
characteristic meets the PRC-026-1 – Attachment B, Criterion A.
Page 49 of 84
PRC-026-1 – Application Guidelines
Figure 13: The infeed diagram shows the impedance in front of the relay R with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes ZL + ZR.
Table 11: Calculations (System Apparent Impedance in the forward direction)
The following equations are provided for calculating the apparent impedance back to the ER
source voltage as seen by relay R. Infeed equations from VS to source ER where ER = 0. See
Figure 13.
Eq. (70)
−
=
Eq. (71)
=
Eq. (72)
=
−
+
=
Eq. (73)
−
Eq. (74)
=
Eq. (75)
=
Eq. (76)
=( ×
Eq. (78)
Eq. (79)
=
=
Rearranged:
=
×
×
)×
− ( +
)+( ×
=
Eq. (77)
=0
Since
=
×
×
+
)+(
+
×
×
=
)
+
× 1+
+
+
Page 50 of 84
PRC-026-1 – Application Guidelines
Table 11: Calculations (System Apparent Impedance in the forward direction)
Eq. (80)
=
The infeed equations shows the impedance in front of the relay R (Figure 13) with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes ZL + ZR.
=
Eq. (81)
+
× 1+
Figure 14: The infeed diagram shows the impedance behind relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes ZS.
Table 12: Calculations (System Apparent Impedance in the Reverse Direction)
The following equations are provided for calculating the apparent impedance back to the ES
source voltage as seen by relay R. Infeed equations from VR back to source ES where ES = 0.
See Figure 14.
Eq. (82)
=
Eq. (83)
=
Eq. (84)
=
Eq. (85)
=
Eq. (86)
=
−
−
+
Since
−
=0
Rearranged:
=
×
×
Page 51 of 84
PRC-026-1 – Application Guidelines
Table 12: Calculations (System Apparent Impedance in the Reverse Direction)
− ( +
Eq. (87)
=
Eq. (88)
=( ×
=
Eq. (89)
Eq. (90)
Eq. (91)
Eq. (92)
=
)+( ×
=
×
=
)×
+
)+(
+
×
×
)
=
+
× 1+
+
×
+
=
The infeed equations shows the impedance behind relay R (Figure 14) with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes ZS.
Eq. (93)
=
+
× 1+
Eq. (94)
=
× 1+
As seen by relay R at the receiving-end of
the line.
Subtract ZL for relay R impedance as seen
at sending-end of the line.
Page 52 of 84
PRC-026-1 – Application Guidelines
Figure 15: Out-of-step trip (OST) inner blinder (i.e., the parallel green lines) meets the PRC026-1 – Attachment B, Criterion A because the inner OST blinder initiates tripping either OnThe-Way-In or On-The-Way-Out. Since the inner blinder is completely contained within the
unstable power swing region (i.e., the orange characteristic), it meets the PRC-026-1 –
Attachment B, Criterion A.
Page 53 of 84
PRC-026-1 – Application Guidelines
Table 13: Example Calculation (Voltage Ratios)
These calculations are based on the loss-of-synchronism characteristics for the cases of N < 1
and N > 1 as found in the Application of Out-of-Step Blocking and Tripping Relays, GER-3180,
p. 12, Figure 3.18 The GE illustration shows the formulae used to calculate the radius and center
of the circles that make up the ends of the portion of the lens.
Voltage ratio equations, source impedance equation with infeed formulae applied, and circle
equations.
Given:
= 0.7
Eq. (95)
=
= 1.0
| | 0.7
=
= 0.7
| | 1.0
The total system impedance as seen by the relay with infeed formulae applied.
Given:
= 2 + 10 Ω
=
Given:
=
= 4 + 20 Ω
× 10 Ω
= (4 + 20) × 10
Eq. (96)
= 4 + 20 Ω
× 1+
Ω
+
+
× 1+
= 10 + 50 Ω
The calculated coordinates of the lower loss-of-synchronism circle center.
Eq. (97)
=−
× 1+
−
= − (2 + 10) Ω × 1 +
×
1−
(4 + 20) Ω
(4 + 20) × 10 Ω
−
0.7 × (10 + 50) Ω
1 − 0.7
= −11.608 − 58.039 Ω
The calculated radius of the lower loss-of-synchronism circle.
Eq. (98)
×
1−
0.7 × (10 + 50) Ω
=
1 − 0.7
=
= 69.987 Ω
The calculated coordinates of the upper loss-of-synchronism circle center.
Given:
18
= 1.0
= 0.7
http://store.gedigitalenergy.com/faq/Documents/Alps/GER-3180.pdf
Page 54 of 84
PRC-026-1 – Application Guidelines
Table 13: Example Calculation (Voltage Ratios)
Eq. (99)
Eq. (100)
=
| | 1.0
=
= 1.43
| | 0.7
=
+
× 1+
+
−1
= 4 + 20 Ω + (4 + 20) Ω × 1 +
(4 + 20) Ω
(4 + 20) × 10 Ω
+
(10 + 50) Ω
1.43 − 1
= 17.608 + 88.039 Ω
The calculated radius of the upper loss-of-synchronism circle.
Eq. (101)
=
×
−1
1.43 × (10 + 50) Ω
=
1.43 − 1
= 69.987 Ω
Page 55 of 84
PRC-026-1 – Application Guidelines
Figure 15a: Lower circle loss-of-synchronism region showing the coordinates of the circle
center and the circle radius.
Page 56 of 84
PRC-026-1 – Application Guidelines
Figure 15b: Lower circle loss-of-synchronism region showing the first three steps to calculate
the coordinates of the points on the circle. 1) Identify the lower circle loss-of-synchronism
points that intersect the lens shape where the sending-end to receiving-end voltage ratio is 0.7
(see lens shape calculations in Tables 2-7). 2) Calculate the distance between the two lower
circle loss-of-synchronism points identified in Step 1. 3) Calculate the angle of arc that
connects the two lower circle loss-of-synchronism points identified in Step 1.
Page 57 of 84
PRC-026-1 – Application Guidelines
Figure 15c: Lower circle loss-of-synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1)
Calculate the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4)
Calculate the angle step size for the desired number of points.
Page 58 of 84
PRC-026-1 – Application Guidelines
Figure 15d: Lower circle loss-of-synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R–X coordinates.
Page 59 of 84
PRC-026-1 – Application Guidelines
Figure 15e: Upper circle loss-of-synchronism region showing the coordinates of the circle
center and the circle radius.
Page 60 of 84
PRC-026-1 – Application Guidelines
Figure 15f: Upper circle loss-of-synchronism region showing the first three steps to calculate
the coordinates of the points on the circle. 1) Identify the upper circle points that intersect the
lens shape where the sending-end to receiving-end voltage ratio is 1.43 (see lens shape
calculations in Tables 2-7). 2) Calculate the distance between the two upper circle points
identified in Step 1. 3) Calculate the angle of arc that connects the two upper circle points
identified in Step 1.
Page 61 of 84
PRC-026-1 – Application Guidelines
Figure 15g: Upper circle loss-of-synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1) Calculate
the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4) Calculate the angle
step size for the desired number of points.
Page 62 of 84
PRC-026-1 – Application Guidelines
Figure 15h: Upper circle loss-of-synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R-X coordinates.
Page 63 of 84
PRC-026-1 – Application Guidelines
Figure 15i: Full tables of calculated lower and upper loss-of-synchronism circle coordinates.
The highlighted row is the detailed calculated points in Figures 15d and 15h.
Application Specific to Criterion B
The PRC-026-1 – Attachment B, Criterion B evaluates overcurrent elements used for tripping. The
same criteria as PRC-026-1 – Attachment B, Criterion A is used except for an additional criterion
(No. 4) that calculates a current magnitude based upon generator internal voltage of 1.05 per unit.
A value of 1.05 per unit generator voltage is used to establish a minimum pickup current value for
overcurrent relays that have a time delay less than 15 cycles. The sending-end and receiving-end
voltages are established at 1.05 per unit at 120 degree system separation angle. The 1.05 per unit
is the typical upper end of the operating voltage, which is also consistent with the maximum power
Page 64 of 84
PRC-026-1 – Application Guidelines
transfer calculation using actual system source impedances in the PRC-023 NERC Reliability
Standard. The formulas used to calculate the current are in Table 14 below.
Table 14: Example Calculation (Overcurrent)
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps secondary times a CT ratio of 160:1 that equals 8,000 amps, primary.
The following calculation is where VS equals the base line-to-ground sending-end generator
source voltage times 1.05 at an angle of 120 degrees, VR equals the base line-to-ground
receiving-end generator internal voltage times 1.05 at an angle of 0 degrees, and Zsys equals the
sum of the sending-end source, line, and receiving-end source impedances in ohms.
Here, the instantaneous phase setting of 8,000 amps is greater than the calculated system current
of 5,716 amps; therefore, it meets PRC-026-1 – Attachment B, Criterion B.
Eq. (102)
∠120°
=
× 1.05
√3
230,000∠120°
=
√3
× 1.05
= 139,430∠120°
Receiving-end generator terminal voltage.
Eq. (103)
=
=
∠0°
× 1.05
√3
230,000∠0°
√3
× 1.05
= 139,430∠0°
The total impedance of the system (Zsys) equals the sum of the sending-end source impedance
(ZS), the impedance of the line (ZL), and receiving-end impedance (ZR) in ohms.
Given:
Eq. (104)
= 3 + 26 Ω
=
+
= 1.3 + 8.7 Ω
= 0.3 + 7.3 Ω
+
= (3 + 26) Ω + (1.3 + 8.7) Ω + (0.3 + 7.3) Ω
= 4.6 + 42 Ω
Total system current.
Eq. (105)
=
=
(
−
)
(139,430∠120° − 139,430∠0° )
(4.6 + 42) Ω
= 5,715.82∠66.25°
Page 65 of 84
PRC-026-1 – Application Guidelines
Application Specific to Three-Terminal Lines
If a three-terminal line is identified as an Element that is susceptible to a power swing based on
Requirement R1, the load-responsive protective relays at each end of the three-terminal line must
be evaluated.
As shown in Figure 15j, the source impedances at each end of the line can be obtained from the
similar short circuit calculation as for the two-terminal line (assuming the parallel transfer
impedances are ignored).
EA
A
B
ZSA
ZL2
ZL1
R
ZSB
EB
ZL3
C
ZSC
EC
Figure 15j: Three-terminal line. To evaluate the load-responsive protective relays on the threeterminal line at Terminal A, the circuit in Figure 15j is first reduced to the equivalent circuit
shown in Figure 15k. The evaluation process for the load-responsive protective relays on the
line at Terminal A will now be the same as that of the two-terminal line.
Page 66 of 84
PRC-026-1 – Application Guidelines
Figure 15k: Three-terminal line reduced to a two-terminal line.
Application to Generation Elements
As with transmission BES Elements, the determination of the apparent impedance seen at an
Element located at, or near, a generation Facility is complex for power swings due to various
interdependent quantities. These variances in quantities are caused by changes in machine internal
voltage, speed governor action, voltage regulator action, the reaction of other local generators, and
the reaction of other interconnected transmission BES Elements as the event progresses through
the time domain. Though transient stability simulations may be used to determine the apparent
impedance for verifying load-responsive relay settings,19,20 Requirement R2, PRC-026-1 –
Attachment B, Criteria A and B provides a simplified method for evaluating the load-responsive
protective relay’s susceptibility to tripping in response to a stable power swing without requiring
stability simulations.
In general, the electrical center will be in the transmission system for cases where the generator is
connected through a weak transmission system (high external impedance). In other cases where
the generator is connected through a strong transmission system, the electrical center could be
inside the unit connected zone.21 In either case, load-responsive protective relays connected at the
generator terminals or at the high-voltage side of the generator step-up (GSU) transformer may be
challenged by power swings. Relays that may be challenged by power swings will be determined
by the Planning Coordinator in Requirement R1 or by the Generator Owner after becoming aware
of a generator, transformer, or transmission line BES Element that tripped22 in response to a stable
or unstable power swing due to the operation of its protective relay(s) in Requirement R2.
19
Donald Reimert, Protective Relaying for Power Generation Systems, Boca Raton, FL, CRC Press, 2006.
20
Prabha Kundur, Power System Stability and Control, EPRI, McGraw Hill, Inc., 1994.
21
Ibid, Kundur.
22
See Guidelines and Technical Basis section, “Becoming Aware of an Element That Tripped in Response to a
Power Swing,”
Page 67 of 84
PRC-026-1 – Application Guidelines
Voltage controlled time-overcurrent and voltage-restrained time-overcurrent relays are excluded
from this standard. When these relays are set based on equipment permissible overload capability,
their operating times are much greater than 15 cycles for the current levels observed during a power
swing.
Instantaneous overcurrent, time-overcurrent, and definite-time overcurrent relays with a time delay
of less than 15 cycles for the current levels observed during a power swing are applicable and are
required to be evaluated for identified Elements.
The generator loss-of-field protective function is provided by impedance relay(s) connected at the
generator terminals. The settings are applied to protect the generator from a partial or complete
loss of excitation under all generator loading conditions and, at the same time, be immune to
tripping on stable power swings. It is more likely that the loss-of-field relay would operate during
a power swing when the automatic voltage regulator (AVR) is in manual mode rather than when
in automatic mode.23 Figure 16 illustrates the loss-of-field relay in the R-X plot, which typically
includes up to three zones of protection.
Figure 16: An R-X graph of typical impedance settings for loss-of-field relays.
23
John Burdy, Loss-of-excitation Protection for Synchronous Generators GER-3183, General Electric Company.
Page 68 of 84
PRC-026-1 – Application Guidelines
Loss-of-field characteristic 40-1 has a wider impedance characteristic (positive offset) than
characteristic 40-2 or characteristic 40-3 and provides additional generator protection for a partial
loss of field or a loss of field under low load (less than 10% of rated). The tripping logic of this
protection scheme is established by a directional contact, a voltage setpoint, and a time delay. The
voltage and time delay add security to the relay operation for stable power swings. Characteristic
40-3 is less sensitive to power swings than characteristic 40-2 and is set outside the generator
capability curve in the leading direction. Regardless of the relay impedance setting, PRC-01924
requires that the “in-service limiters operate before Protection Systems to avoid unnecessary trip”
and “in-service Protection System devices are set to isolate or de-energize equipment in order to
limit the extent of damage when operating conditions exceed equipment capabilities or stability
limits.” Time delays for tripping associated with loss-of-field relays25,26 have a range from 15
cycles for characteristic 40-2 to 60 cycles for characteristic 40-1 to minimize tripping during stable
power swings. In PRC-026-1, 15 cycles establishes a threshold for applicability; however, it is the
responsibility of the Generator Owner to establish settings that provide security against stable
power swings and, at the same time, dependable protection for the generator.
The simple two-machine system circuit (method also used in the Application to Transmission
Elements section) is used to analyze the effect of a power swing at a generator facility for loadresponsive relays. In this section, the calculation method is used for calculating the impedance
seen by the relay connected at a point in the circuit.27 The electrical quantities used to determine
the apparent impedance plot using this method are generator saturated transient reactance (X’d),
GSU transformer impedance (XGSU), transmission line impedance (ZL), and the system equivalent
(Ze) at the point of interconnection. All impedance values are known to the Generator Owner
except for the system equivalent. The system equivalent is obtainable from the Transmission
Owner. The sending-end and receiving-end source voltages are varied from 0.0 to 1.0 per unit to
form the lens shape portion of the unstable power swing region. The voltage range of 0.7 to 1.0
results in a ratio range from 0.7 to 1.43. This ratio range is used to form the lower and upper lossof-synchronism circle shapes of the unstable power swing region. A system separation angle of
120 degrees is used in accordance with PRC-026-1 – Attachment B criteria for each loadresponsive protective relay evaluation.
Table 15 below is an example calculation of the apparent impedance locus method based on
Figures 17 and 18.28 In this example, the generator is connected to the 345 kV transmission system
through the GSU transformer and has the listed ratings. Note that the load-responsive protective
relays in this example may have ownership with the Generator Owner or the Transmission Owner.
24
Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection
25
Ibid, Burdy.
26
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
27
Edward Wilson Kimbark, Power System Stability, Volume II: Power Circuit Breakers and Protective Relays,
Published by John Wiley and Sons, 1950.
28
Ibid, Kimbark.
Page 69 of 84
PRC-026-1 – Application Guidelines
Figure 17: Simple one-line diagram of the
system to be evaluated.
Figure 18: Simple system equivalent
impedance diagram to be evaluated.29
Table15: Example Data (Generator)
Input Descriptions
Input Values
Synchronous Generator nameplate (MVA)
940 MVA
= 0.3845 per unit
Saturated transient reactance (940 MVA base)
Generator rated voltage (Line-to-Line)
20
Generator step-up (GSU) transformer rating
880
GSU transformer reactance (880 MVA base)
X
System Equivalent (100 MVA base)
= 16.05%
= 0.00723∠90° per unit
Generator Owner Load-Responsive Protective Relays
Positive Offset Impedance
40-1
Offset = 0.294 per unit
Diameter = 0.294 per unit
Negative Offset Impedance
40-2
Offset = 0.22 per unit
Diameter = 2.24 per unit
Negative Offset Impedance
40-3
Offset = 0.22 per unit
Diameter = 1.00 per unit
21-1
29
Diameter = 0.643 per unit
MTA = 85°
Ibid, Kimbark.
Page 70 of 84
PRC-026-1 – Application Guidelines
Table15: Example Data (Generator)
I (pickup) = 5.0 per unit
50
Transmission Owned Load-Responsive Protective Relays
Diameter = 0.55 per unit
21-2
MTA = 85°
Calculations shown for a 120 degree angle and ES/ER = 1. The equation for calculating ZR is:30
Eq. (106)
=
(1 −
)( ∠ ) + ( )(
∠ −
)
×
Where m is the relay location as a function of the total impedance (real number less than 1)
ES and ER is the sending-end and receiving-end voltages
Zsys is the total system impedance
ZR is the complex impedance at the relay location and plotted on an R-X diagram
All of the above are constants (940 MVA base) while the angle δ is varied. Table 16 below contains
calculations for a generator using the data listed in Table 15.
Table16: Example Calculations (Generator)
The following calculations are on a 940 MVA base.
Given:
= 0.3845
=
Eq. (107)
= 0.17144
+
= 0.06796
+
= 0.3845
+ 0.17144
+ 0.06796
= 0.6239 ∠90°
Eq. (108)
=
Eq. (109)
=
=
30
=
(1 −
0.3845
= 0.6163
0.6239
)( ∠ ) + ( )(
∠ −
)
×
(1 − 0.6163) × (1∠120°) + (0.6163)(1∠0°)
× (0.6239∠90°)
1∠120° − 1∠0°
Ibid, Kimbark.
Page 71 of 84
PRC-026-1 – Application Guidelines
Table16: Example Calculations (Generator)
Z =
0.4244 + 0.3323
× (0.6239∠90°)
−1.5 + 0.866
Z = (0.3116 ∠ − 111.95°) × (0.6239∠90°)
Z = 0.194 ∠ − 21.95°
Z = −0.18 − 0.073
Table 17 lists the swing impedance values at other angles and at ES/ER = 1, 1.43, and 0.7. The
impedance values are plotted on an R-X graph with the center being at the generator terminals for
use in evaluating impedance relay settings.
Table 17: Sample Calculations for a Swing Impedance Chart for Varying Voltages
at the Sending-End and Receiving-End.
ES/ER=1
ES/ER=1.43
ES/ER=0.7
ZR
ZR
ZR
Angle (δ)
(Degrees)
Magnitude
(pu)
Angle
(Degrees)
Magnitude
(pu)
Angle
Magnitude
Angle
(Degrees)
(pu)
(Degrees)
90
0.320
-13.1
0.296
6.3
0.344
-31.5
120
0.194
-21.9
0.173
-0.4
0.227
-40.1
150
0.111
-41.0
0.082
-10.3
0.154
-58.4
210
0.111
-25.9
0.082
190.3
0.154
238.4
240
0.194
201.9
0.173
180.4
0.225
220.1
270
0.320
193.1
0.296
173.7
0.344
211.5
Requirement R2 Generator Examples
Distance Relay Application
Based on PRC-026-1 – Attachment B, Criterion A, the distance relay (21-1) (i.e., owned by the
Generation Owner) characteristic is in the region where a stable power swing would not occur as
shown in Figure 19. There is no further obligation to the owner in this standard for this loadresponsive protective relay.
The distance relay (21-2) (i.e., owned by the Transmission Owner) is connected at the high-voltage
side of the GSU transformer and its impedance characteristic is in the region where a stable power
swing could occur causing the relay to operate. In this example, if the intentional time delay of this
relay is less than 15 cycles, the PRC-026 – Attachment B, Criterion A cannot be met, thus the
Transmission Owner is required to create a CAP (Requirement R3). Some of the options include,
Page 72 of 84
PRC-026-1 – Application Guidelines
but are not limited to, changing the relay setting (i.e., impedance reach, angle, time delay), modify
the scheme (i.e., add PSB), or replace the Protection System. Note that the relay may be excluded
from this standard if it has an intentional time delay equal to or greater than 15 cycles.
Figure 19: Swing impedance graph for impedance relays at a generating facility.
Loss-of-Field Relay Application
In Figure 20, the R-X diagram shows the loss-of-field relay (40-1 and 40-2) characteristics are in
the region where a stable power swing can cause a relay operation. Protective relay 40-1 would
be excluded if it has an intentional time delay equal to or greater than 15 cycles. Similarly, 40-2
would be excluded if its intentional time delay is equal to or greater than 15 cycles. For example,
if 40-1 has a time delay of 1 second and 40-2 has a time delay of 0.25 seconds, they are excluded
and there is no further obligation on the Generator Owner in this standard for these relays. The
Page 73 of 84
PRC-026-1 – Application Guidelines
loss-of-field relay characteristic 40-3 is entirely inside the unstable power swing region. In this
case, the owner may select high speed tripping on operation of the 40-3 impedance element.
Figure 20: Typical R-X graph for loss-of-field relays with a portion of the unstable power swing
region defined by PRC-026-1 – Attachment B, Criterion A.
Instantaneous Overcurrent Relay
In similar fashion to the transmission line overcurrent example calculation in Table 14, the
instantaneous overcurrent relay minimum setting is established by PRC-026-1 – Attachment B,
Criterion B. The solution is found by:
Eq. (110)
=
−
sys
As stated in the relay settings in Table 15, the relay is installed on the high-voltage side of the GSU
transformer with a pickup of 5.0 per unit. The maximum allowable current is calculated below.
=
(1.05∠120° − 1.05∠0°)
0.6239∠90°
Page 74 of 84
PRC-026-1 – Application Guidelines
=
1.819∠150°
0.6239∠90°
= 2.91 ∠60°
The instantaneous phase setting of 5.0 per unit is greater than the calculated system current of 2.91
per unit; therefore, it meets the PRC-026-1 – Attachment B, Criterion B.
Out-of-Step Tripping for Generation Facilities
Out-of-step protection for the generator generally falls into three different schemes. The first
scheme is a distance relay connected at the high-voltage side of the GSU transformer with the
directional element looking toward the generator. Because this relay setting may be the same
setting used for generator backup protection (see Requirement R2 Generator Examples, Distance
Relay Application), it is susceptible to tripping in response to stable power swings and would
require modification. Because this scheme is susceptible to tripping in response to stable power
swings and any modification to the mho circle will jeopardize the overall protection of the outof-step protection of the generator, available technical literature does not recommend using this
scheme specifically for generator out-of-step protection. The second and third out-of-step
Protection System schemes are commonly referred to as single and double blinder schemes.
These schemes are installed or enabled for out-of-step protection using a combination of
blinders, a mho element, and timers. The combination of these protective relay functions
provides out-of-step protection and discrimination logic for stable and unstable power swings.
Single blinder schemes use logic that discriminate between stable and unstable power swings by
issuing a trip command after the first slip cycle. Double blinder schemes are more complex than
the single blinder scheme and, depending on the settings of the inner blinder, a trip for a stable
power swing may occur. While the logic discriminates between stable and unstable power
swings in either scheme, it is important that the trip initiating blinders be set at an angle greater
than the stability limit of 120 degrees to remove the possibility of a trip for a stable power swing.
Below is a discussion of the double blinder scheme.
Double Blinder Scheme
The double blinder scheme is a method for measuring the rate of change of positive sequence
impedance for out-of-step swing detection. The scheme compares a timer setting to the actual
elapsed time required by the impedance locus to pass between two impedance characteristics. In
this case, the two impedance characteristics are simple blinders, each set to a specific resistive
reach on the R-X plane. Typically, the two blinders on the left half plane are the mirror images of
those on the right half plane. The scheme typically includes a mho characteristic which acts as a
starting element, but is not a tripping element.
The scheme detects the blinder crossings and time delays as represented on the R-X plane as
shown in Figure 21. The system impedance is composed of the generator transient (Xd’), GSU
transformer (XT), and transmission system (Xsystem), impedances.
The scheme logic is initiated when the swing locus crosses the outer Blinder R1 (Figure 21), on
the right at separation angle α. The scheme only commits to take action when a swing crosses the
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inner blinder. At this point the scheme logic seals in the out-of-step trip logic at separation angle
β. Tripping actually asserts as the impedance locus leaves the scheme characteristic at separation
angle δ.
The power swing may leave both inner and outer blinders in either direction, and tripping will
assert. Therefore, the inner blinder must be set such that the separation angle β is large enough
that the system cannot recover. This angle should be set at 120 degrees or more. Setting the angle
greater than 120 degrees satisfies the PRC-026-1 – Attachment B, Criterion A (No. 1, 1st bullet)
since the tripping function is asserted by the blinder element. Transient stability studies may
indicate that a smaller stability limit angle is acceptable under PRC-026-1 – Attachment B,
Criterion A (No. 1, 2nd bullet). In this respect, the double blinder scheme is similar to the double
lens and triple lens schemes and many transmission application out-of-step schemes.
Figure 21: Double Blinder Scheme generic out of step characteristics.
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PRC-026-1 – Application Guidelines
Figure 22 illustrates a sample setting of the double blinder scheme for the example 940 MVA
generator. The only setting requirement for this relay scheme is the right inner blinder, which
must be set greater than the separation angle of 120 degrees (or a lesser angle based on a
transient stability study) to ensure that the out-of-step protective function is expected to not trip
in response to a stable power swing during non-Fault conditions. Other settings such as the mho
characteristic, outer blinders, and timers are set according to transient stability studies and are not
a part of this standard.
Figure 22: Double Blinder Out-of-Step Scheme with unit impedance data and load-responsive
protective relay impedance characteristics for the example 940 MVA generator, scaled in relay
secondary ohms.
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PRC-026-1 – Application Guidelines
Requirement R3
To achieve the stated purpose of this standard, which is to ensure that relays are expected to not
trip in response to stable power swings during non-Fault conditions, this Requirement ensures
that the applicable entity develops a Corrective Action Plan (CAP) that reduces the risk of relays
tripping in response to a stable power swing during non-Fault conditions that may occur on any
applicable BES Element.
Requirement R4
To achieve the stated purpose of this standard, which is to ensure that load-responsive protective
relays are expected to not trip in response to stable power swings during non-Fault conditions, the
applicable entity is required to implement any CAP developed pursuant to Requirement R3 such
that the Protection System will meet PRC-026-1 – Attachment B criteria or can be excluded under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay
functions are supervised by power swing blocking or using relay systems that are immune to power
swings), while maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the BES Element). Protection System owners are
required in the implementation of a CAP to update it when actions or timetable change, until all
actions are complete. Accomplishing this objective is intended to reduce the occurrence of
Protection System tripping during a stable power swing, thereby improving reliability and
minimizing risk to the BES.
The following are examples of actions taken to complete CAPs for a relay that did not meet PRC026-1 – Attachment B and could be at-risk of tripping in response to a stable power swing during
non-Fault conditions. A Protection System change was determined to be acceptable (without
diminishing the ability of the relay to protect for faults within its zone of protection).
Example R4a: Actions: Settings were issued on 6/02/2015 to reduce the Zone 2 reach of
the impedance relay used in the directional comparison unblocking (DCUB) scheme from
30 ohms to 25 ohms so that the relay characteristic is completely contained within the lens
characteristic identified by the criterion. The settings were applied to the relay on
6/25/2015. CAP was completed on 06/25/2015.
Example R4b: Actions: Settings were issued on 6/02/2015 to enable out-of-step blocking
on the existing microprocessor-based relay to prevent tripping in response to stable power
swings. The setting changes were applied to the relay on 6/25/2015. CAP was completed
on 06/25/2015.
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PRC-026-1 – Application Guidelines
The following is an example of actions taken to complete a CAP for a relay responding to a stable
power swing that required the addition of an electromechanical power swing blocking relay.
Example R4c: Actions: A project for the addition of an electromechanical power swing
blocking relay to supervise the Zone 2 impedance relay was initiated on 6/5/2015 to prevent
tripping in response to stable power swings. The relay installation was completed on
9/25/2015. CAP was completed on 9/25/2015.
The following is an example of actions taken to complete a CAP with a timetable that required
updating for the replacement of the relay.
Example R4d: Actions: A project for the replacement of the impedance relays at both
terminals of line X with line current differential relays was initiated on 6/5/2015 to prevent
tripping in response to stable power swings. The completion of the project was postponed
due to line outage rescheduling from 11/15/2015 to 3/15/2016. Following the timetable
change, the impedance relay replacement was completed on 3/18/2016. CAP was
completed on 3/18/2016.
The CAP is complete when all the documented actions to remedy the specific problem (i.e.,
unnecessary tripping during stable power swings) are completed.
Justification for Including Unstable Power Swings in the Requirements
Protection Systems that are applicable to the Standard and must be secure for a stable power swing
condition (i.e., meets PRC-026-1 – Attachment B criteria) are identified based on Elements that
are susceptible to both stable and unstable power swings. This section provides an example of why
Elements that trip in response to unstable power swings (in addition to stable power swings) are
identified and that their load-responsive protective relays need to be evaluated under PRC-026-1
– Attachment B criteria.
Figure 23: A simple electrical system where two lines tie a small utility to a much larger
interconnection.
In Figure 23 the relays at circuit breakers 1, 2, 3, and 4 are equipped with a typical overreaching
Zone 2 pilot system, using a Directional Comparison Blocking (DCB) scheme. Internal faults (or
power swings) will result in instantaneous tripping of the Zone 2 relays if the measured fault or
power swing impedance falls within the zone 2 operating characteristic. These lines will trip on
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PRC-026-1 – Application Guidelines
pilot Zone 2 for out-of-step conditions if the power swing impedance characteristic enters into
Zone 2. All breakers are rated for out-of-phase switching.
Figure 24: In this case, the Zone 2 element on circuit breakers 1, 2, 3, and 4 did not meet the
PRC-026-1 – Attachment B criteria (this figure depicts the power swing as seen by relays on
breakers 3 and 4).
In Figure 24, a large disturbance occurs within the small utility and its system goes out-of-step
with the large interconnect. The small utility is importing power at the time of the disturbance. The
actual power swing, as shown by the solid green line, enters the Zone 2 relay characteristic on the
terminals of Lines 1, 2, 3, and 4 causing both lines to trip as shown in Figure 25.
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PRC-026-1 – Application Guidelines
1
Line 1
3
Large
Small
Utility
2
Line 2
4
Interconnect
Figure 25: Islanding of the small utility due to Lines 1 and 2 tripping in response to an unstable
power swing.
In Figure 25, the relays at circuit breakers 1, 2, 3, and 4 have correctly tripped due to the unstable
power swing (shown by the dashed green line in Figure 24), de-energizing Lines 1 and 2, and
creating an island between the small utility and the big interconnect. The small utility shed 500
MW of load on underfrequency and maintained a load to generation balance.
Figure 26: Line 1 is out-of-service for maintenance, Line 2 is loaded beyond its normal rating
(but within its emergency rating).
Subsequent to the correct tripping of Lines 1 and 2 for the unstable power swing in Figure 25,
another system disturbance occurs while the system is operating with Line 1 out-of-service for
maintenance. The disturbance causes a stable power swing on Line 2, which challenges the relays
at circuit breakers 2 and 4 as shown in Figure 27.
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PRC-026-1 – Application Guidelines
Figure 27: Relays on circuit breakers 2 and 4 were not addressed to meet the PRC-026-1 –
Attachment B criteria following the previous unstable power swing event.
If the relays on circuit breakers 2 and 4 were not addressed under the Requirements for the previous
unstable power swing condition, the relays would trip in response to the stable power swing, which
would result in unnecessary system separation, load shedding, and possibly cascading or blackout.
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PRC-026-1 – Application Guidelines
1
Line 1
3
Large
Small
Utility
2
Line 2
4
Interconnect
Figure 28: Possible blackout of the small utility.
If the relays that tripped in response to the previous unstable power swing condition in Figure 24
were addressed under the Requirements to meet PRC-026-1 - Attachment B criteria, the
unnecessary tripping of the relays for the stable power swing shown in Figure 28 would have been
averted, and the possible blackout of the small utility would have been avoided.
Rationale
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from the rationale
text boxes was moved to this section.
Rationale for R1
The Planning Coordinator has a wide-area view and is in the position to identify generator,
transformer, and transmission line BES Elements which meet the criteria, if any. The criteria-based
approach is consistent with the NERC System Protection and Control Subcommittee (SPCS)
technical document Protection System Response to Power Swings, August 2013 (“PSRPS
Report”),31 which recommends a focused approach to determine an at-risk BES Element. See the
Guidelines and Technical Basis for a detailed discussion of the criteria.
Rationale for R2
The Generator Owner and Transmission Owner are in a position to determine whether their loadresponsive protective relays meet the PRC-026-1 – Attachment B criteria. Generator, transformer,
and transmission line BES Elements are identified by the Planning Coordinator in Requirement
R1 and by the Generator Owner and Transmission Owner following an actual event where the
Generator Owner and Transmission Owner became aware (i.e., through an event analysis or
31
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August
2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
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PRC-026-1 – Application Guidelines
Protection System review) tripping was due to a stable or unstable power swing. A period of 12
calendar months allows sufficient time for the entity to conduct the evaluation.
Rationale for R3
To meet the reliability purpose of the standard, a CAP is necessary to ensure the entity’s Protection
System meets the PRC-026-1 – Attachment B criteria (1st bullet) so that protective relays are
expected to not trip in response to stable power swings. A CAP may also be developed to modify
the Protection System for exclusion under PRC-026-1 – Attachment A (2nd bullet). Such an
exclusion will allow the Protection System to be exempt from the Requirement for future events.
The phrase, “…while maintaining dependable fault detection and dependable out-of-step
tripping…” in Requirement R3 describes that the entity is to comply with this standard, while
achieving their desired protection goals. Refer to the Guidelines and Technical Basis, Introduction,
for more information.
Rationale for R4
Implementation of the CAP must accomplish all identified actions to be complete to achieve the
desired reliability goal. During the course of implementing a CAP, updates may be necessary for
a variety of reasons such as new information, scheduling conflicts, or resource issues.
Documenting CAP changes and completion of activities provides measurable progress and
confirmation of completion.
Rationale for Attachment B (Criterion A)
The PRC-026-1 – Attachment B, Criterion A provides a basis for determining if the relays are
expected to not trip for a stable power swing having a system separation angle of up to 120 degrees
with the sending-end and receiving-end voltages varying from 0.7 to 1.0 per unit (See Guidelines
and Technical Basis).
Page 84 of 84
Exhibit B
Implementation Plan
Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power
Swings
Requested Approvals
PRC-026-1 – Relay Performance During Stable Power Swings
Requested Retirements
None.
Prerequisite Approvals
None.
General Considerations
There are a number of factors that influenced the determination of an implementation period for the
new proposed standard. The following factors may be specific to one or more of the applicable entities
listed below.
1. The effort and resources for all applicable entities to develop or modify internal processes
and/or procedures.
2. The effort and resources for the Planning Coordinator to begin identifying Element(s) according
to the criteria in Requirement R1 is based on existing information (e.g., the most recent
Planning Assessment).
3. The notification of Elements in Requirement R1 is based on the Planning Coordinator’s existing
studies (i.e., annual Planning Assessments) and there will be minimal additional effort to
identify Elements according to the criteria.
4. The need for the Generator Owner or Transmission Owner to plan for and secure resources
(e.g., availability of consultants, if needed) to address the initial influx of Element notifications
from the Planning Coordinator during the implementation period of Requirement R2.
Applicable Entities
Generator Owner
Planning Coordinator
Transmission Owner
Effective Dates
Requirement R1
First day of the first full calendar year that is 12 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 12 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Requirements R2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 36 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Notifications Prior to the Effective Date of Requirement R2
The implementation plan is designed such that the Planning Coordinator will begin notifying the
respective Generator Owners and Transmission Owners of any Elements in Requirement R1 based on
the effective date language. The 36 months for the Generator Owner and Transmission Owner in
Requirement R2 (and Requirements R3 and R4) to become compliant is intended to allow the entity an
opportunity to address the initial influx of identified Elements in Requirement R1. There is no
obligation on the Generator Owner or Transmission Owner to perform Requirement R2, R3, or R4 until
the effective date of these Requirements. Although there is no compliance obligation during the 36
month implementation period, an entity will have the full obligation of Requirements R2, R3, and R4
following the 36 month period. The 36 month implementation period also allows an opportunity for
the entity to establish the evaluation of load-responsive protective relays pursuant to Requirement R2
which will provide the point in time that the five year re-evaluation of such relays will occur.
Justification
The implementation plan is based on the general considerations above and provides sufficient time for
the Generator Owner, Planning Coordinator, and Transmission Owner to begin becoming compliant
with the standard. The Effective date is constructed such that once the standard is adopted or
approved it would become effective on the first day of the first whole calendar year that is 12 months
for Requirement R1 and 36 months for Requirements R2, R3, and R4 after applicable adoption or
approval.
Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power Swings
2
Requirement R1 – The Planning Coordinator will have at least one full calendar year to prepare
itself to identify any generator, transformer, and transmission line BES Elements that meet the
criteria and notify the respective Generator Owner and Transmission Owner of identified
Elements, if any, within the allotted timeframe.
Requirement R2 – The Generator Owner and Transmission Owner will have 36 calendar months
to determine if its load-responsive protective relays for an identified Element pursuant to
Requirement R1 meet the PRC-026-1 – Attachment B criteria for the initial influx of Elements.
Also, both entities are provided an implementation that will allow the entity to conduct initial
evaluations of its load-responsive protective relays for an identified Element during the first 36
calendar months of approval.
Requirement R3 – The implementation period for the development of a Corrective Action Plan
(CAP) is set to be consistent with Requirement R2 to begin during the fourth calendar year of
adoptions or approvals to address any load-responsive protective relays determined in
Requirement R2 not to meet the PRC-026-1 – Attachment B criteria.
Requirement R4 – The implementation period for this Requirement is set to be consistent with
Requirement R3, the development of a CAP.
Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power Swings
3
Exhibit C
Order No. 672 Criteria
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
Please refer to Section VI.A and VI.B of NERC’s petition.
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
is required and who is required to comply.3
Please refer to Section VI.B.2 of NERC’s petition.
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 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.
Order No. 672 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.
3
Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any user, owner,
or operator of such facilities, but not on others.
Order No. 672 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 Bulk-Power System must know
what they are required to do to maintain reliability.
1
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. The assignments of the severity levels for the VSLs are consistent with the
corresponding Requirement and will ensure uniformity and consistency in the determination of
penalties. The VSLs do not use any ambiguous terminology, and support uniformity and
consistency in the determination of similar penalties for similar violations. For these reasons, the
proposed Reliability Standard includes clear and understandable consequences. Justification and
explanation of the VRFs and VSLs is included in Exhibit F.
4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and nonpreferential manner.5
The proposed Reliability Standard contains Measures that support the Requirements by
clearly identifying what is required and how the Requirements will be measured for compliance.
The Measures are listed after each of the Requirements of the proposed PRC-026-1 Reliability
Standard. The Measures provide clarity on the types of evidence to support each Requirement
and will allow the Requirements to be enforced in a consistent and non-preferential manner.
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
4
Order No. 672 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.
5
Order No. 672 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
Order No. 672 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.
2
The proposed Reliability Standard achieves its reliability goal effectively and efficiently
in accordance with Order No. 672. The proposed Reliability Standard appropriately narrows the
applicable Facilities to generator, transformer, and transmission line Bulk Electric System
Elements identified by the Planning Coordinator using specific criteria for which Bulk Electric
System Elements would be at-risk to power swings, similar to the criteria used determine the
applicability of PRC-023, and by the Generator Owner and Transmission Owner upon becoming
aware of Bulk Electric System Elements that actually trip in response to power swings.
Additionally, the Applicability section of the proposed Standard only includes those protective
systems that are not immune to operating in response to power swings. This also includes loadresponsive protective relays associated with backup protection for the applicable Element
meeting the proposed Reliability Standard’s criteria, without regard to the various zones of
protection, when the relay has an intentional time delay of less than 15 cycles or no time delay
(i.e., instantaneous). As a result, the standard drafting team has taken the most efficient approach
to addressing the Commission’s concern in Order No. 733.
The standard drafting team did not adopt the Commission’s approach requiring the use of
protective relay systems that can differentiate between faults and stable power swings and, when
necessary, phasing out protective relay systems that cannot meet this requirement. Given the
relative risks associated with a lack of dependable operation for unstable power swings and the
lack of secure operation for stable swings, it is generally preferable to emphasize dependability
over security when it is not possible to ensure both for all possible system conditions.
Prohibiting use of certain types of relays, such as those protective relay systems that cannot
differentiate between faults and stable power swings, may have unintended negative outcomes
3
for Bulk‐Power System reliability. It is important to note that NERC’s proposed Reliability
Standard does not restrict or discourage entities from employing any technically viable solutions.
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. The standard drafting team continuously sought to meet industry concerns and
continue to maintain essential elements in the proposed Reliability Standard to effectively meet
the purpose statement of the proposed Reliability Standard. The proposed Reliability Standard is
consistent with the technical input received from the SPCS in the SPCS Report. In all drafts of
the proposed Reliability Standard balloted by industry, the standard drafting team determined
that the proposed Reliability Standard was tailored to meet the reliability purpose of the proposed
Reliability Standard. Each draft supported the goal of making certain that Protection Systems
are secure to prevent unnecessary operation during stable power swings and provide dependable
means to separate the system in the event of an unstable power swing.
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,
7
Order No. 672 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 socalled “lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
Although FERC 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.
Order No. 672 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 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.
4
and regional variations in market design if these affect the proposed Reliability
Standard.8
The proposed Reliability Standard applies throughout North America and does not favor one
geographic area or regional model.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability.9
Proposed Reliability Standard PRC-026-1 has no undue negative effect on competition and
does not unreasonably restrict transmission or generation operation on the Bulk-Power System.
9. The implementation time for the proposed Reliability Standard is reasonable.10
The time for transition in the Implementation Plan is reasonable. As noted in the
Implementation Plan, there are a number of factors that influenced the determination of an
implementation period for the proposed Reliability Standard. The additional time for
implementation is necessary to account for the effort and resources for all applicable entities to
develop or modify internal processes and procedures to comply with the proposed Reliability
Standard. Planning Coordinators will need time to begin identifying Element(s) according to the
criteria in Requirement R1 based on existing information (e.g., the most recent Planning
8
Order No. 672 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.
9
Order No. 672 at P 332. As directed by section 215 of the FPA, FERC 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
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable,
FERC 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.
5
Assessment). Time is also needed for the Generator Owner or Transmission Owner to plan for
and secure resources (e.g., availability of consultants, if needed) to address the initial influx of
Element notifications from the Planning Coordinator during the implementation period of
Requirement R2. Additional explanation of the timeframes for implementation is included in
Exhibit B in the “Justification” section of the Implementation Plan. Specifically, the
Implementation Plan contains discussion of the implementation timeframes of each Requirement
relative to the other Requirements.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process.11
The proposed Reliability Standard was developed in accordance with NERC’s Commissionapproved, ANSI- accredited processes for developing and approving Reliability Standards.
Exhibit G includes a summary of the standard development proceedings, and details the
processes followed to develop the proposed Reliability Standard. These processes included,
among other things, multiple 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.12
11
Order No. 672 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 Commission-approved
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 FERC.
12
Order No. 672 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.
6
NERC has not identified competing public interests regarding the request for approval of the
proposed Reliability Standard. No comments were received that indicated the proposed
Reliability Standard conflicts with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors.13
No other factors relevant to whether the proposed Reliability Standard is just and reasonable
were identified.
13
Order No. 672 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.
7
Exhibit D
Consideration of Issues and Directives
Table of Issues and Directives
Project 2010-13.3 – Relay Loadability: Stable Power Swings
Table of Issues and Directives Associated with PRC-026-1
Source
FERC
Order
733
1
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
150. We will not direct the ERO to modify All requirements
PRC-023-1 to address stable power
swings. However, because both NERC and
the Task Force have identified
undesirable relay operation due to stable
power swings as a reliability issue, we
direct the ERO to develop a Reliability
Standard that requires the use of
protective relay systems that can
differentiate between faults and stable
power swings and, when necessary,
phases out protective relay systems that
cannot meet this requirement.
Consideration of Issue or Directive
The PRC-026-1 standard is responsive to this directive by using
an equally effective and efficient focused approach for the
Planning Coordinator to provide notification of BES Elements
according to the Requirement R1 criteria to the respective
Generator Owner and Transmission Owner. The criteria used
to identify a BES Element are based on the NERC System
Protection and Control Subcommittee technical document,
Protection System Response to Power Swings (“PSRPS
Report”).1 The specific criteria are based on where power
swings are expected to challenge load-responsive protective
relays.
The criteria include 1) Generator(s) where an angular stability
constraint exists that is addressed by a System Operating Limit
(SOL) or a Remedial Action Scheme (RAS) and those Elements
NERC System Protection and Control Subcommittee technical document, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf
We also direct the ERO to file a report no
later than 120 days of this Final Rule
addressing the issue of protective relay
operation due to power swings. The
report should include an action plan and
timeline that explains how and when the
ERO intends to address this issue through
its Reliability Standards development
process.
AND
153. While we recognize that addressing
stable power swings is a complex issue,
we note that more than six years have
passed since the August 2003 blackout
and there is still no Reliability Standard
that addresses relays tripping due to
stable power swings. Additionally, NERC
has long identified undesirable relay
operation due to stable power swings as
a reliability issue. Consequently, pursuant
to section 215(d)(5) of the FPA, we find
that undesirable relay operation due to
stable power swings is a specific matter
that the ERO must address to carry out
the goals of section 215, and we direct
the ERO to develop a Reliability Standard
Table of Issues and Directives
Project 2010-13.3 – Relay Loadability: Stable Power Swings
terminating at the Transmission station associated with the
generator(s); 2) An Element that is monitored as part of an SOL
identified by the Planning Coordinator’s methodology based on
an angular stability constraint; 3)
An Element that forms
the boundary of an island in the most recent underfrequency
load shedding (UFLS) design assessment based on application
of the Planning Coordinator’s criteria for identifying islands,
only if the island is formed by tripping the Element based on
angular instability; 4) An Element identified in the most recent
annual Planning Assessment where relay tripping occurs due to
a stable or unstable power swing during a simulated
disturbance.
Requirement R2 requires the Generator Owner and
Transmission Owner to evaluate their load-responsive
protective relays that are applied at all of the terminals of each
BES Element identified by the Planning Coordinator in
Requirement R1 or upon becoming aware of a generator,
transformer, or transmission line BES Element that tripped in
response to a stable or unstable power swing due to the
operation of their protective relay(s). The initial evaluation
allows the Generator Owner and Transmission Owner to
determine whether their load-responsive protective relays
applied at all of the terminals of the BES Element meet the
PRC-026-1 – Attachment B criteria. Additionally, the
Requirement ensures that the Generator Owner and
Transmission Owner must re-evaluate the Protection System
2
addressing undesirable relay operation
due to stable power swings.
on a five year basis should the BES Element continue to be
identified by the Planning Coordinator in Requirement R1.
Requirement R3 mandates the development of a Corrective
Action Plan (CAP) such that the Protection System of a BES
Element will meet the PRC-026-1 –Attachment B criteria or the
Protection System can be excluded under the PRC-026-1 –
Attachment A criteria (e.g., modifying the Protection System so
that relay functions are supervised by power swing blocking or
using relay systems that are immune to power swings).
Requirement R4 mandates that the Generator Owner and
Transmission Owner implement each developed CAP in
Requirement R3 so that load-responsive protective relays are
expected to not trip in response to stable power swings during
non-Fault conditions.
162. The PSEG Companies also assert that Requirement R1,
the Commission’s approach to stable
Criterion 3
power swings should be inclusive and
include “islanding” strategies in
conjunction with out-of-step blocking or
tripping requirements. We agree with the
PSEG Companies and direct the ERO to
consider “islanding” strategies that
achieve the fundamental performance for
all islands in developing the new
Table of Issues and Directives
Project 2010-13.3 – Relay Loadability: Stable Power Swings
Islanding strategies were considered during the development
of the proposed standard. It was determined that islanding
strategies are not an appropriate method to meet the purpose
of the proposed standard. Islanding strategies are developed
to isolate the system from unstable power swings, which is not
prohibited under the proposed standard. The proposed
standard’s intent is to ensure that load-responsive protective
relays are expected to not trip in response to stable power
swings during non-Fault conditions, while maintaining
dependable fault detection and dependable out-of-step
3
Reliability Standard addressing stable
power swings.
Table of Issues and Directives
Project 2010-13.3 – Relay Loadability: Stable Power Swings
tripping (if out-of-step tripping is applied at the terminal of the
BES Element).
4
Exhibit E
NERC System Protection and Control Subcommittee: Protection System Response to Power Swings
Protection System
Response to Power Swings
System Protection and Control Subcommittee
August 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
NERC | Protection System Response to Power Swings | March 6, 2013
404-446-2560 | www.nerc.com
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NERC’s Mission
The North American Electric Reliability Corporation (NERC) is an international regulatory authority established to enhance
the reliability of the Bulk‐Power System in North America. NERC develops and enforces Reliability Standards; assesses
adequacy annually via a ten‐year forecast and winter and summer forecasts; monitors the Bulk‐Power System; and
educates, trains, and certifies industry personnel. NERC is the electric reliability organization for North America, subject to
oversight by the U.S. Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada.1
NERC assesses and reports on the reliability and adequacy of the North American Bulk‐Power System, which is divided into
eight Regional areas, as shown on the map and table below. The users, owners, and operators of the Bulk‐Power System
within these areas account for virtually all the electricity supplied in the U.S., Canada, and a portion of Baja California Norte,
México.
NERC Regional Entities
Note: The highlighted area between SPP RE and
SERC denotes overlapping Regional area
boundaries. For example, some load serving
entities participate in one Region and their
associated transmission owner/operators in
another.
FRCC
Florida Reliability
Coordinating Council
SERC
SERC Reliability Corporation
MRO
Midwest Reliability
Organization
SPP RE
Southwest Power Pool
Regional Entity
NPCC
Northeast Power
Coordinating Council
TRE
Texas Reliability Entity
RFC
ReliabilityFirst Corporation
WECC
Western Electricity
Coordinating Council
1
As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce Reliability
Standards with all U.S. users, owners, and operators of the Bulk‐Power System, and made compliance with those standards mandatory
and enforceable. In Canada, NERC presently has memorandums of understanding in place with provincial authorities in Ontario, New
Brunswick, Nova Scotia, Québec, and Saskatchewan, and with the Canadian National Energy Board. NERC standards are mandatory and
enforceable in Ontario and New Brunswick as a matter of provincial law. NERC has an agreement with Manitoba Hydro making Reliability
Standards mandatory for that entity, and Manitoba has recently adopted legislation setting out a framework for standards to become
mandatory for users, owners, and operators in the province. In addition, NERC has been designated as the “electric reliability
organization” under Alberta’s Transportation Regulation, and certain Reliability Standards have been approved in that jurisdiction; others
are pending. NERC and NPCC have been recognized as standards‐setting bodies by the Régie de l’énergie of Québec, and Québec has the
framework in place for Reliability Standards to become mandatory. NERC’s Reliability Standards are also mandatory in Nova Scotia and
British Columbia. NERC is working with the other governmental authorities in Canada to achieve equivalent recognition.
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Table of Contents
NERC’s Mission ............................................................................................................................................................................ 2
Table of Contents ......................................................................................................................................................................... 3
Executive Summary ..................................................................................................................................................................... 5
Introduction ................................................................................................................................................................................. 6
Issue Statement ....................................................................................................................................................................... 6
Chapter 1 – Historical Perspective ............................................................................................................................................... 7
November 9, 1965 ................................................................................................................................................................... 7
1965 Northeast Blackout Conclusions ................................................................................................................................. 8
July 13, 1977 New York Blackout ............................................................................................................................................. 8
1977 New York Blackout Conclusions .................................................................................................................................. 8
July 2‐3, 1996: West Coast Blackout ........................................................................................................................................ 8
July 2‐3, 1996: West Coast Blackout Conclusions ................................................................................................................ 9
August 10, 1996 ..................................................................................................................................................................... 10
August 10, 1996 Conclusions ............................................................................................................................................. 10
August 14, 2003 ..................................................................................................................................................................... 10
Perry‐Ashtabula‐Erie West 345 kV Transmission Line Trip ................................................................................................ 11
Homer City – Watercure and Homer – City Stolle Rd 345 kV Transmission Line Trips ...................................................... 13
Southeast Michigan Loss of Synchronism .......................................................................................................................... 15
2003 Northeast Blackout Conclusion ................................................................................................................................. 16
September 8, 2011 Arizona‐California Outages .................................................................................................................... 17
Other Efforts from the 2003 Blackout Affecting Relay Response to Stable Power Swings ................................................... 17
Overall Observations from Review of Historical Events ........................................................................................................ 17
Chapter 2 – Reliability Issues ..................................................................................................................................................... 18
Dependability and Security .................................................................................................................................................... 18
Trade‐offs Between Security and Dependability ................................................................................................................... 18
Chapter 3 – Reliability Standard Considerations ....................................................................................................................... 20
Need for a Standard ............................................................................................................................................................... 20
Applicability ........................................................................................................................................................................... 20
Identification of Circuits with Protection Systems Subject to Effects of Power Swings .................................................... 20
Benefits of Defining Applicability for Specific Circuit Characteristics ................................................................................ 21
Requirements ........................................................................................................................................................................ 21
Conclusions ................................................................................................................................................................................ 23
Recommendations ..................................................................................................................................................................... 24
Appendix A – Overview of Power Swings .................................................................................................................................. 25
General Characteristics .......................................................................................................................................................... 25
Impedance Trajectory ........................................................................................................................................................ 25
Appendix B – Protection Systems Attributes Related to Power Swings .................................................................................... 29
Desired Response .................................................................................................................................................................. 29
Response of Distance Protection Schemes ............................................................................................................................ 29
Power Swing Without Faults .............................................................................................................................................. 29
Appendix C – Overview of Out‐of‐Step Protection Functions ................................................................................................... 34
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Power Swing and Out‐of‐Step Phenomenon ......................................................................................................................... 34
Basic Phenomenon Using the Two‐Source Model ............................................................................................................. 34
Representation of Power Swings in the Impedance Plane ................................................................................................ 34
Rate of Change of the Positive‐Sequence Impedance ....................................................................................................... 35
Out‐of‐Step Protection Functions .......................................................................................................................................... 36
Power Swing Detection Methods ...................................................................................................................................... 37
Out‐of‐Step Tripping Function ........................................................................................................................................... 42
Issues Associated With the Concentric or Dual‐Blinder Methods ..................................................................................... 45
OOS Relaying Philosophy ................................................................................................................................................... 46
References ............................................................................................................................................................................. 47
Appendix D – Potential Methods to Demonstrate Security of Protective Relays ...................................................................... 48
IEEE PSRC WG D6 Method ..................................................................................................................................................... 48
Calculation Methods based on the Graphical Analysis Method ............................................................................................ 48
Method 1 ........................................................................................................................................................................... 49
Method 2 ........................................................................................................................................................................... 50
Voltage Dip Screening Method .............................................................................................................................................. 53
Discussion of the Results ................................................................................................................................................... 56
Practical Power System Example ....................................................................................................................................... 56
Appendix E – System Protection and Control Subcommittee ................................................................................................... 59
Appendix F – System Analysis and Modeling Subcommittee .................................................................................................... 60
Appendix G – Additional Contributors ....................................................................................................................................... 61
This technical document was approved by the NERC Planning Committee on August 19, 2013.
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Executive Summary
After the August 14, 2003 Northeast Blackout, the Federal Energy Regulatory Commission (FERC) raised concerns regarding
performance of transmission line protection systems during power swings. These concerns resulted in issuance of a
directive in FERC Order No. 733 for NERC to develop a Reliability Standard that requires the use of protective relay systems
that can differentiate between faults and stable power swings and, when necessary, phases out protective relay systems
that cannot meet this requirement. In the order, FERC stated that operation of zone 3 and zone 2 relays during the August
2003 blackout contributed to the cascade, and that these relays operated because they were unable to distinguish between
a dynamic, but stable power swing and an actual fault. FERC further cited the U.S.‐Canada Power System Outage Task Force
as identifying dynamic power swings and the resulting system instability as the reason why the cascade spread. While FERC
did direct development of a Reliability Standard, FERC also noted that it is not realistic to expect the ERO to develop
Reliability Standards that anticipate every conceivable critical operating condition applicable to unknown future
configurations for regions with various configurations and operating characteristics. Further, FERC acknowledged that relays
cannot be set reliably under extreme multi‐contingency conditions covered by the Category D contingencies of the TPL
Reliability Standards.
In response to the FERC directive, NERC initiated Project 2010‐13.3 – Phase 3 of Relay Loadability: Stable Power Swings to
address the issue of protection system performance during power swings. To support this effort, and in response to a
request for research from the NERC Standards Committee, the NERC System Protection and Control Subcommittee (SPCS),
with support from the System Analysis and Modeling Subcommittee (SAMS), has developed this report to promote
understanding of the overall concepts related to the nature of power swings; the effects of power swings on protection
system operation; techniques for detecting power swings and the limitations of those techniques; and methods for
assessing the impact of power swings on protection system operation.
As part of this assessment the SPCS reviewed six of the most significant system disturbances that have occurred since 1965
and concluded that operation of transmission line protection systems during stable power swings was not causal or
contributory to any of these disturbances. Although it might be reasonable, based on statements in the U.S.‐Canada Power
System Outage Task Force final report, to conclude this was a causal factor on August 14, 2003, subsequent analysis clarifies
the line trips that occurred prior to the system becoming dynamically unstable were a result of steady‐state relay
loadability. The causal factors in these disturbances included weather, equipment failure, relay failure, steady‐state relay
loadability, vegetation management, situational awareness, and operator training. While tripping on stable swings was not
a causal factor, unstable swings caused system separation during several of these disturbances. It is possible that the scope
of some events may have been greater without dependable tripping on unstable swings to physically separate portions of
the system that lost synchronism.
Based on its review of historical events, consideration of the trade‐offs between dependability and security, and recognizing
the indirect benefits of implementing the transmission relay loadability standard (PRC‐023), the SPCS concludes that a NERC
Reliability Standard to address relay performance during stable power swings is not needed, and could result in unintended
adverse impacts to Bulk‐Power System reliability.
The SPCS came to this conclusion in the course of responding to the Standards Committee request for research. During this
process the SPCS evaluated several alternatives for addressing the concerns stated in Order No. 733. While the SPCS
recommends that a Reliability Standard is not needed, the SPCS recognizes the directive in FERC Order No. 733 and the
Standards Committee request for research to support Project 2010‐13.3. Therefore, the SPCS provides recommendations
for applicability and requirements that can be used if NERC chooses to develop a standard. The SPCS recommends that if a
standard is developed, the most effective and efficient use of industry resources would be to limit applicability to
protection systems on circuits where the potential for observing power swings has been demonstrated through system
operating studies, transmission planning assessments, event analyses, and other studies, such as UFLS assessments, that
have identified locations at which a system separation may occur. The SPCS also proposes, as a starting point for a standard
drafting team, criteria to determine the circuits to which the standard should be applicable, as well as methods that entities
could use to demonstrate that protection systems on applicable circuits are set appropriately to mitigate the potential for
operation during stable power swings.
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Introduction
Issue Statement
After the August 14, 2003 Northeast Blackout, the Federal Energy Regulatory Commission (FERC) raised concerns regarding
performance of transmission line protection systems during power swings. These concerns resulted in issuance of a
directive in FERC Order No. 733 for NERC to develop a Reliability Standard that requires the use of protective relay systems
that can differentiate between faults and stable power swings and, when necessary, phases out protective relay systems
that cannot meet this requirement. In the order, FERC stated that operation of zone 3 and zone 2 relays during the August
2003 blackout contributed to the cascade, and that these relays operated because they were unable to distinguish between
a dynamic, but stable power swing and an actual fault. FERC further cited the U.S.‐Canada Power System Outage Task Force
as identifying dynamic power swings and the resulting system instability as the reason why the cascade spread. While FERC
did direct development of a Reliability Standard,2 FERC also noted that it is not realistic to expect the ERO to develop
Reliability Standards that anticipate every conceivable critical operating condition applicable to unknown future
configurations for regions with various configurations and operating characteristics. Further, FERC acknowledged that relays
cannot be set reliably under extreme multi‐contingency conditions covered by the Category D contingencies of the TPL
Reliability Standards.
In response to the FERC directive, NERC initiated Project 2010‐13.3 – Phase 3 of Relay Loadability: Stable Power Swings to
address the issue of protection system performance during power swings. To support this effort, and in response to a
request for research from the NERC Standards Committee, the NERC System Protection and Control Subcommittee (SPCS),
with support from the System Analysis and Modeling Subcommittee (SAMS), has developed this report to promote
understanding of the overall concepts related to the nature of power swings; the effects of power swings on protection
system operation; techniques for detecting power swings and the limitations of those techniques; and methods for
assessing the impact of power swings on protection system operation. The SPCS also proposes, as a starting point for a
standard drafting team, criteria to determine the circuits to which the standard should be applicable, as well as methods
that entities could use to demonstrate that protection systems on applicable circuits are appropriately set to mitigate the
potential for operation during stable power swings.
The SPCS recognizes there are many documents available in the form of textbooks, reports, and transaction papers that
provide detailed background on this subject. Therefore, in this report, the SPCS has intentionally limited information on
subjects covered elsewhere to an overview of the issues and has provided references that can be consulted for additional
detail. The subject matter unique to this report discusses the issues that must be carefully considered, to avoid unintended
consequences that may have a negative impact on system reliability, when addressing the concerns stated in Order No.
733.
2
Transmission Relay Loadability Reliability Standard, 130 FERC 61,221, Order No. 733 (2010) (“Order No. 733”) at P.152.
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Chapter 1 – Historical Perspective
Transient conditions occur following any system perturbation that upsets the balance of power on the interconnected
transmission system, such as changes in load, switching operations, and faults. The resulting transfer of power among
generating units is oscillatory and often is referred to as a power swing. The presence of a power swing does not necessarily
indicate system instability, and in the vast majority of cases, the resulting power swing is a low‐magnitude, well‐damped
oscillation, and the system moves from one steady‐state operating condition to another. In such cases the power swings
are of short duration and do not result in the apparent impedance swinging near the operating characteristic of protective
relays. Examples of this behavior occurred on August 14, 2003, when there were ten occurrences of transmission lines
tripping due to heavy line loading. Each line trip resulted in a low‐magnitude, well‐damped transient and the transmission
system reaching a new stable operating point; however, due to the heavy line loading the apparent impedance associated
with the new operating point was within a transmission line relay characteristic.3 Secure operation of protective relays for
these conditions is addressed by NERC Reliability Standards PRC‐023 – Transmission Relay Loadability and PRC‐025 –
Generator Relay Loadability.4
Power swings of sufficient magnitude to challenge protection systems can occur during stressed system conditions when
large amounts of power are transferred across the system, or during major system disturbances when the system is
operating beyond design and operating criteria due to the occurrence of multiple contingencies in a short period of time.
During these conditions the angular separation between coherent groups of generators can be significant, increasing the
likelihood that a system disturbance will result in higher magnitude power swings that exhibit lower levels of damping. It is
advantageous for system reliability that protective relays do not operate to remove equipment from service during stable
power swings associated with a disturbance from which the system is capable of recovering. Secure operation of protective
relays for these conditions is the subject of a directive in Order No. 733, and is the subject of Project 2010‐13.3 – Phase 3 of
Relay Loadability: Stable Power Swings.
Under extreme operating conditions a system disturbance may result in an unstable power swing of increasing magnitude
or a loss of synchronism between portions of the system. It is advantageous to separate the system under such conditions,
and operation of protection systems associated with system instability is beyond the scope of the standard directed in
Order No. 733. However, it is important that actions to address operation during stable power swings do not have the
unintended consequence of reducing the dependability of protection systems to operate during unstable power swings.
Six major system disturbances are described below, including a discussion of the relationship between power swings and
protection system operation and whether operation of protective relays during stable swings was causal or contributory to
the disturbance.
November 9, 1965
The November 1965 blackout, which occurred in the Northeastern United States and Ontario, provides an example of
steady‐state relay loadability being causal to a major blackout.
The event began when 230 kV transmission lines from a hydro generating facility were heavily loaded due to high demand
of power from a major load center just north of the hydro generating facility. Heavy power transfers prior to the
disturbance resulted from the load center area being hit by cold weather, coupled with an outage of a nearby steam plant.
The transmission line protection included zone 3 backup relays, which were set to operate at a power level well below the
capacity of the lines. The reason for the setting below the line capacity was to detect faults beyond the next switching point
from the generating plant. From the time the relays were initially set, the settings remained unchanged while the loads on
the lines steadily increased.
Under this circumstance a plant operator, who was apparently unaware of the installed relay setting limitation, attempted
to increase power transfer on one of the 230 kV lines. As a result, the load impedance entered the operating characteristics
3
Informational Filing of the North American Electric Reliability Corporations in Response to Order 733‐A on Rehearing, Clarification, and
Request for an Extension of Time, Docket No. RM08‐13‐000 (July 21, 2011) (“NERC Informational Filing”), at p. 4.
4
PRC‐025‐1 is presently in development under Project 2010‐13.2 Phase 2 of Relay Loadability: Generation.
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Chapter 1 – Historical Perspective
of the zone 3 line backup relay. The relay operated and tripped the line breaker. Subsequently, the rest of the lines became
overloaded. As it happened, each line breaker was tripped by the zone 3 line backup relay one‐by‐one over a period of
approximately 2.7 seconds.
When all five lines tripped, the hydro generators accelerated rapidly due to the initial reduction of connected electrical
load. The resulting drop in generation at this hydro plant and the rapid build‐up of generation in the interconnected system
resulted in large power swings that resulted in a loss of synchronism between two portions of the system. This incident
initiated a sequence of events across the power system of the northeastern seaboard. The resulting massive outage lasted
from a few minutes in some locations to more than a few days in others and encompassed 80,000 square miles, directly
affecting an estimated 30 million people in the United States and Canada. This was the largest recorded blackout in history
at the time.
1965 Northeast Blackout Conclusions
Relays tripping due to stable power swings were not contributory or causal factors in this blackout. Relays applied to 230 kV
transmission lines tripping due to load and a lack of operator knowledge of relay loadability limitations caused and
contributed to this outage. The Bulk‐Power System is protected against a recurrence of this type of event by the
requirements in NERC Reliability Standard PRC‐023‐2.
July 13, 1977 New York Blackout
This disturbance resulted in the loss of 6,000 MW of load and affected 9 million people in New York City. Outages lasted for
up to 26 hours. A series of events triggering the separation of the Consolidated Edison system from neighboring systems
and its subsequent collapse began when two 345 kV lines on a common tower in northern Westchester County were struck
by lightning and tripped out. Over the next hour, despite Consolidated Edison (Con Edison) dispatcher actions, the system
electrically separated from surrounding systems and collapsed. With the loss of imports, generation in New York City was
not sufficient to serve the load in the city.
Major causal factors were:
Two 345 kV lines experienced a phase B‐to‐ground fault caused by a lightning strike.
A nuclear generating unit was isolated due to the line trips and tripped due to load rejection. Loss of the ring bus
also resulted in the loss of another 345 kV line.
About 18.5 minutes later, two more 345 kV lines tripped due to lightning. One automatically reclosed and one
failed to reclose isolating the last Con Edison interconnection to the northwest.
The resulting surge of power caused another line to trip due to a relay with a bent contact.
About 23 minutes later, a 345 kV line sagged into a tree and tripped out. Within a minute a 345/138 kV
transformer overloaded and tripped.
The tap‐changing mechanism on a phase‐shifting transformer carrying 1150 MW failed, causing the loss of the
phase‐shifting transformer.
The two remaining 138 kV ties to Con Edison tripped on overload isolating the system. Insufficient generation in the
isolated system caused the Con Edison island to collapse.
1977 New York Blackout Conclusions
Relays tripping due to stable power swings were not contributory or causal factors in this blackout. A series of line and
transformer trips due to weather, equipment failure, relay failure, and overloads caused and contributed to this outage.
July 2-3, 1996: West Coast Blackout
On July 2, 1996 portions of the Western Interconnection were unknowingly operated in an insecure state. The July 2
disturbance was initiated at 14:24 MST by a line‐to‐ground fault on the Jim Bridger – Kinport 345 kV line due to a flashover
to a tree. A protective relay on the Jim Bridger – Goshen 345 kV line misoperated due to a malfunctioning local delay timer,
de‐energizing the line and initiating a remedial action scheme which tripped two units at the Jim Bridger generating station.
The initial line fault, subsequent relay misoperation, inadequate voltage support, and unanticipated system conditions led
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Chapter 1 – Historical Perspective
to cascading outages causing interruption of service to several million customers and the formation of five system islands.
Customer outages affected 11,850 MW of load in the western United States and Canada, and Baja California Norte in
Mexico. Outages lasted from a few minutes to several hours.
Major causal factors were:
A 345 kV line sagged due to high temperatures and loading causing a flashover to a tree within the right‐of‐way
and the line was de‐energized properly. A second line simultaneously tripped incorrectly due to a protective relay
malfunction.
Output of a major generating plant was reduced by design due to the two line trips. Two of four generating units at
that plant were correctly tripped via a Remedial Action Scheme. The trips of these units caused frequency in the
Western Interconnection to decline.
About 2 seconds later, the Round Up – LaGrand 230 kV line tripped via a failed zone 3 relay.
About 13 seconds later a couple of small units tripped via field excitation overcurrent.
About 23 seconds later, the Anaconda – Amps (Mill Point) 230 kV line tripped via a zone 3 relay due to high line
loads.
Over the next 12 seconds, numerous lines tripped due to high loads, low voltage at line terminals, or via planned
operation of out‐of‐step relaying. Low frequency conditions existed in some areas during many of these trips.
The Western Interconnection separated into five planned islands designed to minimize customer outages and
restoration times. The separation occurred mostly by line relay operation with three exceptions: Utah was
separated from Idaho by the Treasureton Separation Scheme, Southern Utah separated by out‐of‐step relaying,
and Nevada separated from SCE by out‐of‐step relaying.
On July 3, 1996, at 2:03 p.m. MST a similar chain to the July 2, 1996 events began. A line‐to‐ground fault occurred on the
Jim Bridger – Kinport 345 kV line due to a flashover to a tree. A protective relay on the Jim Bridger – Goshen 345 kV line
misoperated due to a malfunctioning local delay timer, de‐energizing the line and initiating a remedial action scheme (RAS)
which tripped two units at the Jim Bridger generating station. Scheduled power limits were reduced on the California –
Oregon Intertie (COI) north‐to‐south pending the results of technical studies being conducted to analyze the disturbance of
the previous day. The voltage in the Boise area declined to about 205 kV over a three minute period. The area system
dispatcher manually shed 600 MW of load over the next two minutes to arrest further voltage decline in the Boise area,
containing the disturbance and returning the system voltage to normal 230 kV levels. All customer load was restored within
60 minutes.
The Western Systems Coordinating Council Disturbance Report For the Power System Outages that Occurred on the
Western Interconnection on July 2, 1996 and July 3, 1996 approved by the WSCC Operations Committee on September 19,
1996 includes numerous recommendations one of which is the following:
The WSCC Operations Committee shall oversee a review of out‐of‐step tripping and out‐of‐step blocking within the
WSCC region to evaluate adequacy. This includes:
1.
Out‐of‐step relays that operated;
2.
Out‐of‐step relays that did not operate but should have; and
3.
Out‐of step conditions that caused operation of impedance relays.
Work by C.W. Taylor5 following the disturbance report recommended the review of the use of zone 3 relays which
was a contributing factor to the severity of this disturbance.
July 2-3, 1996: West Coast Blackout Conclusions
Relays tripping due to stable power swings was not causal or contributory to the July 2‐3 West Coast Blackout. Out‐of‐step
relaying did play a role as a safety net designed to limit the extent and duration of customer outages and restoration times.
5
Taylor, C.W., Erickson, Dennis C., IEEE Computer Applications in Power, Vol. 10, Issue 1, 1997.
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Unstudied system conditions including unexpectedly high transfer conditions coupled with a series of line trips due to
vegetation intrusion, relay malfunctions, and relay loadability issues caused and contributed to this outage.
August 10, 1996
At 15:48 PST on August 10, 1996, a major system disturbance separated the Western Interconnection into four islands,
interrupting service to 7.5 million customers, with total load loss of 30,390 MW. The interruption period ranged from
several minutes to nearly nine hours.
The pre‐event system conditions in the Western Interconnection were characterized by high north‐to‐south flows from
Canada to California. At 15:42:37, the Allston – Keeler 500 kV line sagged close to a tree and flashed over, additionally
forcing the Pearl – Keeler 500 kV line out of service due to 500/230 kV transformer outage and breaker replacement work
at Keeler. The line was tripped following unsuccessful single‐pole reclosure. The 500 kV line outage caused overloading and
eventual tripping of several underlying 115 kV and 230 kV lines, also in part due to reduced clearances. System voltages
sagged partly because several plants were operated in var regulation mode. At 15:47:37, sequential tripping of all units at
McNary began due to excitation protection malfunctions at high field voltage as units responded to reduced system
voltages.
Bonneville Power Administration (BPA) automatic generation control (AGC) further aggravated the situation by increasing
generation in the upper Columbia area (Grand Coulee and Chief Joseph) to restore the generation‐load imbalance following
McNary tripping. As a result of the above outages and shift of generation northward, sustained power oscillations
developed across the interconnection. The magnitude of power and voltage oscillations further increased, as Pacific HVdc
Intertie controls started participating in the oscillation. These oscillations were a major factor leading to the separation of
the California – Oregon Intertie and subsequent islanding of the Western Interconnection system.
Ultimately, the magnitude of voltage and current oscillations caused opening of two COI 500 kV lines (Malin – Round
Mountain #1 and #2 500 kV lines) by switch‐onto‐fault relay logic. The third COI 500 kV line tripped 170 ms later. Some of
the power that was flowing into northern California surged east and then south through Idaho, Utah, Colorado, Arizona,
New Mexico, Nevada, and southern California. Numerous transmission lines in this path subsequently tripped due to out‐
of‐step conditions and low system voltage. Because at that time the Northeast – Southeast separation scheme was kept out
of service when all COI lines were in operation, the Western Interconnection experienced uncontrolled islanding. Fifteen
large thermal and nuclear plants in California and the desert southwest failed to ride through the disturbance and tripped
after the system islanding, thereby delaying the system restoration.
August 10, 1996 Conclusions
Relays tripping due to stable power swings were not causal or contributory to the August 10th West Coast Blackout. System
operation was unknowingly in an insecure state prior to the outage of the Keeler‐Allston 500 kV line due to reduced
clearances resulting from a season of rapid tree growth and stagnant atmospheric conditions. Outage of the Keeler‐Allston
500 kV line precipitated the overloading and tripping of underlying parallel 230 kV and 115 kV lines, causing undesirable
tripping of key hydro units, voltage drops, and subsequent increasing of power oscillations, all of which led to tripping of
the COI and other major transmission lines separating the Western Interconnection into four islands. The result was
widespread uncontrolled outage of generation and the interruption of service to approximately 7.5 million customers.
August 14, 2003
Similar to a number of the disturbances discussed above, the disturbance on August 14, 2003 concluded with line trips
during power swings that were preceded by many outages due to other causes. The progression of cascading outages on
August 14, 2003 was initially caused by lines contacting underlying vegetation (the basis for Blackout Recommendation 46
and FAC‐003), followed by a series of lines tripping due to steady‐state relay loadability issues (the basis for Blackout
Recommendation 8a7 and PRC‐023). After the system was severely weakened by these outages, line trips occurred in
response to power swings.
6
7
Approved by the NERC Approved by the Board of Trustees, February 10, 2004.
Ibid.
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Chapter 1 – Historical Perspective
In the days and hours preceding the early afternoon of August 14 the power system experienced a number of generation
and transmission outages that resulted in increased transfers of power between portions of the system. During the early
afternoon a number of lines tripped, first due to contact with underlying vegetation and then due to load encroaching into
the operating characteristics of phase distance relays. The events occurred over a period of hours, with sufficient time
between events for the system to find a new steady‐state condition after each event.
In Order No. 733 and Order No. 733‐A FERC discussed tripping of fourteen transmission lines to support the directive
pertaining to conditions in which relays misoperate due to stable power swings. FERC cited the Blackout Report8, stating the
system did not become dynamically unstable until at least the Thetford – Jewell 345 kV line tripped at 16:10:38 EDT. FERC
noted that up until this point, with each dynamic, but stable, power swing, the transmission system recovered and
appeared to stabilize. However, as the power swings and oscillations increased in magnitude, zone 3, zone 2, and other
relays on fourteen key transmission lines reacted as though there was a fault in their protective zone even though there
was no fault. These relays were not able to differentiate the levels of currents and voltages that the relays measured,
because of their settings, and consequently operated unnecessarily.9 The Commission’s directive pertains to conditions in
which relays misoperate due to stable power swings that were identified as propagating the cascade during the August
2003 Blackout.10
NERC subsequently clarified that the fourteen lines did not trip due to stable power swings; ten of these lines tripped in
response to the steady‐state loadability issue addressed by Reliability Standard PRC‐023, while the last four lines tripped in
response to dynamic instability of the power system. Although the Blackout Report states that the system did not become
dynamically unstable until at least after the Thetford – Jewell 345 kV transmission line trip11, subsequent analysis indicates
that the system became dynamically unstable following tripping of the Argenta – Battle Creek and Argenta – Tompkins 345
kV transmission lines, about two seconds earlier than stated in the Blackout Report. The operations not associated with
faults, up to and including the initial trips of Argenta – Battle Creek and Argenta – Tompkins lines, are associated with the
steady‐state loadability issue addressed by Reliability Standard PRC‐023.12
As the cascade accelerated, 140 discrete events occurred from 16:05:50 to 16:36. The last transmission lines to trip as result
of relay loadability concerns were the Argenta –Battle Creek and Argenta – Tompkins 345 kV transmission lines in southern
Michigan at 16:10:36. Upon tripping of these lines the disturbance entered into a dynamic phase characterized by
significant power swings resulting in electrical separation of portions of the power system. Within the time delay associated
with high‐speed reclosing (500 ms) the angles between the terminals of these lines reached 80 degrees and 120 degrees
respectively prior to unsuccessful high‐speed reclosing of these lines.
The next line trips in the sequence of events occurred as a result of power swings. These trips occurred on the Thetford –
Jewell and Hampton – Pontiac 345 kV transmission lines north of Detroit at 16:10:38. These lines tripped as the result of
apparent impedance trajectories passing through the directional comparison trip relay characteristics at both terminals of
each line. All subsequent line trips occurred as the result of power swings. All but two of these trips occurred during
unstable power swings. A few of the events relevant to this subject are discussed below.
Perry-Ashtabula-Erie West 345 kV Transmission Line Trip
The Perry – Ashtabula – Erie West 345 kV line is a three‐terminal line between Perry substation in northeast Ohio and Erie
West substation in northwest Pennsylvania, with a 345‐138 kV autotransformer tapped at the Ashtabula substation in
northeast Ohio. This transmission line trip is interesting because the line tripped at the Perry terminal by its zone 3 relay.
Typically zone 3 line trips are associated with relay loadability issues, as the zone 3 time delay typically is set longer than the
time it would take for a power swing to traverse the relay trip characteristic. The fact that the protection system trip was
initiated by the zone 3 relay raises questions as to whether the power swing was stable or unstable. The rate‐of‐change of
an apparent impedance trajectory typically is used as a discriminant to identify unstable swings, based on the assumption
that higher rates‐of‐change are associated with unstable swings. In this case the speed of the apparent impedance
8
U.S.‐Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes
and Recommendations (Apr. 2004) (“Blackout Report”).
9
Transmission Relay Loadability Reliability Standard, 134 FERC 61,127, Order No. 733‐A (2011) (“Order No. 733‐A”). Order No. 733‐A at
P.110.
10
Id, P.111.
11
Blackout Report at p. 82.
12
NERC Informational Filing, at p. 6.
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Chapter 1 – Historical Perspective
trajectory was relatively slow, as it would need to be to remain within the zone 3 characteristic long enough to initiate a
trip. Dynamic simulation of the event confirmed that while this swing was slow to develop, had the line not been tripped by
its zone 3 relay the swing eventually would have entered the zone 1 relay characteristic at the Erie West terminal followed
by a loss of synchronism condition.
Figure 1 presents the simulated apparent impedance trajectory observed from the Perry line terminal. This figure shows
that the apparent impedance swing was moving away from the relay characteristic up to the time of the Argenta – Battle
Creek and Argenta – Tompkins 345 kV line trips, at which time the trajectory reversed direction and entered the zone 3
relay characteristic from the second quadrant. The apparent impedance remained in the relay characteristic long enough to
initiate a zone 3 trip.
120
Apparent Reactance (Primary Ohms)
Argenta‐Battle Creek and
Argenta‐Tompkings trips
90
60
30
0
‐15
45
75
Apparent Resistance (Primary Ohms)
Figure 1: Apparent Impedance Trajectory for Perry – Ashtabula 345 kV Line on August 14, 2003
‐30
‐75
‐45
‐15
Figure 2 presents the simulated apparent impedance observed from the Erie West terminal. The first (green) apparent
impedance trajectory is the simulated trajectory with the zone 3 trip at Perry simulated. With the 345 kV path from Erie
West to Perry interrupted, the decreased flow on the line from Erie West into the 345‐138 kV transformer at Ashtabula
resulted in the apparent impedance moving to a new trajectory further from the Erie West terminal. The apparent
impedance trajectory was resimulated with tripping of the Perry terminal blocked. The second (blue) trajectory
demonstrates that the next swing would have been unstable, passing through the zone 1 relay characteristic and eventually
crossing the system impedance indicative of a loss of synchronism condition with the system angle increasing beyond 180
degrees.
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Chapter 1 – Historical Perspective
120
Simulation without Perry terminal trip
Apparent Reactance (Primary Ohms)
90
Simulation with Perry terminal trip
60
30
0
Perry terminal trip
75
‐15
45
Apparent Resistance (Primary Ohms)
Figure 2: Apparent Impedance Trajectory for Erie West – Ashtabula 345 kV Line on August 14, 2003
‐30
‐75
‐45
‐15
In addition to the Perry – Ashtabula – Erie West trip demonstrating that the apparent impedance trajectory of a power
swing can result in a time delayed trip, it also demonstrates that for severely stressed system conditions with a rapid
succession of events exciting multiple dynamic modes, the resulting apparent impedance trajectories may vary significantly
from the traditional textbook trajectories that are based on two‐machine system models. This points to the difficulty of
establishing standardized applications to address out‐of‐step conditions that are both secure and dependable for all
possible system conditions.
Homer City – Watercure and Homer – City Stolle Rd 345 kV Transmission Line Trips
These two transmission lines connect the Homer City generating plant in central Pennsylvania to the Watercure and Stolle
Rd substations in western New York. As the power swing traveled across the system, this was the next place the swing was
observable: along the interface between New York and the PJM Interconnection. These two transmission lines were tripped
by their respective zone 1 relays at Homer City.
The recorded and simulated powerflow across this interface are presented in Figure 3 below. Following the separation in
southern Michigan, two swings occurred between the New York and PJM systems. The first swing occurred at
approximately 16:10:39.5 corresponding to tripping of the Homer City – Watercure and Homer City – Stolle Road 345 kV
transmission lines. The second swing occurred approximately 4 seconds later corresponding with the New York‐PJM
separation completed by the Branchburg – Ramapo 500 kV line trip.
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Chapter 1 – Historical Perspective
5000
Real Power (MW)
3000
1000
Simulated
‐1000
Recorded
‐3000
16:10:48
16:10:52
16:10:44
Time (EST)
Figure 3: PJM-New York Interface Flow on August 14, 2003
‐5000
16:10:32
16:10:36
16:10:40
Since only two transmission lines between the PJM Interconnection and the New York system tripped during the first swing,
it raises the question as to whether these lines tripped on a stable swing, and if so, would these two portions of the system
have remained synchronized if all lines comprising the PJM‐New York interface had been in service at the time of the
second power swing.
The dynamic simulation was run twice for this time‐frame: once with the Homer City line trips modeled and once with the
Homer City line trips blocked. Figure 4 presents the apparent impedance for the Homer City terminal of the Homer City –
Watercure transmission line for each simulation.
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Chapter 1 – Historical Perspective
300
Apparent Reactance (Primary Ohms)
220
Simulation with Homer City
line trips simulated
Simulation with Homer City
line trips blocked
140
60
‐20
200
40
120
Apparent Resistance (Primary Ohms)
Figure 4: Apparent Impedance Trajectory for Homer City – Watercure 345 kV Line on
August 14, 2003
‐100
‐200
‐120
‐40
The first (green) apparent impedance trajectory shows the apparent impedance entering the zone 1 relay characteristic and
the line tripping (represented in the plot by the apparent impedance “jumping” to the origin. The second (blue) trajectory
representing the simulation with line tripping blocked demonstrates that the first swing was stable with the trajectory
turning around just after entering the zone 1 relay characteristic. On the next swing, occurring about 4 seconds later, it is
clear that the swing is unstable and the apparent impedance exits the relay characteristic through the second quadrant. The
plot shows that with tripping of these lines blocked that these two portions of the system lose synchronism and slip poles
as long as the two systems remain physically connected.
The blackout investigation team concluded that while these two lines did trip on a stable swing, these trips were not
contributory to the blackout since the lines would have tripped four seconds later on the next swing, which was unstable.
The blackout investigation team further concluded that since the protection systems on these lines did demonstrate the
potential for tripping on stable swings, the Transmission Owners should investigate changes that could be made to improve
the security of protection system operation on the Homer City 345 kV transmission lines to Watercure and Stolle Road. The
Transmission Owners have performed extensive testing of the out‐of‐step tripping and power swing blocking functions on
new protection systems using simulated power swings from the August 14, 2003 blackout investigation. This testing has
identified susceptibility of some protection systems to misoperate, which highlights the difficulty of providing both
dependable and secure operation for every conceivable critical operating condition, particularly when considering
conditions well beyond the N‐1 or N‐2 conditions for which power systems typically are designed and when considering
more complex swings with multiple modes and time‐varying voltage..
Southeast Michigan Loss of Synchronism
Following the Michigan East‐West separation and Perry – Ashtabula – Erie West trip, the power flow from Ontario to
Michigan and from Michigan to Ohio increased. During this time voltages in southeast Michigan began to drop rapidly. In
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Chapter 1 – Historical Perspective
response to the decreased voltage and corresponding drop in load, the generating units south of Detroit began to
accelerate rapidly and slipped two poles.
The system conditions associated with the generating units slipping two poles resulted in turbine trips on many of these
generating units. As mechanical power to the turbines was reduced, the generators slowed down and frequency in
southern Detroit began to decline. Many of these generating units rely on a reverse power relay to trip the generator after
the turbine is tripped and mechanical power is reduced. Since these units lost synchronism with the rest of the system the
electrical power on these units changed direction with each pole slip and the reverse power condition was not sustained
long enough for the reverse power relay to trip the unit. As a result, the southeast Michigan portion of the system operated
asynchronously while connected through the two 120 kV lines. Figure 5 illustrates the effect of the out‐of‐step conditions
on system voltage. The first trace (blue) is the recorded voltage at the Keith substation in southern Ontario which shows
five voltage swings of approximately 0.8 per unit corresponding to each pole slip until the mechanical input to the turbines
was tripped. This plot illustrates the voltage stress on equipment when two systems operate asynchronously without
dependable tripping for out‐of‐step conditions. Generating units may experience corresponding shaft stress during each
pole slip.
400
Simulated
320
Voltage (kV)
Recorded
240
160
80
16:10:48
16:10:52
16:10:44
Time (EST)
Figure 5: Keith Voltage During Southern Michigan Loss-of-Synchronism
0
16:10:32
16:10:36
16:10:40
2003 Northeast Blackout Conclusion
Relays tripping due to stable power swings were not contributory or causal factors in this blackout. Although it is
reasonable to conclude this was a causal factor based on statements in the Blackout Report and cited in FERC Order No. 733
and subsequent FERC orders, subsequent analysis cited in the NERC Informational filing clarifies that only two 345 kV lines
tripped in response to stable power swings, and these two trips occurred well into the cascading portion of the disturbance.
Simulations confirm that if the relays had not tripped these lines on the stable power swing, the relays would have tripped
on an unstable swing a few seconds later, with no significant difference in the subsequent events or the magnitude and
duration of the resulting outages. Recorded and simulated data also demonstrate the adverse effect of not having
dependable tripping for unstable power swings.
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Chapter 1 – Historical Perspective
September 8, 2011 Arizona-California Outages
This disturbance is well documented in the April 2012 FERC/NERC Staff Report on the September 8, 2011 Blackout, available
on the NERC website. Twenty seven findings and recommendations were made in this report. Relays tripping due to stable
power swings were not cited in any of the recommendations from the NERC/FERC report. Relays tripping due to stable
power swings were not contributory or causal factors in this blackout.
Other Efforts from the 2003 Blackout Affecting Relay Response to
Stable Power Swings
The August 14, 2003 northeast blackout spawned the effort that raised the bar on relay loadability. Efforts included the
“Zone 3” and “Beyond Zone 3” relays reviews that preceded development of the PRC‐023 Transmission Relay Loadability
standard. The SPCTF report, Protection System Review Program – Beyond Zone 3, dated December 7, 2006 identified that
22 percent of the 11,499 EHV relays reviewed required changes to meet the NERC Recommendation 8a criterion or a
Technical Exception (equivalent to the criteria under Requirement R1 of PRC‐023‐2). Methods used to attain the greater
loadability typically included limiting relay reaches or changing relay characteristic shapes or both. These relay changes
affected relays with the largest distance zones susceptible to tripping on stable power swings such as the Perry – Ashtabula
– Erie West zone 3 trip discussed above. In many cases these relay changes also affected distance zones that trip high‐speed
such as zone 2 functions that are part of communication‐assisted protection systems, and in some cases even zone 1 relays
that trip without intentional time delay. While it is not possible to quantify the extent to which these modifications
improved security against tripping for stable power swings, reducing the resistive reach of phase distance protection
functions does increase the power system angular separation necessary to enter the relay characteristic. Thus, these
changes increased security throughout North America for relays susceptible to tripping on stable power swings.
Overall Observations from Review of Historical Events
Relays tripping on stable power swings were not causal or contributory in any of the historical events reviewed. Causal
factors in the events included lines sagging into trees, lines tripping via relay action due to high loads, lines tripping due to
relay malfunctions, and other causes. These causes have been addressed in several NERC Reliability Standards.
Relays tripping on unstable swings occurred in several of the historical events reviewed. The tripping was not causal or
contributory as tripping on unstable swings occurs after the system has reached the point of instability, cascading, or
uncontrolled separation. However, it is possible that the scope of some events may have been greater without dependable
tripping on unstable swings to physically separate portions of the system that lost synchronism.
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Chapter 2 – Reliability Issues
Dependability and Security
When considering power swings, both facets of protection system reliability are important to consider. To support power
system reliability it is desirable that protection systems are secure to prevent undesired operation during stable power
swings. It also is desirable to provide dependable means to separate the system in the event of an unstable power swing.
Protection system security during stable swings is important to maintaining reliable power system operation. Unnecessary
tripping of transmission lines during stable power swings may lead to cascade tripping due to increased loading on parallel
circuits or may lead directly to power system instability by increasing the apparent impedance between two portions of the
system.
Ensuring that dependable means are available to separate portions of the system that have lost synchronism is essential to
maintaining reliable power system operation. Failing to physically separate portions of the system that have lost
synchronism will result in adverse impacts due to the system slipping poles, resulting in significant voltage and power flow
deviations occurring at the system slip frequency. Near the electrical center of the power swing the voltage deviations will
have amplitude of nearly 1 per unit, stressing equipment insulation. Rapid changes in power flow also stress equipment, in
particular rotating machines that are participating in the swings.
Trade-offs Between Security and Dependability
Secure and dependable operation of protection systems are both important to power system reliability. While methods for
discriminating between stable and unstable power swings have improved over time, ensuring both secure and dependable
operation for all possible system events remains a challenge. Testing out‐of‐step functions using simulated power system
swings from the August 14, 2003 blackout investigation has identified susceptibility of some protection systems to
misoperate, which highlights the difficulty of providing both dependable and secure operation for every conceivable critical
operating condition, particularly when considering conditions well beyond the N‐1 or N‐2 conditions for which power
systems typically are designed and when considering more complex swings with multiple modes and time‐varying voltage.
While the directive in Order No. 733 is focused on protective relays operating unnecessarily due to stable power swings, it
is important that focusing on this aspect of security does not occur to the detriment of system reliability by producing the
unintended consequence of decreasing ability to dependably identify unstable swings and separate portions of the system
that have lost synchronism.
It certainly is possible to provide transmission line protection that can discriminate between fault and power swing
conditions. Current‐based protection systems such as current differential or phase comparison can be utilized to provide a
high degree of security against operation for stable power swings. However, application of such protection systems in
locations where the system may be prone to unstable power swings does not provide a dependable means of separating
portions of the system that lose synchronism. In such cases it would be necessary to install out‐of‐step protection to initiate
system separation, which reintroduces the need to discriminate between stable and unstable power swings. Installing
current‐based protection systems does not remove the need to install impedance‐based back up protection, which
reintroduces the need to discriminate between stable and unstable power swings.
Recognizing that no one protection system design can provide security and dependability for all possible power swings
under all possible system conditions, two questions must be considered: (1) for what conditions must protection systems
operate reliably, and (2) under conditions for which reliable operation cannot be assured, should protection system design
err on the side of security or dependability. The trade‐offs between secure and dependable operation in response to
system faults are discussed much more frequently than the trade‐offs in response to power swings; however, there are
similarities when comparing fault and power swing conditions. In both cases, a lack of dependability is more likely to result
in an undesirable outcome. For a fault condition, a failure to trip will result in increased equipment damage and
acceleration of rotating machines that may result in system instability. For an unstable power swing, a failure to trip will
result in portions of the system slipping poles against each other and resultant increased equipment stress and an increased
probability of system collapse.
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Chapter 2 – Reliability Issues
By comparison, tripping an additional circuit in response to a fault may lead to unacceptable system performance; however,
the potential for equipment damage or instability is less than for a failure to trip, particularly in highly networked systems.
In theory tripping a circuit for a stable power swing may lead to cascade tripping of power system circuits; however,
analysis of historical events supports that the probability of undesirable system performance is less than for a failure to trip
for an unstable swing.
Given the relative risks associated with a lack of dependable operation for unstable power swings and the lack of secure
operation for stable swings, over‐emphasizing secure operation for stable powers swings could be detrimental to Bulk‐
Power System reliability. It therefore is preferable to emphasize dependability over security when it is not possible to
ensure both for all possible system conditions.
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Chapter 3 – Reliability Standard Considerations
Need for a Standard
Based on its review of historical events, consideration of the trade‐offs between dependability and security, and recognizing
the indirect benefits of implementing the transmission relay loadability standard (PRC‐023), the SPCS concludes that a NERC
Reliability Standard to address relay performance during stable swings is not needed, and could result in unintended
adverse impacts to Bulk‐Power System reliability.
In the course of coming to this conclusion, however, the SPCS has developed recommendations for implementing a
standard. Given the directive in FERC Order No. 733 and the Standards Committee request for research to support Project
2010‐13.3, the SPCS recommends that if a standard is developed it should include the following applicability and
requirements.
Applicability
Two options exist for developing requirements for secure operation of protection systems during power swings: (i) develop
requirements applicable to protection systems on all circuits, or (ii) identify the circuits on which a power swing may affect
protection system operation and develop requirements applicable to protection systems on those specific circuits. The
effort to assess every protection system to assure it will not operate during stable power swings would be significant. An
equally effective and more efficient approach would be to identify the types of circuits on which protection systems would
be challenged by power swings, and limit the applicability of a new standard to these circuits.
During development of this report the SPCS explored the possibility of recommending a standard applicable to all circuits
and requiring that entities verify for each circuit that either a power swing will not pass through the circuit or that the
protection system on the circuit would not operate for a stable power swing. The SPCS investigated several different
approaches including the analytical assessment and system study approaches described in Appendix D. Analysis of the
various approaches indicated that applying one or more of these approaches to each circuit would be a significant effort
with varying results that are dependent on the system topology and the assumptions specified for the analysis. Extreme
system topologies are often present during actual relay trips during power swings. These topologies would be very difficult
to anticipate in a study. The historical evidence supports taking a more efficient approach to limit burden on responsible
entities given the limited role that undesired tripping in response to stable power swings has played in major disturbances.
Such an approach is consistent with taking a risk‐based approach to Reliability Standards by focusing the applicability to
circuits on which protection systems are most likely to be affected during power swings.
This section recommends an approach for identifying those power system circuits on which protection systems are
susceptible to operation for stable power swings. Although past system disturbances do not provide specific input on which
circuits are most at risk, past disturbances demonstrate it is not necessary for a Reliability Standard to apply to all lines. In
the absence of direct input from past disturbances, the SPCS believes it is reasonable to recommend an approach that uses
information from existing planning and operating studies and experience, and physical attributes of power systems. This
approach provides the opportunity to effectively identify circuits of concern without requiring extensive, and in many cases
duplicative, studies. The recommended approach is an effective and efficient manner that can be used to limit the number
of circuits for which entities are required to evaluate and provide a basis for protection system response during power
swings.
Identification of Circuits with Protection Systems Subject to Effects of Power Swings
Power system swings, stable or unstable, are caused by the relative motion of generators with respect to each other. These
power swings manifest themselves as swings in the apparent impedance “seen” by protective relays due to the variations in
voltages and currents which occur during these swings. Power swings are classified as local mode or inter‐area mode. Local
mode oscillations are characterized by units at a generating station swinging with respect to the rest of the system. This is
in contrast to inter‐area mode oscillations, where a coherent group13 of generating stations in one part of the system is
swinging against another coherent group of generators in a different part of the system.
13
In this context, the generators in a coherent group exhibit similar waveforms for their rotor‐angle response to a system disturbance.
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Chapter 3 – Reliability Standard Considerations
The electrical center of a local mode swing tends to remain relatively close to the generating station that is causing the
swing. The electrical center of an inter‐area mode oscillation will occur between the two coherent groups of generators.
Therefore, it can be concluded that stable power swings are most likely to challenge protective relays on lines terminating
at generating stations or on lines between coherent groups of generators. This is a useful filter in identifying transmission
lines on which protective relays should be subject to the Reliability Standard.
The electrical center of a power swing is determined by physical characteristics of the system. The electrical center may
vary depending on the dispatch of generators and status of transmission equipment making it difficult to assure that all
possible power swings are identified. This is particularly true when considering power swings that may occur during major
system disturbances after a number of circuits have tripped. However, it is possible to identify the most likely locations of
electrical centers of power swings and focus attention on protections systems applied on the circuits where the electrical
centers exist. In the case of local mode oscillations the electrical center is most likely to occur in the generator step‐up
(GSU) transformer or on a transmission line connected to the bus on the high‐side of the GSU transformer. In the case of an
inter‐area oscillation the electrical center is more difficult to predict; however, the electrical center already will have been
identified if any planning or operating studies have identified the need to apply a System Operating Limit (SOL) based on
stability constraints, or if other studies or event analyses have identified the potential for tripping during a system
disturbance that includes power swings.
The standard drafting team should consider the following criteria in establishing the applicability of the Reliability Standard
to limit applicability to only those transmission lines on which protective relays are most likely to be challenged during
stable power swings.
Lines terminating at a generating plant, where a generating plant stability constraint is addressed by an operating
limit or Special Protection System (SPS) (including line‐out conditions).
Lines that are associated with a System Operating Limit (SOL) that has been established based on stability
constraints identified in system planning or operating studies (including line‐out conditions).
Lines that have tripped due to power swings during system disturbances.
Lines that form a boundary of the Bulk Electric System that may form an island.14
Lines identified through other studies, including but not limited to, event analyses and transmission planning or
operational planning assessments.
Benefits of Defining Applicability for Specific Circuit Characteristics
Limiting the applicability of a Reliability Standard provides a number of benefits.
Efforts may be more focused, creating the possibility to include dynamic simulations assessing a greater number of
fault types and system configurations.
It may be possible, subject to relay model availability, to model specific relay settings in the dynamic simulation
software, to more precisely identify the likelihood of a stable swing entering the relay characteristic. Including
relay models in transient stability simulations could be used to monitor security of settings and identify potential
concerns. Present software and computing developments are reducing limitations that historically have prevented
such modeling, as well as practical limits to managing the volume of data. However, models are not presently
available for all tripping relay characteristics, such as when load encroachment features are used to limit the trip
characteristic to meet relay loadability requirements.
Requirements
The following requirements should be applicable to the circuits identified in the preceding section to mitigate the risk of
protection systems operating during stable power swings.
A requirement for each Reliability Coordinator and Planning Coordinator to identify lines that meet the criteria in
the applicability section and notify the owners of applicable circuits.
14
See NERC Reliability Standard PRC‐006‐1 – Automatic Underfrequency Load Shedding, Requirement R1.
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Chapter 3 – Reliability Standard Considerations
A Functional Model entity with a wide‐area view should have responsibility for identifying the circuits to which the
standard is applicable. This approach promotes consistent application of the criteria and assures that facility
owners are aware of their responsibilities, given that a facility owner may not be aware of all relevant system
studies. It is most appropriate to assign this responsibility to the Reliability Coordinator and the Planning
Coordinator given their wide‐area view and awareness of reliability issues. Both entities should be involved since
stability issues may be identified in both operating and planning studies. The standard should require periodic
review to assure the list of applicable circuits is up‐to‐date.
A requirement for each facility owner to document its basis for applying protection to each of its applicable circuits
(as identified above), and provide this information to its Reliability Coordinator, Planning Coordinator, and
Transmission Planner.15
There are multiple ways for a facility owner to mitigate the potential of protection systems tripping for stable
power swings. In some cases conventional impedance‐based protection may be acceptable (e.g., on a short line a
mho characteristic may not be susceptible to tripping for stable swings), in other cases a modified protection
characteristic may be suitable, in some cases it may be appropriate to supervise the protection to enable or to
block tripping during power swings, and in some cases the consequences of failing to trip for an unstable swing
may be so significant that a risk of tripping for some stable swings is deemed in the best interest of Bulk‐Power
System reliability. Decisions whether to apply out‐of‐step protection should be made between the facility owner
who has knowledge of the protection system design and the Reliability Coordinator, Planning Coordinator, and
Transmission Planner who have knowledge of the characteristics of the power system performance. The
documented basis should include rationale for whether out‐of‐step protection is needed, and if so, whether out‐
of‐step tripping or power swing blocking is applied. Although this requirement is focused on documentation, this
information is necessary for Reliable Operation of the Bulk‐Power System. Entities responsible for operating and
planning the Bulk‐Power System need this information to understand how protection systems may respond during
extreme system conditions.
Entities may find the information presented in the appendices of this report useful in developing a basis for
applying protection to each applicable line.
The SPCS discussed additional requirements related to modeling the tripping functions of phase protection systems
responsive to power swings. Modeling these protective functions in transient stability simulations could be an effective
method of verifying that protection systems will not operate on stable power swings. Default phase distance relay models
exist in simulation software that can be used to monitor apparent impedance and identify lines and conditions where relay
operation is possible, as well as explicit models for many typical trip function characteristics. However, existing models do
not address some of the unique features, such as load encroachment, that many entities have utilized to meet the
transmission relay loadability requirements. The SPCS supports use of existing relay models in operating studies and
transmission planning assessments; however, the SPCS believes is not possible to implement a measurable requirement
until explicit models are available. NERC, through its technical committees, could monitor the availability of relay models
and provide further recommendations at an appropriate time.
Modeling the tripping functions of phase protection systems responsive to power swings would enable the Reliability
Coordinator, Planning Coordinator, and Transmission Planner to identify cases for which the protection systems applied are
susceptible to tripping on stable power swings. Simulation results could provide important feedback since it is not practical
to consider every potential power swing at the time settings are applied to a protection system. Given the difficulty of
identifying all potential power swings, it is important that any information obtained through actual events and system
studies is evaluated by the facility owner. In some cases this new information may identify the need to modify a protection
system design or its settings. Decisions to modify a protection system, or not, should be made between the facility owner
who has knowledge of the protection system design and the Reliability Coordinator, Planning Coordinator, and
Transmission Planner who have knowledge of the characteristics of both the power system performance and protection
system design. Decisions whether to modify a protection system should consider the need for dependable tripping during
unstable power swings in addition to the objective of secure operation for stable power swings.
15
This and subsequent requirements should include all entities responsible for assessing dynamic performance of the Bulk‐Power System.
The Reliability Coordinator has responsibility for operating studies and the Planning Coordinator and Transmission Planner have
responsibility for transmission planning assessments.
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Conclusions
Operation of transmission line protection systems was not causal or contributory to six of the most significant system
disturbances that have occurred since 1965. System separation during several of these disturbances did occur due to
unstable power swings, and it is likely that the scope of some events and potential for equipment damage would have been
greater without dependable tripping on unstable swings to physically separate portions of the system that lost
synchronism.
Given the relative risks associated with a lack of dependable operation for unstable power swings and the lack of secure
operation for stable swings, it is generally preferable to emphasize dependability over security when it is not possible to
ensure both for all possible system conditions. Prohibiting use of certain types of relays may have unintended negative
outcomes for Bulk‐Power System reliability.
Efforts to improve transmission relay loadability subsequent to the August 14, 2003 northeast blackout had a secondary
effect of reducing the susceptibility of some protection systems to tripping on stable power swings. While it is not possible
to quantify the extent to which these modifications improved security against tripping for stable power swings, reducing
the resistive reach of phase distance protection functions does increase the power system angular separation necessary to
enter the relay characteristic.
Although current‐only‐based protection is immune to operating during power swings, exclusive use of current‐only‐based
protection is not practical and would reduce dependability of tripping for system faults and unstable power swings. A
power system with no remote backup protection is susceptible to uncleared faults and the inability to separate during
unstable power swings during extreme system events. Although current‐only‐based protection is secure for stable power
swings and can be used on lines which require tripping on out‐of‐step conditions, additional separate out‐of‐step protection
is required. Application of impedance‐based backup protection and, where necessary, out‐of‐step protection, reintroduces
the need to discriminate between stable and unstable power swings.
Although many new algorithms exist to discriminate between stable and unstable swings, testing out‐of‐step functions
using actual power system swings has identified susceptibility of some protection systems to misoperate, which highlights
the difficulty of providing both dependable and secure operation.
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Recommendations
Based on its review of historical events, consideration of the trade‐offs between dependability and security, and recognizing
the indirect benefits of implementing the transmission relay loadability standard (PRC‐023), the SPCS concludes that a NERC
Reliability Standard to address relay performance during stable swings is not needed, and could result in unintended
adverse impacts to Bulk‐Power System reliability.
While the SPCS recommends that a Reliability Standard is not needed, the SPCS recognizes the directive in FERC Order No.
733 and the Standards Committee request for research to support Project 2010‐13.3. Therefore, the SPCS provides
recommendations for applicability and requirements that can be used if NERC chooses to develop a standard.
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Appendix A – Overview of Power Swings
General Characteristics
An electric power grid, consisting of generators connected to loads via transmission lines, is constantly in a dynamic state as
generators automatically adjust their output to satisfy real and reactive power demand. During steady‐state operating
conditions, a balance exists between the power generated and the power consumed, with the absolute differences in the
voltages between buses typically maintained within 5 percent and frequency within 0.02 Hz of nominal. In the balanced
system state, each generator in the system maintains its voltage and internal machine rotor angle at an appropriate
relationship with the other generators as dictated by required power flow conditions in the system.
Sudden changes in electrical power caused by power system faults, line switching, generator disconnection, or the loss or
connection of large blocks of load, disturb the balance between the mechanical power into and the required electrical
power out of generators, causing acceleration or deceleration of the generating units because the mechanical power input
responds more slowly than the generator electrical power. Such system disturbances cause the machine rotor angles of the
generators to swing or oscillate with respect to one another in the search for a new equilibrium state. During this period,
transmission lines will experience power swings, which can be stable or unstable, depending of the severity of the
disturbance. In a stable swing, the power system will return to a new equilibrium state where the generator machine rotor
angle differences are within stable operating range to generate power that is balanced with the load. In an unstable swing,
the generation and load do not find a balance and the machine rotor angles between coherent groups of generators
continue to increase, eventually leading to loss of synchronism between the coherent groups of generators. The location at
which loss of synchronism occurs is based on the physical attributes of the system and is unlikely to correspond to
boundaries between neighboring utilities. When synchronism is lost among areas of a power system, the areas should be
separated quickly to avoid equipment damage and to avoid possible collapse of the entire power system. Ideally, the
system is separated at predetermined locations into self‐contained areas, each of which can maintain a generation/load
balance, where the attainment of the balance may require appropriate generation or load shedding.
Impedance Trajectory
The dynamic state of the power system can be represented by the impedance “seen” at a bus in the power system. The two
machine equivalent shown in Figure 6 can be used to illustrate the concept, where the source voltages at the two ends of
the system, EG and EH, are constant magnitudes behind their transient impedances, ZG and ZH.
Figure 6: Two-Machine Equivalent of a Power System
Figure 7, the geometrical interpretation of the power equation for this simple two source system, shows the R‐X diagram
with a mho characteristic of the relay at Bus A, set to a typical zone 1 setting for protection of the line (line impedance is ZL).
The total impedance across the system is represented by Points G to H, where ZG extends from the origin to point G in the
third quadrant and ZH extends from the tip of ZL to Point H in the first quadrant.
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Appendix A – Overview of Power Swings
Figure 7: Illustration of Electrical Center of the Equivalent Power System
With EG and EH of equal magnitude and with a phase angle difference of (EG leading) the apparent impedance during a
swing will fall on a straight line perpendicular to and bisecting the total system impedance between G and H. As source EG
moves ahead of source EH in angle during a swing (with magnitudes of EG and EH equal), the angle increases. On the R‐X
diagram, the angle formed by the intersection of lines PG and PH at P is the angle of separation between the source
voltages EG and EH. Point P on the R‐X diagram of Figure 7 is the apparent impedance seen at Bus A. When = 90º, the
impedance lies on the circle whose diameter is the total impedance (GH) across the system. This is the point of maximum
load transfer between G and H. When reaches 120º, and beyond, the systems are not likely to recover.16 When the locus
intersects the total system impedance line GH, is 180º and the systems are completely out of phase. This point is called
the electrical center (at the mid‐point of the total system impedance when EG and EH are of equal magnitude). The voltage
is zero at this point and, therefore, it is equivalent to a three‐phase fault at the electrical center. As the impedance locus
moves to the left of impedance line GH, increases beyond 180º and eventually the systems will be in phase again. If the
systems are not separated, source EG continues to move ahead of source EH, and the cycle repeats itself. When the
impedance locus reaches the starting point of the swing, one slip cycle has been completed.
16
Application of Out‐of‐Step Blocking and Tripping Relays, John Berdy.
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Power (p.u)
Appendix A – Overview of Power Swings
Figure 8: Power Angle Curve
Figure 8 plots the power angle equation and shows the theoretical power transfer across a simplified transmission system
such as that shown in Figure 6 for various values of where is the angular difference between the voltages at the two
ends of the system. Normally, systems and transmission lines operate at low angles that are perhaps 30 degrees or less
(longer lines and weaker systems may operate at higher angles and shorter lines and stronger systems operate at lower
angles).
Transmission of power in actual power systems is more complex than in the simple two source model discussed above. Two
systems of coherent generators are typically connected by several lines of varying voltages. The plot of the power angle
equation will vary with system conditions. An example is illustrated in Figure 9. This example illustrates conditions that may
exist during a severe destabilizing fault and its aftermath. Prior to the fault, the system is stable, transmitting an amount of
power P1 from one system to the other. When the severe fault occurs, the transfer capability of the system is reduced. The
power delivered by the generators is less than the input from their prime movers, which causes the sending generators to
accelerate, increasing the angle between the systems. When the faulted line is cleared, the transfer capability is increased,
but to a lower level than the prefault level, due to the loss of the faulted line. The power delivered by the accelerated
generators at this angle is greater than the input from their prime movers, which causes the generators to decelerate. For
this condition, the system angle will continue to increase as the generators decelerate. If the angle is greater than 90
degrees, then the angle increases as the power delivered is lowered and the deceleration rate is reduced. If the angle
reaches 120 degrees and is still increasing, it is likely that the system will not reach equilibrium (the decelerating area A2
equals the accelerating area A1) before the power delivered by the generators decreases below the prime mover inputs. If
that occurs, the generators will accelerate again and pull out of synchronism.
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Appendix A – Overview of Power Swings
Figure 9: Power Angle Curve for Various Conditions
At any given relay location, it is impossible to predict all possible system configurations and power transfer capabilities. The
critical angle for maintaining stability will vary depending on the contingency and the system condition at the time the
contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is marginal and 120
degrees is generally accepted as an appropriate basis for setting out‐of‐step protection.17 Given the importance of
separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a proper balance between
dependable tripping for unstable power swings and secure operation for stable power swings.
17
Ibid.
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Appendix B – Protection Systems Attributes Related to Power
Swings
Desired Response
A transmission line protection system is required to detect line faults and trip appropriately. This applies during swing
conditions where, in addition, the following also applies:
(a) If the power swing is stable, from which the system will recover, a line protection should not operate because the
unnecessary loss of lines could exacerbate the power swing to the extent that a stable swing becomes unstable.
Hence, in this case, the relevant protections should be set to not operate on detection of a power swing. This may
be achievable by selection of the protection system operating characteristics and settings, or may require
dedicated logic to block operation.
(b) If the power swing is unstable, also referred to as an out‐of‐step condition, separation at predetermined locations
is desirable, as previously mentioned. To this end, line protection systems that should not trip on the out‐of step
condition should be blocked, while protection systems on lines that have been identified as the desired separation
points should have out‐of‐step tripping capability.
The blocking requirements set out in (a) and (b) above create a condition where if an internal fault occurs during the power
swing, the line protection is unable to perform its protection function, unless the blocking is removed. The challenge is the
manner in which the blocking can be reliably removed. Methods that have been used to address this condition are
discussed in the IEEE Power System Relaying Committee Working Group WG D6 report, Power Swing and Out‐of‐Step
Considerations on Transmission Lines, July 2005..
Response of Distance Protection Schemes
Power Swing Without Faults
Distance Elements
While it is evident from the illustration in Figure 7 that a swing locus can cause the apparent impedance to enter the relay
element characteristic, resulting in operation of the element, the performance of distance elements is dependent to some
extent on the relative magnitudes of system and line impedances. For example, if the line impedance is small compared to
the system impedances, it is likely that the various distance zones will trip only on swings from which the system will not
recover. This is illustrated in Figure 10 for the relay at Bus A (with three zones), showing that the swing locus will only enter
the distance relay characteristics when the angular separation between sources EG and EH exceeds 120º. In the case
illustrated, the angle must significantly exceed 120º . If the swing locus does not traverse zone 1 but traverses zone 2, the
response of the line protection depends on the scheme used, as discussed in the sections below.
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Appendix B – Protection Systems Attributes Related to Power Swings
Figure 10: Line Impedance is Small Compared to System Impedances
When the line impedance is large compared to the system impedances, the distance relay elements could operate for
swings from which the system could recover. This is illustrated in the example shown in Figure 11, where two zones are
shown for clarity. It is evident that zone 2 will operate before the angular separation of the systems exceeds 90º, while zone
1 will operate before angular separation of 120º is reached. In this case the protection system is susceptible to tripping on a
stable power swing unless the relay characteristic is modified or some form of blocking is provided to prevent tripping.
Time delayed zone 2 relays in a step distance scheme will trip if the locus resides within the characteristic for a time
exceeding the delay setting.
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Appendix B – Protection Systems Attributes Related to Power Swings
Figure 11: Line Impedance is Large Compared to System Impedances
Distance Relay Based Pilot Scheme Response to Power Swings
Figure 12 Shows impedance elements as they are typically applied in directional comparison pilot schemes. The green
characteristics represent zone 2 tripping elements. The tripping elements are used in both Directional Comparison Blocking
(DCB) schemes, and Permissive Over Reaching (POR) schemes. The red characteristics represent blocking elements. They
are used in all DCB schemes and many variations of POR schemes. Depending on the path of the impedance locus, power
swings will affect the performance of DCB and POR schemes differently.
To cause a POR scheme to open a line, the impedance locus must be within both zone 2 tripping characteristics
simultaneously. For POR schemes employing transient blocking functions, the locus must enter both tripping characteristics
within a short time of each other, usually within about a power cycle. A DCB scheme will open at least one line terminal any
time the locus enters either tripping characteristic, without also entering a blocking characteristic.
If the locus enters a blocking element, DCB schemes will transmit blocking signals, and POR terminals with blocking
elements will not respond to received permissive signals. If a fault occurs on the protected line subsequent to the power
swing locus entering the blocking element, a DCB scheme will trip. The performance of the POR terminal will depend on the
system strength behind the terminal and on details of the permissive scheme logic associated with the blocking function.
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Appendix B – Protection Systems Attributes Related to Power Swings
Figure 12: Directional Comparison Trip and Block
Response of Line Current Differential Protections
With recent advancements in digital communication systems, the current differential principle has been effectively applied
to line protection, providing good sensitivity for detection of line faults, including high resistance ground faults, while
maintaining high degree of selectivity between internal and external faults. Many of these characteristics apply during
power swing and out‐of‐step conditions. With the current differential principle measuring the current at one terminal of the
line and computing the differential current with the current levels transmitted from the other terminal(s), the protection
remains secure during a swing condition because the computed differential current remains below the threshold that
would signify a fault. With increasing angular separation between the swinging systems, the current levels at each of the
terminals increase beyond normal load levels, making the condition look like a through fault. Phase comparison protection
systems exhibit performance similar to current differential protection systems.
One shortcoming in the characteristics of these current‐only‐based protections is that during some portion of the power
swing, the protection could become insensitive to line faults. For example, if a line fault occurs at the electrical center of a
two‐terminal system when the angular separation between the swinging systems is 180, the current levels at the two
terminals are equal in magnitude and opposite in phase. This results in zero difference current, rendering the protection
blind to this fault condition. However, as the power swing moves away from the electrical center (i.e., as the angular
separation becomes different from 180), the difference current becomes non‐zero, re‐establishing the protection’s
sensitivity to detection of faults on the line being protected. Hence, the existence of the blind spot could delay the
detection of some faults, as the angular separation needs to move from a less favorable to a more favorable value. The
impact of this delay is system dependent, i.e., if the system slip is relatively fast, the delay could be minimal. For example, at
slip frequency of 5 Hz, angular separation of 180 takes place in 100 ms. so the blind spot could last for less than 10 ms. The
blind spot lasts for correspondingly longer periods of time when the slip frequency is reduced.
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Appendix B – Protection Systems Attributes Related to Power Swings
The shortcoming discussed above may be inconsequential in many applications; however, current‐only‐based protection
systems have another shortcoming because backup protection is needed to address failures of the communication channel.
In practice, a second independent current‐based protection scheme could be applied to provide backup protection.
However, a power system with no remote backup protection is susceptible to uncleared faults unless back‐up protection is
applied. Although a current‐only‐based protection system is secure for stable power swings and can be used on lines which
require tripping on out‐of‐step conditions, an out‐of‐step tripping protection function is still required. Using an impedance‐
based back‐up protection or out‐of‐step tripping function reintroduces the need to discriminate between stable and
unstable power swings. The shortcomings of impedance‐based out‐of‐step tripping functions can be mitigated by applying
an integrated out‐of‐step tripping function that is supervised by non impedance‐based algorithms; however, testing out‐of‐
step tripping functions using simulated power system swings from the August 14, 2003 blackout investigation has identified
susceptibility of some such protection systems to misoperate.
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Appendix C – Overview of Out-of-Step Protection Functions
Power Swing and Out-of-Step Phenomenon
A power swing is a system phenomenon that is observed when the phase angle of one power source varies in time with
respect to another source on the same network. The phenomenon occurs following any system perturbation, such as
changes in load, switching operations, and faults, that alters the mechanical equilibrium of one or more machines. A power
swing is stable when, following a disturbance, the rotation speed of all machines returns to synchronous speed. A power
swing is unstable when, following a disturbance, one or more machines do not return to synchronous speed, thereby losing
synchronism with the rest of the system.
Basic Phenomenon Using the Two-Source Model
The simplest network for studying the power swing phenomenon is the two‐source model, as shown in Fig. 12. The left
source has a phase angle advance equal to θ, and this angle will vary during a power swing. The right source represents an
infinite bus, and its angle will not vary with time. This elementary network can be used to understand the behavior of more
complex networks, although it has limitations when considering swings with multiple modes and time‐varying voltages.
Figure 13: Two-source Equivalent Elementary Network
Representation of Power Swings in the Impedance Plane
Assuming the sources have equal impedance amplitude, for a particular phase angle θ, the location of the positive‐
sequence impedance (Z1) calculated at the left bus is provided by the following equation [1]:
Z1
V1S
ES
ZT •
– ZS
I1
ES – E R
(1)
In (1), ZT is the total impedance, as in:
ZT ZS ZL ZR
(2)
Assuming the two sources are of equal magnitude, the Z1 impedance locus in the complex plane is given by (3).
Z1
ZT
2
• 1 jcot ZS
2
(3)
When the angle θ varies, the locus of the Z1 impedance is a straight line that intersects the segment ZT orthogonally at its
middle point, as shown in Figure 14. The intersection occurs when the angular difference between the two sources is 180
degrees. When a generator torque angle reaches 180 degrees, the machine is said to have slipped a pole, reached an out‐
of‐step (OOS) condition, or lost synchronism.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Figure 14: Locus of the Z1 Impedance During a Power Swing with Sources of Equal Magnitude
When the two sources have unequal magnitudes such that n is the ratio of ES over ER, the locus of the Z1 impedance
trajectory will correspond to the circles shown in Figure 15. For any angle θ, the ratio of the two segments joining the
location of the extremity of Z1 (Point P) to the total impedance extremities A and B is equal to the ratio of the source
magnitudes.
n
ES PA
E R PB
(4)
The precise equation for the center and radius of the circles as a function of the ratio n can be found in [1].
X
PA
=n
PB
B
P
θ
n>1
Z1
n=1
R
A
n<1
Figure 15: Locus of the Z1 Impedance During a Power Swing with Sources of Unequal Magnitude
It should be noted that synchronous generators are not ideal voltage sources as represented in the equivalent two‐source
model. Furthermore, the impact of automatic voltage regulators must be considered. During a power swing, the ratio of
two power source magnitudes will not remain constant. Therefore, the resulting locus of the Z1 impedance will not follow a
unique circle, with the trajectory depending upon the instantaneous voltage magnitude ratio.
Rate of Change of the Positive-Sequence Impedance
Starting with (1) and assuming the two sources are of equal magnitude, the time derivative of the Z1 impedance is provided
by (5) [2].
dZ1
e j
jZ T •
dt
1 e j
2
•
d
dt
(5)
Assuming the phase angle has a linear variation with a slip frequency in radians per second given as:
d
dt
(6)
and using the identity:
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Appendix C – Overview of Out‐of‐Step Protection Functions
2
the rate of change of the Z1 impedance is finally expressed as:
1 e j 2 • sin
ZT
dZ1
•
dt
4 • sin 2
2
(7)
(8)
Equation (8) expresses the principle that the rate of change of the Z1 impedance depends upon the sources, transmission
line impedances, and the slip frequency, which, in turn, depend upon the severity of the power system disturbance.
As a consequence, any algorithm that uses the Z1 impedance displacement speed in the complex plane to detect a power
swing will depend upon the network impedances and the nature of the disturbance. Furthermore, the source impedances
vary during the disturbance and typically are not introduced into the relay settings so the relay cannot usually predict the
displacement speed.
Out-of-Step Protection Functions
The detection of power swings is performed with two fundamental functions: the power swing blocking (PSB) function and
the out‐of‐step tripping (OST) function [3]. The PSB function discriminates faults from stable or unstable power swings. The
PSB function blocks relay elements that are prone to operate during stable or unstable power swings to prevent system
separation in an indiscriminate manner. In addition, the PSB function unblocks previously blocked relay elements and
allows them to operate for faults, in their zone of protection, that occur during an out‐of‐step (OOS) condition.
The OST function discriminates stable from unstable power swings and initiates network islanding during loss of
synchronism. OST schemes are designed to protect the power system during unstable conditions, isolating unstable
generators or larger power system areas from each other with the formation of system islands, to maintain stability within
each island by balancing the generation resources with the area load.
To accomplish this, OST systems must be applied at preselected network locations, typically near the network electrical
center. The isolated portions of the system are most likely to survive when network separation takes place at locations that
preserve a close balance between load and generation. Since it is not always possible to achieve a load‐generation balance,
some means of shedding nonessential load or generation is necessary to avoid a collapse of the isolated portions of the
power system.
Many relay systems are prone to operate during an OOS condition, which may result in undesired tripping. Therefore, OST
systems may need to be complemented with PSB functions to prevent undesired relay system operations and to achieve a
controlled system separation. When transmission separation schemes trip before fault protective relays operate, it may be
desirable to not use the PSB function so that the fault protection can provide a last line of defense against asynchronous
conditions.
Typically, the location of OST relay systems determines the location where system islanding takes place during loss of
synchronism. However, it may be necessary in some systems to separate the network at a location other than the one
where OST is installed. This is accomplished with the application of a transfer tripping type of scheme.
Uncontrolled tripping during OOS conditions can cause damage to power system breakers due to high transient
overvoltages that appear across the breaker contacts when switching a line that contains the electrical center of a power
swing. The maximum transient recovery voltage occurs when the relative phase angle of the two systems is 180° during the
OOS condition. Circuit breaker opening angle should be considered in applying out‐of‐step protection for transmission
circuits because opening at angles greater than 120 degrees may cause excess voltage stress on the circuit breaker. When
selecting out‐of‐step relay settings it may be necessary to balance the potential breaker opening angle, the potential
adverse impact of transmission voltage dips associated with a loss of synchronism, and the need to avoid tripping for
recoverable swings.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Power Swing Detection Methods
There are many different methods that are used to detect power swings, each with its strengths and drawbacks [4]. This
section presents some of those detection methods.
Conventional Rate of Change of Impedance Methods
The rate of change of impedance methods are based on the principle that the Z1 impedance travels in the complex plane
with a relatively slow speed, whereas during a fault, Z1 switches from the load point to the fault location almost
instantaneously.
Blinder Schemes
Figure 16 shows an example of a single‐blinder scheme. This scheme detects an unstable power swing when the time
interval required to cross the distance between the right and left blinders exceeds a minimum time setting. The scheme
allows for the implementation of OST on the way out of the zone and cannot be used for PSB because the mho
characteristics will be crossed before the power swing is detected. This method is most commonly implemented in
conjunction with generator protection and not line protection.
Figure 16: Single-Blinder Characteristic
Figure 17 shows an example of a dual‐blinder scheme. During a power swing, the dual‐blinder element measures the time
interval T that it takes the Z1 trajectory to cross the distance between the outer and inner blinders. When this measured
time interval is longer than a set time delay, a power swing is declared. The set time delay is adjusted so that it will be
greater than the time interval measured during a fault and smaller than the time interval measured during the Z1 travel at
maximum speed. Using the dual‐blinder scheme, an OST scheme can be set up to either trip on the way into the zone or on
the way out of the zone.
Figure 17: Dual-Blinder Characteristic
Concentric Characteristic Schemes
Concentric characteristics for the detection of power swings work on the same principle as dual‐blinder schemes: after an
outer characteristic has been crossed by the Z1 impedance, a timer is started and the interval of time before the inner
characteristic is reached is measured. A power swing is detected when the time interval is longer than a set time delay.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Characteristics with various shapes have been used, as shown in Figure 18. The dual‐quadrilateral characteristic
represented at the bottom right of Figure 18 has been one of the most popular.
Figure 18: Concentric Characteristic of Various Shapes
Nonconventional Power Swing Detection Methods
Continuous Impedance Calculation
The continuous impedance calculation consists of monitoring the progression in the complex plane (Figure 19) of three
modified loop impedances [5]. A power swing is declared when the criteria for all three loop impedances have been
fulfilled: continuity, monotony, and smoothness. Continuity verifies that the trajectory is not motionless and requires that
the successive R and X be above a threshold. Monotony verifies that the trajectory does not change direction by
checking that the successive R and X have the same signs. Finally, smoothness verifies that there are no abrupt changes
in the trajectory by looking at the ratios of the successive R and X that must be below some threshold.
Figure 19: Continuous Impedance Calculation
The continuous impedance calculation is supplemented by a concentric characteristic to detect very slow‐moving
trajectories.
One of the advantages of the continuous impedance calculation is that it does not require any settings and can handle slip
frequencies up to 7 Hz. It does not require, therefore, any power swing studies involving complex simulations.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Continuous Calculation of Incremental Current
During a power swing, both the phase voltages and currents undergo magnitude variations. The continuous calculation of
the incremental current method computes the difference between the present current sample value and the value stored
in a buffer 2 cycles before (see Figure 20). This method declares a power swing when the absolute value of the measured
incremental current is greater than 5 percent of the nominal current and that this same condition is present for a duration
of 3 cycles [6].
I
I
Figure 20: Continuous Calculation of Incremental ΔI
The main advantage of the continuous calculation of incremental current is that it can detect very fast power swings,
particularly for heavy load conditions.
R-Rdot OOS Scheme
The R‐Rdot relay for OST was devised specifically for the Pacific 500 kV ac intertie and was installed in the early 1980s. The
R‐Rdot relay uses the rate of change of resistance to detect an OOS condition.
An impedance‐based control law for OOS detection is created by defining the following function [7‐8]:
dZ
(9)
dt
If we define a phase plane where the abscissa is the impedance magnitude and the ordinate is the rate of change of the
impedance magnitude, (9) represents a switching line. An OOS trip is initiated when the switching line is crossed by the
impedance trajectory from right to left. The effect of adding the impedance magnitude derivative is that the tripping will be
faster at a higher impedance changing rate. At a small impedance changing rate, the characteristic is equivalent to the
conventional OOS scheme.
In the R‐Rdot characteristic, the impedance magnitude is replaced by the resistance measured at the relay location and the
rate of change of the impedance magnitude is replaced by the rate of change of the measured resistance (see Figure 21).
The advantage of this latter modification is that the relay becomes less sensitive to the location of the swing center with
respect to the relay location.
U1 (Z – Z1 ) T1 •
dR
(10)
dt
In the R‐Rdot plane the switching line U1 is a straight line having slope T1. System separation is initiated when output U1
becomes negative. For low separation rates (small dR/dt), the performance of the R‐Rdot scheme is similar to the
conventional OST relaying schemes. However, higher separation rates (dR/dt) would cause a larger negative value of U1 and
initiate tripping much earlier. For a conventional OST relay without a rate of change of apparent resistance, augmentation is
just a vertical line in the R‐Rdot plane offset by the R1 relay setting parameter.
U1 (R – R1 ) T1 •
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Appendix C – Overview of Out‐of‐Step Protection Functions
R1
R1
Figure 21: R-Rdot OOS Characteristic in the Phase Plane
Rate of Change of Swing Center Voltage (SCV)
SCV is defined as the voltage at the location of a two‐source equivalent system where the voltage value is zero when the
angles between the two sources are 180 degrees apart. Figure 22 illustrates the voltage phasor diagram of a general two‐
source system, with the SCV shown as the phasor from origin o to the point o’.
Figure 22: Voltage Phasor Diagram of a Two-Source System
When a two‐source system loses stability and enters an OOS condition, the angle difference of the two sources, θ(t),
increases as a function of time [2]. We can represent the SCV with (11), assuming equal source magnitudes in a two‐source
equivalent system, E = |ES| = |ER|.
t
t
SCV t 2Esin t
• cos
2
2
(11)
SCV(t) is the instantaneous SCV that is to be differentiated from the SCV that the relay estimates. Equation (11) is a typical
amplitude‐modulated sinusoidal waveform. The first sine term is the base sinusoidal wave, or the carrier, with an average
frequency of ω + (1/2)(dθ/dt). The second term is the cosine amplitude modulation.
One popular approximation of the SCV obtained through the use of locally available quantities is as follows:
SCV VS • cos
(12)
where:
|VS| is the magnitude of locally measured voltage.
φ is the angle difference between VS and the local current, as shown in Figure 23.
The quantity of Vcosφ was first introduced by Ilar for the detection of power swings [9].
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Appendix C – Overview of Out‐of‐Step Protection Functions
Figure 23: Vcosφ is a Projection of Local Voltage, VS, onto Local Current, I
In Figure 23, we can see that Vcosφ is a projection of VS onto the axis of the current, I. For a homogeneous system with the
system impedance angles close to 90 degrees, Vcosφ approximates well the magnitude of the SCV. For the purpose of
power swing detection, it is the rate of change of the SCV that provides the main information of system swings. Therefore,
some difference in magnitude between the system SCV and its local estimate has little impact in detecting power swings.
We will, therefore, refer to Vcosφ as the SCV in the following discussion.
Using (11) and keeping in mind that the local SCV is estimated using the magnitude of the local voltage, VS, the relation
between the SCV and the phase angle difference, θ, of two source voltage phasors can be simplified to the following:
SCV1 E1• cos
2
(13)
In (13), E1 is the positive‐sequence magnitude of the source voltage, ES, shown in Figure 23 and is assumed to be also equal
to ER. The time derivative of SCV1 is given by (14).
d SCV1
E1 d
sin
dt
2
2 dt
(14)
Equation (14) provides the relationship between the rate of change of the SCV and the two‐machine system slip frequency,
dθ/dt. Equation (14) shows that the derivative of SCV1 is independent of power system impedances. Figure 24 is a plot of
SCV1 and the rate of change of SCV1 for a system with a constant slip frequency of 1 radian per second.
Figure 24: SCV1 and Its Rate of Change with Unity Source Voltage Magnitudes
Synchrophasor-Based OOS Relaying
Consider the two‐source equivalent network of Figure 13, and assume that the synchrophasors of the positive‐sequence
voltages are measured at the left and right buses as V1S and V1R.
The ratio of the two synchronized vectors is provided by the following equation:
ZS
Z
(1 – S ) • k E
V1S
ZT
ZT
V1R ZS ZL (1 – ZS ZL ) • k
E
ZT
ZT
(15)
where:
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Appendix C – Overview of Out‐of‐Step Protection Functions
kE is the ratio of the magnitudes of the source voltages:
kE
ES
ER
(16)
Assuming the source impedances are small with respect to the line impedance and the ratio kE is close to 1, the ratio of the
synchronized vectors can be approximated by unity for its magnitude and by the angle between the two sources for its
phase angle.
When using the two‐source network equivalent, the result of (15) indicates that the ratio of the synchrophasors measured
at the line extremities has a phase angle that can be approximated by the phase angle between the two sources. During a
disturbance, the trajectory of the phase angle between the two phasors replicates the variation of the phase angle between
the two machines. It is therefore possible to determine if an OOS condition is taking place when the measured phase angle
trajectory becomes unstable [10].
Reference 10 presents the implementation of three functions based on synchrophasor measurements, the purpose of
which is to trigger a network separation after a loss of synchronism has been detected. Positive‐sequence voltage‐based
synchrophasors are measured at two locations of the network, assuming that the two‐source equivalent can model the
network. Following the measurement of the synchrophasors, two quantities are derived: the slip frequency SR, which is the
rate of change of the angle between the two measurements, and the acceleration AR, which is the rate of change of the slip
frequency. The three functions are defined as follows:
Power swing detection is asserted when SR is not zero and is increasing, which indicates AR is positive and
increasing.
Predictive OST is asserted when, in the slip frequency against the acceleration plane, the trajectory falls in the
unstable region (see Figure 25) defined by the condition:
A R 78 _ Slope • SR A Offset
(17)
OOS detection asserts when the absolute value of the angle difference between the two synchrophasors becomes
greater than a threshold.
Figure 25: Predictive OST in the Slip-AccelerationPlane
A network separation or OST is initiated when the three functions are asserted.
Out-of-Step Tripping Function
The OST function protects the power system during unstable conditions by isolating unstable generators or larger power
system areas from each other by forming system islands. The main criterion is to maintain stability within each island. To
accomplish this, OST systems should be applied at preselected network locations, typically near the network electrical
center, to achieve a controlled system separation. The isolated portions of the system are most likely to survive when
network separation takes place at locations in the network that preserve a close balance between load and generation.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Since it is not always possible to achieve a load‐generation balance, some means of shedding load or generation is
necessary to avoid a collapse of isolated portions of the power system.
OST systems may be complemented with PSB functions to prevent undesired relay system operations, equipment damage,
and the shutdown of major portions of the power system. In addition, PSB blocking may be applied at other network
locations to prevent system separation in an indiscriminate manner.
The selection of network locations for the placement of OST systems can best be obtained through transient stability
studies covering many possible operating conditions. The maximum rate of slip is typically estimated from angular change
versus time plots from stability studies. The stability study results are also used to identify the optimal location of OST and
PSB relay systems, because the apparent impedance measured by OOS relay elements is a function of the MW and Mvar
flows in transmission lines. Stability studies help identify the parts of the power system that impose limits on angular
stability, generators that are prone to go out of step during system disturbances and those that remain stable, and groups
of generators that tend to behave similarly during a disturbance.
Typically, the location of OST relay systems determines the location where system islanding takes place during loss of
synchronism. However, in some systems, it may be necessary to separate the network at a location other than the one
where OST is installed. This is accomplished with the application of a transfer tripping scheme. Current supervision may be
necessary when performing OST at a different power system location than the location of OST detection to avoid issuing a
tripping command to a circuit breaker at an unfavorable phase angle. Another important aspect of OST is to avoid tripping a
line when the angle between systems exceeds the circuit breaker capability. Tripping during this condition imposes high
stresses on the breaker and could cause breaker damage as a result of high recovery voltage across the breaker contacts,
unless the breaker is rated for out‐of‐phase switching [11].
Conventional OST Schemes
Conventional OST schemes are based on the rate of change of the measured positive‐sequence impedance vector during a
power swing. The OST function is designed to differentiate between a stable and an unstable power swing and, if the power
swing is unstable, to send a tripping command at the appropriate time to trip the line breakers. Traditional OST schemes
use distance characteristics similar to the PSB schemes shown in Figures 16, 17, and 18. OST schemes also use a timer to
time how long it takes for the measured impedance to travel between the two concentric characteristics. If the timer
expires before the measured impedance vector travels between the two characteristics, the relay declares the power swing
as an unstable swing and issues a tripping signal. Voltage supervision will increase the security of the OST scheme.
Figure 18 shows the dual‐quadrilateral characteristic used for the detection of power swings. When the positive‐sequence
impedance enters the outer zone, two OOS logic timers start (OSTD and OSBD). Figure 26 illustrates how these timers
operate.
There are two methods to implement out‐of‐step tripping. The first method is to trip on the way in (TOWI) when the OSTD
timer expires and the positive‐sequence impedance enters the inner zone. The second method is to select to trip on the
way out (TOWO) when the OSTD timer expires and the positive‐sequence impedance enters and then exits the inner zone.
TOWO has the advantage of tripping the breaker at a more favorable time during the slip cycle when the two systems are
close to an in‐phase condition.
TOWI is necessary in some systems to prevent severe voltage dips and potential loss of loads. TOWI is typically applied in
very large systems where the angular movement of one system with respect to another is very slow. It is also applied where
there is a risk that transmission line thermal damage will occur if tripping is delayed until a more favorable angle exists
between the two systems. However, it is necessary to evaluate potential trip conditions against the circuit breaker
capability because the relay issues the tripping command to the circuit breaker when the relative phase angles of the two
systems are approaching 180 degrees, which results in greater breaker stress than for OST applications that implement
TOWO.
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Appendix C – Overview of Out‐of‐Step Protection Functions
jX
Z1 Plane
Re (Z1)
–
R7
+
Re (Z1)
–
R6
+
Start
R6
R7
R
OSBD
OSTD
Block
Trip
Figure 26: Dual-Quadrilateral Timer Scheme
One of the most important and difficult aspects of an OST scheme is the calculation of proper settings for the distance relay
OST characteristics and the OST time‐delay setting. Detailed dynamic simulation studies are recommended for cases where
a transmission separation scheme is being developed for a specific disturbance scenario. These simulation studies can be
used to address issues such as the maximum recoverable swing impedance and the adverse impact of the transient voltage
dips associated with the swing. In some cases out of step settings may involve a tradeoff between minimizing transient
voltage dips and avoid separation for recoverable swings.
The other difficult aspect of OST schemes is determining the appropriate time at which to issue a trip signal to the line
breakers to avoid equipment damage and ensure personnel safety. To adequately protect the circuit breakers and ensure
personnel safety, it may be necessary to prevent uncontrolled tripping during an OOS condition by restricting operation of
the OST function to relative voltage angles between the two systems within the circuit breaker capability. Logic is included
to allow delayed OST on the way out to minimize the possibility of breaker damage.
Non-conventional OST Schemes
The previously discussed OST setting complexities and the need for stability studies can be eliminated if the OST function is
supervised by the output of a robust PSB function that makes certain that the network is experiencing a power swing and
not a fault [4]. Using a reliable bit from the SCV PSB function for example to supervise an SCV‐assisted OST function allows
the implementation of a TOWO OST scheme without the need to perform any stability studies, which is a major advantage
over traditional OST schemes.
The SCV‐assisted OST function tracks and verifies that the measured Z1 impedance trajectory crosses the complex
impedance plane from right to left, or from left to right, and issues a TOWO at a desired phase angle difference between
sources. Verifying that the Z1 impedance enters the complex impedance plane from the left or right side and making sure it
exits at the opposite side of the complex impedance plane ensures that the function operates only for unstable power
swings. On the contrary, traditional OST schemes that do not track the Z1 impedance throughout the complex impedance
plane may operate for a stable swing that was not considered during stability studies and happens to cross the inner OST
characteristic.
Four resistive and four reactive blinders are still used in the SCV‐assisted OST scheme, as shown in Figure 18. However, the
settings for these blinders are easy to calculate when applying TOWO. The outermost OST resistive blinders can be placed
around 80 to 90 degrees in the complex impedance plane, regardless of whether a stable power swing crosses these
blinders or whether the load impedance of a long, heavily loaded line encroaches upon them. The inner OST resistive
blinder can be set anywhere from 120 to 150 degrees. In addition, there are no OST timer settings involved in the SCV‐
assisted OST scheme.
To apply TOWI, stability studies are still required to ensure that no stable swings will cause the operation of the inner OST
characteristic.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Issues Associated With the Concentric or Dual-Blinder Methods
Impact of System Impedances
To guarantee enough time to carry out blocking of the distance elements after a power swing is detected, the inner
impedance of the blinder element must be placed outside the largest distance element for which blocking is required. In
addition, the outer blinder impedance element should be placed away from the load region to prevent PSB logic operation
caused by heavy loads, thus establishing an incorrect blocking of the line mho tripping elements. The previous requirements
are difficult to achieve in some applications, depending on the relative line impedance and source impedance magnitudes
(see Figure 27).
Figure 27a depicts a system in which the line impedance is large compared with system impedances (strong source), and
Figure 27b depicts a system in which the line impedance is much smaller than the system impedances (weak source).
We can observe from Figure 27a that the swing locus could enter the zone 2 and zone 1 relay characteristics during a stable
power swing from which the system could recover. For this particular system, it may be difficult to set the inner and outer
PSB blinder elements, especially if the line is heavily loaded, because the necessary PSB settings are so large that the load
impedance could establish incorrect blocking. To avoid incorrect blocking resulting from load, lenticular distance relay
characteristics, load encroachment, or blinders that restrict the tripping area of the mho elements have been applied in the
past. On the other hand, the system shown in Figure 27b becomes unstable before the swing locus enters the zone 2 and
zone 1 mho elements, and it is relatively easy to set the inner and outer PSB blinder elements.
Another difficulty with the blinder characteristic method is the separation between the inner and outer PSB blinder
elements and the timer setting that is used to differentiate a fault from a power swing. These settings are not difficult to
calculate, but depending on the system under consideration, it may be necessary to run extensive stability studies to
determine the fastest power swing and the proper PSB blinder element settings. The rate of slip between two systems is a
function of the accelerating torque and system inertias. In general, a relay cannot determine the slip analytically because of
the complexity of the power system. However, by performing system stability studies and analyzing the angular excursions
of systems as a function of time, it is possible to estimate an average slip in degrees per second or cycles per second. This
approach may be appropriate for systems where slip frequency does not change considerably as the systems go out of step.
However, in many systems where the slip frequency increases considerably after the first slip cycle and on subsequent slip
cycles, a fixed impedance separation between the blinder PSB elements and a fixed time delay may not be suitable to
provide a continuous blocking signal to the mho distance elements.
In a complex power system, it is very difficult to obtain the proper source impedances that are necessary to establish the
blinder and PSB delay timer settings [3]. The source impedances vary continuously according to network changes, such as
additions of new generation and other system elements. The source impedances could also change drastically during a
major disturbance and at a time when the PSB and OST functions are called upon to take the proper actions. Normally, very
detailed system stability studies are necessary to consider all contingency conditions in determining the most suitable
equivalent source impedance to set the PSB or OST functions.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Figure 27: Effects of Source and Line Impedances on the PSB Function
Impact of Heavy Load on the Resistive Settings of the Quadrilateral Element
References [3] and [4] recommend setting the concentric dual‐quadrilateral power swing characteristic inside the maximum
load condition but outside the maximum distance element reach desired to be blocked. In long‐line applications with a
heavy load flow, following these settings guidelines may be difficult, if not impossible. Fortunately, most numerical distance
relays allow some form of programming capability to address these special cases. However, in order to set the relay
correctly, stability studies are required; a simple impedance‐based solution is not possible.
The approach for this application is to set the power swing blinder such that it is inside the maximum load flow impedance
and the worst‐case power swing impedance. Using this approach can result in cutting off part of the distance element
characteristic. Reference [11] provides additional information and logic to address the issues of PSB settings on heavily
loaded transmission lines.
OOS Relaying Philosophy
There are many different power swing detection methods that can be used to protect a power system from OOS conditions,
each of which has its own benefits and drawbacks. While the OOS relaying philosophy is simple, it is often difficult to
implement in a large power system because of the complexity of the system and the different operating conditions that
must be studied.
The recommended approach for OOS relaying application is summarized below:
Perform system transient stability studies to identify system stability constraints based on many operating
conditions and stressed‐system operating scenarios. The stability studies will help identify the parts of the power
system that impose limits to angular stability, generators that are prone to go OOS during system disturbances,
and those that remain stable. The results of stability studies are also used to identify the optimal location of OST
and PSB protection relay systems.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Determine the locations of the swing loci during various system conditions and identify the optimal locations to
implement the OST protection function. The optimal location for the detection of the OOS condition is near the
electrical center of the power system. However, it is necessary to determine that the behavior of the impedance
locus near the electrical center would facilitate the successful detection of OOS.
Determine the optimal location for system separation during an OOS condition. This will typically depend on the
impedance between islands, the potential to attain a good load/generation balance, and the ability to establish
stable operating areas after separation. High impedance paths between system areas typically represent
appropriate locations for network separation.
Establish the maximum rate of slip between systems for OOS timer setting requirements, as well as the minimum
forward and reverse reach settings required for successful detection of OOS conditions. The swing frequency of a
particular power system area or group of generators relative to another power system area or group of generators
does not remain constant. The dynamic response of generator control systems, such as automatic voltage
regulators, and the dynamic behavior of loads or other power system devices, such as SVCs and FACTS, can
influence the rate of change of the impedance measured by OOS protection devices.
References
[1]
C. R. Mason, The Art and Science of Protective Relaying. John Wiley & Sons, Inc., New York, 1956.
[2]
G. Benmouyal, D. Hou, and D. Tziouvaras, "Zero‐setting Power‐Swing Blocking Protection ", proceedings of the 31st
Annual Western Protective Relay Conference, Spokane, WA, October 2004.
[3]
D. Tziouvaras, and D. Hou, “Out‐of‐Step Protection Fundamentals and Advancements,” proceedings of the 30th
Annual Western Protective Relay Conference, Spokane, WA, October 2003.
[4]
N. Fischer, G. Benmouyal, Da. Hou, D. Tziouvaras, J. Byrne‐Finley, and B. Smyth, “Tutorial on Power Swing Blocking and
Out‐of‐Step Tripping,” proceedings of the 39th Annual Western Protective Relay Conference, Spokane, WA, October
2012.
[5]
J. Holbach, “New Blocking Algorithm for Detecting Fast Power Swing Frequencies,” proceedings of the 30th Annual
Western Protective Relay Conference, Spokane, WA, October 2003.
[6]
Q. Verzosa, “Realistic Testing of Power Swing Blocking and Out‐of‐Step Tripping Functions,” proceedings of the 38th
Annual Western Protective Relay Conference, Spokane, WA, October 2011.
[7]
C. W. Taylor, J. M. Haner, L. A. Hill, W. A. Mittelstadt, and R. L. Cresap, “A New Out‐of‐Step Relay With Rate of Change
of Apparent Resistance Augmentation,” IEEE Transactions on Power Apparatus and Systems, Vol. PAS‐102, No. 3,
March 1983.
[8]
J. M. Haner, T. D. Laughlin, and C. W. Taylor, “Experience with the R Rdot Out‐of‐Step Relay,” IEEE Transactions on
Power Delivery, Vol. 1, No. 2, April 1986.
[9]
F. Ilar, “Innovations in the Detection of Power Swings in Electrical Networks,” Brown Boveri Publication CH‐ES 35‐
30.10E, 1997.
[10] A. Guzmán, V. Mynam, and G. Zweigle, “Backup Transmission Line Protection for Ground Faults and Power Swing
Detection Using Synchrophasors,” proceedings of the 34th Annual Western Protective Relay Conference, Spokane,
WA, October 2007.
[11] J. Mooney and N. Fischer, “Application Guidelines for Power Swing Detection on Transmission Systems,” proceedings
of the 32nd Annual Western Protective Relay Conference, Spokane, WA, October 2005.
[12] W. A. Elmore, "The Fundamentals of Out‐of‐Step Relaying," proceedings of the 34th Annual Conference for Protective
Relay Engineers, Texas A&M University, College Station, TX, April 1981.
[13] IEEE Power System Relaying Committee, Working Group D‐6 Report, Power Swing and Out‐of‐Step Considerations on
Transmission Lines. Available: http://www.pes‐psrc.org/.
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Appendix D – Potential Methods to Demonstrate Security of
Protective Relays
IEEE PSRC WG D6 Method
Appendix A of the IEEE PSRC WG D6 paper on power swing considerations presents the process of reducing a complex
power system to a two source equivalent system connected by a single transmission line in parallel with a second line which
is the equivalent of the remaining transmission system connecting the two sources. The two source equivalent system will
be accurate for faults anywhere on the retained transmission line. It can also be used to determine whether the swing
center of the two systems lies within the retained transmission. The usefulness of the method of determining whether the
swing center is contained within the line depends on the probability of the actual power system to consist of two coherent
systems of generators connected by the modeled system.
This method was applied to a system in the northwest portion of the eastern interconnection. The system consists of a
double circuit ring of 345 kV lines around an underlying 115 kV system. Large generation stations are located at several
points around the ring. The 345 kV lines connect with other systems from the east, southeast, and southwest parts of the
ring. When applied to these connections, the method of Appendix A predicts that the swing center will pass through these
lines. In fact this system has been observed to have at least one of these swing centers, and the system of generators
around the ring will behave as a coherent set relative to the connected system across the ties.
The method also predicts that virtually every 115kV line within the 345kV ring will also contain the swing center when the
system is reduced to a two source equivalent. It is extremely unlikely to separate into two independent sets of coherent
generators within this ring. In his paper “The Fundamentals of Out‐Of‐Step Relaying”, Walt Elmore presents this method
and states, “When more than a line or two are to be analyzed, it is virtually impossible to use the method.”
When applied to the 345kV lines making up the double circuit ring, the method shows that for a majority of them the swing
center will not pass through them, but will fall just outside the line. For the most part, these lines are fairly short with many
interconnections. An assessment was not performed examining the effect of taking two or three lines out, but this likely
would result in bringing the center into one end of the line. With several of these lines out the possibility of two sets of
generators swinging relative to each other increases.
For the most part, the Appendix A method looks useful for identifying swing centers between relatively independent
systems connected by a small number of ties.
Calculation Methods based on the Graphical Analysis Method
A classical method to determine if a particular relay is subject to tripping during a power swing is discussed in Appendix A.
In this method, the system consists of the line where the relay is applied with a system equivalent generator and
impedance at each end of a particular line (see Figure 6). For this system, assuming equal voltage magnitudes for the
equivalent generator, a power swing traverses along the perpendicular bisector of the total system impedance. Figure 6
shows a graphical interpretation of this. In Figure 7, the dashed line is the path the impedance traverses during the power
swing and the angle delta is the angle between the two equivalent generator sources. The impedance seen at relay terminal
A is to the right of the relay’s impedance characteristic prior to the onset of the power swing. As a stable power swing
occurs, the angle between the two equivalent generators increases causing the impedance to move to the left along the
dashed line. When the system stabilizes, the power swing will switch directions (this can take a significant amount of time)
and move to the right along the dashed line, oscillate, and then end at a new stable operating point. Depending on the size
of the overall system impedance, the length of the line, and the reach of the impedance relay, the stable power swing may
or may not fall within the relay characteristic. For cases where the relay’s impedance characteristic intersects the electrical
center of the system, the power swing will enter the relay’s characteristic at some value of the angle delta. When the power
swing enters the relay’s characteristic, the relay will trip quickly if it is a zone 1 type relay. Because stable power swings may
be slower to reverse direction than it takes a typical time delayed relay to trip, time delayed zones must also be evaluated.
As stated in this report and many others it is generally accepted based on many power swing studies that if a power swing
traverses beyond an angle delta greater than or equal to 120 degrees, the power swing will not be stable. This 120 degree
angle is often called the “critical angle.” The logic behind the general acceptance of 120 degrees as the critical angle for
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
stability is discussed above in Appendix A. Two potential methods are presented to screen relays for susceptibility to stable
power swings based on the use of the 120 degree critical angle.
Method 1
The first method uses an equivalent circuit based on the system shown in Figure 28. A calculation is made of the impedance
seen at a relay terminal when the difference between the generator angles in the equivalent system described above is 120
degrees. If the impedance calculated does not fall within the relays impedance characteristic, it is not susceptible to
tripping for a stable power swing. The discussion that follows pertains to a mho type relay characteristic, but the same
process could be used for other characteristics.
Figure 28: Two-Machine Equivalent of a Power System
Since this calculation does not use a computer model, various parameters must be established:
It is a reasonable and conservative assumption to assume that the voltage at the equivalent generator terminals is
1.05 per unit even under these severe conditions.
The angle between the generator voltages is set to the 120 degree critical angle.
Line and equivalent generator impedance angles are set to 90 degrees. This causes minimal variation in the
calculation and simplifies the calculation.
The equivalent generator impedances can be calculated using a fault study program and calculated with the line
under study out of service.
Given these parameters the allowable impedance for the relay (circular mho type) at terminal A can be calculated as
follows. Referring to Figure 28:
VA = EG ‐ IA*ZG and
IA = (EG‐EH)/(ZG + ZL + ZH) and
ZA = VA/IA = ZAMAG@ZAang and
ZAallowable = ZAMAG/(cos(MTA – ZAang))
Similarly, the Zallowable at the B terminal can be calculated:
VB = EH ‐ IH*ZH and
IB = ‐IA
ZB = VB/IB = ZBMAG@ZBang and
ZBallowable = ZBMAG/(cos(MTA – ZBang))
An example of some Zallowable calculations using this method for a 345kV system is shown below:
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Table 1: Examples of Zallowable for a Sample 345 kV System Using Method 1
System
Angle
(degrees)
System and Line
Impedance (Ohms)
EG
EH
Z G
ZL
Z H
90º
MTA
85º
MTA
80º
MTA
75º
MTA
90º
MTA
85º
MTA
80º
MTA
75º
MTA
0
120
5
5
10
11.7
13.0
14.9
17.5
11.7
10.6
9.8
9.2
0
120
13
5
10
66.3
227.4
‐158.4
‐58.9
16.3
15.1
14.3
13.6
0
120
20
20
10
46.7
62.7
96.5
213.3
46.7
37.4
31.4
27.2
0
120
5
5
60
43.6
46.5
50.3
55.1
43.6
41.3
39.6
38.2
ZA allowable
ZB allowable
Note 1) A negative number means that no stable power swings will fall within the zone.
Note 2) If EG = 120 and EH = 0, then the ZA allowable impedances shown become the ZB allowable impedances and vice
versa.
This method is conservative for a number of reasons:
This simplified calculation assumes a large stable power swing with the system in a normal configuration. Tripping
for a stable power swing is more likely with the system weakened. Weakening the system increases the allowable
impedance for a given line.
This simplified calculation estimates the equivalent system impedances from the fault model which uses sub‐
transient reactances for generators. Power Swings are longer time phenomena and use transient reactances which
are larger (X’’d ~ 0.7X’d).
It does not include the effects of parallel paths to the line under test (i.e., it ignores the transfer impedance – see
Method 2). Including parallel paths allows for a higher distance zone setting. This method essentially assumes that
the line under test is the only line connecting two systems.
Some conclusions that are generally known can also be drawn from this method:
Shorter lines with shorter relay settings are less susceptible to tripping on power swings than longer lines with
larger settings.
Zone 1 relays on short lines (i.e. lines < ~ 40 miles at 345kV and probably greater) are basically immune to tripping
on stable power swings. Overreaching distance zones (zone 2, zone 3, etc.) with reaches equivalent to this short
line zone 1 reach are also basically immune to tripping on stable power swings. Note that distances vary
proportionally with voltage level (lower at lower voltages and higher at higher voltage levels).
As source impedances change due to system configuration changes, the susceptibility of a mho relay to trip for a
stable power swing can vary a great deal.
Depending on the direction of power flow during the stable swing (into or out of the relay terminal), the
susceptibility of a mho relay to trip for a stable power swing can vary a great deal.
This method will screen out backup zones in some cases, but does not screen out backup zones well, even on
highly connected systems where stable power swings are less likely or highly unlikely.
Method 2
The second method uses an equivalent circuit based on the system shown in Figure 29. A calculation of the impedance seen
at a relay terminal when the difference between the generator angles in the equivalent system described above is 120
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
degrees is made. If the impedance calculated does not fall within the relays impedance characteristic, it is not susceptible to
tripping for a stable power swing. The discussion that follows pertains to a mho type relay characteristic, but the same
process could be used for other characteristics.
Figure 29: Two-Machine Equivalent of a Power System with Parallel System Transfer Impedance
Since this calculation does not use a computer model, various parameters must be established:
It is a reasonable and conservative assumption to assume that the voltage at the equivalent generator terminals is
1.05 per unit even under these severe conditions.
The angle between the generator voltages is set to the 120 degree critical angle.
Line and equivalent generator impedance angles are set to 90 degrees. This causes minimal variation in the
calculation and simplifies the calculation.
The equivalent generator impedances and transfer impedances can be obtained from a fault study program.
Given these parameters the allowable impedance for the relay (circular mho type) at terminal A can be calculated as
follows. Referring to Figure 29:
VA = EG – ITOTAL*ZG and
ITOTAL = (EG‐EH)/(ZG + Zeq + ZH) where Zeq = (ZL*ZTR)/(ZL + ZTR) and
IA = ITOTAL*(ZTR/(ZTR + ZL))
ZA = VA/IA = ZAMAG@ZAang and
ZAallowable = ZAMAG/(cos(MTA – ZAang))
Similarly, the Zallowable at the B terminal can be calculated:
VB = EH ‐ IH*ZH and
IB = ‐IA
ZB = VB/IB = ZBMAG@ZBang and
ZBallowable = ZBMAG/(cos(MTA – ZBang))
An example of some Zallowable calculations using this method for a 345kV system is shown below:
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Table 2: Examples of Zallowable for a Sample 345 kV System Using Method 2
System Angles
System, Line, and Transfer
Impedances
ZA allowable
ZB allowable
EG
EH
Z G
Z H
ZTR
ZL
90º
MTA
85º
MTA
80º
MTA
75º
MTA
90º 85º 80º
MTA MTA MTA
75º
MTA
0
120
5
5
10
10
20.0
23.7
29.2
38.6
17.5
16.3
15.4
14.7
0
120
5
5
50
10
13.1
14.8
17.1
20.5
12.7
11.7
10.9
10.3
0
120
5
5
100
10
12.4
13.9
16.0
18.9
12.2
11.2
10.4
9.7
0
120
5
5
500
10
11.8
13.2
15.1
17.8
11.8
10.7
9.9
9.3
0
120
13
5
10
10
-61.8
-44.7
-35.2
-29.3
27.8
26.2
25.0
24.0
0
120
13
5
50
10
416.3
-139.7
-60.0
-38.4
18.5
17.3
16.4
15.6
0
120
13
5
100
10
123.9
-489.1
-82.4
-45.2
17.4
16.2
15.3
14.6
0
120
20
20
10
10
140.0
257.7
1696.9
-369.5
52.0
47.8
44.6
42.1
0
120
20
20
50
10
61.1
86.7
151.4
615.4
40.1
34.7
30.7
27.7
0
120
20
20
100
10
53.6
74.0
120.9
337.1
41.7
35.0
30.4
27.0
0
120
5
5
10
60
76.9
86.7
100.2
119.8
83.5
79.4
76.3
74.0
0
120
5
5
50
60
48.7
52.5
57.4
63.9
51.6
48.9
46.9
45.4
0
120
5
5
100
60
46.0
49.4
53.7
59.3
47.6
45.1
43.2
41.8
Note 1) A negative number means that no stable power swings will fall within the zone.
Note 2) If EG = 120 and EH = 0, then the ZA allowable impedances shown become the ZB allowable impedances and vice
versa.
This method is conservative for a number of reasons:
This simplified calculation assumes a large stable power swing with the system in a normal configuration. Tripping
for a stable power swing is more likely with the system weakened. Weakening the system increases the allowable
impedance for a given line.
This simplified calculation estimates the equivalent system impedances from the fault model which uses sub‐
transient reactances for generators. Power Swings are longer time phenomena and use transient reactances which
are larger (X’’d ~ 0.7X’d).
Some conclusions that are generally known can also be drawn from this method:
If the transfer impedance is high, this method is essentially the same as method 1. If the transfer impedance is
infinite, this method is equivalent to method 1.
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
If the transfer impedance is low as in a more interconnected system, this method shows that a greater relay reach
can be set before a relay will trip during a stable power swing versus method 1. This method is a more accurate
representation of the power system and hence is more accurate than method 1. However, as transfer impedances
change due to system configuration changes, the susceptibility of a mho relay to trip for a stable power swing also
changes.
Shorter lines with shorter relay settings are less susceptible to tripping on power swings than longer lines with
larger settings.
Zone 1 relays on short lines (i.e. lines < ~ 40 miles at 345kV and probably greater) are basically immune to tripping
on stable power swings. Overreaching distance zones (zone 2, zone 3, etc.) with reaches equivalent to this short
line zone 1 reach are also basically immune to tripping on stable power swings. Note that distances vary with
voltage level (lower at lower voltages and higher at higher voltage levels).
As source impedances change due to system configuration changes, the susceptibility of a mho relay to trip for a
stable power swing can vary a great deal.
Depending on the direction of power flow during the stable swing (into or out of the relay terminal), the
susceptibility of a mho relay to trip for a stable power swing can vary a great deal.
This method will screen out backup zones better than method 1.
Like the methods for loadability in PRC‐023, both method 1 and method 2 address a single impedance relay or a single relay
element. This method does not provide a calculation for a composite scheme like a Permissive Overreach with Transfer Trip
scheme where two relays may be required to pick up to cause a trip.
Voltage Dip Screening Method
Although there are number of successful power swing detection methods, the goal of the voltage dip method is to establish
a reliable screening tool easily applicable in transient stability planning studies. Transient stability planning studies evaluate
many contingencies and monitor performance of many variables of the Bulk‐Power System in order to demonstrate
compliance with applicable standards and criteria. Due to the comprehensive nature of the analysis, a practical screening
method that flags potential power swing problems is essential.
It is well known that the most accurate method of identifying stable/unstable power swing requires a model of the
protection system (susceptible to stable and unstable power swings) in place and detailed simulation of the event that
produces the power swing. A plot of apparent impedance trajectory during the system disturbance against an appropriate
relay characteristic determines the power swing status. In large scale transient stability planning studies where many
contingencies are considered, that approach requires an effort of modeling and maintaining many relay characteristics and
recording many apparent impedance channels. The proposed screening method seeks a reliable way of identifying potential
power swings with minimal burden on additional modeling as part of the analysis.
While the power swing is the result of angular separation between units or coherent groups of units that oscillate against
each other, finding the coherent groups requires multiple simulation runs. In power swing identification primary question is
whether the swing is stable or not and the subsequent question is to identify which units drive the power swing. As a result
of coherent units swings, the transmission voltage magnitude gets low near the center of the swing. Therefore, since
transmission voltages are monitored in transient stability planning studies and voltage performance is subject to planning
criteria in many areas (WECC Transmission planning standard and ISO‐NE voltage sag guidelines), post‐disturbance voltage
dips can be used as a potential screening tool for power swing identification.
In order to establish a theory behind the proposed method, a two‐source equivalent is examined first. Since the system has
only one path between two sources, the idea is to study a range of system conditions subject to the power swing and then
test the voltage dip criteria on the transmission line terminals. The two‐source system in Figure 30 is analyzed. The system
is assumed to be symmetrical (i.e., the source terminal voltages are equal in magnitude, |EG|=|EH|), during the power
swing, the electrical center occurs in the middle of the impedance between two sources.
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Figure 30:Two-source equivalent system
The following assumptions have been made regarding the system in Figure 30:
1) Source and line resistances are neglected
2) Distance relay characteristic is a circle with diameter equal to 100 percent of line reactance
3) Relay maximum torque angle is equal to line angle
4) For simplicity it will be assumed that XG+XL+XH=1 pu
5) Source voltage magnitudes are equal EG=EH=1.0 pu
6) EH0, represents an infinite bus
7) EG , with (0,180) swings against EH
8) Angle M represents angle of separation between sources G and H at which swing trajectory enters line relay
characteristic.
The equations used in numerical simulations of the system represented in Figure 30 are as follows.
The current between two sources is determined by:
I
EG E H 0
j( X G X L X H )
The voltage at the electrical center of the swing is:
VC E G j
XG XL XH
I
2
The complex voltages at the line ends A and B are:
V A EG jX G I
VB EH jX H I
The goal of the following analysis is that depending on different system conditions in terms of strength of systems and
length of the line, investigate values of different quantities of the two source system at the moment when power swing
locus enters the line relay characteristic (designated with angle M in Figure 30) and test whether power swing could be
identified based on voltage dip at the line terminals.
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Following system conditions are investigated.
1) Case 1: two strong systems connected with long line (i.e., XG = XH=0.1 pu and XL=0.8 pu)
2) Case 2: two weak systems connected with long line (XG = XH=0.3 pu and XL=0.4 pu)
3) Case 3: weak system G connected to strong system H with long line (XG = 0.3 XH=0.1pu and XL=0.6 pu)
4) Case 4: variation of case 3 with XG = 0.4 XH=0.2pu and XL=0.4 pu
Results of the analysis are summarized in Table 3 while power swing characteristics are plotted in Figures 31 and 32.
Table 3: Results
Case
XG [pu]
XL [pu]
XH [pu]
Zr [pudeg]
M
[deg]
VC [pu]
VA
A
[deg]
VB
B
[deg]
1
0.1
0.8
0.1
0.63951.5
103
0.622
0.883
96.7
0.883
6.33
2
0.3
0.4
0.3
0.53768.5
137
0.366
0.522
113.9
0.522
23.06
3
0.3
0.6
0.1
0.57261
122
0.485
0.598
96.8
0.851
5.72
4
0.4
0.4
0.2
0.52971
142
0.326
0.376
101.2
0.654
10.85
Figure 31: Case 1 and Case 2 Voltage Plots
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Figure 32: Case 3 and Case 4 Voltage Plots
Discussion of the Results
Case 1: sets the minimal angle M at which power swing trajectory enters the line relay characteristic. Voltage magnitudes
at line ends VA and VB are highest since they are electrically closer to sources than to the center of the swing. Figure 31a
illustrates the voltage magnitude plot for this scenario.
Case 2: If the systems are weak (high source reactance) angle M increases and voltage magnitudes at the line end get lower
(around 0.522 pu). The reason for lower line terminal voltages is its proximity to the electrical center of the swing. Fig. 30b
represents voltage plot for case 2 scenario.
Case 3: This case represents a weak system G that swings against strong system H. Angle M is around 120 and the line end
voltage VA that is closer to electrical center of the swing is below 0.6 pu. Figure 32a represents voltage plot for case 3
scenario.
Case 4: This case presents variation of Case 3. The weaker is the system G (higher reactance XG) the higher is the angle at
which power swing enters the line relay characteristic (M) which makes it difficult to set 120 as a threshold for stable
power swing detection. However, line terminal voltage closer to the electrical center gets very low; VA = 0.376 pu which
makes it more reliable indicator for a swing. Figure 32b represents voltage plot for case 4 scenario.
The cases considered in two‐source equivalent system indicate that voltage magnitude at the line terminal is a reliable
indication of the power swing.
Practical Power System Example
In order to make the proposed method practical for planning studies, and to establish potential voltage threshold for
identification of stable power swings, a few transient stability simulation with a known stable power swing were performed.
The first practical example is tested on New England’s bulk power system with three contingencies of increasing level of
severity. Voltage at the one terminal of the line subject to power swing and apparent impedance recorded by the relay at
the same line are monitored. Post disturbance apparent impedance and voltage magnitude performance for all three
contingencies are presented in Figure 33.
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Figure 33: Apparent Impedance and Voltage Dip Plots
From Figure 34 one can notice a strong coupling between voltage dip and minimum apparent impedance. It is also of
interest to confirm that the most severe contingency produces a stable power swing and the largest voltage dip. Since the
apparent impedance plot is not time dependent, an additional analysis is performed to correlate minimum voltage dip with
minimum apparent impedance during the power swing. Figure 34 presents such analysis with bold segments indicating
quantities during the same time interval.
Figure 34: Power Swing in the New England System
The second example presented in Figure 35 is the stable power swing simulation results in the Florida system.
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Figure 35: Power Swing in the Florida System
Analysis conducted on the New England and Florida systems suggest a few important conclusions.
Apparent impedance and voltage magnitude are correlated, therefore for screening purposes in planning studies
voltage magnitude can be used.
Presented cases suggest that post disturbance voltage magnitude in the range of 0.5 and 0.6 pu might be used as a
screening tool for power swing identification.
Cases identified in the screening analysis require further detailed study.
Although theory and practice of the proposed voltage dip method are consistent, more test cases are needed in order to
establish voltage dip threshold and applicable margin.
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Appendix E – System Protection and Control Subcommittee
William J. Miller
Chair
Principal Engineer
Exelon Corporation
David Penney, P.E.
RE – TRE – Alternate
Senior Reliability Engineer
Texas Reliability Entity
Philip B. Winston
Vice Chair
Chief Engineer, Protection and Control
Southern Company
Baj Agrawal
RE – WECC
Principal Engineer
Arizona Public Service Company
Michael Putt
RE – FRCC
Manager, Protection and Control Engineering Applications
Florida Power & Light Co.
Forrest Brock
Cooperative
Station Services Superintendent
Western Farmers Electric Cooperative
Mark Gutzmann
RE – MRO
Manager, System Protection Engineering
Xcel Energy, Inc.
Miroslav Kostic
Federal/Provincial Utility
P&C Planning Manager, Transmission
Hydro One Networks, Inc.
Richard Quest
RE – MRO – Alternate
Principal Systems Protection Engineer
Midwest Reliability Organization
Sungsoo Kim
Federal/Provincial Utility
Section Manager – Protections and Technical Compliance
Ontario Power Generation Inc.
George Wegh
RE – NPCC
Manager – Transmission Protection and Controls Engineering
Northeast Utilities
Joe T. Uchiyama
Federal/Provincial Utility
Senior Electrical Engineer
U.S. Bureau of Reclamation
Quoc Le
RE – NPCC ‐‐ Alternate
Manager, System Planning and Protection
NPCC
Daniel McNeely
Federal/Provincial Utility ‐ Alternate
Engineer ‐ System Protection and Analysis
Tennessee Valley Authority
Jeff Iler
RE – RFC
Principal Engineer, Protection and Control Engineering
American Electric Power
Michael J. McDonald
Investor‐Owned Utility
Principal Engineer, System Protection
Ameren Services Company
Therron Wingard
RE – SERC
Principal Engineer
Southern Company
Jonathan Sykes
Investor‐Owned Utility
Manager of System Protection
Pacific Gas and Electric Company
David Greene
RE – SERC ‐‐ Alternate
Reliability Engineer
SERC Reliability Corporation
Charles W. Rogers
Transmission Dependent Utility
Principal Engineer
Consumers Energy Co.
Lynn Schroeder
RE – SPP
Manager, Substation Protection and Control
Westar Energy
Philip J. Tatro
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Samuel Francis
RE – TRE
System Protection Specialist
Oncor Electric Delivery
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Appendix F – System Analysis and Modeling Subcommittee
John Simonelli
Chair
Director ‐ Operations Support Services
ISO New England
Hari Singh, Ph.D.
RE – WECC
Transmission Asset Management
Xcel Energy, Inc.
K. R Chakravarthi
Vice Chair
Manager, Interconnection and Special Studies
Southern Company Services, Inc.
Kent Bolton
RE – WECC – Alternate
Staff Engineer
Western Electricity Coordinating Council
G Brantley Tillis, P.E.
RE – FRCC
Manager, Transmission Planning Florida
Progress Energy Florida
Patricia E Metro
Cooperative
Manager, Transmission and Reliability Standards
National Rural Electric Cooperative Association
Kiko Barredo
RE – FRCC – Alternate
Manager, Bulk Transmission Planning
Florida Power & Light Co.
Paul McCurley
Cooperative – Alternate
Manager, Power Supply and Chief Engineer
National Rural Electric Cooperative Association
Thomas C. Mielnik
RE – MRO
Manager Electric System Planning
MidAmerican Energy Co.
Ajay Garg
Federal/Provincial Utility
Manager, Policy and Approvals
Hydro One Networks, Inc.
Salva R. Andiappan
RE – MRO – Alternate
Manager ‐ Modeling and Reliability Assessments
Midwest Reliability Organization
Amos Ang, P.E.
Investor‐Owned Utility
Engineer, Transmission Interconnection Planning
Southern California Edison
Donal Kidney
RE – NPCC
Manager, System Compliance Program Implementation
Northeast Power Coordinating Council
Bobby Jones
Investor‐Owned Utility
Project Manager, Stability Studies
Southern Company Services, Inc.
Quoc Le
RE – NPCC ‐‐ Alternate
Manager, System Planning and Protection
NPCC
Scott M. Helyer
IPP
Vice President, Transmission
Tenaska, Inc.
Eric Mortenson, P.E.
Investor‐Owned Utility
Principal Rates & Regulatory Specialist
Exelon Business Services Company
Digaunto Chatterjee
ISO/RTO
Manager of Transmission Expansion Planning
Midwest ISO, Inc.
Mark Byrd
RE – SERC
Manager ‐ Transmission Planning
Progress Energy Carolinas
Bill Harm
ISO/RTO
Senior Consultant
PJM Interconnection, L.L.C.
Gary T Brownfield
RE – SERC – Alternate
Supervising Engineer, Transmission Planning
Ameren Services
Steve Corey
ISO/RTO – Alternate
Manager, Transmission Planning
New York Independent System Operator
Jonathan E Hayes
RE – SPP
Reliability Standards Development Engineer
Southwest Power Pool, Inc.
Bob Cummings
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Kenneth A. Donohoo, P.E.
RE – TRE
Director System Planning
Oncor Electric Delivery
NERC | Protection System Response to Power Swings | August 2013
60 of 61
Appendix G – Additional Contributors
John Ciufo, P.Eng.
Principal Engineer
Ciufo & Cooperberg Consulting, Inc.
Tom Gentile
Vice President Transmission
Quanta Technology
Bryan Gwyn
Senior Director, Protection and Control Asset Management
Quanta Technology
Kevin W. Jones
Principal Engineer, System Protection Engineering
Xcel Energy
Dmitry Kosterev
Bonneville Power Administration
Chuck Matthews
Bonneville Power Administration
John O’Connor
Principal Engineer
Progress Energy Carolinas
Slobodan Pajic
Senior Engineer, Energy Consulting
GE Energy Management
Fabio Rodriguez
Principal Engineer
Progress Energy Florida
Tracy Rolstad
Senior Power System Consultant
Avista Corporation
Joseph Seabrook
Consulting Engineer
Puget Sound Energy, Inc.
Demetrios Tziouvaras
Senior Research Engineer
Schweitzer Engineering Laboratories, Inc.
NERC | Protection System Response to Power Swings | August 2013
61 of 61
Exhibit F
Analysis of Violation Risk Factors and Violation Severity Levels
Violation Risk Factors and
Violation Severity Level Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
(PRC-026-1 – Relay Performance During Stable Power Swings)
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: PRC-026-1 – Relay
Performance During Stable Power Swings.
Each primary requirement is assigned a VRF and a set of one or more VSLs. 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 ERO
Sanction Guidelines.
The Protection System Response to Power Swings Standard Drafting Team applied the following
NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under
this project.
NERC Criteria - Violation Risk Factors
High Risk Requirem ent
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
M edium R isk Requirem ent
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric 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 electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
Low er R isk Requirem ent
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 electric system, or the
ability to effectively monitor and control the bulk electric 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 electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
The standard drafting team (SDT) also considered consistency with the FERC Violation Risk Factor
Guidelines for setting VRFs: 1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors 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: 2
•
•
•
•
•
•
•
•
•
•
•
•
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
Guideline (2) — Consistency within a Reliability Standard
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
2 Id. at footnote 15.
1
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
2
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk
Factor 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.
NERC Criteria - Violation Severity Levels
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.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets
the full intent of the
requirement.
Moderate
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
High
Severe
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
3
FER C Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the
following four guidelines for determining whether to approve VSLs:
Guideline 1: Violation Severity Level Assignm ents Should Not Have the Unintended
Consequence of Low ering the Current Level of Com pliance
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 Assignm ents Should Ensure Uniform ity and
Consistency in the Determ ination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe
noncompliant performance.
Guideline 3: Violation Severity Level Assignm ent Should Be Consistent w ith the
Corresponding Requirem ent
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignm ent Should Be Based on A Single
Violation, Not on A Cum ulative Num ber 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 and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
4
VRF and VSL Justifications – PRC-026-1, R1
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to notify the respective Generator Owner or Transmission Owner of the BES Element(s) that
meet the Requirement R1 criteria prohibits further evaluation of any load-responsive protective relay
applied at the terminal of the Element(s). A load-responsive protective relay that goes without evaluation
may not be secure for a stable power swing and could, in the planning time frame, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two Bulk Power System (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Identification and
evaluation of BES Elements susceptible to power swings and the subsequent mitigation of load-responsive
protective relays applied at the terminals of these BES Elements that do not meet the PRC-026-1 –
Attachment B criteria will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on the issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
5
VRF and VSL Justifications – PRC-026-1, R1
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard FAC-014-2, R6 (“…Planning Authority shall
identify the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure of the Planning Coordinator to notify the respective Generator Owner or Transmission Owner of
the BES Element(s) that meet the Requirement R1 criteria prohibits further evaluation of any loadresponsive protective relay applied at the terminal of the Element. A load-responsive protective relay that
goes without evaluation may not be secure for a stable power swing and could, in the planning time
frame, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
6
VRF and VSL Justifications – PRC-026-1, R1
Proposed VSL
Lower
Moderate
High
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was less
than or equal to 30 calendar
days late.
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The Planning Coordinator provided
notification of the BES Element(s)
in accordance with Requirement
R1, but was more than 60 calendar
days and less than or equal to 90
calendar days late.
Severe
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 90 calendar days late.
OR
The Planning Coordinator failed to
provide notification of the BES
Element(s) in accordance with
Requirement R1.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is Element-driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
7
VRF and VSL Justifications – PRC-026-1, R1
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is binary and utilizes a VSL of Severe for failure in addition to incremental VSLs for
tardiness.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
8
VRF and VSL Justifications – PRC-026-1, R2
Proposed VRF
High
NERC VRF Discussion
A Violation Risk Factor of High is consistent with the NERC VRF Guidelines:
A failure to evaluate the Protection System to determine that it is expected to not trip for a stable power
swing for a BES Element could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
A Protection System that does not meet the PRC-026-1 – Attachment B criteria is less secure during stable
power swings, which increases the risk of tripping should the Protection System be challenged by a power
swing.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Evaluation of loadresponsive protective relays applied at the terminals of identified BES Elements will allow the Generator
Owner and Transmission Owner to determine whether the load-responsive protective relays meet the
PRC-026-1 – Attachment B criteria.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
9
VRF and VSL Justifications – PRC-026-1, R2
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard PRC-023-3, R1 “…Each Transmission Owner,
Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per unit voltage and a
power factor angle of 30 degrees”) which has a VRF of High.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure of the Generator Owner or Transmission Owner to evaluate that the Protection System is
expected to not trip in response to a stable power swing during a non-Fault condition for a BES Element
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to bulk electric system instability, separation, or a cascading sequence of failures, or
could place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures,
or could hinder restoration to a normal condition.
A Protection System that does not meet the PRC-026-1 – Attachment B criteria is less secure during stable
power swings, it increases the risk of tripping should the Protection System be challenged by a power
swing.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
10
VRF and VSL Justifications – PRC-026-1, R2
Proposed VSL
Lower
Moderate
High
The Generator Owner or
Transmission Owner evaluated
its load-responsive protective
relay(s) in accordance with
Requirement R2, but was less
than or equal to 30 calendar
days late.
The Generator Owner or
Transmission Owner evaluated
its load-responsive protective
relay(s) in accordance with
Requirement R2, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The Generator Owner or
Transmission Owner evaluated its
load-responsive protective relay(s)
in accordance with Requirement
R2, but was more than 60 calendar
days and less than or equal to 90
calendar days late.
Severe
The Generator Owner or
Transmission Owner evaluated its
load-responsive protective relay(s)
in accordance with Requirement
R2, but was more than 90 calendar
days late.
OR
The Generator Owner or
Transmission Owner failed to
evaluate its load-responsive
protective relay(s) in accordance
with Requirement R2.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is driven by exception. For example, each
identified Element must be evaluated.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
11
VRF and VSL Justifications – PRC-026-1, R2
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
12
VRF and VSL Justifications – PRC-004-3, R3
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
Failure to develop a Corrective Action Plan (CAP) such that the Protection System of a BES Element will
meet the PRC-026-1 – Attachment B criteria or to exclude the Protection System under the PRC-026-1 –
Attachment A criteria (e.g., modifying the Protection System so that relay functions are supervised by
power swing blocking or using relay systems that are immune to power swings) could in the planning time
frame, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Developing a CAP such
that the Protection System will meet the Attachment B criteria or to exclude the Protection System under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) applied at
the terminals of BES Elements will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
13
VRF and VSL Justifications – PRC-004-3, R3
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
This Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which require corrective actions
(e.g., Corrective Action Plans); PRC-016-0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC-003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all three of which have a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to develop the Corrective Action Plan (CAP) such that the Protection System of a BES Element will
meet the Attachment B criteria or to exclude the Protection System under the PRC-026-1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings) could, in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
14
VRF and VSL Justifications – PRC-004-3, R3
Proposed VSL
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R3, but in more
than six calendar months and
less than or equal to seven
calendar months.
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R3, but in more
than seven calendar months
and less than or equal to eight
calendar months.
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement R3,
but in more than eight calendar
months and less than or equal to
nine calendar months.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to develop the
Corrective Action Plan in a timely fashion and a binary aspect for a complete failure. The VSL is entity sizeneutral because performance is driven by the need to mitigate the Protection System so that it is expected
to not trip on a stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement R3,
but in more than nine calendar
months.
OR
The Generator Owner or
Transmission Owner failed to
develop a CAP in accordance with
Requirement R3.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
15
VRF and VSL Justifications – PRC-004-3, R3
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is binary and utilizes a VSL of Severe for failure in addition to incremental VSLs for
tardiness.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
This proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
This proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with this Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
16
VRF and VSL Justifications – PRC-026-1, R4
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan (CAP) to meet the PRC-026-1 – Attachment B criteria or
to exclude the Protection System under the PRC-026-1 – Attachment A criteria (e.g., modifying the
Protection System so that relay functions are supervised by power swing blocking or using relay systems
that are immune to power swings) could, in the planning time frame, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk
electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Implementing a CAP such
that the Protection System will meet the Attachment B criteria or to exclude the Protection System under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) applied at
the terminals of these Elements will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
17
VRF and VSL Justifications – PRC-026-1, R4
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which require corrective actions
(e.g., Corrective Action Plans): PRC-016-0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC-003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all of which have a VRF of Medium.
FERC VRF G4 Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan such that the Protection System of a BES Element will
meet the Attachment B criteria or to exclude the Protection System under the PRC-026-1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings) could, in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
18
VRF and VSL Justifications – PRC-026-1, R4
Proposed VSL
Lower
Moderate
The responsible entity
implemented, but failed to
update a CAP, when actions or
timetables changed, in
accordance with Requirement
R4.
N/A
High
N/A
Severe
The responsible entity failed to
implement a CAP in accordance
with Requirement R4.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to update the
Corrective Action Plan and a binary aspect for failure to implement. The VSL is entity size-neutral because
performance is driven by the need to mitigate the Protection System so that it is expected to not trip on a
stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
19
VRF and VSL Justifications – PRC-026-1, R4
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
20
Exhibit G
Summary of Development History and Complete Record of Development
Exhibit G: Summary of Development History
The development record for proposed Reliability Standard PRC-026-1 is
summarized below. The proposed Reliability Standard was developed in an open and fair
manner and in accordance with the Commission-approved Reliability Standard
development process.1 NERC develops Reliability Standards in accordance with Section
300 (Reliability Standards Development) of its Rules of Procedure and the NERC
Standard Processes Manual.2 In its order certifying NERC as the Commission’s Electric
Reliability Organization, 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 Standards3 and thus satisfies certain of the
criteria for approving Reliability Standards.4 The development process is open to any
person or entity with a legitimate interest in the reliability of the Bulk-Power System.
NERC considers the comments of all stakeholders, and stakeholders must approve, and
the NERC Board of Trustees must adopt a Reliability Standard before the Reliability
Standard is submitted to the Commission for approval.
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672 at P 334, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006) (“Further, in considering
whether a proposed Reliability Standard meets the legal standard of review, we will entertain comments about
whether the ERO implemented its Commission-approved 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 FERC.”).
2
The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
3
116 FERC ¶ 61,062 at P 250.
4
Order No. 672 at PP 268, 270.
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 ERO5. The technical expertise of the
ERO is derived from the standard drafting team. For this project, the standard drafting
team consisted of industry experts, all with a diverse set of experiences. A roster of the
standard drafting team members is included in Exhibit H.
II.
Standard Development History
A. Standard Authorization Request
The Standard Authorization Request (“SAR”) was posted for a formal comment
period from August 19, 2010 through September 19, 2010. The Standards Committee
approved the SAR on August 12, 2010.
B. First Posting- Comment Period, Ballot and Non-Binding Poll
Proposed Reliability Standard PRC-026-1 was posted for a 45-day public comment
period April 25, 2014 through June 9, 2014, with an initial ballot held from May 30, 2014
through June 9, 2014. The initial ballot received a 79.06% quorum, and an approval of
17.02%. The Non-Binding Poll achieved a 77.71% quorum and 17.88% of supportive
opinions. There were 70 sets of responses, including comments from approximately 181
individuals from approximately 117 companies, representing all 10 industry segments.
The standard drafting team considered stakeholder comments regarding proposed
Reliability Standard PRC-026-1 and made the following observations and modifications
based on those comments:
•
5
The standard’s purpose was revised from ensuring “relays do not trip” to “relays
are expected to not trip” … in response to stable power swings during non-Fault
conditions.
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d) (2) (2012).
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
The Reliability Coordinator and Transmission Planner were removed from the
standard to address concerns about overlap and potential gaps when identifying
Elements.
Applicability for the Generator Owner and Transmission Owner was augmented
to refer to an appended “Attachment A” which describes load-responsive
protective relays that are included in the standard and associated exclusions.
Requirement R1 was revised substantively to remove the Reliability Coordinator
and Transmission Planner functions.
Added “angular” to clarify that this is not referring to other constraints such as
voltage. Also replaced “Special Protection System (SPS)” with “Remedial Action
Scheme (RAS)” to comport with expected changes to these NERC defined terms.
Clarified that criterion 2 applies only to “monitored” Elements of a System
Operating Limit (SOL). Also, added “angular” to clarify that this is not referring
to other constraints such as voltage.
Revised the “islanding” criterion to remove ambiguity about islands that formed
during planning assessments. Also, added “angular” to clarify that this is not
referring to other constraints such as voltage.
Replaced the term “Disturbance” with the phrase “simulated disturbance,”
because it generally refers to an actual and not simulated event. The lowercase
term “disturbance” was considered to be consistent with the NERC TPL-001-4
Reliability Standard, but it was determined that its usage would continue to create
questions so “simulated” was added. The phrase “stable or unstable” was inserted
to clarify that both are applicable to power swings because the goal of the
standard is to identify Elements susceptible to either.
This criterion was added as a mechanism to require the Planning Coordinator to
continue identifying any Element that has been reported by a Generator Owner
due to a stable or unstable power swing during an actual system Disturbance or by
the Transmission Owner due to a stable or unstable power swing during an actual
system Disturbance or islanding event.
Requirement R2 was revised to remove the Generator Owner performance
because the Generator Owner does not “island.”
Requirement R3 is a new requirement created from the previous Requirement R2
specifically for the Generator Owner.
Requirement R4 (previously R3) has been substantially rewritten to eliminate
multiple and varying activities such as, demonstrate, develop, and obtain
agreement.
Requirement R5 was added to address the requirement for developing a
Corrective Action Plan (CAP) that was contained in the previous Draft 1,
Requirement R3.
Requirement R6 was previously R4 and only received comporting updates due to
numbering changes.
The PRC-026-1 – Attachment A was added to the standard due to reduce
stakeholder confusion about what load-responsive protective relays are in scope
and to provide specific exclusions.
The PRC-026-1 – Attachment B was added to the standard to remove the
“Criteria” for evaluating load-responsive protective relays from within the
•
Requirement itself and provide it in an attachment for referencing by Requirement
R4.
The PRC-026-1 – Attachment B now includes an additional Criteria B which
provides criteria for overcurrent-based protective relays.
C. Second Posting
Proposed Reliability Standard PRC-026-1 was posted for a 45-day comment
period from August 22, 2014 through October 6, 2014, with an additional ballot from
September 26, 2014 through October 6, 2014. The additional ballot achieved a 79.01%
quorum, and an approval of 53.02%. The Non-Binding Poll achieved a 77.71% quorum
and 51.71% of supportive opinions. There were 53 sets of responses, including comments
from approximately 147 individuals from approximately 102 companies, representing all
10 industry segments.
The standard drafting team considered stakeholder comments regarding proposed
Reliability Standard PRC-026-1 and made the following observations and modifications
based on those comments:
•
•
•
•
•
•
•
Section 4.2, Facilities was revised from “The following Bulk Electric System
Elements” to “The following Elements that are part of the Bulk Electric System
(BES)” to clarify that the listed items are the items being addressed in the
Requirements as the “Elements.”
The Elements from the Applicability 4.2 (i.e., generator, transformer, and
transmission line BES Elements) was added for clarity.
Requirement R1 was modified to specifically require “notification” rather than
“identify and provide notification.”
The term “operating limit” was clarified to be “System Operating Limit (SOL)” to
remove ambiguity between the operating and planning time frame.
“Transmission switching station” was revised to be “Transmission station.”
In Requirement R1, Criterion 2, the phrase “constraints identified in system
planning or operating studies” was modified to be “…a SOL identified by the
Planning Coordinator’s methodology.”
Requirement R1, Criterion 3 was rewritten to reflect it is the Element which
tripped on angular stability thus forming the island.
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Requirement R1, Criterion 3 was updated to reflect the most recent “design
assessment” by the Planning Coordinator (i.e., PRC‐006) and when the Planning
Coordinator uses angular stability as a design criteria for identifying islands.
In Requirement R1, Criterion 4, the term “annual” was added to provide clarity.
In Requirement R1, Criterion 5 was removed from Requirement R1 because
Requirements R2 and R3 in Draft 2 were eliminated.
Measure M1 was updated to reflect changes to Requirement R1 and to clarify that
the focus is on notification and not identification of Elements.
Requirements R2 and R3 were removed due to structural changes in Requirement
R4 (now Requirement R2).
The evaluation Requirement (now R2) was restructured to have two conditions
for performance; 1) upon notification of an Element pursuant to Requirement R1,
and 2) an actual event due to a stable or unstable power swing.
Requirements R4 became Requirement R2 due to the removal of Requirements
R2 and R3. Most significantly, the Requirement was restructured to incorporate
the removal of Requirements R2 and R3.
Requirements R5 and R6 became Requirements R3 and R4 due to the removal of
Requirements R2 and R3.
The development period of the CAP was extended from 90 calendar days to six
calendar months due to the complexities that might be involved with determining
appropriate remediation of a Protection System that did not meet PRC‐026‐1 –
Attachment B criteria.
Section C1.1.2 was modified to conform evidence retention to the Reliability
Assurance Initiative (RAI).
Retention periods were set to 12 calendar months.
The Violation Severity Levels (VSLs) were modified to align them with the
revisions made to the Requirements.
Attachment A received editorial changes and Attachment B, Criteria A was
rewritten to clarify that a relay characteristic that is completely contained within
the unstable power swing region meets the criteria.
The Guidelines and Technical Basis section was revised substantively in response
to comments and due to the removal of Requirements R2 and R3.
D. Third Posting
Proposed Reliability Standard PRC-026-1 was posted for a 21-day comment
period from November 4, 2014 through November 24, 2014, with an additional ballot
from November 14, 2014 through November 24, 2014. The additional ballot achieved a
79.83% quorum, and an approval of 67.39%. The Non-Binding Poll achieved a 78.61%
quorum and 66.13% of supportive opinions. There were 42 sets of responses, including
comments from approximately 142 individuals from approximately 88 companies,
representing all 10 industry segments. On December 9, 2014, the Standards Committee
approved a waiver request to shorten the next additional formal comment period (and any
subsequent additional formal comment periods) for proposed PRC-026-1 from forty-five
days to twenty-one days.6
The standard drafting team considered stakeholder comments regarding proposed
Reliability Standard PRC-026-1 and made the following observations and modifications
based on those comments:
•
•
•
•
•
•
•
•
•
•
6
The Background section was updated for clarity.
In Requirement R1 a footnote was added to draw attention to new detail provided
in the Guidelines and Technical Basis concerning the inclusion of “unstable” in
Criterion 4.
Requirement R2, the word “determine” was removed from the main requirement
body based on comments as it is duplicative of Parts 2.1 and 2.2.
In Requirement R2 a footnote was added to draw attention to examples provided
in the Guidelines and Technical Basis of how an entity would “become aware” of
a stable or unstable power swing.
In Requirement R2 a footnote was added to draw attention to new detail provided
in the Guidelines and Technical Basis concerning the inclusion of “unstable” in
Part 2.2.
In Requirement R2, the rationale box text was updated for clarity.
In Requirement R3, the phrase “pursuant to Requirement R2” was inserted based
on comments to provide a referential link to the previous requirement which
triggers performance under Requirement R3.
In Requirement R3, the clause “or more” was deleted based on comments to
remove confusion about whether either or both of the Corrective Action Plan
options were required. Although an entity may perform both under certain
circumstances, the standard drafting team concluded that performing one of the
two bulleted items would achieve the reliability goal of the standard.
In Requirement R3 the rationale box text was updated for clarity.
In PRC-026-1 – Attachment A the phrase “provided the distance element is set in
accordance with the criteria outlined in the standard” has been removed from a
bullet in the PRC-026-1 – Attachment A (protection system functions that are
excluded from the standard) pertaining to phase fault detector relay elements that
supervise other load-responsive phase distance elements.
See Standards Committee Dec. 9, 2014 Meeting Agenda at 2, available at
http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/sc_agenda_package_120914_final2_12
0314.pdf.
•
•
•
•
•
•
•
•
•
In PRC-026-1 – Attachment B the uses of “Criteria” were replaced by “Criterion”
for correctness.
In PRC-026-1 – Attachment B the order of “sending-end” to “receiving-end”
voltages were reversed and swapped for correctness.
In the Guidelines and Technical Basis several Figures were corrected due to errors
reported through the comments.
Several calculations in the Tables were corrected, Table 13 in particular.
Several revisions were due to inconsistencies within the document on how
information is presented.
The format of the Guidelines and Technical Basis was updated for consistency
with the NERC style guide.
The section, “Justification for Including Unstable Power Swings in the
Requirements” was appended to provide an understanding of why “unstable”
power swings are relevant to the performance of the Standard.
In the Implementation Plan, “Notifications Prior to the Effective Date of
Requirement R2” was made to clarify an entity’s obligations during the
implementation plan period.
In the VRF and VSL Justifications section several paragraphs that were redundant
with other information were removed.
E. Final Ballot
Proposed Reliability Standard PRC-026-1 was posted for a 10-day public
comment period from December 5, 2014 through December 16, 2014.7 The proposed
Reliability Standard received a quorum of 84.81% and an approval of 68.08%.
F. Board of Trustees Adoption
Proposed Reliability Standard PRC-026-1 was adopted by the NERC Board of
Trustees on December 17, 2014.
7
The final ballot close date was extended one day to December 16, 2014 due to a NERC.com maintenance
outage that occurred Saturday, December 13, 2014.
Program Areas & Departments > Standards > Project 2010-13.3 Phase 3
of Relay Loadability: Stable Power Swings
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Rich HTML Content 1
Related Files
Status:
A final ballot for PRC-026-1 – Relay Performance During Stable Power
Swings concluded at 8 p.m. Eastern on Tuesday, December 16, 2014.
Voting results can be accessed via the link below. The standard will be
submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Background:
The March 18, 2010, FERC Order No. 733, approved Reliability Standard
PRC-023-1 – Transmission Relay Loadability. In this Order, FERC directed
NERC to address three areas of relay loadability that include modifications to
the approved PRC-023-1, developing a new Reliability Standard to address
generator protective relay loadability, and another Reliability Standard to
address the operation of protective relays due to stable power swings. This
project’s SAR addresses these directives and establishes a three-phased
approach to standard development.
This Phase 3 of the project is focused on developing a new Reliability
Standard, PRC-026-1 – Stable Power Swing Relay Loadability, to address
protective relay operations due to stable power swings. This Reliability
Standard will establish requirements aimed at preventing protective relays
from operating unnecessarily due to stable power swings by requiring the use
of protective relay systems that can differentiate between faults and stable
power swings and, when necessary, phases-out relays that cannot meet this
requirement.
Phase 2 was focused on developing a new Reliability Standard, PRC-025-1 –
Generator Relay Loadability, to address generator protective relay loadability
which is currently awaiting regulatory approval.
Phase 1 was focused on making the specific modifications to PRC-023-1 and
was completed in the approved Reliability Standard PRC-023-2, which
became mandatory on July 1, 2012.
Purpose/Industry Need:
The Commission observed that PRC-023-1 does not address stable power
swings, and pointed out that currently available protection applications and
relays, such as pilot wire differential, phase comparison and blinder-blocking
applications and relays, and impedance relays with non-circular operating
characteristics, are demonstrably less susceptible to operating unnecessarily
because of stable power swings. Given the availability of alternatives, the
Commission stated that the use of protective relay systems that cannot
differentiate between faults and stable power swings constitutes
miscoordination of the protection system and is inconsistent with entities’
obligations under existing Reliability Standards.
In this Final Rule the Commission decided not to direct the ERO to modify
PRC-023-1 to address stable power swings. However, because both NERC
and the U.S.-Canada Power System Outage Task Force have identified
undesirable relay operation due to stable power swings as a reliability issue,
the Commission directed the ERO to develop a Reliability Standard that
requires use of protective relay systems that can differentiate between faults
and stable power swings and, when necessary, phases out protective relays
that cannot meet this requirement.
Draft
Action
Dates
Final Draft
PRC-026-1
Clean (53) |
Redline to Last
Posted (54)
Implementation
Plan
Clean (55) |
Redline to Last
Posted (56)
Supporting
Documents:
VRF and VSL
Justification
Clean (57) |
Redline to Last
Posted (58)
Final Ballot
Info>> (60)
Vote>>
12/05/14
–
12/16/14
(closed)
Results
Consideration
of Comments
Summary>>
(61)
The final ballot close date was
extended one day to December 16,
2014 due to a NERC.com
maintenance outage that occurred
Saturday, December 13, 2014.
Ballot
Results>>
(62)
Responses to
Directives and
Issues (59)
Draft 3
PRC-026-1
Clean (37) |
Redline (38)
Additional Ballot and
Non-binding Poll
Updated Info>> (45)
11/14/14
11/24/14
(closed)
Summary>>
(48)
Ballot
Results>>
(49)
Consideration
of
Comments>>
(52)
Implementation
Plan
Clean (39) |
Redline (40)
Info>> (46)
Supporting
Documents:
Comment Period
Unofficial
Comment Form
(Word) (41)
Non-Binding
Poll
Results>>
(50)
Vote>>
Info>> (47)
Submit Comments>>
11/04/14
11/24/14
(closed)
VRF and VSL
Justification
Clean (42) |
Redline (43)
Response to
Directives and
Issues (44)
Lens
Characteristic
Tool
(Link to
projects page)
Lens
Characteristic
Tool
(Generator)
(Link to
projects page)
Draft RSAW
Notice of
Request to
Waive the
Standard
Process (36)
Please send RSAW
11/12/14
Feedback to:
[email protected]
12/02/14
Comments
Received>>
(51)
Summary>>
(31)
Draft 2
PRC-026-1
Clean (20) |
Redline (21)
Implementation
Plan
Clean (22) |
Redline (23)
Supporting
Documents:
Unofficial
Comment Form
(Word) (24)
Additional Ballot and
Non-binding Poll
Updated Info>> (28)
Info>> (29)
09/26/14
10/06/14
(closed)
Vote>>
Comment Period
Info>> (30)
Submit Comments>>
Ballot
Results>>
(32)
Non-Binding
Poll
Results>>
(33)
08/22/14
10/06/14
(closed)
VRF and VSL
Justification
Clean (25) |
Redline (26)
Consideration
of
Comments>>
(35)
Response to
Directives and
Issues (27)
Lens
Characteristic
Tool
(Link to
projects page)
Lens
Characteristic
Tool
(Generator)
(Link to
projects page)
Comments
Received>>
(34)
09/11/14
Please send RSAW
–
Feedback to:
10/06/14
[email protected]
(The above are
MS Excel
macro-enabled
spreadsheets)
Draft RSAW
Summary>>
(15)
Draft 1
PRC-026-1 (6)
Implementation
Plan (7)
Supporting
Documents:
Unofficial
Comment Form
(Word) (8)
VRF and VSL
Justifications
(9)
Response to
Issues and
Directives (10)
SPCS
Protection
System (11)
Response to
Power Swings
Ballot and Non-binding
Poll
Updated Info>> (12)
Info>> (13)
Vote>>
Comment Period
Info>> (14)
Submit Comments>>
05/30/14
06/09/14
(closed)
Ballot
Results>>
(16)
Non-Binding
Poll
Results>>
(17)
04/25/14
–
06/09/14
(closed)
Consideration
of
Comments>>
(19)
Comments
Received>>
(18)
Join Ballot Pool>>
04/25/14
– 5/27/14
(closed)
Comment Period
Info>> (3)
Submit Comments>>
08/19/10
09/19/10
(closed)
Draft RSAW
SAR for Relay
Loadability
Order 733
Draft SAR
Version 1 (1)
Supporting
Materials:
Comments
Received>>
(4)
Consideration
of Comments
(5)
Comment Form
(Word) (2)
Standard Authorization Request Form
Title of Proposed Standard
Relay Loadability Order 733
Request Date
8/5/2010
SC Approval Date
8/12/2010
SAR Type (Check a box for each one
that applies.)
SAR Requester Information
Name
Stephanie Monzon
New Standard
Primary Contact
[email protected]
Revision to existing Standard
Telephone
610-608-8084
Withdrawal of existing Standard
[email protected]
Urgent Action
Fax
E-mail
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Standards Authorization Request Form
Purpose As the ERO, NERC must address all directives in Orders issued by FERC. On March
18, 2010 FERC issued Order No. 733 which approved Reliability Standard PRC-023-1 –
Transmission Relay Loadability, and also directed NERC, as the Electric Reliability
Organization (“ERO”), to develop certain modifications to the PRC-023-1 standard through
its Reliability Standards development process, to be completed by specific deadlines.
Attachment 1 to the SAR contains the directives and associated deadlines. The Order also
directed development of two new Reliability Standards to address issues related to
generator relay loadability and the operation of protective relays due to power swings. The
standards-related directives in Order 733 are aimed at closing some reliability-related gaps
in the scope of PRC-023-1.
Industry Need
FERC directed NERC to develop modifications related to Relay Loadability by specific
deadlines in Order No. 733. Attachment 1 to the SAR contains the directives and associated
deadlines.
PRC-023-1 Directed Modifications
The Commission directed a number of changes to the approved standard including a test to
be applied by Planning Coordinators to determine applicability to elements operated at less
than 200 kV. This test will be included in PRC-023-1 either in the form of a Requirement or
as an attachment to the standard.
Generator Step-up and Auxiliary Transformers
The Commission directed the ERO to develop a new Reliability Standard addressing
generator relay loadability, with its own individual timeline, and not a revision to an existing
Standard.
Protective Relays Operating Unnecessarily Due to Stable Power Swings
The Commission observed that PRC-023-1 does not address stable power swings, and
pointed out that currently available protection applications and relays, such as pilot wire
differential, phase comparison and blinder-blocking applications and relays, and impedance
relays with non-circular operating characteristics, are demonstrably less susceptible to
operating unnecessarily because of stable power swings. Given the availability of
alternatives, the Commission stated that the use of protective relay systems that cannot
differentiate between faults and stable power swings constitutes miscoordination of the
protection system and is inconsistent with entities’ obligations under existing Reliability
Standards.
In this Final Rule the Commission decided not to direct the ERO to modify PRC-023-1 to
address stable power swings. However, because both NERC and the U.S.-Canada Power
System Outage Task Force have identified undesirable relay operation due to stable power
swings as a reliability issue, the Commission directed the ERO to develop a Reliability
Standard that requires use of protective relay systems that can differentiate between faults
and stable power swings and, when necessary, phases out protective relays that cannot
meet this requirement.
Brief Description
This SAR’s scope includes three standard development phases to address the standardsrelated directives in Order No. 733 directives. Phase I is focused on making the specific
modifications to PRC-023-1 that were identified in the order; Phase II is focused on
SAR–2
Standards Authorization Request Form
developing a new standard to address generator relay loadability; and Phase III is focused
on developing requirements that address protective relay operations due to power swings.
Detailed Description
Phase I: Develop modifications to PRC-023-1- Transmission Relay Loadability by March 18,
2011 to address the following directives from Order 733:
•
p. 60 . . . modify PRC-023-1 to apply an “add in” approach to sub-100 kV facilities that
are owned or operated by currently-Registered Entities or entities that become
Registered Entities in the future, and are associated with a facility that is included on a
critical facilities list defined by the Regional Entity.
•
p. 69 . . . modify Requirement R3 of the Reliability Standard to specify the test that
planning coordinators must use to determine whether a sub-200 kV facility is critical to
the reliability of the Bulk-Power System.
•
p 162 . . . consider “islanding” strategies that achieve the fundamental performance for
all islands in developing the new Reliability Standard addressing stable power swings.
•
p. 186 . . . require that transmission owners, generator owners, and distribution
providers give their transmission operators a list of transmission facilities that implement
sub-requirement R1.2.
•
p. 203 . . . modify sub-requirement R1.10 so that it requires entities to verify that the
limiting piece of equipment is capable of sustaining the anticipated overload for the
longest clearing time associated with the fault.
•
p. 237 . . . modify the Reliability Standard to add the Regional Entity to the list of
entities that receive the critical facilities list. [sub-requirement R3.3]
•
p. 244 . . . include section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and violation severity
level.
•
p. 264 . . . revise section 1 of Attachment A to include supervising relay elements on the
list of relays and protection systems that are specifically subject to the Reliability
Standard.
•
p. 283 . . . modify the Reliability Standard to include an implementation plan for sub100 kV facilities.
•
p. 284 . . . remove the exceptions footnote from the “Effective Dates” section.
In Phase I of the project, the NERC Relay Loadability standard drafting team will either
modify the PRC-023-1 Reliability Standard to incorporate the directed modifications or will
propose equally efficient and effective alternative approaches that address the Commission’s
reliability-related concerns. (In parallel with this effort, NERC plans to convene a panel of
industry subject matter experts to develop a straw man proposal for the test Planning
Coordinators must use to identify sub-200 kV facilities that are critical to the reliability of
the Bulk Power System. The panel will collect industry feedback on the straw man test
using the current standards development process that will be incorporated into Requirement
R3 of PRC-023-1 by the Standard Drafting Team.)
Phase II: Develop a new Standard Addressing Generator Relay Loadability
In Phase II of the project, a new Reliability Standard will be developed by the end of 2012
to address the subject of generator relay loadability in support of NERC’s filing indicating it
would develop such a standard and to address the following directive from Order No. 733:
•
p. 108 . . . consider the PSEG Companies’ suggestion in developing a Reliability
SAR–3
Standards Authorization Request Form
Standard that addresses generator relay loadability.
As indicated in NERC’s Order No. 733 clarification and rehearing request, NERC believes
adding additional requirements to the PRC-023 standard in addition to developing a new
Reliability Standard to address generator relay loadability could lead to confusion over
applicability and the possibility of conflicting requirements. Therefore, NERC proposed in its
clarification and rehearing request to address the issue of generator relay loadability in a
new Reliability Standard, separate and distinct from the PRC-023 Reliability Standard, which
is intended to address relays that protect transmission elements. Subject to the
Commission’s response to NERC’s pending clarification and rehearing request, NERC plans
to address generator relay loadability in a new Reliability Standard for applications where
the relays are set with a shorter reach to protect the generator and the generator step-up
transformer, and for applications where the relays are set with a longer reach to provide
backup protection for transmission system faults. The standard drafting team will use
relevant sections of the NERC technical reference document, Power Plant and Transmission
System Protection Coordination Section 3.1 and Appendix E to develop the requirements by
which generator relay loadability will be assessed.
Phase III: Development of a New Standard Addressing the Issue of Protective Relay
Operations Due To Power Swings
In Phase III of the project, a new Reliability Standard will be developed to address the
subject of protective relay operations due to power swings to address the following directive
from Order No. 733 by the end of 2014:
•
p. 150 - develop a Reliability Standard that requires the use of protective relay systems
that can differentiate between faults and stable power swings and, when necessary,
phases out protective relay systems that cannot meet this requirement.
SAR–4
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer
Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.
LoadServing
Entity
Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.
SAR–5
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all 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.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
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
SAR–6
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
PRC-023-1
Order No. 733 approved Reliability Standard PRC-023-1 – Transmission
Relay Loadability, and directed NERC, as the Electric Reliability
Organization (“ERO”), to develop certain modifications to the PRC-023-1
standard through its Reliability Standards development process, to be
completed by specific deadlines.
New Reliability
Standard
Development of a New Standard Addressing Generator Relay Loadability
New Reliability
Standard
Development of a New Standard Addressing the Issue of Protective Relay
Operations Due To Power Swings
Related SARs
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR–7
Attachment 1 - Order No. 733 – Action Plan and Timetable
Note that the scope of the SAR is
Order No. 733 approved Reliability Standard PRC-023-1 – Transmission
limited to addressing the directives
Relay Loadability, and directed NERC, as the Electric Reliability
highlighted in the table below.
Organization (“ERO”), to develop certain modifications to the PRC-023-1
standard through its Reliability Standards development process, to be
completed by specific deadlines and directed NERC to develop requirements to address issues related to Relay
Loadability. The Order also directed development of two new Reliability Standards to address issues related to
generator relay loadability and the operation of protective relays due to power swings. The following table lists the
FERC directives in Order No. 733 and for each directive associates it with a project phase. Note that some of the
tasks within each phase will be managed by NERC staff, not the standard drafting team.
Paragraph
Text
Project Phase/
Timeline
60
With respect to sub-100 kV facilities, we adopt the NOPR proposal and direct
the ERO to modify PRC-023-1 to apply an “add in” approach to sub-100 kV
facilities that are owned or operated by currently-Registered Entities or entities
that become Registered Entities in the future, and are associated with a facility
that is included on a critical facilities list defined by the Regional Entity. We
also direct that additions to the Regional Entities’ critical facility list be tested
for their applicability to PRC-023-1 and made subject to the Reliability
Standard as appropriate.
Phase I -- by
March 18, 2011
69
Finally, pursuant to section 215(d)(5) of the FPA, we direct the ERO to modify
Requirement R3 of the Reliability Standard to specify the test that planning
coordinators must use to determine whether a sub-200 kV facility is critical to
the reliability of the Bulk-Power System. We direct the ERO to file its test, and
the results of applying the test to a representative sample of utilities from each
of the three Interconnections, for Commission approval no later than one year
from the date of this Final Rule.
Phase I -- Note
NERC’s pending
request for
rehearing filed on
April 19, 2010
regarding this
directive.
97
Finally, commenters argue that there should be some mechanism for entities to
challenge criticality determinations. We agree that such a mechanism is
appropriate and direct the ERO to develop an appeals process (or point to a
process in its existing procedures) and submit it to the Commission no later
than one year after the date of this Final Rule.
Phase I – by
March 18, 2011
105
In light of the ERO’s statement that within two years it expects to submit to the
Commission a proposed Reliability Standard addressing generator relay
loadability, we direct the ERO to submit to the Commission an updated and
specific timeline explaining when it expects to develop and submit this
proposed Standard.
Phase II – by the
end of 2012
108
Finally, the PSEG Companies suggest that the ERO consider whether a generic
rating percentage can be established for generator step-up transformers and, if
so, determine that percentage. Although we do not adopt the NOPR proposal,
we encourage the ERO to consider the PSEG Companies’ suggestion in
developing a Reliability Standard that addresses generator relay loadability.
Phase II – by the
end of 2012
150
However, because both NERC and the Task Force have identified undesirable
relay operation due to stable power swings as a reliability issue, we direct the
ERO to develop a Reliability Standard that requires the use of protective relay
systems that can differentiate between faults and stable power swings and,
Phase III – by the
end of 2014
8
Attachment 1 - Order No. 733 – Action Plan and Timetable
Paragraph
Text
Project Phase/
Timeline
when necessary, phases out protective relay systems that cannot meet this
requirement. We also direct the ERO to file a report no later than 120 days of
this Final Rule addressing the issue of protective relay operation due to power
swings. The report should include an action plan and timeline that explains
how and when the ERO intends to address this issue through its Reliability
Standards development process.
162
We agree with the PSEG Companies and direct the ERO to consider
“islanding” strategies that achieve the fundamental performance for all islands
in developing the new Reliability Standard addressing stable power swings.
Phase I – by
March 18, 2011
186
However, we will adopt the NOPR proposal to direct the ERO to modify PRC023-1 to require that transmission owners, generator owners, and distribution
providers give their transmission operators a list of transmission facilities that
implement sub-requirement R1.2.
Phase I – by
March 18, 2011
203
We adopt the NOPR proposal and direct the ERO to modify sub-requirement
R1.10 so that it requires entities to verify that the limiting piece of equipment
is capable of sustaining the anticipated overload for the longest clearing time
associated with the fault.
Phase I – by
March 18, 2011
224
While we are not adopting the NOPR proposal, we direct the ERO to
document, subject to audit by the Commission, and to make available for
review to users, owners and operators of the Bulk-Power System, by request, a
list of those facilities that have protective relays set pursuant sub-requirement
R1.12.
Phase I – by
March 18, 2011
237
We adopt the NOPR proposal and direct the ERO to modify the Reliability
Standard to add the Regional Entity to the list of entities that receive the
critical facilities list. [sub-requirement R3.3]
Phase I – by
March 18, 2011
244
We adopt the NOPR proposal and direct the ERO to include section 2 of
Attachment A in the modified Reliability Standard as an additional
Requirement with the appropriate violation risk factor and violation severity
level.
Phase I – by
March 18, 2011
264
After further consideration, and in light of the comments, we will not direct the
ERO to remove any exclusion from section 3, except for the exclusion of
supervising relay elements in section 3.1. Consequently, we direct the ERO to
revise section 1 of Attachment A to include supervising relay elements on the
list of relays and protection systems that are specifically subject to the
Reliability Standard.
Phase I – by
March 18, 2011
283
Additionally, in light of our directive to the ERO to expand the Reliability
Standard’s scope to include sub-100 kV facilities that Regional Entities have
already identified as necessary to the reliability of the Bulk-Power System
through inclusion in the Compliance Registry, we direct the ERO to modify the
Reliability Standard to include an implementation plan for sub-100 kV
facilities.
Phase I – by
March 18, 2011
9
Attachment 1 - Order No. 733 – Action Plan and Timetable
Paragraph
Text
Project Phase/
Timeline
284
We also direct the ERO to remove the exceptions footnote from the “Effective
Dates” section.
Phase I – by
March 18, 2011
297
Finally, we direct the ERO to assign a “high” violation risk factor to
Requirement R3.
Filed with the
Commission on
April 19, 2010
308
Consequently, we direct the ERO to assign a single violation severity level of
“severe” for violations of Requirement R1.
Filed with the
Commission on
April 19, 2010
310
Accordingly, we direct the ERO to change the violation severity level assigned
to Requirement R2 from “lower” to “severe” to be consistent with Guideline
2a.
Filed with the
Commission on
April 19, 2010
311
Finally, we direct the ERO to assign a “severe” violation severity level to
Requirement R3.
Filed with the
Commission on
April 19, 2010
10
Unofficial Comment Form for Relay Loadability Order (No. 733) (Project
2010-13)
Please DO NOT use this form. Please use the electronic form located at the link below to
submit comments on the proposed standard, PRC-023-2 and on the associated SAR. The
electronic comment form must be completed by September 19, 2010.
https://www.nerc.net/nercsurvey/Survey.aspx?s=c64a2b0a1f9d4e98aef8640932516830
If you have questions please contact Stephanie Monzon at [email protected] or
by telephone at [610-608-8084
Project 2010-13: Relay Loadability Order (RLO SDT) – PRC-023-2
Background Information
NERC Standard PRC-023-1 – Transmission Relay Loadability was approved by FERC as
mandatory and enforceable in March 2010, with direction that NERC make a number of
changes.
The Standard Drafting Team has made changes to PRC-023 to address the following
directives from Order 733
• p. 60 . . . modify PRC-023-1 to apply an “add in” approach to sub-100 kV facilities that
are owned or operated by currently-Registered Entities or entities that become
Registered Entities in the future, and are associated with a facility that is included on a
critical facilities list defined by the Regional Entity.
• p. 186 . . . require that transmission owners, generator owners, and distribution
providers give their transmission operators a list of transmission facilities that implement
sub-requirement R1.2.
• p. 203 . . . modify sub-requirement R1.10 so that it requires entities to verify that the
limiting piece of equipment is capable of sustaining the anticipated overload for the
longest clearing time associated with the fault.• p. 224 . . . make available for review to
users, owners and operators of the Bulk-Power System, by request, a list of those
facilities that have protective relays
• p. 237 . . . modify the Reliability Standard to add the Regional Entity to the list of
entities that receive the critical facilities list. [sub-requirement R3.3]
• p. 244 . . . include section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and violation severity
level.
• p. 264 . . . revise section 1 of Attachment A to include supervising relay elements on
the list of relays and protection systems that are specifically subject to the Reliability
Standard.
• p. 283 . . . modify the Reliability Standard to include an implementation plan for sub100 kV facilities.
• p. 284 . . . remove the exceptions footnote from the “Effective Dates” section.
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Unofficial Comment Form for Relay Loadability Order (No. 733) (Project 2010-13)
However, the directive below is not yet addressed, even though it is referenced within the
draft standard text. It will be included in a subsequent posting of this draft standard.
• p. 69 . . . modify Requirement R3 of the Reliability Standard to specify the test that
planning coordinators must use to determine whether a sub-200 kV facility is critical to
the reliability of the Bulk-Power System.
To expedite the project to address the directives from FERC Order No. 733, the Standard
Drafting Team is posting the draft modifications to PRC-023-1 for an informal comment
period.
Please note that the posting of PRC-023-2 is an INFORMAL posting.
2
Unofficial Comment Form for Relay Loadability Order (No. 733) (Project 2010-13)
1. The Applicability Section (4.1.2 and 4.1.4) and Requirement R5 (previously
Requirement R3) have been modified to address the directive in Paragraph 60 of
Order no. 733. Do you agree that this is an acceptable and effective method of
meeting this directive? If not, please explain.
Yes
No
Comments:
2. Requirement R1 has been modified to address the directive in Paragraph 244 of
Order no. 733. Do you agree that this is an acceptable and effective method of
meeting this directive? If not, please explain.
Yes
No
Comments:
3. Requirement R1, section 10 has been modified to address the directive in Paragraph
203 of Order no. 733. Do you agree that this is an acceptable and effective method
of meeting this directive? If not, please explain.
Yes
No
Comments:
4. Requirement R3 has been added to address the directive in Paragraph 186 of Order
no. 733. Do you agree that this is an acceptable and effective method of meeting
this directive? If not, please explain.
Yes
No
Comments:
5. Requirement R4 has been added to address the directive in Paragraph 224 of Order
no. 733. Do you agree that this is an acceptable and effective method of meeting
this directive? If not, please explain.
Yes
No
Comments:
6. Requirement R5 and part 5.1 (previously Requirement R3 and part 3.1) have been
modified to establish the framework to address the directive in Paragraph 69 of
Order no. 733, although the criteria itself (which will be Attachment B) is still being
3
Unofficial Comment Form for Relay Loadability Order (No. 733) (Project 2010-13)
developed. Do you agree that this is an acceptable and effective method of meeting
this directive considering that Requirement R5 is establishing the construct to insert
the criteria at a future time in the form of Attachment B? If not, please explain.
Yes
No
Comments:
7. Attachment A has been modified to address the directive in Paragraph 264 of Order
no. 733. Do you agree that this is an acceptable and effective method of meeting
this directive? If not, please explain.
Yes
No
Comments:
8. Do you agree that the SDT has addressed the remaining directives: Paragraph 284 to
remove the footnote and Paragraph 283 to modify the implementation plan for sub100 kV facilities (by revising the Effective Date section of the standard)?
Yes
No
Comments:
Questions 9-13 relate to the SAR
9. Do you agree that the scope of the proposed standards action addresses the
directive or directives?
Yes
No
Comments:
10. Can you identify an equally efficient and effective method of achieving the reliability
intent of the directive or directives?
Yes
No
Comments:
4
Unofficial Comment Form for Relay Loadability Order (No. 733) (Project 2010-13)
11. Do you agree with the scope of the proposed standards action?
Yes
No
Comments:
12. Are you aware of any regional variances that we should consider with this SAR?
Yes
No
Comments:
13. Are you aware of any associated business practices that we should consider with this
SAR?
Yes
No
Comments:
5
Standards Announcement
Standards Authorization Request (SAR) and Draft Standard
Formal and Informal Comment Periods Open
August 19–September 19, 2010
Now available at:
http://www.nerc.com/filez/standards/Reliability_Standards_Under_Development.html
Project 2010-13: Revisions to Relay Loadability for Order 733
The drafting team associated with this project is seeking comments on a proposed SAR and an
initial set of proposed requirements until 8 p.m. Eastern on September 19, 2010.
The SAR is being posted for a 30-day formal comment period and the standard is being posted
for a 30-day informal comment period; comments on both the SAR and the proposed
requirements will be collected using a single comment form.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using
the electronic form, please contact Monica Benson at [email protected]. An off-line,
unofficial copy of the comment form is posted on the project page:
http://www.nerc.com/filez/standards/SAR_Project%20201013_Order%20733%20Relay%20Modifiations.html
Next Steps
The drafting team will draft and post responses to comments received during this period.
•
The SAR is being posted for a 30-day formal comment period. With a formal comment
period the team is required to provide a response to each comment submitted.
•
The proposed requirements in the standard are being posted for a 30-day informal
comment period. With an informal comment period, for each question asked on the
comment form, the drafting team will provide a summary response to indicate whether
stakeholders support the proposed revision and to identify any additional changes made
based on stakeholder comments. The team will not provide an individual response to
each comment submitted.
Project Background
When FERC issued Order 733, approving PRC-023-1 — Transmission Relay Loadability, it
directed several changes to that standard and also directed development of one or more new
standards within specified time periods. NERC filed for clarification and rehearing asking for
clarity and an extension of time to address the directives, however without a response to the
requests for clarification and rehearing, NERC must progress as though these requests will be
denied.
The SAR for Project 2010-13 subdivides the standard development related directives into three
phases. Phase I addresses the specific directives from Order 733 that identified required
modifications to various elements within PRC-023-1. Phase II addresses directives associated
with development of a new standard to address generator relay loadabilty. Phase III addresses
directives associated with writing requirements to address protective relay operations due to
power swings.
Applicability of Proposed PRC-023-2
Distribution Providers that own specific facilities (see standard for details)
Generator Owners that own specific facilities (see standard for details)
Planning Coordinators
Transmission Owners that own specific facilities (see standard for details)
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
Individual or group. (36 Responses)
Name (20 Responses)
Organization (20 Responses)
Group Name (15 Responses)
Lead Contact (15 Responses)
Question 1 (32 Responses)
Question 1 Comments (36 Responses)
Question 2 (29 Responses)
Question 2 Comments (36 Responses)
Question 3 (29 Responses)
Question 3 Comments (36 Responses)
Question 4 (29 Responses)
Question 4 Comments (36 Responses)
Question 5 (27 Responses)
Question 5 Comments (36 Responses)
Question 6 (32 Responses)
Question 6 Comments (36 Responses)
Question 7 (32 Responses)
Question 7 Comments (36 Responses)
Question 8 (26 Responses)
Question 8 Comments (36 Responses)
Question 9 (27 Responses)
Question 9 Comments (36 Responses)
Question 10 (25 Responses)
Question 10 Comments (36 Responses)
Question 11 (27 Responses)
Question 11 Comments (36 Responses)
Question 12 (29 Responses)
Question 12 Comments (36 Responses)
Question 13 (29 Responses)
Question 13 Comments (36 Responses)
Individual
Gene Henneberg
NV Energy
Yes
No
The proposed phrase added to R1 is only a start: “. . . , and to prevent its out-of-step blocking schemes from blocking
tripping for fault conditions.” The specific wording proposed by the Drafting Team may prevent using the out-of-step-block
functions of many modern and widely used line protection relays (e.g. SEL-321 and later models and GE-UR). These
relay’s OSB function first blocks the protection elements from tripping, then uses a short delay and/or other information to
determine whether the observed and perhaps evolving condition really represents a fault, in which case the blocking is
reset to allow tripping. Such a block/reset operation is the most common technology available and would appear to lie
within the intent of FERC in paragraph 244, but could be excluded by the presently proposed language. If an out-of-step
blocking phrase is inserted in Requirement R1 of the standard, the emphasis should be modified to read something like: “.
. . , and its out-of-step blocking schemes must allow tripping for fault conditions.” This standard should also require that
out-of-step blocking settings coordinate with both the loadability and protection characteristics. The out-of-step blocking
references would seem to fit best within the organization of the standard if included as a new Requirement R2 (FERC’s
paragraph 244 anticipates “. . . an additional Requirement . . .”), with re-numbering of the proposed R2 through R5 as R3
through R6. The essential content of the DT’s proposed phrase in R1 would be included as part of this new R2, which
would read something like: R2. Each Transmission Owner, Generator Owner, and Distribution Provider shall evaluate its
out-of-step blocking schemes to ensure that both: R2.1. Out-of-step blocking schemes allow tripping for fault conditions
during the loading conditions determined from Requirement R1 parts R1.1 through R1.13. R2.2. Relay out-of-step
blocking settings coordinate with both the relay loadability characteristic determined from Requirement R1 parts R1.1
through R1.13 and the facility protection settings. The Measure for this proposed R2 would read something like: M2.The
Transmission Owner, Generator Owner, and Distribution Provider with out-of-step blocking schemes shall have evidence
such as spreadsheets or summaries of calculations to show that each of its out-of-step blocking schemes is set to comply
with the requirements of R2.1 and R2.2. The VSL for R1 would not change; specifically it would not reference out-of-step
blocking schemes. The VSL for this proposed new R2 would be “Severe” and read something like: A Transmission Owner,
Generator Owner, or Distribution Provider did not allow its out-of-step blocking schemes to trip for fault conditions during
the loading conditions determined from Requirement R1 parts R1.1 through R1.13. OR A Transmission Owner, Generator
Owner, or Distribution Provider did not coordinate operation of its out-of-step blocking schemes with both the relay
loadability characteristic determined from Requirement R1 parts R1.1 through R1.13 and the facility protection settings.
Yes
Yes
Yes
No
This approach is not yet an acceptable and effective method of meeting the directive of paragraph 69. Whether it becomes
an acceptable and effective method of meeting the directive will depend on the content of Attachment B. I’ll reserve
specific judgment and concerns until Attachment B is available for comment.
Yes
Yes
Yes
No
NERC's proposed Phase I, II, II process seems reasonable.
Yes
No
Individual
Steve Wadas
NPPD
Yes
As long as you keep BES.
Yes
I'm ok with that. It could have easily been left in Attachment A. You didn't bring the other language from attachment A to
R1. You could of created a separate requirement for OOS, but I'm fine with moving it to R1.
No
Setting the relay to 150% of a 336MVA or 500MVA transformer can force you to cross the transformer damage curve and
now your transformer is at risk to loss of life.
Yes
Yes
No
Attachment B has not even been developed.
No
Please remove Attachment A, R1.6. "Protective functions that supervise operation of other protection functions in 1.1
through 1.5.". If you do not remove R1.6 you must provide a detailed explanation of what supervise operation means and
give examples. Utilities have thousands of relays that have imbedded fault detective supervision overcurrents for phase
distance elements that are set at 0.5 amps or some similar value. This can not be changed. From your requirement these
utilities would have to replace all of these relays or we would have to lower the Facality rating to 0.5 amp
secondary/150%. You are also stating that if we have an external phase overcurrent fault detector that supervises a phase
distance relay that this fault detector must now have to meet Requirement 1. This is an unacceptable requirement if this is
your intent. You are putting the system at risk if this is your intent. We must set our relays to protect the line. We must also
set fault detectors to pickup for all faults considering N-1 conditions at a minimum where the strongest source must be
remove and the relays must still clear the fault. Please do not lose focus of the purpose: "Protective relay settings shall be
set to reliably detect all fault conditions and protect the electrical network from these faults". If you have questions on my
comments feel free to contact me. Steve Wadas, NPPD, 402 563 5917 Wk.
Yes
No
No
No
No
Yes
See Question 7.
Group
E.ON U.S. LLC
Brent Ingebrigtson
No
E.ON U.S. believes that it is confusing the way R5 is currently written due to the last part of the sentence “ … when
protective relay settings limit transmission loadability.” There is a need for clarification on how this is to be applied. As an
alternative: If the directive is to have the Planning Coordinator determine which sub-100kV facilities should be subject to
the Reliability Standard; R5 should be modified to read “Each Planning Coordinator shall apply the criteria in Attachment B
to determine which of the facilities in its Planning Coordinator Area are to be included in 4.1.2 and 4.1.4.”
No
Since correct operation of the out-of-step blocking feature is integral to and only a single component of a successful trip
operation (for fault conditions), this is already included in the requirement to “maintain reliable protection of the BES for all
fault conditions” and does not have to be mentioned separately. Also, R1 (as written) may be interpreted to require one of
the settings (1 through 13) to be used to prevent out-of-step blocking schemes from blocking tripping for fault conditions.
But Settings 1 thru 13 do not address specific setting criteria for out-of-step blocking.
No
E.ON U.S. is concerned that the proposal requires a fault protection scheme separate from the phase overload relays.
With the phase overload relays set at 150% of the maximum transformer nameplate, they (by themselves) will not be able
to coordinate with the transformer damage curve (as defined by IEEE) for low level faults. R1, Section 10 meets the
directive of Paragraph 203; however it is not clear that Section 10 only applies when there is no high side breaker at the
transformer, as discussed in Order No. 733. E.ON U.S. recommends that an exclusion of the transmission line relay
settings should be considered when transformer overload protection is provided by other means (i.e. A low side breaker
trip or a direct transfer trip of the remote breaker initiated by an overload relay installed on the transformer).
Yes
Yes
No
See comments for item #1.
No
E.ON U.S. requests a clarification of “protective functions” such that it applies only to those protective relay elements that
would respond to non-fault or load conditions, and could issue a direct trip, upon operation, during a loss of
communication or loss of potential condition.
No
Cannot assess the impact until Attachment B is developed and commented sections above are clarified.
No
See commented sections above. Also, the directive identified in Paragraph 224 was not included in the detailed
description or highlighted in Attachment 1 of the SAR. However it was included in the proposed modifications as R4.
Yes
No
No
No
Individual
Joylyn Faust
Consumers Energy
Yes
Yes
Yes
Yes
Yes
Yes
We are concerned about the criteria still undergoing development, and will offer any relevant comments on that criteria
when it is published.
No
The supervising elements addressed within this change may fundamentally be unable to be set in accordance with the
requirements of PRC-023, while still permitting the Protection System to function properly for fault conditions. The
supervising element is usually present to assure that a distance element does not operate inadvertently for close-in zerovoltage faults near the relay location in the non-trip direction, but does not, by itself, produce a trip. We appreciate that
NERC must respond to this directive, but believe that the change, as expressed, will be detrimental to reliability.
Yes
Yes
Yes
NERC should, again, oppose the FERC directive in paragraph 264, since, as explained above, this directive is both
unnecessary and detrimental to reliability.
Yes
No
No
Individual
Jonathan Meyer
Idaho Power - System Protection
Yes
Yes
No
The reworded Requirement should to be clarified. The fault level and duration that the limiting element will be exposed can
be a function of fault location and contingencies, such as relay failures, that are not addressed or defined. No measure is
specified in the reliability standard that will demonstrate compliance with the revised requirements in R1.10.
Yes
Yes
No
It is not acceptable or effective until Attachment B is completed and available for review.
Yes
The order has been met, but there is significant concern about the inclusion of supervisory elements in protective systems.
A supervisory element is not performing a tripping function. As stated in Attachment A “This standard includes any
protective functions which could trip with or without time delay, on load current, including but not limited to:…”. Supervisory
elements, used properly, do not trip for load current.
Yes
Yes
No
Yes
No
No
Group
Northeast Power Coordinating Council
Guy Zito
No
The revised Applicability paragraph 4.1.4 reads: 4.1.4 Transformers with low voltage terminals connected below 200 kV as
designated by the Planning Coordinator as critical to the reliability of the Bulk Electric System (BES). The phrase "low
voltage terminals" is open to interpretation because some transformers have low-voltage terminals which are do not
supply a load, or supply only local substation AC service. Sometimes the transformer is a 3-winding bank, with the lowvoltage winding not used, or the low-voltage winding is used solely to provide additional grounding, as in the case of a
delta-connected tertiary, unconnected to any load. Is this what is intended? If yes, then they should remove the ambiguity.
Note the phrase "low-voltage" terminal was part of Revision 1 and is unchanged by Revision 2, however, the new
applicability to below 200 kV raises the new concern. What is meant by “critical to the reliability of the Bulk Electric System
(BES)”? Also, replace “as designated” with “and designated”. Suggest 4.1.4 be revised to read: 4.1.4 Transformers with
low voltage terminals connected below 200 kV and designated by the Planning Coordinator as Critical Assets. Clarification
is needed to explain the disconnect between FERC’s “sub-100kV”, and the proposed “below 200kV”.
No
The last sentence in R1 should be revised to read: Each Transmission Owner, Generator Owner, and Distribution provider
shall evaluate relay loadability at 0.85 per unit voltage, and a power factor angle of 30 degrees. Settings are to be applied
as listed following: “Setting” should be replaced throughout R1 when referring to a part, or sub-requirement of R1. The
terminology should be whatever is preferred by NERC. Requirement R1, Parts 7, 8 and 9: Requirement R1, Parts 7, 8 and
9, replace the phrase “under any system configuration” with "under any system condition:" 7. Set transmission line relays
applied at the load center terminal, remote from generation stations, so they do not operate at or below 115% of the
maximum current flow from the load to the generation source under any system condition. 8. Set transmission line relays
applied on the bulk system-end of transmission lines that serve load remote to the system so they do not operate at or
below 115% of the maximum current flow from the system to the load under any system condition. 9. Set transmission line
relays applied on the load-end of transmission lines that serve load remote to the bulk system so they do not operate at or
below 115% of the maximum current flow from the [___] to the under any system condition. [Brackets added, also see
further comment on missing wording following] This phrase "under any system configuration" could be construed as being
too all-inclusive, as one could postulate multiple events, e.g., simultaneous outages, which however unlikely could permit
power flows in a direction for which the system was not originally designed. As with the second comment below, the
phrase "under any system condition" was part of Revision 1 and is unchanged by Revision 2, however, the new
applicability to below 200 kV creates the new concern. Requirement 1, part 9: As currently written, Requirement 1, part 9
states: 9. Set transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk
system so they do not operate at or below 115% of the maximum current flow from the [___] to the under any system
configuration. [Brackets added] Some words are missing. The brackets have been added above to show one place where
at least some of the needed wording may be missing. A rewrite is necessary in order for this sentence to make any sense.
Yes
No
Referring to the response to Question 2 above, “Setting” should be replaced with Part, or Sub-requirement, whichever is
the terminology preferred by NERC to use.
No
R4 addresses the directive, but as commented on previously, “Setting” should be replaced with Part, or Sub-requirement,
whichever is the terminology preferred by NERC to use.
No
Requirement R5 states that the Planning Coordinator will determine which facilities below 200kV are critical to the
reliability of the Bulk Electric System by applying criteria defined in Attachment B, which is to be developed. Therefore,
respondents cannot comment on Attachment B. Respondents reserve the right to comment when Attachment B is
available for review. Because the document has been presented to the industry without Attachment B, how will
Attachment B be presented to the industry? Regarding sub-requirement 5.3, it must be revised to clarify that the Planning
Coordinator will provide the list of facilities subject to the Standard to all of the TOs, GOs, and DPs registered in its
footprint, not just to those entities that have facilities on the list. 5.2 refers to “Part 1”. As commented on previously in
Question 5 and elsewhere, Part or Sub-requirement should be used for consistency.
Yes
Yes
Yes
No
Yes
No
No
Individual
Michael Gammon
Kansas City Power & Light
No
Agree the changes for 4.1.2 and 4.1.4 are effective in meeting the “add in” approach in the FERC order. However, do not
agree with the approach in R5. R5 proposes to establish the criteria by which Reliability Coordinators will determine
facilities critical to the reliability of the BES. There are a variety of differing, and often complex, operating conditions that
dictate the need for transmission facilities. The TPL standards require extensive studies of the transmission system be
performed under steady state and dynamic conditions to understand and identify sensitive areas of the transmission
system and enable Reliability Coordinators to identify flowgates in their respective regions. In light of the Reliability
Coordinators awareness of transmission sensitivities through these studies, it seems unnecessary to dictate to the
Reliability Coordinators additional criteria.
Yes
No
Although setting #10 includes language to protect the most limiting element for a transmission circuit ending with a
transformer, the relay settings in the bulleted items are absent any consideration for other elements such as disconnect
switches, wave traps, current transformers, potential transformers, etc. and are only with concern to the transformer. The
relay settings should consider the fault current capabilities of all the facilities involved and be set in magnitude and
duration of the lowest facility rating.
No
Do not agree that the Regional Entity be included as a recipient of the list of transmission facilities. By NERC definition,
the Regional Entity is the Compliance Monitor and Enforcement Authority for the NERC Reliability Standards and is not an
operating entity. It is inappropriate to include Regional Entities as an entity to provide this information outside of the audit
process established by the NERC Rules of Procedure. By definition, in the NERC Reliability Terminology, the Regional
Entity is a compliance enforcement agent and not an operating organization of the Bulk Power System, and, therefore,
has no operating reason to obtain this information. See definition below: Regional Entity – The term ‘regional entity’ is
defined in Section 215 of the Federal Power Act means an entity having enforcement authority pursuant to subsection
(e)(4) [of Section 215]. A regional entity (RE) is an entity to which NERC has delegated enforcement authority through an
agreement approved by FERC. There are eight RE’s. The regional entities were formed by the eight North American
regional reliability organizations to receive delegated authority and to carry out compliance monitoring and enforcement
activities. The regional entities monitor compliance with the standards and impose enforcement actions when violations
are identified.
No
The proposed R4 exceeds the concerns of FERC in this matter. FERC directed a requirement to provide information upon
request. The proposed R4 requires data submission without request of the parties with interest to the information.
Recommend the SDT consider modifying this requirement to provide this information upon the request of appropriate
operating parties. Do not agree that the Regional Entity be included as a recipient of the list of transmission facilities. By
NERC definition, the Regional Entity is the Compliance Monitor and Enforcement Authority for the NERC Reliability
Standards and is not an operating entity. It is inappropriate to include Regional Entities as an entity to provide this
information outside of the audit process established by the NERC Rules of Procedure. By definition, in the NERC
Reliability Terminology, the Regional Entity is a compliance enforcement agent and not an operating organization of the
Bulk Power System, and, therefore, has no operating reason to obtain this information. See definition below: Regional
Entity – The term ‘regional entity’ is defined in Section 215 of the Federal Power Act means an entity having enforcement
authority pursuant to subsection (e)(4) [of Section 215]. A regional entity (RE) is an entity to which NERC has delegated
enforcement authority through an agreement approved by FERC. There are eight RE’s. The regional entities were formed
by the eight North American regional reliability organizations to receive delegated authority and to carry out compliance
monitoring and enforcement activities. The regional entities monitor compliance with the standards and impose
enforcement actions when violations are identified.
No
Do not agree with the approach in R5 and R5.1. This proposes to establish the criteria by which Reliability Coordinators
will determine facilities critical to the reliability of the BES. There are a variety of differing, and often complex, operating
conditions that dictate the need for transmission facilities. The TPL standards require extensive studies of the transmission
system be performed under steady state and dynamic conditions to understand and identify sensitive areas of the
transmission system and enable Reliability Coordinators to identify flowgates in their respective regions. In light of the
Reliability Coordinators awareness of transmission sensitivities through these studies, it seems unnecessary to dictate to
the Reliability Coordinators additional criteria. In addition, in R5.3, do not agree that the Regional Entity be included as a
recipient of the list of transmission facilities. By NERC definition, the Regional Entity is the Compliance Monitor and
Enforcement Authority for the NERC Reliability Standards and is not an operating entity. It is inappropriate to include
Regional Entities as an entity to provide this information outside of the audit process established by the NERC Rules of
Procedure. By definition, in the NERC Reliability Terminology, the Regional Entity is a compliance enforcement agent and
not an operating organization of the Bulk Power System, and, therefore, has no operating reason to obtain this
information. See definition below: Regional Entity – The term ‘regional entity’ is defined in Section 215 of the Federal
Power Act means an entity having enforcement authority pursuant to subsection (e)(4) [of Section 215]. A regional entity
(RE) is an entity to which NERC has delegated enforcement authority through an agreement approved by FERC. There
are eight RE’s. The regional entities were formed by the eight North American regional reliability organizations to receive
delegated authority and to carry out compliance monitoring and enforcement activities. The regional entities monitor
compliance with the standards and impose enforcement actions when violations are identified.
Yes
No
It is inappropriate for this standard to supersede any other agreements and the provisions of those agreements that have
been established between NERC and Registered Entities. The footnote made it clear those agreements would continue to
be honored. Recommend the SDT reinstate the principles established by the footnote directly into the Effective Dates
section to recognize the authority of those agreements. Agree with the effective dates of 18 months after applicable
approvals for R5 and for 24 months after notification by the Planning Coordinator of a new critical facility.
Yes
Agree that the SDT has made revisions that attempted to address the FERC directives. Do not agree with all the
proposals by the SDT as indicated by the comments regarding questions 1 through 8.
No
No other comments.
No
Do not agree with all the proposals by the SDT as indicated by the comments regarding questions 1 through 8.
No
No
Group
Transmission Access Policy Study Group
William Gallagher
No
The modifications to the Applicability Section meet the FERC directive but have the unacceptable unintended
consequence of increasing the burden on DPs with no reliability benefit. Specifically, the modifications make all DPs
potentially subject to PRC-023, thus requiring all DPs to incur costs to determine whether the standard is applicable to
them. Because PRC-023 should never be applicable to a DP in its capacity as a DP (as opposed to a TO that also
happens to be registered as a DP), as explained in TAPS’ response to question 6 below, the SDT should simply remove
DPs from the Applicability section to prevent the significant potential for confusion and unnecessary costs.
No
The proposed method of identifying facilities to which the standard will apply may be reasonable, though we cannot
comment definitively until a draft of Attachment B is available. The standard should not be applicable to DPs, however.
TAPS has been unable to find or think of an example in which a DP would have a load-responsive transmission phase
protection system, aside from a DP that is also a TO and has such a phase protection system because of its TO function.
There is thus no reason to include DPs as potentially applicable entities. If the SDT retains DPs on the list of potentially
applicable entities, it should at minimum clarify Requirement R5.3 to state that the Planning Coordinator will provide the
list of facilities subject to the standard to all of the TOs, GOs and DPs registered in its footprint, not just to the entities who
have facilities on the list. It is important that DPs who do not have facilities on the list have documentation from the
Planning Coordinator demonstrating that fact.
Individual
Dan Rochester
Independent Electricity System Operator
Yes
We agree with the Applicability Section and the modification to R5. Note that there is a discrepancy between the entities
listed in the Applicability Section and those checked off in the SAR. The latter indicates that the SAR is also applicable to
the RC, which we do not believe is required.
No
We agree with the inclusion of Section 2 of Attachment A in the Requirement Section but the proposed modification may
not fully meet the directive that the additional requirement is assigned a VRF and VSL. This may require the creation of a
separate main requirement rather than simply including the condition as a part of a requirement.
No
The proposed revision goes beyond what’s asked for in the directive as it requires the responsible entities to provide the
list to entities other than the TOP. The directive asks for providing the list to the TOP only.
No
The objective of R4 as written is unclear. We speculate that by requiring the TOs, GOs and DPs to provide the list
(associated with R1, Section 12) to the REs, the ERO will collect the relevant information from all REs to facilitate
provision of such information to owners, users and operators of the BES upon request. If this is the intent, we suggest to
replace “REs” with “ERO” to make it a more direct and efficient way to provide the information needed to support the
request for information process. The requirement as written does not conform with the results-based concept in that it
does not clearly specify a reliability directive. Hence alternatively, we suggest removal of this requirement altogether since
the directive asks the ERO to document, subject to audit by the Commission, and to make available for review to users,
owners and operators of the Bulk-Power System, by request, a list of those facilities. This can be dealt with outside of the
standard process, for example, through RoP 1600.
No
We are unable to assess its acceptability and effectiveness until Attachment B is developed.
Yes
No
We are unable to comment on this in the absence of a proposed implementation plan.
Yes
As indicated in our comment submitted under Q1, there is a discrepancy between the entities listed in the Applicability
Section and those checked off in the SAR. The latter indicates that the SAR is also applicable to the RC, which we do not
believe is required.
Yes
We general agree with the proposed action but there are detailed changes that we have comments on, which are noted in
our comments under Q1 to Q8
No
No
Individual
Bill Miller
ComEd
Yes
Yes
Yes
Yes
Yes
Yes
No
1) Certain relay elements may be thought to be “supervising relay elements”, when their function is specific and more
limited. A very common example would be a phase overcurrent relay that is required to actuate along with a phase
distance relay to cause a trip. In many applications, the phase overcurrent relays function is only to assure that the phase
distance relay will not cause a trip when a line is taken out of service and no potential restraint is applied to the phase
distance relay. Thus, loadability of the phase overcurrent relay is not a concern. Raising the level of the overcurrent
element may negatively impact the fault detecting ability of the two relays. This is perhaps a limited function supervising
relay element. It is complementary to the phase distance relay which provides the necessary loadability. 2) Although we
don’t employ out of step tripping, it would seem that the argument for the overcurrent element of an out of step tripping
scheme would be the same as for the phase distance element. 3) Are there supervisory elements for switch onto fault
schemes that could limit loadability? 4) In our experience, relays that supervise overcurrent relays are typically specifically
designed to provide loadability in order to allow the overcurrent relay to provide greater sensitivity without worrying about
its loadability. Thus this requirement would limit the use of such a scheme. 5) FERC’s main example seems to refer to an
old style of current differential relaying scheme that is likely not very widely applied. Most modern current differential
schemes use digital communications and will not trip on loss of communications regardless of the settings of any elements
that may be considered to be supervisory relay elements. The drafting team should consider modifying 1.6 of Attachment
A to clarify and more specifically address the FERC concern. Three suggestions are as follows: 1) 1.6. Protective
functions that supervise operation of other protective functions in 1.5. This is required for communications aided protection
schemes in 1.5 only when those schemes require communication channel integrity to maintain scheme loadability. 2) 1.6.
Protective functions that supervise operation of other protective functions in 1.2 through 1.5. This is required for
communications aided protection schemes in 1.5 only when those schemes require communication channel integrity to
maintain scheme loadability. 3) 1.6. Protective functions that supervise operation of other protective functions in 1.2
through 1.5.
Yes
Yes
No
No, other than the comments provided for question 7.
Yes
Yes, given that we assume that NERC must address all the FERC directives whether or not NERC or the industry agrees
with them.
No
No
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
Yes
Yes
Yes
Yes
Yes
No
Item 1.6 in Attachment A is not necessary. If the protection functions in 1.1 through 1.5 already meet all the loadability
requirements, the facility would not trip under heavy load condition by the supervising protection element alone. The
directive in paragraph 264 of Order 733 seems to deal with the supervising protection element on the current differential
scheme only. It is still arguable whether it is better to allow tripping of the line or restrain from tripping during loss
communication and heavy loading condition.
No
Even though this version of the standard does seem to have addressed Paragraph 284 of Order 733, we still do not agree
with the uniform effective date without taking into consideration how many critical circuits or equipment could be added for
an individual utility.
Yes
Yes
The effective date can be dependent upon how many critical circuits or equipment are identified for each individual
company.
Yes
No
No
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
No
Agree with the content. However, there is no justification for VRF to be High for the circuits lower than 200 kV.
Yes
Yes
Yes
No
FERC Order required the list to be made available for review to users, owners and operators of the Bulk-Power System
upon request. Requirement 4 does not include the "request" requirement, implying that the Registered Entity must provide
the list without a request. Further, the requirement does not specify what the Regional Entity will do with the list once it is
provided.
Yes
Yes
Yes
Yes
No
No
Individual
Brian Evans-Mongeon
Utility Services
No
The modifications to the Applicability Section meet the FERC directive but have the unacceptable unintended
consequence of increasing the burden on DPs with no reliability benefit. Specifically, the modifications make all DPs
potentially subject to PRC-023, thus requiring all DPs to incur costs to determine whether the standard is applicable to
them. Because PRC-023 should never be applicable to a DP in its capacity as a DP (as opposed to a TO that also
happens to be registered as a DP), as explained in our response to question 6 below, the SDT should simply remove DPs
from the Applicability section to prevent the significant potential for confusion and unnecessary costs.
No
The proposed method of identifying facilities to which the standard will apply may be reasonable, though we cannot
comment definitively until a draft of Attachment B is available. The standard should not be applicable to DPs, however. We
have been unable to find or think of an example in which a DP would have a load-responsive transmission phase
protection system , aside from a DP that is also a TO and has such a phase protection system because of its TO function.
There is thus no reason to include DPs as potentially applicable entities. If the SDT retains DPs on the list of potentially
applicable entities, it should at minimum clarify Requirement R5.3 to state that the Planning Coordinator will provide the
list of facilities subject to the standard to all of the TOs, GOs and DPs registered in its footprint, not just to the entities who
have facilities on the list. It is important that DPs who do not have facilities on the list have documentation from the
Planning Coordinator demonstrating that fact.
Group
Pepco Holdings, Inc - Affiliates
Richard Kafka
Yes
While philosophically we do not agree that this standard should apply to facilities below 100kV (i.e. facilities that are not
defined as BES facilities) we believe that as long as a sound engineering methodology is developed and applied uniformly
to identify those facilities critical to the reliability of the BES, then the revised wording is acceptable. Our response,
however, is qualified based on being granted an opportunity to comment and vote on the methodology once it is
developed.
No
The revised wording in paragraph R1 regarding out-of-step blocking schemes is confusing. We suggest rewording the
paragraph by splitting the sentence as follows: …while maintaining reliable protection of the BES for all fault conditions.
Use of out-of-step blocking schemes shall be evaluated to ensure that they do not block tripping for faults during the
loading conditions defined within these requirements.
No
It would appear that this requirement has already been addressed in the R1 introductory paragraph by the phrase “...while
maintaining reliable protection of the BES for all fault conditions.” How could one “maintain reliable protection of the BES”
if relays are set with operating times that result in equipment being exposed to fault levels and durations that exceed their
capability. This introductory requirement to provide reliable fault protection applies to all sub requirements not just to
section 10 (old R1.10). As such, the added language in section 10 seems redundant and superfluous. Secondly, if the
proposed language were to remain in section 10, why is the term “limiting piece of equipment” used and not just
“transformer”? It appears the major concerns related to the comments contained in Order 733 were around exceeding
transformer fault level/duration limitations. If that is the concern, why not just use the phrase “do not expose the
transformer to fault levels and durations that exceeds its capability”
No
To avoid confusion, the wording of R3 should be revised as follows: “Each Transmission Owner, Generator Owner, and
Distribution Provider that chooses to utilize Requirement R1 Setting 2 as the basis for verifying transmission line relay
loadability shall provide….” The problem with the SDT’s proposed wording of R3 is that suppose a TO chose to utilize R1
Setting 1 criteria (> 150% of 4 hr rating) as their basis for verifying loadability, but the actual relay setting also satisfied
criteria R1 Setting 2 (> 115% of 15 min rating) the entity may interpret that they are still obligated to forward the list since
the relay settings also satisfied R1 Setting 2 criteria
Yes
Yes
While philosophically we do not agree that this standard should apply to facilities below 100kV (i.e. facilities that are not
defined as BES facilities) we believe that as long as a sound engineering methodology is developed and applied uniformly
to identify those facilities critical to the reliability of the BES, then the revised wording is acceptable. Our response,
however, is qualified based on being granted an opportunity to comment and vote on the methodology contained in
Attachment B once it is developed.
No
We do not agree with the proposed wording of Section 1.6 of Attachment A which makes the standard apply to “Protective
functions that supervise operation of other protective functions in 1.1 through 1.5”. The standard should apply to
“protective systems” not individual components of protective systems. Compliance should be based on the ability of the
“protective system” as a whole to meet the performance criteria established by the standard. Delving into the details of
individual scheme designs and supervising element operation goes well beyond the purpose and scope of this standard.
In paragraph 251 of Order 733 the Commission “expressed concern that section 3.1 could be interpreted to exclude
certain protection systems that use communications to compare current quantities and directions at both ends of a
transmission line, such as pilot wire protection or current differential protection systems supervised by fault detector
relays” and requested comment on “whether it should direct the ERO to modify section 3.1 to clarify that it does not
exclude from the requirements of PRC-023-1 pilot wire protection or current differential protection systems supervised by
fault detector relays.” The Commission reiterated again in paragraphs 266, 268, and 270 their concern with not including
supervising elements associated with “current differential schemes” to prevent them for operating on loss of
communications. That being said, the proposed revision to Attachment A to include supervising elements for all protective
functions in 1.1 through 1.5 goes well beyond addressing the Commission’s concern. We believe the Commission’s
concern could be addressed by simply modifying Attachment A by deleting proposed section 1.6 and adding a new
section 1.5.5 “Line current differential schemes, including supervising overcurrent elements”. The SDT’s current proposed
wording for Section 1.6 would require the overcurrent element in a switch-on-to-fault scheme to be subject to the
loadability criteria. However, the NERC SPCTF in their June 7, 2006 technical paper “Switch-on-to-Fault Schemes in the
Context of Line Relay Loadability” indicated there is no suggested loadability criterion if the voltage arming threshold is set
low enough. Similarly, fault detectors which supervise distance elements would be subject to the loadability standard.
However, there are no criteria established on how to set these elements, particularly on weak source systems, or zone 3
applications, where in order to reliably detect faults at the end of the zone of protection may require setting the supervising
fault detector below 150% of line rating. The NERC SPCTF in their June 7, 2006 technical paper “Methods to Increase
Line Relay Loadability” provided recommendations to increase loadability of distance elements through various
techniques, such as the use of load encroachment elements or blinders, but does not specifically address setting of
supervising elements. In fact, at present, there is no reliability standard requiring the use of supervising elements, and
some newer microprocessor relays do not even employ supervising fault detectors on their distance elements. FERC in
their Order 733 stated “As with our other directives in this Final Rule, we do not prescribe this specific change as an
exclusive solution to our reliability concerns regarding the exclusion of supervising relay elements. As we have stated, the
ERO can propose an alternative solution that it believes is an equally effective and efficient approach to addressing the
Commission’s reliability concerns.” In summary, we believe that addressing the Commission’s concern regarding
supervising elements on current differential schemes, as described in our second paragraph above, would satisfy the
intent of Order 733, while not imposing unnecessary additional restrictions on what has proven historically to be extremely
reliable protection practices.
No
We agree with the removal of the footnote regarding temporary exceptions. However, there appears to be a contradiction
between the effective dates for sub 200kV facilities noted in section 5.1.2 (39 months following regulatory approvals) and
5.1.3 (24 months after being notified by its Planning coordinator). If the planning coordinator takes the full 18 months to
determine the R5 list (per effective date section 5.2) and the TO has 24 months after that to comply, that would be 42
months following regulatory approval, which is in conflict with the 39 month requirement in 5.1.2. Since the list of sub
200kV facilities may change from year to year, it would seem prudent to make the effective date for those facilities always
tied to a defined interval following being notified by the Planning Coordinator and eliminate the 39 month requirement for
sub 200kV facilities from 5.1.2. Also, since the Attachment B methodology has not yet been determined, it is unclear how
many sub 200kV facilities may fall under these requirements. As such, one cannot yet determine if the proposed 24
months would be sufficient. We propose at least a 36 month interval until the methodology is finalized and the magnitude
of the scope better defined. In addition, if supervising elements are included in the standard in some form, an
implementation schedule (i.e. appropriate effective dates) need to be developed based on this significant increase in
scope and number of facilities to be reviewed.
Yes
While the scope of the proposed standards action addresses the directive(s) outlined in FERC Order 733 we believe that
there are two significant issues that need to be much more thoroughly investigated before being included. Those areas
are the inclusion of supervising elements in the existing relay loadability standard and the development of any new
standard that would “require the use of protective relay systems that can differentiate between faults and stable power
swings and when necessary phase out protective relay systems that cannot meet this requirement.”
Yes
Regarding the response of protective relay systems to stable power swings, Draft 5 of TPL-001-2 Requirement R4
(stability assessment) section 4.3.1 requires a contingency analysis be performed which includes “tripping of transmission
lines and transformers where transient swings cause protection system operation based on generic or actual relay
models.” Therefore the impact of power swings on relay operation is already addressed in TPL-001. If the tripping of a line
is identified during this study phase the impact of the line trip is assessed to ensure the system meets the performance
criteria identified in Table 1. If not, mitigating measures would be required, such as modifying that protection scheme to
prevent its operation during a stable power swing. However, this would be done on a case by case basis when identified.
This seems a much more prudent approach than to require “all protection systems be modified to prevent operation during
stable power swings.” That would be similar to requiring the re-conductoring all lines so that they could never experience
an overload. Also, Appendix F of the “PJM Relay Subcommittee Protective Relaying Philosophy and Design Standards”
employs a methodology to address relay response during power swings by calculating a transient load limit for the relay
instead of just the steady state limit identified in PRC-023. The relay loadability is evaluated at the maximum projection
along the +R axis (the most susceptible point for swings to enter) rather than at a 30 degree load angle. Various
multiplying factors are used to account for the relay operating time delay. This methodology of calculating relay transient
loadability limits, which was developed by the PJM Relay Subcommittee over 30 years ago, has worked extremely well in
eliminating relay operations during stable power swings. In summary, there are other methods to evaluate and improve the
performance of protection systems during power swings short of hardware replacements. All options should be evaluated.
No
We do not agree with the scope of the proposed standards action for numerous reasons. The documented responses to
the original FERC NOPR on PRC-023 from numerous sources, including NERC and EEI, together make a rather
convincing technical argument against many of these proposed actions. We support these technical arguments, which for
the sake of brevity will not be repeated here. In addition, we have provided comments and objections on specific portions
of the proposed standards action in our responses to questions 1 through 10 above.
No
No
Group
American Transmission Company
Andrew Z. Pusztai
Yes
However, this affirmative response is conditional depending on whether the criteria that will be established within
Attachment B (see R5.1) are reasonable and apply to properly qualified facilities below 200 kV.
Yes
Yes
The word change meets the strict interpretation of the directive, but it is not necessarily improving the reliability of the
system. Faults are cleared in cycles and transformer damage curves do not start until at least one second.
Yes
Yes
While achievable, this will not come without effort and does not necessarily improve the reliability of the BES
commensurate with the compliance burden.
No
As noted in Q1 above, an affirmative response would be conditional and depend on whether the criteria that will be
established within Attachment B (see R5.1) are reasonable and apply to properly qualified facilities below 200 kV. In
addition, the R5 requirement should include wording that limits the scope of the transmission facilities (line and
transformer circuits) to be evaluated to only those transmission facilities that can be tripped by the relay settings subject to
requirement R1. Requirement R5 should also qualify that only the transmission facilities that are “known” to be associated
with the relay settings subject to requirement R1 need to be evaluated. If the SDT wants to better assure that the Planning
Coordinator knows about all of the pertinent transmission facilities, then they should add a requirement that obligates
Transmission Owners, Generator Owners, and Distribution Providers to provide the Planning Coordinator with a list of the
transmission facilities that are associated with the relay setting subject to requirement R1.
No
In Order 733, the Commission cites in footnote 186 (p. 161) the definitions of dependability and security, two components
of reliability for protective relays. The Commission did not recognize that the two tend to be mutually exclusive. Raising
dependability (making sure breakers trip during a fault) can sacrifice some degree of security (tripping more than is
needed). Historically, protection engineers have been biased toward dependability to ensure the safety of people and
equipment. The exclusions allow that to happen. These are contingency scenarios where protective schemes are
compromised. For a second contingency, the dependability is at risk if fast tripping is not employed. By removing the
exclusion, reliability could be negatively jeopardized. For example, an operational decision to open breakers will be
needed for loss of potential. The corollary would be leaving the element in service with fast tripping enabled for a fault until
the loss of potential condition can be diagnosed and corrected
Yes
Yes
It addresses the directives per the letter of the order; however, it is not necessarily improving reliability.
Yes
On the topic of ‘adding in’ - listing and evaluating the transmission facilities below 200 kV, we propose the inclusion of
qualifications that prevent the consideration and evaluation of irrelevant facilities (e.g. facilities that are not tripped by the
applicable relay settings).
No
We agree that the topics of generator relay loadability and power swing protective relaying should be referred to in other
separate standards. While we acknowledge that it is in everyone’s best interest to respond to the FERC directives, there
are numerous technical flaws that need to be resolved in their request. Forming a team and spending considerable
resources will not gain industry acceptance to these directives.
No
No
Individual
Tribhuwan Choubey
Southern California Edison
No
Applicability clause 4.12 and 4.14 - Formulating a consistent methodology test to determine for a sub 200KV facility by the
Planning Coordinator is quite an uphill task keeping in view the different circuit configuration different utilities may have. It
is best left alone to each utility to determine the facilities which can be a candidate for inclusion as a bulk power system.
The current risk based assessment criteria to determine bulk power facility should be continued.
No
Requirement R1.7, R1.8, R1.13 do not provide a clear guideline on generators connected to the load center on Radial
basis, where load current into the generators ( forward direction current seen by the relay) is just an auxiliary load and
insignificant compared to the transmission line rating.
No
The relay if set according to Requirement R1.2 are based upon 15 minute highest seasonal facility loading duration. This
gives sufficient time for the operators to take manual corrective action, if the deem so. There is no need for the Registered
entity to provide a list, as it would not be efficient and cost effective.
Group
PSEG Companies
Kenneth D. Brown
No
In attachment A was added a new requirement, item 1.6. We not agree with this. Sometimes these elements have to be
set lower than the criteria. As long as the protection system as a whole does not trip the line, then that should meet the
criteria. Individual elements that supervise tripping element should NOT be part of the standard.
No
No
Individual
Dale Fredrickson
Wisconsin Electric
No comment
No comment
No comment
No comment
No comment
No comment
No
We strongly disagree with this change. Applying the loadability requirement to supervisory functions in protection system
will have an extremely negative effect on BES reliability. With this change, protection systems will be less dependable,
resulting in increased probability of a failure to detect a system fault. This change should not be implemented.
No comment
No comment
No comment
No comment
No
No
Group
PacifiCorp
Sandra Shaffer
Yes
Yes
Yes
Yes
Yes
No
Paragraph No. 264 directs a revision to Section 1 of Attachment A in order to include supervising relay elements. This
change as currently written requires further clarification to meet this directive. For example, a Distance element is
commonly supervised by a phase overcurrent element (Fault detector). If this change suggests that the overcurrent
element has to be set above maximum load, then PacifiCorp disagrees with the modification. The fault detector will not trip
the line by itself; it operates to qualify the distance element assertion. It is our standard practice to set this element above
load where possible, but without restricting the reach of the distance element. This means that if the fault current at the
maximum reach of the distance element is below load, setting the fault detector above load will restrict the reach of the
distance element- this would compromise the protection scheme. In microprocessor relays where Load encroachment is
used this is even more critical. The Load encroachment function will prevent the distance element from operating in the
load region and a fault detector setting that is sensitive enough can be used safely without the need to set it above load
current to enhance the distance element reach.
Yes
No
No
It is very difficult to comment on test parameters that have not been determined.
No
No
Group
Southern Company
Andy Tillery
Yes
Yes
Yes
Yes
Yes
Yes
No
The language that has been added to PRC-023 related to the inclusion of protection elements (fault detectors) supervising
protection functions that are subject to the PRC-023-2 requirements is not appropriate and will likely decrease the
reliability of the BES for the following reasons: - The tripping logic utilizing these elements is an AND function, it takes
distance element AND the fault detector (FD) to trip. Since all distance elements meet the loadability criteria, it is not
necessary to also ensure FD meet hese requirements. - Setting FD above nominal load point would unnecessarily reduce
sensitivity of distance element and in many cases eliminate the distance element’s ability to protect the very system
element it is designed and intended to protect - It would require very expensive communications based relay schemes to
replicate this lost protection if it is even possible to do so; a long radial line is one instance where it would not be possible Eliminating the FD would actually reduce Security and Dependability in electromechanical schemes - There is a whole
generation of microprocessor based relays that it is not possible to eliminate the FD; to effectively take it out of service,
one would have to set it to the most sensitive setting which would violate the loadability criteria - Relays at terminals with
high SIR, a weak source system, and line with large conductors where the far end fault current may be smaller than
maximum line current (similar to Exception 6 of the Relay Loadability Exceptions: Determination and Applications of
Practical Relaying Loadability Ratings, Version 1.1 published November 2004 by the System Protection and Control Task
Force of NERC) - Faults with low power factor could present a similar magnitude of line current as normal high power
factor load currents
Yes
Yes
No
Yes
No
No
Group
Bonneville Power Administration
Denise Koehn
Yes
No
The modified Requirement R1 requires that one of the 13 criteria be used to prevent out-of-step blocking schemes from
blocking tripping for fault conditions. The problem is that the 13 criteria are only related to loading conditions, and it is not
clear how they would be applied to prevent out-of-step blocking schemes from blocking a trip during a fault, or if it is even
possible to use these criteria for this purpose. The modified Requirement R1 requires actions that are ambiguous and we
cannot support it as written.
No
In some cases, Section 10 of Requirement R1 would be impossible to meet. For example, a 150/200/250 MVA,
OA/FOA1/FOA2 transformer is required by Section 10 to have its protection set so that it doesn’t operate at or below
150% of the maximum transformer rating of 250MVA, or 1.5x250=375MVA. The modified Section 10 would also require
that the protection not expose the transformer to a fault level and duration that exceeds its capability. According to IEEE
C37.91, a through-fault of two times the transformers base rating, 2x150=300MVA, will be damaging to the transformer.
For this particular transformer, which is not unusual, Requirement R1, Section 10, requires the protection to operate for
through faults of 300MVA or greater, but not operate for loads of 375MVA or less. It is impossible to simultaneously meet
both of these conditions, so Section 10 is unacceptable. One possible way to correct the problem is to change the
requirement so that the protection does not operate below 200% of the transformer base rating. This would allow the
protection to meet IEEE C37.91 for through-faults and still allow overloading of the transformer.
This change adds an additional burden to the applicable entities, but serves no purpose other than to satisfy FERC’s
misinterpretation of what a fifteen-minute facility rating is.
No
Requirement R5 is okay, but Part 5.1 adds an additional and useless extra burden to the applicable entities. The process
that the Planning Coordinator is required by this part to have would almost certainly be to simply apply the criteria in
Attachment B to lines and transformers operated below 200kV to determine if they are critical to the BES. Requiring
documentation for such a trivial process results in increased paper work, additional preparation for an audit, and is a
waste of everyone’s time. We suggest deleting Part 5.1.
No
Here we have a situation where the standard is being compromised to satisfy FERC’s misunderstanding of what a
supervising relay is. In Paragraph 266, FERC gives an example of how a line differential relay works in an attempt to
demonstrate why supervisory elements must not operate for load, but instead they clearly demonstrate their
misunderstanding of the details of differential relay operation and what a supervisory relay is. Modern differential relays
will disable the differential function upon loss of communications. If an overcurrent element is present, it would be used for
backup protection, not as a supervisory element. If an overcurrent element were used to supervise a differential element,
the sensitivity of the differential relay would be lost and the result would be a simple overcurrent relay. FERC’s
misunderstanding has resulted in the improper addition of supervisory relays in Attachment A, Section 1. Sometimes
supervisory relays must be set below maximum loading to obtain the purpose they were intended for. For example, it is
often necessary to set overcurrent supervision of distance relays below the maximum load current of the line so that they
will operate for remote faults. This modification to Attachment A would prohibit that action and make it impossible to set
the supervisory relays to comply with the standard and still provide adequate protection. The modification to Attachment A
is unacceptable.
5.1.2 and 5.1.3 both apply to the same systems and should be combined into one sub-requirement. Also, since the date of
the applicable regulatory approval is now established, please consider replacing the cryptic phrase “at the beginning of the
first calendar quarter 39 months following applicable regulatory approval” with an actual date.
Yes
No
Yes
No
No
Individual
Kathleen Goodman
ISO New England Inc.
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise language is crafted
to adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
Some immediate concerns with the proposal include: 1) Our understanding is that the application of NERC standards is
limited to the BES. Thus, facilities below 100 kV must be included in the Regional Entity definition of BES to be eligible.
The requirements should reflect this. The way the proposed standard reads, one might conclude the PC must test every
facility below 100 kV. This surely can’t be the intent. 2) Furthermore, the directive appears to require some action on the
Regional Entities. From paragraph 60, “We also direct that additions to the Regional Entities’ critical facility list be tested
for their applicability to PRC-023-1 and made subject to the Reliability Standard as appropriate.” It is not clear how this
directive is reflected in the standard to ensure that this work is completed prior to the PC’s performing their assessment for
below 200 kV facilities. The bottom line is that the changes here are significant enough that they would benefit from a
group of experts reviewing the directives and proposing the precise language that is needed.
No
Requirement R1, Parts 7, 8 and 9: Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system configuration”
with "under any system condition:" 7. Set transmission line relays applied at the load center terminal, remote from
generation stations, so they do not operate at or below 115% of the maximum current flow from the load to the generation
source under any systemcondition. 8. Set transmission line relays applied on the bulk system-end of transmission lines
that serve load remote to the system so they do not operate at or below 115% of the maximum current flow from the
system to the load under any systemcondition. 9. Set transmission line relays applied on the load-end of transmission
lines that serve load remote to the bulk system so they do not operate at or below 115% of the maximum current flow from
the [___] to the under any system condition. [Brackets added, also see further comment on missing wording following]
This phrase "under any system configuration" could be construed as being too all-inclusive, as one could postulate
multiple events, e.g., simultaneous outages, which however unlikely could permit power flows in a direction for which the
system was not originally designed. As with the second comment below, the phrase "under any system condition" was
part of Revision 1 and is unchanged by Revision 2, however, the new applicability to below 200 kV creates the new
concern. Requirement 1, part 9: As currently written, Requirement 1, part 9 states: 9. Set transmission line relays applied
on the load-end of transmission lines that serve load remote to the bulk system so they do not operate at or below 115%
of the maximum current flow from the [___] to the under any system configuration. [Brackets added] Some words are
missing. The brackets have been added above to show one place where at least some of the needed wording may be
missing. A rewrite is necessary in order for this sentence to make any sense.
Yes
No
We do not understand the need for this directive or requirement. A relay that is set to operate at 115% greater than the 15minute rating of the facility does not equate to damage occurring on that facility if operated at that point in 15 minutes.
Furthermore, it does not mean the relay will operate in 15 minutes nor does it mean the operator has only 15 minutes to
take action. In fact, the operator may have less time depending on the time delay set on the relay. It is no different than
any other relay. Usually, the facility will be operated with some buffer so that there is no chance that an entity could trip the
facility due to loading above the relay limit. In fact, the transmission operator should be aware of any relay that might be
the limiting facility so they can operate the facility with some margin of error to ensure they don’t inadvertently cause a
relay operation due to loading.
Yes
Yes
Yes
No
While we agree removing the footnote is straight forward and addresses one Commission directive. In particular, we
believe that only a full drafting team could adequately assess if any additional time will be needed to comply with the
standard for sub-100 kV facilities particularly when we consider there are some outstanding issues a regional entities
critical facilities list identified in Question 1. Also, we are unable to assess if the two directives are fully addressed absent a
proposed implementation plan.
Yes
No
We are not prepared at this time to offer equally efficient and effective alternatives. Rather, we believe this is the purpose
for convening a full drafting team and that the drafting team should propose their alternatives.
No
We largely believe the scope will allow the drafting team to address the directives. However, we request that the scope be
modified to make clear that the drafting may use equally effective alternatives to address the Commission’s directives per
the Commission in this order and other orders such as Order 693. The scope should address apparent conflicts in the
timing of requirements posed by the standard. It is our understanding that, based on the final date afforded NERC to
develop the criteria for the determination of sub-200 kV facilities,a newly proposed implementation plan will be offered to
allow the Planning Coordinators an appropriate time frame to apply the criteria to determine the “critical” facilities below
200 kV. The implementation plan should cause the effective date for circuits described in 4.1.2 and 4.1.4 to be changed
from “39 months following applicable regulatory approvals” to a date linked to the Planning Coordinators schedule to
provide a list to its TOs, GOs and DPs.
No
We are not aware of any regional variances per se. However, each regional entity has its own definition for BES and this
needs to be considered when addressing sub-100 kV facilities.
No
Individual
Robert Ganley
Long Island Power Authority
No
There appears to be a disconnect between FERC’s “sub 100 kV” and proposed “below 200 kV” revision in the Applicability
Section. LIPA seeks clarification on this. Also, by whom and by which method will the criticality of the substations be
ascertained?
No
Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system configuration” with "under any system condition:"
This phrase "under any system configuration" could be construed as being too all-inclusive, as one could postulate
multiple events, e.g., simultaneous outages, which however unlikely could permit power flows in a direction for which the
system was not originally designed. Requirement 1, part 9: As currently written, Requirement 1, part 9 states: 9. Set
transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk system so they do
not operate at or below 115% of the maximum current flow from the [___] to the under any system configuration. [Brackets
added] Some words are missing. The brackets have been added above to show one place where at least some of the
needed wording may be missing. A rewrite is necessary in order for this sentence to make any sense.
Yes
Yes
No
FERC order 733 p224 requires that the list of facilities that have protective relays set pursuant to R1.12 of anticipated
overload be made available to users, owners, and operators of the BPS. However, the proposed revision to R4 requires
the list to be made available to Regional Entity only. Please clarify. Also, FERC order uses the term “by request” which is
missing from the proposed revision.
No
LIPA understands the drafting team’s rationale, however, believes that the proposed method in Attachment B should be
developed before providing comments.
No
LIPA believes that the new wording in 1.6 Attachment A is unnecessary since the existing wording already complies with
the FERC order p.264. Supervisory functions are already part of the protective functions 1.1 through 1.5. Also, this new
wording will be subject to varied interpretation and create more confusion.
No
Yes
Yes
Involving industry working groups such as IEEE, EPRI, etc who have proven technical experts will also help in effectively
achieving reliability.
Yes
LIPA agrees with the scope in general. Please consider our comments above for answers to specific issues.
Yes
NPCC BPS definition based on A10 criteria is a regional variance.
No
Individual
Kirit Shah
Ameren
No
Attachment B as mentioned in R5 is not available for review.
Yes
No
The language is not clear. It appears that the transmission line relays are being used as the thermal overload protection
for the transformer.
Yes
No
See our response to Question 1
No
In attachment A – 1.6 is not a tripping function – it’s a supervisory function – it in itself does not trip which is the description
of ‘1’ therefore needs to be elsewhere if kept.
Yes
No
No
Individual
Thad Ness
American Electric Power
No
AEP understands the intent of the FERC Order (Paragraph 60) to address the sub-100 KV facilities only if they are
associated with critical facilities above 100 KV. The applicability and the associated requirements should be reworded to
ensure that the Planning Coordinator does not have to identify critical facilities below 100 KV.
Yes
Yes
Yes
Yes
No
Please refer to our comment under question number 1. AEP reserves the right to provide additional comments once
Attachment B has been drafted and supplied for industry review.
No
AEP requests some clarifying information regarding what is envisioned for 1.6 of Attachment A.
No
It is unclear how much time a TO, GO, or DP would have to implement the changes based on the results of the analysis
by the Planning Coordinator. In addition, the Effective Date section is a one-time event upon regulatory approval. What
are the on-going implementation expectations? There should be some allowed lead beyond initial implementation after
facilities are identified by the Planning Coordinator.
No
Refer to our comment under question 1.
No
Not at this time, but AEP would like to consider all viable options throughout the standard development process.
Yes
No
No
Individual
Michael Moltane
ITC Holdings
Yes
No
The proposed wording seems out of place in this requirement and is not clear as how it is being applied to
subrequirements 1 - 13
No
R1 -10 is all about loadability of the relays protecting the transformer. If the requirements of R1-10 cannot be met without
exceeding the transformer damage curve, then we go to R1-11. We do not feel that there should be anything to do with
fault duty.
Yes
Yes
Yes
No
It appears from the new 1.6 (Attachmnt A) that fault detectors must meet loadability requirements. These do not trip and
must not be included in PRC023. We will not be able to adequately protect longer lines in weak areas with this
requirement in place.
No
The new effective dates for 5.1.2 will for the most part be ok. Some of these below 200 kV lines will have to be
reconstructed to be able to have adequate protection and meet the required loadability. It will be difficult to do this in 39
months. We suggest a mitigation program be required for those lines that will be difficult to meet the 39 month deadline.
Yes
No
No
Several parts of the standard go too far (Appendix A R1.10) and will require us to document faults and clearing times to
prove the fault duty of transformer connections. Also the requirements to deal with out of step blocking relays should go in
phase 3 and not in this standard.
: Utilities with long lines and in weak areas will have difficulty protecting their lines and meeting the required loadability.
Regions where there are very rural systems will want to write standards that allow adequate protection for their systems.
No
Group
FirstEnergy
Doug Hohlbaugh
Yes
Yes
No
Although it is true that the FERC directive specifically states "limiting piece of equipment" their reasons and justifications
all involve transformers. We propose replacing "limiting piece of equipment" with "transformer" would meet the FERC's
reliability concern as well as provide clarity to applicable entities. We believe this is an equally effective means of meeting
the directive.
No
We suggest removing the Regional Entity from the list of entities receiving this information since they do not have a
reliability-related need for it.
Yes
Yes
Although we agree that R5 is the appropriate requirement to reference the criteria to be used, it is still to be determined if
we agree with the criteria since it is still being developed.
No
FirstEnergy supports applying PRC-023 to certain supervising relays, such as overcurrent relays that are enabled only
when another (usually communications based) scheme is out of service, or overcurrent relays that are ANDed with current
differential elements that can trip by themselves if the communications path used by the current differential scheme is
compromised. However, it is not clear that a 150% factor is the correct one to use in this case. Our understanding is that
150% is a combination of an error factor (widely utilized by industry) of 15% plus a 35% margin to approximate a 15
minute interval rating to give operators time to react to adverse system conditions. It is unclear that this extra 35% margin
is needed for these supervising relays, when the reliability goal is to prevent relays being continuously picked-up. We
recommend that the standard utilize a 115% margin (rating duration nearest 4 hours) for these types of supervising relays
and that this would be adequate to meet the Commission's stated reliability concerns. However, there are several other
types of schemes that utilize supervising relays where applying PRC-023 would be detrimental to the reliability of the bulk
power system. One widely used case is the supervision of an impedance relay when there is no communications scheme
involved. There are cases where an impedance element/relay which is set per PRC-023, correctly operates for a fault it is
intended to see, but that the actual current value will be on the order of the line rating, which will result in the scheme not
operating if the supervising relay is set as the commission proposes. The alternative for these types of schemes is to
remove the supervision from the scheme, which will result in the scheme operating purely on the impedance element,
which is exactly the reliability concern that the Commission is trying to address with this directive. However, many
microprocessor relays have inherent overcurrent supervision of impedance elements which cannot be disabled, adding to
the complexity of the issue. Since this is a fairly complex theoretical/technical issue, we recommend that the NERC
System Protection and Control Subcommittee (SPCS) investigate this issue and produce a white paper or other document
describing any unintended consequences of implementing the FERC directive. The work of the SPCS could also consider
equally effective alternatives to meeting the Commission’s directive.
Yes
No
i. The SAR shows the directive from P. 162 as part of Phase I to be implemented by March 18, 2011. However, this
directive should be included in Phase III since it deals with the subject of relay operations due to power swings. ii. The
directive from P. 224 is missing from the detailed section of the SAR, but is included in the table in the back of the SAR. iii.
As mentioned in our response to Question 7, we do not agree with how the project is proposing to address the P. 264
directive.
No
Regarding the direcive of Par. 264, since this is a fairly complex theoretical/technical issue, we recommend that the NERC
System Protection and Control Subcommittee (SPCS) investigate this issue and produce a white paper or other document
describing any unintended consequences of implementing the FERC directive. The work of the SPCS could also consider
equally effective alternatives to meeting the Commission’s directive.
Yes
We agree that this standards action is necessary to meet the FERC directives, but have some concerns as we have stated
in previous responses above.
No
No
Group
TSGT System Planning Group
Bill Middaugh
Yes
No
We suggest that the added phrase be removed from R1 and a new requirement created. Suggested wording is “Protection
Systems that block for stable swings or out-of-step conditions shall be evaluated to ensure that appropriate tripping will
occur for in-section faults that occur during the condition. Some additional delay may be required and is acceptable to
ensure that the appropriate tripping occurs.”
Yes
No
We think that the data needs to be given only to the Transmission Operators, which is what FERC Order No. 733 requires.
We also believe that an initial submittal is sufficient until any responsible entity begins or stops using Requirement 1,
Setting 2 for setting a phase protective relay that is used to protect an applicable facility. There is no need for periodic
duplicate submittals.
No
FERC Order No. 733 requires the settings be provided upon request and no initial or periodic submittal is required.
No
While we agree that the purpose of Requirement R5 is beneficial, there is much confusion about registration and
responsibilities of Planning Coordinators. Though the FERC order proposes that planning coordinators perform the test
developed herein, there is also flexibility in how NERC can achieve the same result. We believe that the Regional Entity
(or the Reliability Coordinator, as was included in the System Protection and Control Task Force recommendation) should
be the responsible functional entity for determining which elements operated at less than 200 kV need to meet
Requirement R1. The Region was responsible for determining operationally significant facilities during the “Beyond Zone
3” process.
Yes
As we interpret the changes to Attachment A they are acceptable. However, there appears to be uncertainty about the
intent of the drafting team. We interpret the change to 1.6, in conjunction with 2.1, to allow setting impedance relay fault
detector supervisory elements at levels below load current levels. This understanding comes from the realization that the
fault detector elements by themselves do not “trip with or without time delay, on load current,” a requirement described in
1. The fault detector elements can cause tripping on their own, but only for conditions of loss of potential or loss of
communications, which are both excluded from the loadability requirements as steted in 2.1. If Tri-State’s interpretation of
the intent of Attachment A, Sections 1, 1.6, and 2.1 is incorrect, then we do not agree that this is an acceptable and
effective method of meeting this directive. There are many protection system locations in our system that require the fault
detector supervision elements to be set below load current levels in order for backup impedance relays to operate
securely in the event of loss of potential and to operate dependably for remote faults that inherently have low fault current
magnitudes.
Yes
No
As stated in our earlier comments, we believe that some proposals exceed the directives. It is also not clear how p 162
was addressed in PRC-023-2 as indicated on SAR-3.
Yes
We included specific proposals in our comments to questions 2, 4, 5, and 6.
Yes
We agree that the scope meets the FERC directive, but some of the proposals in the proposed standard reach beyond the
directive.
No
No
Individual
Yes
Yes
Yes
Yes
Yes
Yes
No
Removal of exclusion 3.1 in Att. A, will lead to reduced reliability because an operational decision to open breakers will be
needed for loss of potential conditions. The corollary would be leaving the element in service with fast tripping enabled for
a fault until the loss of potential condition can be diagnosed and corrected.
Yes
Yes
No
No
Removal of exclusion 3.1 in Att. A, will lead to reduced reliability because an operational decision to open breakers will be
needed for loss of potential conditions. The corollary would be leaving the element in service with fast tripping enabled for
a fault until the loss of potential condition can be diagnosed and corrected.
No
No
Individual
Laura Zotter, Steve Myers
ERCOT ISO
The entities who receive the list of facilities should be the same from R3 to R4.
The entities who receive the list of facilities should be the same from R3 to R4.
No
ERCOT ISO respectfully asserts that the changes in this standard need more thorough discussion. This standard is
incomplete without the Attachment B and the intent of the requirements is not explicitly clear. A standard drafting team
(not a SAR SDT) needs to develop Attachment B through discussion of the entire process that will meet Order 733
directives. Attachment B is a critical component needed to assess R5 and provide further feedback. Requirement 5 needs
to be reworded for clarity. The standard drafting team assigned to this project needs to work closely with the Reliability
Coordination SDT (Project 2006-06), which is tasked with defining critical facilities or identifying criteria for developing a
list of critical facilities. ERCOT ISO disagrees with the use of the phrase ‘facilities that are critical’ in this requirement. A
requirement to create a list of critical facilities should not be addressed in this standard.
ERCOT ISO thinks a standard drafting team can evaluate the Order 733 directives, work in conjunction with other
Standard Drafting Teams already addressing some aspects of critical facilities, may be able to more succinctly arrive at an
equally efficient and effective method of achieving the intent of the directive(s). The coordination between teams is vital to
avoid confusion and possible overlap.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
This requirement needs to be refined to clearly state the intent. It is unclear if “limiting piece of equipment” is referring to
just transformers or other elements. Some of the elements involved in the construction of a transmission line/transformer
arrangement such as line conductors, etc. may not have published fault current ratings. It is unclear how to determine the
most limiting piece of equipment if published fault current ratings are not available for these devices
No
Item 1.6 of Attachment A needs to be clarified. If the intent is to include protective functions such as fault detectors then
this could possibly lead to relay sensitivity problems when switching contingencies create weaker systems than normal
and a line is faulted. It is unclear why supervisory functions are considered if the protective functions they supervise will
operate in compliance with R1
Individual
Jon Kapitz
Xcel Energy
Yes
Yes
Yes
Yes
Yes
Yes
No
Xcel Energy disagrees with the inclusion of the supervising functions in part 1.6 of Section 1 in Attachment A. Supervising
functions in protection schemes provide security for non-power system fault events and are not the principal elements for
scheme operation. Only principal elements should be considered in the requirements of the PRC-023 standard. Functions
such as overcurrent fault detectors provide security in the event of a failed potential source or blown secondary fusing.
Fault detectors must be set below the minimum end-of-zone fault with a single system contingency in effect. It is common
industry practice to set these functions at 60-80% of these minimum fault levels and may necessitate a setting that is
below the Facility Rating of a circuit. Increasing the setpoint of an overcurrent fault detector above the Facility Rating will
limit the coverage of the protection system and may impact the system’s ability to protect the electrical network from
Faults. An alternative is to limit the Facility Rating as allowed in Requirement R1.12. However limiting this Facility Rating
places an arbitrary constraint on the circuit and is not justifiable for a non-principal function. Eliminating the fault detector is
not possible in the case of some microprocessor-based relays and if it is possible, reduces the security of the protective
scheme.
Yes
Group
IRC Standards Review Committee
Ben Li
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise language is crafted
to adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
Some immediate concerns with the proposal include: 1) It is not clear what a “critical facilities list identified by the Regional
Entity” is as specified within the order so addressing the directive is a challenge. This standard is not the appropriate
venue for development or consideration of a critical facilities list. There is a supplemental SAR in process for the Reliability
Coordination project that is to address that topic. 2) Our understanding is that the application of NERC standards is limited
to the BES. Thus, facilities below 100 kV must be included in the Regional Entity definition of BES to be eligible. The
requirements should reflect this. The way the proposed standard reads, one might conclude the PC must test every facility
below 100 kV. This surely can’t be the intent. 3) Furthermore, the directive appears to require some action on the Regional
Entities. From paragraph 60, “We also direct that additions to the Regional Entities’ critical facility list be tested for their
applicability to PRC-023-1 and made subject to the Reliability Standard as appropriate.” It is not clear how this directive is
reflected in the standard to ensure that this work is completed prior to the PC’s performing their assessment for below 200
kV facilities. This standard is not the appropriate venue to determine or revise a critical facilities list, nor is it appropriate for
a Regional Entity to establish such a list. The bottom line is that the changes here are significant enough that they would
benefit from a group of experts reviewing the directives and proposing the precise language that is needed.
No
We believe this directive needs to be addressed by a standards drafting team to ensure the precise language is crafted to
adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise language is crafted
to adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
Additionally, we question if this directive should be addressed in the FAC standards rather than in PRC-023.
No
We do not understand the need for this directive or requirement. A relay that is set to operate at 115% greater than the 15minute rating of the facility does not equate to damage occurring on that facility if operated at that point in 15 minutes.
Furthermore, it does not mean the relay will operate in 15 minutes nor does it mean the operator has only 15 minutes to
take action. In fact, the operator may have less time depending on the time delay set on the relay. It is no different than
any other relay. Usually, the facility will be operated with some buffer so that there is no chance that an entity could trip the
facility due to loading above the relay limit. In fact, the transmission operator should be aware of any relay that might be
the limiting facility so they can operate the facility with some margin of error to ensure they don’t inadvertently cause a
relay operation due to loading.
No
The objective of R4 as written is unclear and does not conform with the results-based concept in that it does not clearly
specify a reliability directive. We suggest removing this requirement altogether as we do not believe this should be an ongoing enforceable requirement. Rather, we think it makes more sense for NERC to use section 1600 of its Rules of
Procedure to request the data. We believe that NERC and the Commission will likely determine that they don’t need to
continually receive this data after reviewing it the first time. Nothing in the directive indicates this must be accomplished
through a standard. If NERC and FERC do identify a continuing need for the data, the standard could be modified at a
later date.
No
We disagree with modifying the requirement until the criteria is identified. Modifying the requirement now presumes the
criteria will have no impact to the requirement. Contrarily, we believe that the criteria may cause some change to the
requirement as well. The criteria in Attachment B along with any necessary modifications to the associated requirement
should be developed by a full standards drafting team. Only the full standards drafting team could identify equally effective
alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise language is crafted
to adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
No
While we agree removing the footnote is straight forward and addresses one Commission directive, we believe the other
directives need to be addressed by a full standards drafting team to ensure the precise language is crafted to adequately
address the directives. Furthermore, we believe only the full standards drafting team could identify equally effective
alternatives to the Commission’s directives as they have made clear they allow in this Order and many others. In
particular, we believe that only a full drafting team could adequately assess if any additional time will be needed to comply
with the standard for sub-100 kV facilities particularly when we consider there are some outstanding issues including a
regional entity’s critical facilities list identified in Question 1. Also, we are unable to assess if the two directives are fully
addressed absent a proposed implementation plan.
No
We largely believe the scope will allow the drafting team to address the directives. However, we request that the scope be
modified to make clear that the drafting team may use equally effective alternatives to address the Commission’s
directives per the Commission in this order and other orders such as Order 693. There is a discrepancy between the
entities listed in the Applicability Section and those checked off in the SAR. The latter indicates that the SAR is also
applicable to the Reliability Coordinator, which we do not believe is appropriate.
No
We are not prepared at this time to offer equally efficient and effective alternatives. Rather, we believe this is the purpose
for convening a full drafting team and that the drafting team should propose their alternatives.
No
We largely believe the scope will allow the drafting team to address the directives. However, we request that the scope be
modified to make clear that the drafting team may use equally effective alternatives to address the Commission’s
directives per the Commission in this order and other orders such as Order 693.
No
We are not aware of any regional variances per se. However, each regional entity has its own definition for BES and this
needs to be considered when addressing sub-100 kV facilities.
No
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
No
However, this response is conditional depending on whether the criteria that will be established within Attachment B (see
R5.1) are reasonable and apply to properly qualified facilities below 200 kV.
Yes
No
The word change meets the strict interpretation of the directive, but it is not necessarily improving the reliability of the
system. Faults are cleared in cycles and transformer damage curves do not start until at least one second.
Yes
No
While achievable, this will not come without effort and does not necessarily improve the reliability of the BES
commensurate with the compliance burden.
No
As noted in Q1 above, a response would be conditional and depend on whether the criteria that will be established within
Attachment B (see R5.1) are reasonable and apply to properly qualified faculties below 200 kV. In addition, the R5
requirement should include wording that limits the scope of the transmission facilities (line and transformer circuits) to be
evaluated to only those transmission facilities that can be tripped by the relay settings subject to requirement R1.
Requirement R5 should also qualify that only the transmission facilities that are “known” to be associated with the relay
settings subject to requirement R1 need to be evaluated. If the SDT wants to better assure that the Planning Coordinator
knows about all of the pertinent transmission facilities, then they should add a requirement that obligates Transmission
Owners, Generator Owners, and Distribution Providers to provide the Planning Coordinator with a list of the transmission
facilities that are associated with the relay setting subject to requirement R1.
No
In Order 733, the Commission cites in footnote 186 (p. 161) the definitions of dependability and security, two components
of reliability for protective relays. The Commission did not recognize that the two tend to be mutually exclusive. Raising
dependability (making sure breakers trip during a fault) can sacrifice some degree of security (tripping more than is
needed). Historically, protection engineers have been biased toward dependability to ensure the safety of people and
equipment. The exclusions allow that to happen. These are contingency scenarios where protective schemes are
compromised. For a second contingency, the dependability is at risk if fast tripping is not employed. By removing the
exclusion, reliability could be negatively jeopardized. For example, an operational decision to open breakers will be
needed for loss of potential. The corollary would be leaving the element in service with fast tripping enabled for a fault until
the loss of potential condition can be diagnosed and corrected.
Yes
No
It addresses the directives per the letter of the order; however, it is not necessarily improving reliability.
Yes
On the topic of ‘adding in’ - listing and evaluating the transmission facilities below 200 kV, we propose the inclusion of
qualifications that prevent the consideration and evaluation of irrelevant facilities (e.g. facilities that are not tripped by the
applicable relay settings).
No
We agree that the topics of generator relay loadability and power swing protective relaying should be referred to in other
separate standards. While we acknowledge that it is in everyone’s best interest to respond to the FERC directives, there
are numerous technical flaws that need to be resolved in their request. Forming a team and spending considerable
resources will not gain industry acceptance to these directives.
No
No
Group
Dominion Electric Market Policy
Mike Garton
No
It depends on what Attachment B (R5.1) requires once it is developed. Without knowledge of the final content developed
for Attachment B, we do not support this.
Yes
No
The requirement is not clear. For example, how do we determine and verify the limiting piece of equipment under fault
conditions? It might be a splice or a jumper. Since the document refers to duration, this seems to apply mainly to
transformer overcurrent relaying which would be for overload protection not fault protection that has no intentional delay.
Yes
Yes
Yes
No
Dominion disagrees with the directive to the ERO to revise section1 to include supervising relays for example, the fault
detectors that we have in electromechanical distance schemes. The impedance relays are set to meet Reliability Standard
PRC-023-1 while the overcurrent fault detector does not trip the transmission line breaker(s) independently of the
impedance relays. Simultaneously meeting full allowance of the line terminal emergency loading limit and providing
adequate sensitivity for detecting line faults with this fault detector will simply not be achievable for many of our lines.
Yes
Yes
No
Yes
No
No
Since there is no question that asks if there are other concerns with this draft, I will add one here….. R2 should be
modified to read “ The Each Transmission Owner, Generator Owner, or and Distribution Provider that uses a circuit
capability with the practical limitations described in Requirement R1, Settings1.6, R1.7, R1.8, R1.9, R1.12, or R1.13 shall
use the calculated circuit capability as the Facility Rating of the circuit and shall forward this information to the Planning
Coordinator, Transmission Operator, and Reliability Coordinator. The burden for acknowledging agreement or specifying
reasons for disagreement should reside with the Planning Coordinator, Transmission Operator, and Reliability
Coordinator. Suggest SDT develop additional requirements similar to those in FAC-008 @ R2 and R3.
Individual
Greg Rowland
Duke Energy
Yes
Yes
No
R1.10 has added the requirement that protection settings can’t expose transformers to fault levels and durations that
exceeds its capability, while at the same time not operate at or below 115% of highest emergency rating. We would argue
that an overcurrent relay cannot be set to satisfy both requirements. A transformer’s through-fault protection curve
(C37.91) begins at 200% of the transformers self-cooled rating. The highest emergency rating is commonly 150% (or
higher) of the transformer’s highest (cooled) rating. Overcurrent relays could not be set to coordinate with both the
damage curve and the overload rating.
Yes
Yes
Paragraph 224 addresses R1.12, requiring documentation and making available a list of facilities that have protective
relays set pursuant to R1.12. Although Order 733 was silent on R1.13, should the new R4 not also apply to R1.13?
No
We don’t have Attachment B yet, and the standard development timeline has the standard being submitted to FERC in
March of 2011, which we believe is an unreasonable timeline.
No
Attachment A has added 1.6 stating “Protective functions that supervise operation of other protective functions” is included
in the standard. We would argue that it is not reasonable to include overcurrent fault detectors used to supervise distance
elements or breaker failure schemes. These relays provide security to the protection scheme, such as for loss of potential
conditions, and do not trip on their own. If these relays would be set per the standard, it would render the schemes
ineffective for many fault conditions. In the case of electromechanical schemes, the supervising relay could be removed
from service which could make the protection scheme misoperate. In the case of microprocessor relays, the supervising
relay is embedded in logic and can’t be removed.
No
Until we see the criteria for Attachment B, we can’t agree that 39 months is sufficient time.
Yes
No
No
• The SAR states that Paragraph 162 is part of Phase I, but the new standard addressing stable power swings is Phase III.
No
No
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR
and an initial set of proposed requirements — Project 2010-13
The Revisions to Relay Loadability for Order 733 SAR Drafting Team thanks all commenters
who submitted comments on the proposed SAR and an initial set of proposed requirements.
The SAR and proposed standard were posted for a 30-day public comment period from
August 19 through September 19, 2010. The stakeholders were asked to provide feedback
on the standards through a special Electronic Comment Form. There were 36 sets of
comments, including comments from more than 88 different people from approximately 36
companies representing 8 of the 10 Industry Segments as shown in the table on the
following pages.
The Standard was posted for an “informal” comment period – the team provided a summary
responses to the comments submitted on the proposed standard (Questions 1-8) and the
SAR was posted for a “formal” comment period - and the team provided detailed responses
to the comments submitted on the SAR (Questions 9-13)
Summary of Changes:
The SDT revised sections 4.1.2 and 4.1.4 for consistency and to refer to facilities “determined by
the Planning Coordinator to comply with this standard.”
The SDT added a new 4.1.3 “Transmission lines operated below 100 kV that Regional Entities
have identified as critical facilities for the purposes of the Compliance Registry and are also
determined by the Planning Coordinator as required to comply with this standard. "
The SDT renumbered old 4.1.3 to 4.1.4.
The SDT renumbered old 4.1.4 to 4.1.5 and reverted the voltage threshold to the original text
consistent with the modification to section 4.1.2.
The SDT added "4.1.6 Transformers with low voltage terminals connected below 100 kV that
Regional Entities have identified as critical facilities for the purposes of the Compliance Registry
and are also determined by the Planning Coordinator as required to comply with this standard."
In response to comments that Requirement R5 is confusing the SDT deleted “to prevent
cascading when protective relay settings limit transmission loadability” from Requirement R5.
Removing this does not change the intent of the requirement.
Commenters indicated for a variety of reasons that the requirement related to out-of-step
blocking added to Requirement R1 is confusing. The SDT agrees and removed out-of-step
blocking from Requirement R1. The requirement pertaining to evaluation of out-of-step
blocking protection has been moved to a separate requirement (now Requirement R2) to more
clearly delineate this requirement from assessment of relay loadability of phase protective relays.
Some commenters indicated that the word “settings” should be replaced throughout R1 when
referring to a part, or sub-requirement of R1. The SDT modified Requirement R1 by replacing
the word “settings” with “criteria.” This is consistent with the main Requirement R1 which in
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of
proposed requirements — Project 2010-13
the presently approved standard (PRC-023-1) refers to sub-requirements R1.1 through R1.13 as
criteria to prevent phase protective relay settings from limiting transmission system loadability.
Some commenters identified an error in the draft standard in criterion 9 in Requirement R1 that
resulted in omitting a phrase contained in the presently approved standard. The SDT modified
criterion 9 in Requirement R1 to reinsert the deleted phrase.
IEEE C37.91 Figure A5 has two components to the thermal damage curve for through-faults: the
“thermal component” begins at 2x the transformer nominal nameplate rating, and seems to be the
root of commenters’ concerns. The “mechanical component” begins at a current equal to the
reciprocal of the twice the transformer impedance. The commenters are correct in their
characterization of the “thermal component” of the transformer damage curve, in that it is not
possible to satisfy the posted PRC-023-2 R1, criterion 10 and also protect the transformer for
currents in this region. Upon careful consideration of FERC Order 733, the SDT revised R1
criterion 10 to reference only the mechanical withstand capability.
Many commenters questioned the inclusion of “limiting piece of equipment” rather than
“transformer”, as the fault-withstand capability of terminal equipment (switches, breakers,
current transformers, etc) may be unavailable. Upon further consideration of FERC Order 733,
the SDT modified criterion 10 by replacing “limiting equipment” with “transformer.”
The SDT modified the wording of R4 as follows. "Each Transmission Owner, Generator Owner,
and Distribution Provider that chooses to utilize Requirement R1 criterion 2 as the basis for
verifying transmission line relay loadability shall provide....” as a result of comments.
The SDT agreed to remove the Regional Entity from the list of entities receiving this information
in Requirement R4.
One commenter noted that the SDT needs to work closely with the Reliability Coordination SDT
(Project 2006-06) which is tasked with defining critical facilities or indentifying criteria for
developing a list of critical facilities. The commenter disagreed with use of the phrase “facilities
that are critical” in this requirement and cautioned that a requirement to create a list of critical
facilities should not be addressed in this standard. The SDT notes that although the phrase
“critical to reliability of bulk electric system” appears in the approved PRC-023-1 and is used in
Order No. 733, the SDT recognizes that use of the same or similar terms in multiple standards
will result in confusion. Use of the phrase “critical to reliability of the Bulk Electric System” in
PRC-023 is intended to have meaning specific to the issue of relay loadability; specifically to
identify facilities, that if they trip due to relay loadability following an initiating event, may
contribute to undesirable system performance similar to what occurred during the August 2003
blackout. The SDT has modified the standard to replace the phrase “critical to the reliability of
the bulk electric system” with “that must comply with this standard.” The SDT believes this will
avoid potential confusion and that reliability will be adequately addressed because the criteria in
PRC-023 - Attachment B identify all facilities that must be subject to this standard to maintain
reliability of the Bulk Electric System.
One commenter noted that Requirement R5, Part 5.1 is unnecessary since the process to use the
criteria in PRC-023 - Attachment B would almost certainly be to simply apply the criteria and
November 1, 2010
2
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of
proposed requirements — Project 2010-13
that requiring documentation of such a process will result in increased paperwork and additional
preparation for an audit without a reliability benefit. The SDT agrees that this part of
Requirement R5 is unnecessary and has removed it from the Standard.
Three-fourths of commenters believe the addition of section 1.6 in PRC-023 - Attachment A is
not an equally efficient and effective method of meeting this directive. More than one-half of
commenters believe that addressing the directive in the proposed manner will have a negative
impact on reliability of the bulk electric system. The SDT agrees that addressing the directive in
the manner proposed in the first posting will have the unintended consequence of impacting the
dependability and security of certain protection systems. The SDT has revised the draft standard
to address the following concerns noted by commenters.
•
More than one-half of commenters noted that the proposed modification would
require overcurrent fault detectors applied to supervise distance (impedance) elements to
meet the relay loadability requirements which would have a detrimental impact on
reliability. Setting these fault detectors to meet PRC-023 would restrict the ability of
some distance elements to trip for end-of-zone faults, particularly on weak source
systems. Eliminating the fault detector to avoid this concern would have the negative
impact of making the protection system susceptible to undesired tripping during close-in
faults on adjacent elements. Some commenters further noted that many microprocessor
relays have inherent overcurrent supervision of impedance elements which cannot be
disabled.
•
Several commenters noted that the standard should apply to protective systems
and not to individual components of protective systems and that compliance should be
based on the ability of the protective system as a whole to meet the performance criteria
established by the standard. Some commenters also noted that a clarification is required
that “protective functions” applies only to those protective relay elements that would
respond to non-fault or load conditions and could issue a direct trip.
•
Some commenters noted their belief that the modification goes well beyond the
Commission’s concern and they proposed alternatives they believe would be equally
effective and efficient approaches to addressing the Commission’s reliability concerns.
In response to these concerns, in particular the negative impact on reliability associated with the
proposed modification, the SDT has modified section 1.6 to include “1.6. Supervisory elements
associated with current based communication assisted schemes where the scheme is capable of
tripping for loss of communications.” The SDT also modified the second bulleted item in
section 2.1 to add the clause, “except as noted in section 1.6 above.”
The SDT agrees with several commenters about the proposed language for Effective Dates and
has changed the language to the following:
5.1.
Requirement R1: the first day of the first calendar quarter after applicable regulatory
approvals, except as noted below.
5.1.1 For the addition to Requirement R1, criterion 10, to set transformer fault
protection relays and transmission line relays on transmission lines terminated only with a
November 1, 2010
3
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of
proposed requirements — Project 2010-13
transformer such that the protection settings do not expose the transformer to fault level and
duration that exceeds its mechanical withstand capability, the first day of the first calendar
quarter 12 months after applicable regulatory approvals.
5.1.2 For supervisory elements as described in Attachment A, section 1.6, the first day
of the first calendar quarter following 24 months after applicable regulatory approvals.
5.2.
Requirements R2 and R3: the first day of the first calendar quarter after applicable
regulatory approvals.
5.3.
Requirements R4 and R5: the first day of the first calendar quarter following 24 months
after applicable regulatory approvals.
5.4.
Requirement R6: the first day of the first calendar quarter 18 months after applicable
regulatory approvals.
5.5.
Requirement R7: the first day of the first calendar quarter after applicable regulatory
approvals.
To address the need for entities to meet the requirements of the standard for facilities identified
by the Planning Coordinator in the future, the SDT added a new requirement (R7).
Several commenters indicated that the directive from P. 224 is missing from the detailed section
of the SAR, but is included in the table in the back of the SAR. This was an error in the SAR and
the SDT has added this directive to the detailed section of the SAR for Phase I. The new
Requirement R5 will support collection of the data necessary for the ERO to address the
directive. The ERO will provide the data upon request, but outside of PRC-023.
http://www.nerc.com/filez/standards/SAR_Project%20201013_Order%20733%20Relay%20Modifiations.html
If you feel that your comment has been overlooked, please 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, you can contact the Vice President and Director of Standards, Herb Schrayshuen, at
609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
November 1, 2010
4
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of
proposed requirements — Project 2010-13
Index to Questions, Comments, and Responses
1.
The Applicability Section (4.1.2 and 4.1.4) and Requirement R5 (previously Requirement R3) have
been modified to address the directive in Paragraph 60 of Order no. 733. Do you agree that this is
an acceptable and effective method of meeting this directive? If not, please explain. ..................... 13
2.
R1 has been modified to address the directive in Paragraph 244 of Order no. 733. Do you agree
that this is an acceptable and effective method of meeting this directive? If not, please explain. .... 19
3.
Requirement R1, setting 10 has been modified to address the directive in Paragraph 203 of Order
no. 733. Do you agree that this is an acceptable and effective method of meeting this directive? If
not, please explain. ........................................................................................................................... 25
4.
Requirement R3 has been added to address the directive in Paragraph 186 of Order no. 733. Do
you agree that this is an acceptable and effective method of meeting this directive? If not, please
explain. .............................................................................................................................................. 29
5.
Requirement R4 has been added to address the directive in Paragraph 224 of Order no. 733. Do
you agree that this is an acceptable and effective method of meeting this directive? If not, please
explain. .............................................................................................................................................. 33
6.
Requirement R5 and part 5.1 (previously Requirement R3 and part 3.1) have been modified to
establish the framework to address the directive in Paragraph 69 of Order no. 733, although the
criteria itself (which will be Attachment B) is still being developed. Do you agree that this is an
acceptable and effective method of meeting this directive considering that Requirement R5 is
establishing the construct to insert the criteria at a future time in the form of Attachment B? If not,
please explain. .................................................................................................................................. 37
7.
Attachment A has been modified to address the directive in Paragraph 264 of Order no. 733. Do
you agree that this is an acceptable and effective method of meeting this directive? If not, please
explain. .............................................................................................................................................. 44
8.
Do you agree that the SDT has addressed the remaining directives: Paragraph 284 to remove the
footnote and Paragraph 283 to modify the implementation plan for sub-100 kV facilities (by revising
the Effective Date section of the standard)? ..................................................................................... 54
9.
Do you agree that the scope of the proposed standards action addresses the directive or
directives? ......................................................................................................................................... 58
10.
Can you identify an equally efficient and effective method of achieving the reliability intent of the
directive or directives? ....................................................................................................................... 63
11.
Do you agree with the scope of the proposed standards action? ..................................................... 68
12.
Are you aware of any regional variances that we should consider with this SAR? .......................... 74
13.
Are you aware of any associated business practices that we should consider with this SAR? ........ 78
November 1, 2010
5
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
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
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Guy Zito
Northeast Power Coordinating Council
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Alan Adamson
NY State Reliability
Council
NPCC 10
2. Gregory Campoli
NY Independent
System Operator
NPCC 2
3. Kurtis Chong
Independent Electricity
System Operator
NPCC 2
4. Sylvain Clermont
Hydro-Quebec
TransEnergie
NPCC 1
5. Gerry Dunbar
NPCC
NPCC 10
Utility Services
NPCC 7
7. Dean Ellis
Dynegy Generation
NPCC 5
8. Brian L. Gooder
Ontario Power
Generation
NPCC 5
6.
Brian EvansMongeon
November 1, 2010
6
10
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9. Kathleen Goodman ISO New England
NPCC 2
10. Chantel Haswell
FPL Group Inc
NPCC 5
11. David Kiguel
Hydro One Networks
NPCC 1
Northeast Utilities
NPCC 1
13. Randy MacDonald
New Brunswick System
Operator
NPCC 2
14. Bruce Metruck
NY Power Authority
NPCC 6
15. Lee Pedowicz
NPCC
NPCC 10
16. Robert Pellegrini
The United Illuminating
Company
NPCC 1
17. Si Truc Phan
Hydro-Quebec
TransEnergie
NPCC 1
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Peter Yost
Consolidated Edison of
New York
NPCC 3
Dominion Resources
NPCC 5
12.
Michael R.
Lombardi
21. Mike Garton
2.
Group
Richard Kafka
Additional Member
Additional
Organization
Pepco Holdings, Inc - Affiliates
Region
3
4
5
6
7
8
9
1, 3, 5, 6
Segment
Selection
1. Alvin Depew
Potomac Electric Power
RFC
Company
1
2. Carl Kinsley
Delmarva Power & Light
RFC
Company
1
3. Evan Sage
Potomac Electric Power
RFC
Company
1
November 1, 2010
2
7
10
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Rob Wharton
3.
Group
Atlantic City Electric
Kenneth D. Brown
RFC
PSEG Power
RFC
5
2. Jim Hebson
PSEG ER &T
NPCC
6
3. Scott Slickers
PSEG Connecticut
NPCC
5
4. Jerzy Slusarz
Odessa power Partners
ERCOT
5
5. Jim Hubertus
PSEG
RFC
1,3
Denise Koehn
Bonneville Power Administration
Additional Member Additional Organization Region
1. Dean Bender
5.
Group
BPA
Doug Hohlbaugh
WECC
6.
Group
FE
Ben Li
7
8
9
1, 3, 5, 6
1, 3, 5, 6
1, 3, 4, 5, 6
Segment
Selection
1, 3, 4, 5, 6
IRC Standards Review Committee
Additional Member Additional Organization Region
2
Segment
Selection
1. Bill Phillips
MISO
MRO
2
2. Patrick Brown
PJM
RFC
2
3. James Castle
NYISO
NPCC
2
November 1, 2010
6
1
FirstEnergy
RFC
5
Segment
Selection
Additional Member Additional Organization Region
1. Sam Ciccone
4
Segment
Selection
1. Dave Murray
Group
3
1
PSEG Companies
Additional Member Additional Organization Region
4.
2
8
10
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Greg Van Pelt
CAISO
WECC
2
5. Charles Yeung
SPP
SPP
2
6. Steve Myers
ERCOT
ERCOT
2
7. Mark Thompson
AESO
WECC
2
7.
Group
Carol Gerou
MRO's NERC Standards Review
Subcommittee
Additional Member Additional Organization Region
Omaha Public Utility
District
MRO
1,3,5,6
2. Chuck Lawrence
American Transmission
Company
MRO
1
3. Tom Webb
WPS Corp
MRO
3,4,5,6
4. Jason Marshall
Midwest ISO
MRO
2
5. Jodi Jenson
Western Area Power
Admin.
MRO
1,6
6. Ken Goldsmith
Alliant Energy
MRO
4
7. Dave Rudolph
Basin Electric Power
Cooperative
MRO
1,3,5,6
8. Eric Ruskamp
Lincoln Electric System
MRO
1,3,5,6
9. Joseph Knight
Great River Energy
MRO
1,3,5,6
10. Joe DePoorter
Madison Gas & Electric
MRO
3,4,5,6
11. Scott Nickels
Rochester Public Utilities MRO
4
12. Terry Harbour
Mid American Energy
Co.
1,3,5,6
November 1, 2010
3
4
5
6
7
8
9
10
Segment
Selection
1. Mahmood Safi
MRO
2
9
10
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Group
8.
Mike Garton
Dominion Electric Market Policy
Additional Member Additional Organization Region
2
3
4
5
6
Dominion Resource
Services
NPCC
5
2. Louis Slade
Dominion Resource
Services
SERC
6
9
1, 3, 5, 6
9.
Individual
Brent Ingebrigtson
E.ON U.S. LLC
X
X
X
X
10.
Individual
William Gallagher
Transmission Access Policy Study Group
X
X
X
X
Individual
Jana Van Ness, Director
Regulatory Compliance
Arizona Public Service Company
X
X
X
X
12.
Individual
Andrew Z. Pusztai
American Transmission Company
X
13.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
14.
Individual
Andy Tillery
Southern Company
X
X
15.
Individual
Bill Middaugh
TSGT System Planning Group
X
16.
Individual
Gene Henneberg
NV Energy
X
17.
Individual
Steve Wadas
NPPD
X
18.
Individual
Joylyn Faust
Consumers Energy
19.
Individual
Jonathan Meyer
Idaho Power - System Protection
November 1, 2010
8
Segment
Selection
1. Michael Gildea
11.
7
X
X
X
X
X
X
X
X
X
10
10
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
4
5
Individual
Michael Gammon
Kansas City Power & Light
21.
Individual
Dan Rochester
Independent Electricity System Operator
22.
Individual
Bill Miller
ComEd
23.
Individual
Kasia Mihalchuk
Manitoba Hydro
24.
Individual
Brian Evans-Mongeon
Utility Services
25.
Individual
Tribhuwan Choubey
Southern California Edison
26.
Individual
Dale Fredrickson
Wisconsin Electric
27.
Individual
Kathleen Goodman
ISO New England Inc.
28.
Individual
Robert Ganley
Long Island Power Authority
X
29.
Individual
Kirit Shah
Ameren
X
X
X
X
30.
Individual
Thad Ness
American Electric Power
X
X
X
X
31.
Individual
Michael Moltane
ITC Holdings
X
32.
Individual
Not indicated
Not Indicated
Individual
Laura Zotter, Steve
Myers
ERCOT ISO
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
34.
November 1, 2010
X
X
X
X
X
X
X
X
6
20.
33.
X
3
7
8
9
X
X
X
X
X
X
X
X
X
X
X
11
10
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
35.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
36.
Individual
Greg Rowland
Duke Energy
X
X
X
X
November 1, 2010
7
8
9
12
10
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
1. The Applicability Section (4.1.2 and 4.1.4) and Requirement R5 (previously Requirement R3) have been modified to address the
directive in Paragraph 60 of Order no. 733. Do you agree that this is an acceptable and effective method of meeting this directive? If
not, please explain.
Summary Consideration:
Several commenters wanted to know what is meant by “critical to the reliability of the Bulk Electric System (BES)”. The SDT notes that although
the phrase “critical to reliability of bulk electric system” appears in the approved PRC-023-1 and is used in Order No. 733, the SDT recognizes that
use of the same or similar terms in multiple standards will result in confusion. Use of the phrase “critical to reliability of the Bulk Electric System” in
PRC-023 is intended to have meaning specific to the issue of relay loadability; specifically to identify facilities, that if they trip due to relay
loadability following an initiating event, may contribute to undesirable system performance similar to what occurred during the August 2003
blackout. The SDT has modified the standard to replace the phrase “critical to the reliability of the bulk electric system” with “that must comply
with this standard.” The SDT believes this will avoid potential confusion and that reliability will be adequately addressed because the criteria in
Attachment B identify all facilities that must be subject to this standard to maintain reliability of the Bulk Electric System.
Several commenters indicated that the phrase "low voltage terminals" is open to interpretation. This term is part of the existing standard and not
included in the scope of the SAR; however, Attachment B will clarify the criteria to determine which facilities must comply with the standard.
The SDT revised sections 4.1.2 and 4.1.4 for consistency and to refer to facilities “determined by the Planning Coordinator to comply with this
standard.”
Commenters indicated that they did not believe the standard should apply to facilities below 100 kV; however, in Order 733, NERC was directed to
apply PRC-023 to facilities below 100 kV, as well as 100 kV to 200 kV, and to provide criteria to establish which of those facilities to which PRC023 was to apply. As noted with this posting, the criteria was posted for public comment and is intended to be included with the next posting of
this standard.
Commenters indicated that they did not believe the standard should apply to facilities below 100 kV; however, in Order 733, NERC was directed to
apply PRC-023 to facilities below 100 kV, as well as 100 kV to 200 kV, and to provide criteria to establish those facilities to which PRC-023 was to
apply. As noted with this posting, the criteria were posted for public comment and will be included with the next posting of this standard.
Commenters were reluctant to offer a firm response to the proposed modifications without reviewing the proposed criteria in Attachment B. As
noted with this posting, the criteria were posted for public comment and will be included with the next posting of this standard.
The SDT reverted the voltage threshold in section 4.1.2 to the original text because commenters suggested that only facilities below 100 kV that
are on the Regional Entity’s list should be subjected to the criteria in Attachment B, while all facilities between 100 kV and 200 kV should be
subject to the criteria in Attachment B.
The SDT added a new 4.1.3 “Transmission lines operated below 100 kV that Regional Entities have identified as critical facilities for the purposes
of the Compliance Registry and are also determined by the Planning Coordinator as required to comply with this standard. "
The SDT renumbered old 4.1.3 to 4.1.4.
The SDT renumbered old 4.1.4 to 4.1.5 and reverted the voltage threshold to the original text consistent with the modification to section 4.1.2.
November 1, 2010
13
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
The SDT added "4.1.6 Transformers with low voltage terminals connected below 100 kV that Regional Entities have identified as critical facilities
for the purposes of the Compliance Registry and are also determined by the Planning Coordinator as required to comply with this standard."
In response to comments that Requirement R5 is confusing the SDT deleted “to prevent cascading when protective relay settings limit
transmission loadability” from Requirement R5. Removing this term does not change the intent of the requirement.
Commenters indicated that the modifications to the applicability section may have the unintended consequence of increasing the burden on
Distribution Providers (DPs) with no reliability benefit; however, 1) the proposed modifications are directed changes and 2) the DPs would only be
affected if the Planning Coordinators apply the criteria in Attachment B and determine that the DPs have a facility that must comply with the
standard.
One comment indicated that Requirement R1’s VRF “High” has no justification. The SDT thinks that the revision to Requirement R1 to include
below 200 kV facilities should have no impact on the VRF assignment. If a facility is designated as a facility critical to the reliability of the BES the
impact on reliability is High regardless of the voltage level.
Some commenters noted the Reliability Coordinator (RC) is included in the SAR, but the SDT did not include the RC in the applicability section of
the standard. The SDT notes that the SAR contains a list of entities that could potentially be included in the standard, but it is not necessary that
the SDT include each entity in the applicability section of the standard.
Organization
Yes or No
Question 1 Comment
Northeast Power Coordinating
Council
No
The revised Applicability paragraph 4.1.4 reads:4.1.4 Transformers with low voltage terminals connected
below 200 kV as designated by the Planning Coordinator as critical to the reliability of the Bulk Electric
System (BES). The phrase "low voltage terminals" is open to interpretation because some transformers have
low-voltage terminals which are do not supply a load, or supply only local substation AC service. Sometimes
the transformer is a 3-winding bank, with the low-voltage winding not used, or the low-voltage winding is used
solely to provide additional grounding, as in the case of a delta-connected tertiary, unconnected to any load.
Is this what is intended? If yes, then they should remove the ambiguity. Note the phrase "low-voltage"
terminal was part of Revision 1 and is unchanged by Revision 2, however, the new applicability to below 200
kV raises the new concern. What is meant by “critical to the reliability of the Bulk Electric System (BES)”?
Also, replace “as designated” with “and designated”.Suggest 4.1.4 be revised to read:4.1.4 Transformers with
low voltage terminals connected below 200 kV and designated by the Planning Coordinator as Critical Assets.
Clarification is needed to explain the disconnect between FERC’s “sub-100kV”, and the proposed “below
200kV”.
IRC Standards Review
Committee
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise
language is crafted to adequately address the directive. Furthermore, we believe only the full standards
drafting team could identify equally effective alternatives to the Commission’s directives as they have made
November 1, 2010
14
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 1 Comment
clear they allow in this Order and many others. Some immediate concerns with the proposal include: 1) It is
not clear what a “critical facilities list identified by the Regional Entity” is as specified within the order so
addressing the directive is a challenge. This standard is not the appropriate venue for development or
consideration of a critical facilities list. There is a supplemental SAR in process for the Reliability
Coordination project that is to address that topic. 2) Our understanding is that the application of NERC
standards is limited to the BES. Thus, facilities below 100 kV must be included in the Regional Entity
definition of BES to be eligible. The requirements should reflect this. The way the proposed standard reads,
one might conclude the PC must test every facility below 100 kV. This surely can’t be the intent.3)
Furthermore, the directive appears to require some action on the Regional Entities. From paragraph 60, “We
also direct that additions to the Regional Entities’ critical facility list be tested for their applicability to PRC-0231 and made subject to the Reliability Standard as appropriate.” It is not clear how this directive is reflected in
the standard to ensure that this work is completed prior to the PC’s performing their assessment for below
200 kV facilities. This standard is not the appropriate venue to determine or revise a critical facilities list, nor
is it appropriate for a Regional Entity to establish such a list. The bottom line is that the changes here are
significant enough that they would benefit from a group of experts reviewing the directives and proposing the
precise language that is needed.
MRO's NERC Standards Review
Subcommittee
No
However, this response is conditional depending on whether the criteria that will be established within
Attachment B (see R5.1) are reasonable and apply to properly qualified facilities below 200 kV.
Dominion Electric Market Policy
No
It depends on what Attachment B (R5.1) requires once it is developed. Without knowledge of the final content
developed for Attachment B, we do not support this.
E.ON U.S. LLC
No
E.ON U.S. believes that it is confusing the way R5 is currently written due to the last part of the sentence “ ...
when protective relay settings limit transmission loadability.” There is a need for clarification on how this is to
be applied. As an alternative: If the directive is to have the Planning Coordinator determine which sub-100kV
facilities should be subject to the Reliability Standard; R5 should be modified to read “Each Planning
Coordinator shall apply the criteria in Attachment B to determine which of the facilities in its Planning
Coordinator Area are to be included in 4.1.2 and 4.1.4.”
Transmission Access Policy
Study Group
No
The modifications to the Applicability Section meet the FERC directive but have the unacceptable unintended
consequence of increasing the burden on DPs with no reliability benefit. Specifically, the modifications make
all DPs potentially subject to PRC-023, thus requiring all DPs to incur costs to determine whether the
standard is applicable to them. Because PRC-023 should never be applicable to a DP in its capacity as a DP
(as opposed to a TO that also happens to be registered as a DP), as explained in TAPS’ response to question
6 below, the SDT should simply remove DPs from the Applicability section to prevent the significant potential
November 1, 2010
15
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 1 Comment
for confusion and unnecessary costs.
Arizona Public Service Company
No
Agree with the content. However, there is no justification for VRF to be High for the circuits lower than 200 kV.
Kansas City Power & Light
No
Agree the changes for 4.1.2 and 4.1.4 are effective in meeting the “add in” approach in the FERC order.
However, do not agree with the approach in R5. R5 proposes to establish the criteria by which Reliability
Coordinators will determine facilities critical to the reliability of the BES. There are a variety of differing, and
often complex, operating conditions that dictate the need for transmission facilities. The TPL standards
require extensive studies of the transmission system be performed under steady state and dynamic
conditions to understand and identify sensitive areas of the transmission system and enable Reliability
Coordinators to identify flowgates in their respective regions. In light of the Reliability Coordinators
awareness of transmission sensitivities through these studies, it seems unnecessary to dictate to the
Reliability Coordinators additional criteria.
Utility Services
No
The modifications to the Applicability Section meet the FERC directive but have the unacceptable unintended
consequence of increasing the burden on DPs with no reliability benefit. Specifically, the modifications make
all DPs potentially subject to PRC-023, thus requiring all DPs to incur costs to determine whether the
standard is applicable to them. Because PRC-023 should never be applicable to a DP in its capacity as a DP
(as opposed to a TO that also happens to be registered as a DP), as explained in our response to question 6
below, the SDT should simply remove DPs from the Applicability section to prevent the significant potential for
confusion and unnecessary costs.
ISO New England Inc.
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise
language is crafted to adequately address the directive. Furthermore, we believe only the full standards
drafting team could identify equally effective alternatives to the Commission’s directives as they have made
clear they allow in this Order and many others. Some immediate concerns with the proposal include: 1) Our
understanding is that the application of NERC standards is limited to the BES. Thus, facilities below 100 kV
must be included in the Regional Entity definition of BES to be eligible. The requirements should reflect this.
The way the proposed standard reads, one might conclude the PC must test every facility below 100 kV. This
surely can’t be the intent.2) Furthermore, the directive appears to require some action on the Regional
Entities. From paragraph 60, “We also direct that additions to the Regional Entities’ critical facility list be
tested for their applicability to PRC-023-1 and made subject to the Reliability Standard as appropriate.” It is
not clear how this directive is reflected in the standard to ensure that this work is completed prior to the PC’s
performing their assessment for below 200 kV facilities. The bottom line is that the changes here are
significant enough that they would benefit from a group of experts reviewing the directives and proposing the
precise language that is needed.
November 1, 2010
16
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 1 Comment
Long Island Power Authority
No
There appears to be a disconnect between FERC’s “sub 100 kV” and proposed “below 200 kV” revision in the
Applicability Section. LIPA seeks clarification on this. Also, by whom and by which method will the criticality of
the substations be ascertained?
Ameren
No
Attachment B as mentioned in R5 is not available for review.
American Electric Power
No
AEP understands the intent of the FERC Order (Paragraph 60) to address the sub-100 KV facilities only if
they are associated with critical facilities above 100 KV. The applicability and the associated requirements
should be reworded to ensure that the Planning Coordinator does not have to identify critical facilities below
100 KV.
Southern California Edison
No
Applicability clause 4.12 and 4.14 - Formulating a consistent methodology test to determine for a sub 200KV
facility by the Planning Coordinator is quite an uphill task keeping in view the different circuit configuration
different utilities may have. It is best left alone to each utility to determine the facilities which can be a
candidate for inclusion as a bulk power system. The current risk based assessment criteria to determine bulk
power facility should be continued.
American Transmission
Company
Yes
However, this affirmative response is conditional depending on whether the criteria that will be established
within Attachment B (see R5.1) are reasonable and apply to properly qualified facilities below 200 kV.
Pepco Holdings, Inc - Affiliates
Yes
While philosophically we do not agree that this standard should apply to facilities below 100kV (i.e. facilities
that are not defined as BES facilities) we believe that as long as a sound engineering methodology is
developed and applied uniformly to identify those facilities critical to the reliability of the BES, then the revised
wording is acceptable. Our response, however, is qualified based on being granted an opportunity to
comment and vote on the methodology once it is developed.
NPPD
Yes
As long as you keep BES.
Independent Electricity System
Operator
Yes
We agree with the Applicability Section and the modification to R5. Note that there is a discrepancy between
the entities listed in the Applicability Section and those checked off in the SAR. The latter indicates that the
SAR is also applicable to the RC, which we do not believe is required.
Bonneville Power Administration
Yes
FirstEnergy
Yes
November 1, 2010
17
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
PacifiCorp
Yes
Southern Company
Yes
TSGT System Planning Group
Yes
NV Energy
Yes
Consumers Energy
Yes
Idaho Power - System Protection
Yes
ComEd
Yes
Manitoba Hydro
Yes
ITC Holdings
Yes
Question 1 Comment
Yes
Xcel Energy
Yes
Duke Energy
Yes
Wisconsin Electric
November 1, 2010
No comment
18
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
2.
R1 h a s b e e n m o d ifie d to a d d re s s th e d ire c tive in P a ra g ra p h 244 o f Ord e r n o . 733. Do yo u a g re e th a t th is is a n a c c e p ta b le a n d
e ffe c tive m e th o d o f m e e tin g th is d ire c tive ? If n o t, p le a s e e xp la in .
Summary Consideration:
Commenters indicated for a variety of reasons that the requirement related to out-of-step blocking added to Requirement R1 is confusing. The
SDT agrees and removed out-of-step blocking from Requirement R1. The requirement pertaining to evaluation of out-of-step blocking protection
has been moved to a separate requirement (now Requirement R2) to more clearly delineate this requirement from assessment of relay loadability
of phase protective relays.
One commenter noted that it is not clear how loadability requirements apply during fault conditions. In the new requirement the SDT clarified that
the evaluation must ensure that out-of-step blocking elements allow tripping of phase protective relays for faults that occur during the loading
conditions used to verify transmission line relay loadability per Requirement R1.
Some commenters indicated that the word “settings” should be replaced throughout R1 when referring to a part, or sub-requirement of R1. The
SDT modified Requirement R1 by replacing the word “settings” with “criteria.” This is consistent with the main Requirement R1 which in the
presently approved standard (PRC-023-1) refers to sub-requirements R1.1 through R1.13 as criteria to prevent phase protective relay settings
from limiting transmission system loadability.
Some commenters identified an error in the draft standard in criterion 9 in Requirement R1 that resulted in omitting a phrase contained in the
presently approved standard. The SDT modified criterion 9 in Requirement R1 to reinsert the deleted phrase.
One commenter noted that this directive needs to be addressed by a full standard drafting team to adequately address this directive and identify
equally effective alternatives to the Commission’s directives. The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been
reconvened to address the directed modifications to the standard. The SDT believes that the issues indentified in Order No. 733 can be
addressed adequately by this SDT with industry stakeholder input through the NERC Standard Development Process.
One commenter indicated that they agreed with the inclusion of Section 2 of Attachment A in the Requirement Section but the proposed
modification may not fully meet the directive that the additional requirement is assigned a VRF and VSL. This may require the creation of a
separate main requirement rather than simply including the condition as a part of a requirement. However, the VRFs and VSLs are associated
directly with R1, and thus all its’ subparts/criteria. Therefore, as Attachment A is referenced as being part of R1, the R1 VRFs and VSLs
automatically apply.
Organization
Northeast Power Coordinating
Council
Yes or No
No
Question 2 Comment
1. The last sentence in R1 should be revised to read: Each Transmission Owner, Generator Owner, and
Distribution provider shall evaluate relay loadability at 0.85 per unit voltage, and a power factor angle of
30 degrees.
2. Settings are to be applied as listed following:”Setting” should be replaced throughout R1 when referring to
November 1, 2010
19
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 2 Comment
a part, or sub-requirement of R1. The terminology should be whatever is preferred by
NERC.Requirement R1, Parts 7, 8 and 9:
3. Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system configuration” with "under any
system condition:" 7. Set transmission line relays applied at the load center terminal, remote from
generation stations, so they do not operate at or below 115% of the maximum current flow from the load
to the generation source under any system condition.8. Set transmission line relays applied on the bulk
system-end of transmission lines that serve load remote to the system so they do not operate at or below
115% of the maximum current flow from the system to the load under any system condition.9. Set
transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk
system so they do not operate at or below 115% of the maximum current flow from the [___] to the under
any system condition. [Brackets added, also see further comment on missing wording following]This
phrase "under any system configuration" could be construed as being too all-inclusive, as one could
postulate multiple events, e.g., simultaneous outages, which however unlikely could permit power flows in
a direction for which the system was not originally designed. As with the second comment below, the
phrase "under any system condition" was part of Revision 1 and is unchanged by Revision 2, however,
the new applicability to below 200 kV creates the new concern.
4. Requirement 1, part 9:As currently written, Requirement 1, part 9 states:9. Set transmission line relays
applied on the load-end of transmission lines that serve load remote to the bulk system so they do not
operate at or below 115% of the maximum current flow from the [___] to the under any system
configuration. [Brackets added]Some words are missing. The brackets have been added above to show
one place where at least some of the needed wording may be missing. A rewrite is necessary in order for
this sentence to make any sense.
Pepco Holdings, Inc - Affiliates
No
The revised wording in paragraph R1 regarding out-of-step blocking schemes is confusing. We suggest
rewording the paragraph by splitting the sentence as follows: ...while maintaining reliable protection of the
BES for all fault conditions. Use of out-of-step blocking schemes shall be evaluated to ensure that they do
not block tripping for faults during the loading conditions defined within these requirements.
Bonneville Power Administration
No
The modified Requirement R1 requires that one of the 13 criteria be used to prevent out-of-step blocking
schemes from blocking tripping for fault conditions. The problem is that the 13 criteria are only related to
loading conditions, and it is not clear how they would be applied to prevent out-of-step blocking schemes from
blocking a trip during a fault, or if it is even possible to use these criteria for this purpose. The modified
Requirement R1 requires actions that are ambiguous and we cannot support it as written.
IRC Standards Review
No
We believe this directive needs to be addressed by a standards drafting team to ensure the precise language
is crafted to adequately address the directive. Furthermore, we believe only the full standards drafting team
November 1, 2010
20
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Committee
Question 2 Comment
could identify equally effective alternatives to the Commission’s directives as they have made clear they allow
in this Order and many others.
E.ON U.S. LLC
No
Since correct operation of the out-of-step blocking feature is integral to and only a single component of a
successful trip operation (for fault conditions), this is already included in the requirement to “maintain reliable
protection of the BES for all fault conditions” and does not have to be mentioned separately. Also, R1 (as
written) may be interpreted to require one of the settings (1 through 13) to be used to prevent out-of-step
blocking schemes from blocking tripping for fault conditions. But Settings 1 thru 13 do not address specific
setting criteria for out-of-step blocking.
TSGT System Planning Group
No
We suggest that the added phrase be removed from R1 and a new requirement created. Suggested wording
is “Protection Systems that block for stable swings or out-of-step conditions shall be evaluated to ensure that
appropriate tripping will occur for in-section faults that occur during the condition. Some additional delay may
be required and is acceptable to ensure that the appropriate tripping occurs.”
NV Energy
No
The proposed phrase added to R1 is only a start: “. . . , and to prevent its out-of-step blocking schemes
from blocking tripping for fault conditions.” The specific wording proposed by the Drafting Team may
prevent using the out-of-step-block functions of many modern and widely used line protection relays (e.g.
SEL-321 and later models and GE-UR). These relay’s OSB function first blocks the protection elements from
tripping, then uses a short delay and/or other information to determine whether the observed and perhaps
evolving condition really represents a fault, in which case the blocking is reset to allow tripping. Such a
block/reset operation is the most common technology available and would appear to lie within the intent of
FERC in paragraph 244, but could be excluded by the presently proposed language. If an out-of-step
blocking phrase is inserted in Requirement R1 of the standard, the emphasis should be modified to read
something like: “. . . , and its out-of-step blocking schemes must allow tripping for fault conditions.”
This
standard should also require that out-of-step blocking settings coordinate with both the loadability and
protection characteristics.
The out-of-step blocking references would seem to fit best within the
organization of the standard if included as a new Requirement R2 (FERC’s paragraph 244 anticipates “. . . an
additional Requirement . . .”), with re-numbering of the proposed R2 through R5 as R3 through R6. The
essential content of the DT’s proposed phrase in R1 would be included as part of this new R2, which would
read something like:R2. Each Transmission Owner, Generator Owner, and Distribution Provider shall
evaluate its out-of-step blocking schemes to ensure that both: R2.1. Out-of-step blocking schemes allow
tripping for fault conditions during the loading conditions determined from Requirement R1 parts R1.1 through
R1.13. R2.2. Relay out-of-step blocking settings coordinate with both the relay loadability characteristic
determined from Requirement R1 parts R1.1 through R1.13 and the facility protection settings. The Measure
for this proposed R2 would read something like:M2.The Transmission Owner, Generator Owner, and
Distribution Provider with out-of-step blocking schemes shall have evidence such as spreadsheets or
November 1, 2010
21
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 2 Comment
summaries of calculations to show that each of its out-of-step blocking schemes is set to comply with the
requirements of R2.1 and R2.2. The VSL for R1 would not change; specifically it would not reference out-ofstep blocking schemes. The VSL for this proposed new R2 would be “Severe” and read something like:A
Transmission Owner, Generator Owner, or Distribution Provider did not allow its out-of-step blocking schemes
to trip for fault conditions during the loading conditions determined from Requirement R1 parts R1.1 through
R1.13. ORA Transmission Owner, Generator Owner, or Distribution Provider did not coordinate operation of
its out-of-step blocking schemes with both the relay loadability characteristic determined from Requirement
R1 parts R1.1 through R1.13 and the facility protection settings.
Independent Electricity System
Operator
No
We agree with the inclusion of Section 2 of Attachment A in the Requirement Section but the proposed
modification may not fully meet the directive that the additional requirement is assigned a VRF and VSL. This
may require the creation of a separate main requirement rather than simply including the condition as a part
of a requirement.
Southern California Edison
No
Requirement R1.7, R1.8, R1.13 do not provide a clear guideline on generators connected to the load center
on Radial basis, where load current into the generators ( forward direction current seen by the relay) is just an
auxiliary load and insignificant compared to the transmission line rating.
ISO New England Inc.
No
Requirement R1, Parts 7, 8 and 9:Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system
configuration” with "under any system condition:" 7. Set transmission line relays applied at the load center
terminal, remote from generation stations, so they do not operate at or below 115% of the maximum current
flow from the load to the generation source under any systemcondition.8. Set transmission line relays applied
on the bulk system-end of transmission lines that serve load remote to the system so they do not operate at
or below 115% of the maximum current flow from the system to the load under any systemcondition.9. Set
transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk
system so they do not operate at or below 115% of the maximum current flow from the [___] to the under any
system condition. [Brackets added, also see further comment on missing wording following]This phrase
"under any system configuration" could be construed as being too all-inclusive, as one could postulate
multiple events, e.g., simultaneous outages, which however unlikely could permit power flows in a direction
for which the system was not originally designed. As with the second comment below, the phrase "under any
system condition" was part of Revision 1 and is unchanged by Revision 2, however, the new applicability to
below 200 kV creates the new concern.Requirement 1, part 9:As currently written, Requirement 1, part 9
states:9. Set transmission line relays applied on the load-end of transmission lines that serve load remote to
the bulk system so they do not operate at or below 115% of the maximum current flow from the [___] to the
under any system configuration. [Brackets added]
Some words are missing. The brackets have been
added above to show one place where at least some of the needed wording may be missing. A rewrite is
November 1, 2010
22
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 2 Comment
necessary in order for this sentence to make any sense.
Long Island Power Authority
No
Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system configuration” with "under any
system condition:" This phrase "under any system configuration" could be construed as being too allinclusive, as one could postulate multiple events, e.g., simultaneous outages, which however unlikely could
permit power flows in a direction for which the system was not originally designed. Requirement 1, part 9:As
currently written, Requirement 1, part 9 states:9. Set transmission line relays applied on the load-end of
transmission lines that serve load remote to the bulk system so they do not operate at or below 115% of the
maximum current flow from the [___] to the under any system configuration. [Brackets added]
Some words
are missing. The brackets have been added above to show one place where at least some of the needed
wording may be missing. A rewrite is necessary in order for this sentence to make any sense.
ITC Holdings
No
The proposed wording seems out of place in this requirement and is not clear as how it is being applied to
subrequirements 1 - 13
NPPD
Yes
I'm ok with that. It could have easily been left in Attachment A. You didn't bring the other language from
attachment A to R1. You could of created a separate requirement for OOS, but I'm fine with moving it to R1.
FirstEnergy
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Dominion Electric Market Policy
Yes
Arizona Public Service Company
Yes
American Transmission
Company
Yes
Southern Company
Yes
Consumers Energy
Yes
Idaho Power - System Protection
Yes
November 1, 2010
23
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Kansas City Power & Light
Yes
ComEd
Yes
Manitoba Hydro
Yes
Ameren
Yes
American Electric Power
Yes
Question 2 Comment
Yes
Xcel Energy
Yes
Duke Energy
Yes
Wisconsin Electric
November 1, 2010
No comment
24
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
3.
Requirement R1, setting 10 has been modified to address the directive in Paragraph 203 of Order no. 733. Do you agree that this is
an acceptable and effective method of meeting this directive? If not, please explain.
Summary Consideration:
Many commenters were concerned about the coordination with the relay loadability requirements of R1 – criterion 1.10 with the transformer
damage curve as expressed in IEEE C37.91 Figure A4, which defines transformer through-fault withstand capability as starting at twice the
nominal nameplate rating; R1, criterion 1.10 requires that loadability be 150% of the maximum nameplate (which itself is often 1.66 times the
nominal nameplate – resulting in loadability of over 2.5 times the nominal nameplate rating).
IEEE C37.91 Figure A5 has two components to the thermal damage curve for through-faults: the “thermal component” begins at 2x the
transformer nominal nameplate rating, and seems to be the root of commenters’ concerns. The “mechanical component” begins at a current equal
to the reciprocal of the twice the transformer impedance. The commenters are correct in their characterization of the “thermal component” of the
transformer damage curve, in that it is not possible to satisfy the posted PRC-023-2 R1, criterion 10 and also protect the transformer for currents in
this region. Upon careful consideration of FERC Order 733, the SDT revised R1 criterion 10 to reference only the mechanical withstand capability.
Many commenters questioned the inclusion of “limiting piece of equipment” rather than “transformer”, as the fault withstand capability of terminal
equipment (switches, breakers, current transformers, etc) may be unavailable. Upon further consideration of FERC Order 733, the SDT modified
criterion 10 by replacing “limiting equipment” with “transformer.”
Organization
Yes or No
Question 3 Comment
Pepco Holdings, Inc - Affiliates
No
It would appear that this requirement has already been addressed in the R1 introductory paragraph by the
phrase “...while maintaining reliable protection of the BES for all fault conditions.” How could one “maintain
reliable protection of the BES” if relays are set with operating times that result in equipment being exposed to
fault levels and durations that exceed their capability. This introductory requirement to provide reliable fault
protection applies to all sub requirements not just to section 10 (old R1.10). As such, the added language in
section 10 seems redundant and superfluous. Secondly, if the proposed language were to remain in section
10, why is the term “limiting piece of equipment” used and not just “transformer”? It appears the major
concerns related to the comments contained in Order 733 were around exceeding transformer fault
level/duration limitations. If that is the concern, why not just use the phrase “do not expose the transformer to
fault levels and durations that exceeds its capability”
Bonneville Power Administration
No
In some cases, Section 10 of Requirement R1 would be impossible to meet. For example, a 150/200/250
MVA, OA/FOA1/FOA2 transformer is required by Section 10 to have its protection set so that it doesn’t
operate at or below 150% of the maximum transformer rating of 250MVA, or 1.5x250=375MVA. The modified
Section 10 would also require that the protection not expose the transformer to a fault level and duration that
November 1, 2010
25
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 3 Comment
exceeds its capability. According to IEEE C37.91, a through-fault of two times the transformers base rating,
2x150=300MVA, will be damaging to the transformer. For this particular transformer, which is not unusual,
Requirement R1, Section 10, requires the protection to operate for through faults of 300MVA or greater, but
not operate for loads of 375MVA or less. It is impossible to simultaneously meet both of these conditions, so
Section 10 is unacceptable. One possible way to correct the problem is to change the requirement so that the
protection does not operate below 200% of the transformer base rating. This would allow the protection to
meet IEEE C37.91 for through-faults and still allow overloading of the transformer.
FirstEnergy
No
Although it is true that the FERC directive specifically states "limiting piece of equipment" their reasons and
justifications all involve transformers. We propose replacing "limiting piece of equipment" with "transformer"
would meet the FERC's reliability concern as well as provide clarity to applicable entities. We believe this is
an equally effective means of meeting the directive.
IRC Standards Review
Committee
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise
language is crafted to adequately address the directive. Furthermore, we believe only the full standards
drafting team could identify equally effective alternatives to the Commission’s directives as they have made
clear they allow in this Order and many others. Additionally, we question if this directive should be addressed
in the FAC standards rather than in PRC-023.
MRO's NERC Standards Review
Subcommittee
No
The word change meets the strict interpretation of the directive, but it is not necessarily improving the
reliability of the system. Faults are cleared in cycles and transformer damage curves do not start until at least
one second
Dominion Electric Market Policy
No
The requirement is not clear. For example, how do we determine and verify the limiting piece of equipment
under fault conditions? It might be a splice or a jumper. Since the document refers to duration, this seems to
apply mainly to transformer overcurrent relaying which would be for overload protection not fault protection
that has no intentional delay.
E.ON U.S. LLC
No
E.ON U.S. is concerned that the proposal requires a fault protection scheme separate from the phase
overload relays. With the phase overload relays set at 150% of the maximum transformer nameplate, they (by
themselves) will not be able to coordinate with the transformer damage curve (as defined by IEEE) for low
level faults.R1, Section 10 meets the directive of Paragraph 203; however it is not clear that Section 10 only
applies when there is no high side breaker at the transformer, as discussed in Order No. 733. E.ON U.S.
recommends that an exclusion of the transmission line relay settings should be considered when transformer
overload protection is provided by other means (i.e. A low side breaker trip or a direct transfer trip of the
remote breaker initiated by an overload relay installed on the transformer).
November 1, 2010
26
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 3 Comment
NPPD
No
Setting the relay to 150% of a 336MVA or 500MVA transformer can force you to cross the transformer
damage curve and now your transformer is at risk to loss of life.
Idaho Power - System Protection
No
The reworded Requirement should to be clarified. The fault level and duration that the limiting element will be
exposed can be a function of fault location and contingencies, such as relay failures, that are not addressed
or defined. No measure is specified in the reliability standard that will demonstrate compliance with the
revised requirements in R1.10.
Kansas City Power & Light
No
Although setting #10 includes language to protect the most limiting element for a transmission circuit ending
with a transformer, the relay settings in the bulleted items are absent any consideration for other elements
such as disconnect switches, wave traps, current transformers, potential transformers, etc. and are only with
concern to the transformer. The relay settings should consider the fault current capabilities of all the facilities
involved and be set in magnitude and duration of the lowest facility rating.
Ameren
No
The language is not clear. It appears that the transmission line relays are being used as the thermal overload
protection for the transformer.
ITC Holdings
No
R1 -10 is all about loadability of the relays protecting the transformer. If the requirements of R1-10 cannot be
met without exceeding the transformer damage curve, then we go to R1-11. We do not feel that there should
be anything to do with fault duty.
Duke Energy
No
R1.10 has added the requirement that protection settings can’t expose transformers to fault levels and
durations that exceeds its capability, while at the same time not operate at or below 115% of highest
emergency rating. We would argue that an overcurrent relay cannot be set to satisfy both requirements. A
transformer’s through-fault protection curve (C37.91) begins at 200% of the transformers self-cooled rating.
The highest emergency rating is commonly 150% (or higher) of the transformer’s highest (cooled) rating.
Overcurrent relays could not be set to coordinate with both the damage curve and the overload rating.
South Carolina Electric and Gas
No
This requirement needs to be refined to clearly state the intent. It is unclear if “limiting piece of equipment” is
referring to just transformers or other elements. Some of the elements involved in the construction of a
transmission line/transformer arrangement such as line conductors, etc. may not have published fault current
ratings. It is unclear how to determine the most limiting piece of equipment if published fault current ratings
are not available for these devices
American Transmission
Yes
The word change meets the strict interpretation of the directive, but it is not necessarily improving the
reliability of the system. Faults are cleared in cycles and transformer damage curves do not start until at least
November 1, 2010
27
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Company
Question 3 Comment
one second.
Arizona Public Service Company
Yes
Northeast Power Coordinating
Council
Yes
PacifiCorp
Yes
Southern Company
Yes
TSGT System Planning Group
Yes
NV Energy
Yes
Consumers Energy
Yes
ComEd
Yes
Manitoba Hydro
Yes
ISO New England Inc.
Yes
Long Island Power Authority
Yes
American Electric Power
Yes
Yes
Xcel Energy
Wisconsin Electric
November 1, 2010
Yes
No comment
28
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
4.
Requirement R3 has been added to address the directive in Paragraph 186 of Order no. 733. Do you agree that this is an acceptable
and effective method of meeting this directive? If not, please explain.
Summary Consideration:
The SDT modified the wording of R4 as follows. "Each Transmission Owner, Generator Owner, and Distribution Provider that chooses to utilize
Requirement R1 criterion 2 as the basis for verifying transmission line relay loadability shall provide....” as a result of comments.
The SDT agreed to remove the Regional Entity from the list of entities receiving this information in Requirement R4.
Comments indicated that all relay setting limitations should be included in the Facility Rating per FAC-008. The operator will then be made aware
of any and all relay limitations through the use of those ratings (FAC-009). FERC Order 733 paragraph 186 requires an additional notification of
relay setting limitations specifically for relay settings that are set based upon the 15 minute criteria. This is being done to ensure that transmission
operators have knowledge of which facilities have relays set using a 15 minute criteria and which facilities have relays set using a 4-hour criteria.
The SDT believes that requiring periodic submittals of this information will help create a clear and less ambiguous requirement and improve
measurability which should aid applicable entities in compliance and result in more uniform enforcement actions.
Organization
Yes or No
Question 4 Comment
Bonneville Power Administration
This change adds an additional burden to the applicable entities, but serves no purpose other than to satisfy
FERC’s misinterpretation of what a fifteen-minute facility rating is.
ERCOT ISO
The entities who receive the list of facilities should be the same from R3 to R4.
Northeast Power Coordinating
Council
No
Referring to the response to Question 2 above, “Setting” should be replaced with Part, or Sub-requirement,
whichever is the terminology preferred by NERC to use.
Pepco Holdings, Inc - Affiliates
No
To avoid confusion, the wording of R3 should be revised as follows: “Each Transmission Owner, Generator
Owner, and Distribution Provider that chooses to utilize Requirement R1 Setting 2 as the basis for verifying
transmission line relay loadability shall provide....” The problem with the SDT’s proposed wording of R3 is
that suppose a TO chose to utilize R1 Setting 1 criteria (> 150% of 4 hr rating) as their basis for verifying
loadability, but the actual relay setting also satisfied criteria R1 Setting 2 (> 115% of 15 min rating) the entity
may interpret that they are still obligated to forward the list since the relay settings also satisfied R1 Setting 2
criteria
FirstEnergy
No
We suggest removing the Regional Entity from the list of entities receiving this information since they do not
have a reliability-related need for it.
November 1, 2010
29
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 4 Comment
IRC Standards Review
Committee
No
We do not understand the need for this directive or requirement. A relay that is set to operate at 115%
greater than the 15-minute rating of the facility does not equate to damage occurring on that facility if
operated at that point in 15 minutes. Furthermore, it does not mean the relay will operate in 15 minutes nor
does it mean the operator has only 15 minutes to take action. In fact, the operator may have less time
depending on the time delay set on the relay. It is no different than any other relay. Usually, the facility will
be operated with some buffer so that there is no chance that an entity could trip the facility due to loading
above the relay limit. In fact, the transmission operator should be aware of any relay that might be the limiting
facility so they can operate the facility with some margin of error to ensure they don’t inadvertently cause a
relay operation due to loading.
TSGT System Planning Group
No
We think that the data needs to be given only to the Transmission Operators, which is what FERC Order No.
733 requires. We also believe that an initial submittal is sufficient until any responsible entity begins or stops
using Requirement 1, Setting 2 for setting a phase protective relay that is used to protect an applicable
facility. There is no need for periodic duplicate submittals.
Kansas City Power & Light
No
Do not agree that the Regional Entity be included as a recipient of the list of transmission facilities. By NERC
definition, the Regional Entity is the Compliance Monitor and Enforcement Authority for the NERC Reliability
Standards and is not an operating entity. It is inappropriate to include Regional Entities as an entity to provide
this information outside of the audit process established by the NERC Rules of Procedure. By definition, in
the NERC Reliability Terminology, the Regional Entity is a compliance enforcement agent and not an
operating organization of the Bulk Power System, and, therefore, has no operating reason to obtain this
information. See definition below:Regional Entity - The term ‘regional entity’ is defined in Section 215 of the
Federal Power Act means an entity having enforcement authority pursuant to subsection (e)(4) [of Section
215]. A regional entity (RE) is an entity to which NERC has delegated enforcement authority through an
agreement approved by FERC. There are eight RE’s. The regional entities were formed by the eight North
American regional reliability organizations to receive delegated authority and to carry out compliance
monitoring and enforcement activities. The regional entities monitor compliance with the standards and
impose enforcement actions when violations are identified.
Independent Electricity System
Operator
No
The proposed revision goes beyond what’s asked for in the directive as it requires the responsible entities to
provide the list to entities other than the TOP. The directive asks for providing the list to the TOP only.
Southern California Edison
No
The relay if set according to Requirement R1.2 are based upon 15 minute highest seasonal facility loading
duration. This gives sufficient time for the operators to take manual corrective action, if the deem so. There is
no need for the Registered entity to provide a list, as it would not be efficient and cost effective.
November 1, 2010
30
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 4 Comment
ISO New England Inc.
No
We do not understand the need for this directive or requirement. A relay that is set to operate at 115%
greater than the 15-minute rating of the facility does not equate to damage occurring on that facility if
operated at that point in 15 minutes. Furthermore, it does not mean the relay will operate in 15 minutes nor
does it mean the operator has only 15 minutes to take action. In fact, the operator may have less time
depending on the time delay set on the relay. It is no different than any other relay. Usually, the facility will
be operated with some buffer so that there is no chance that an entity could trip the facility due to loading
above the relay limit. In fact, the transmission operator should be aware of any relay that might be the limiting
facility so they can operate the facility with some margin of error to ensure they don’t inadvertently cause a
relay operation due to loading.
MRO's NERC Standards Review
Subcommittee
Yes
Dominion Electric Market Policy
Yes
E.ON U.S. LLC
Yes
Arizona Public Service Company
Yes
American Transmission
Company
Yes
PacifiCorp
Yes
Southern Company
Yes
NV Energy
Yes
NPPD
Yes
Consumers Energy
Yes
Idaho Power - System Protection
Yes
November 1, 2010
31
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
ComEd
Yes
Manitoba Hydro
Yes
Long Island Power Authority
Yes
Ameren
Yes
American Electric Power
Yes
ITC Holdings
Yes
Question 4 Comment
Yes
Xcel Energy
Yes
Duke Energy
Yes
Wisconsin Electric
November 1, 2010
No comment
32
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
5.
Requirement R4 has been added to address the directive in Paragraph 224 of Order no. 733. Do you agree that this is an acceptable
and effective method of meeting this directive? If not, please explain.
Summary Consideration:
The FERC Order “direct(s) the ERO to document, subject to audit by the Commission, and to make available for review to users,
owners and operators of the Bulk-Power System, by request, a list of those facilities that have protective relays set pursuant subrequirement R1.12.”
Since the data is subject to audit, the SDT interprets this to mean that the ERO must gather and have continuously available a list of
facilities using Requirement R1 criterion 12. The SDT therefore interprets the “by request” nature of the directive to indicate the way
the ERO makes the list available to users, owners and operators of the Bulk-Power System, not how the ERO gathers the data from
TOs, GOs and DOs.
As suggested by one of the comments, the SDT intended for registered entities to provide this data to their Regional Entities who
would in turn provide it to the ERO. Although some comments have suggested other ways to accomplish this, the majority of
responders appear to agree with the SDT proposed method.
Organization
Yes or No
ERCOT ISO
Question 5 Comment
The entities who receive the list of facilities should be the same from R3 to R4.
Northeast Power Coordinating
Council
No
R4 addresses the directive, but as commented on previously, “Setting” should be replaced with Part, or Subrequirement, whichever is the terminology preferred by NERC to use.
IRC Standards Review
Committee
No
The objective of R4 as written is unclear and does not conform with the results-based concept in that it does
not clearly specify a reliability directive. We suggest removing this requirement altogether as we do not
believe this should be an on-going enforceable requirement. Rather, we think it makes more sense for NERC
to use section 1600 of its Rules of Procedure to request the data. We believe that NERC and the
Commission will likely determine that they don’t need to continually receive this data after reviewing it the first
time. Nothing in the directive indicates this must be accomplished through a standard. If NERC and FERC
do identify a continuing need for the data, the standard could be modified at a later date.
MRO's NERC Standards Review
Subcommittee
No
While achievable, this will not come without effort and does not necessarily improve the reliability of the BES
commensurate with the compliance burden.
November 1, 2010
33
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 5 Comment
Arizona Public Service Company
No
FERC Order required the list to be made available for review to users, owners and operators of the BulkPower System upon request. Requirement 4 does not include the "request" requirement, implying that the
Registered Entity must provide the list without a request. Further, the requirement does not specify what the
Regional Entity will do with the list once it is provided.
TSGT System Planning Group
No
FERC Order No. 733 requires the settings be provided upon request and no initial or periodic submittal is
required.
Kansas City Power & Light
No
The proposed R4 exceeds the concerns of FERC in this matter. FERC directed a requirement to provide
information upon request. The proposed R4 requires data submission without request of the parties with
interest to the information. Recommend the SDT consider modifying this requirement to provide this
information upon the request of appropriate operating parties.Do not agree that the Regional Entity be
included as a recipient of the list of transmission facilities. By NERC definition, the Regional Entity is the
Compliance Monitor and Enforcement Authority for the NERC Reliability Standards and is not an operating
entity. It is inappropriate to include Regional Entities as an entity to provide this information outside of the
audit process established by the NERC Rules of Procedure. By definition, in the NERC Reliability
Terminology, the Regional Entity is a compliance enforcement agent and not an operating organization of the
Bulk Power System, and, therefore, has no operating reason to obtain this information. See definition
below:Regional Entity - The term ‘regional entity’ is defined in Section 215 of the Federal Power Act means an
entity having enforcement authority pursuant to subsection (e)(4) [of Section 215]. A regional entity (RE) is an
entity to which NERC has delegated enforcement authority through an agreement approved by FERC. There
are eight RE’s. The regional entities were formed by the eight North American regional reliability organizations
to receive delegated authority and to carry out compliance monitoring and enforcement activities. The
regional entities monitor compliance with the standards and impose enforcement actions when violations are
identified.
Independent Electricity System
Operator
No
The objective of R4 as written is unclear. We speculate that by requiring the TOs, GOs and DPs to provide
the list (associated with R1, Section 12) to the REs, the ERO will collect the relevant information from all REs
to facilitate provision of such information to owners, users and operators of the BES upon request. If this is
the intent, we suggest to replace “REs” with “ERO” to make it a more direct and efficient way to provide the
information needed to support the request for information process.The requirement as written does not
conform with the results-based concept in that it does not clearly specify a reliability directive. Hence
alternatively, we suggest removal of this requirement altogether since the directive asks the ERO to
document, subject to audit by the Commission, and to make available for review to users, owners and
operators of the Bulk-Power System, by request, a list of those facilities. This can be dealt with outside of the
standard process, for example, through RoP 1600.
November 1, 2010
34
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 5 Comment
Long Island Power Authority
No
FERC order 733 p224 requires that the list of facilities that have protective relays set pursuant to R1.12 of
anticipated overload be made available to users, owners, and operators of the BPS. However, the proposed
revision to R4 requires the list to be made available to Regional Entity only. Please clarify. Also, FERC order
uses the term “by request” which is missing from the proposed revision.
American Transmission
Company
Yes
While achievable, this will not come without effort and does not necessarily improve the reliability of the BES
commensurate with the compliance burden.
Pepco Holdings, Inc - Affiliates
Yes
FirstEnergy
Yes
Dominion Electric Market Policy
Yes
E.ON U.S. LLC
Yes
PacifiCorp
Yes
Southern Company
Yes
NV Energy
Yes
NPPD
Yes
Consumers Energy
Yes
Idaho Power - System Protection
Yes
ComEd
Yes
Manitoba Hydro
Yes
ISO New England Inc.
Yes
November 1, 2010
35
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
American Electric Power
Yes
ITC Holdings
Yes
Question 5 Comment
Yes
Xcel Energy
Yes
Duke Energy
Yes
Wisconsin Electric
November 1, 2010
Paragraph 224 addresses R1.12, requiring documentation and making available a list of facilities that have
protective relays set pursuant to R1.12. Although Order 733 was silent on R1.13, should the new R4 not also
apply to R1.13?
No comment
36
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
6.
Requirement R5 and part 5.1 (previously Requirement R3 and part 3.1) have been modified to establish the framework to address
the directive in Paragraph 69 of Order no. 733, although the criteria itself (which will be Attachment B) is still being developed. Do
you agree that this is an acceptable and effective method of meeting this directive considering that Requirement R5 is establishing
the construct to insert the criteria at a future time in the form of Attachment B? If not, please explain.
Summary Consideration:
A majority of commenters do not believe, or were unable to determine whether, the construct established in Requirement R5 is an acceptable and
effective method of meeting this directive. Almost all commenters, regardless of whether they responded “Yes” or “No,” indicated their responses
are conditional pending review of the criteria. The criteria that Planning Coordinators will use to determine which facilities must comply with PRC023 were posted on September 23 for a 20-day informal comment period. The SDT has reviewed Requirement R5 and the criteria in Attachment B
and has made conforming changes to ensure no conflicts exist. The full standard with Attachment B will be posted for a 45-day formal comment
period.
One commenter disagreed with the approach in Requirement R5, part R5.1, noting there are a variety of differing, and often complex, operating
conditions that dictate the need for transmission facilities. The commenter observed it is not necessary to dictate additional criteria because the
TPL standards already require extensive studies of the transmission system. The SDT believes the proposed criteria defining the test Planning
Coordinators will use to determine which facilities must comply with PRC-023 will address the commenters concerns. The proposed criteria are
consistent with the simulations and assessments required by the TPL Reliability Standards and allow the Planning Coordinators to utilize those
assessments as directed in Order No. 733.
One commenter noted that the SDT needs to work closely with the Reliability Coordination SDT (Project 2006-06) which is tasked with defining
critical facilities or indentifying criteria for developing a list of critical facilities. The commenter disagreed with use of the phrase “facilities that are
critical” in this requirement and cautioned that a requirement to create a list of critical facilities should not be addressed in this standard. The SDT
notes that although the phrase “critical to reliability of bulk electric system” appears in the approved PRC-023-1 and is used in Order No. 733, the
SDT recognizes that use of the same or similar terms in multiple standards will result in confusion. Use of the phrase “critical to reliability of the
Bulk Electric System” in PRC-023 is intended to have meaning specific to the issue of relay loadability; specifically to identify facilities, that if they
trip due to relay loadability following an initiating event, may contribute to undesirable system performance similar to what occurred during the
August 2003 blackout. The SDT has modified the standard to replace the phrase “critical to the reliability of the bulk electric system” with “that
must comply with this standard.” The SDT believes this will avoid potential confusion and that reliability will be adequately addressed because the
criteria in Attachment B identify all facilities that must be subject to this standard to maintain reliability of the Bulk Electric System.
Some commenters noted that Requirement R5, Part 5.3 should require that the Planning Coordinator provide its list of facilities to all Transmission
Owners, Generator Owners, and Distribution Providers within its area; not only the entities with facilities on the list. The SDT believes this is
consistent with the intent of the requirement and has modified the standard accordingly to make this requirement explicit.
One commenter noted that Requirement R5, Part 5.1 is unnecessary since the process to use the criteria in Attachment B would almost certainly
be to simply apply the criteria and that requiring documentation of such a process will result in increased paperwork and additional preparation for
an audit without a reliability benefit. The SDT agrees that this part of Requirement R5 is unnecessary and has removed it from the Standard.
November 1, 2010
37
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Several commenters requested modifications that are outside the scope of the SAR for this project.
•
Two commenters indicated Requirement R5 should include wording that limits the scope of the transmission facilities to be evaluated to only
those that can be tripped by the relay settings subject to Requirement R1 and that the SDT should add a requirement that the Transmission
Owners, Generator Owners, and Distribution Providers provide the Planning Coordinators with a list of such transmission facilities. The SDT
believes that since the existing Requirement R3 does not restrict the facilities which the Planning Coordinator must consider, the proposed
modifications are outside the scope of the SAR for this project. The SDT further believes that transmission facilities that have no phase
protective relays subject to tripping on load are sufficiently uncommon that the proposed requirement would place a significant burden on
Transmission Owners, Generator Owners, and Distribution Providers while providing limited benefit to the Planning Coordinators.
•
Two commenters believe the standard should not be applicable to Distribution Providers. The SDT believes that since the approved PRC023-1 includes Distribution Providers, the proposal to exclude Distribution Providers is outside the scope of the SAR for this project. However,
the SDT further believes it is possible for a Distribution Provider to own a relay that protects a transmission facility, even if the Distribution
Provider does not own the protected facility.
•
One commenter observed there is much confusion about the registration of Planning Coordinators and suggests that while the Order proposes
the Planning Coordinator perform this test, it could be assigned to the Regional Entity or the Reliability Coordinator (as in the SPCTF
recommendation) and achieve the same result. The SDT notes the approved PRC-023-1 already assigns the Planning Coordinator with the
requirement to determine which facilities must comply with PRC-023. The SDT believes there is no reason to revisit this issue.
One commenter believes it is not appropriate to modify Requirement R5, part 5.3 to include the Regional Entity as a recipient of the list of
transmission facilities because the Regional Entity is the Compliance Monitor and Enforcement Authority for the NERC Reliability Standards and is
not an operating entity. The SDT believes the role of the Regional Entity in compliance enforcement does not preclude a Reliability Standard from
including Regional Entities as the recipients of data. The SDT further believes that providing the Regional Entity with the list of transmission
facilities subject to Requirement R1 is the most direct way to address the Commission’s objective to aid in the overall coordination of planning and
operational studies among Planning Coordinators, Transmission Owners, Generator Owners, Distribution Providers, and Regional Entities.
Two commenters believe the criteria in Attachment B along with any necessary modifications to the associated requirement should be developed
by a full drafting team. The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been reconvened to address the directed
modifications to the standard. The criteria that Planning Coordinators will use to determine which facilities must comply with PRC-023 were
developed with the assistance of a “Blue Ribbon Panel” comprised of members from each region who are Subject Matter Experts in the area of
Transmission Planning. Order No. 733 directs that the criteria in PRC-023 must include or be consistent with the system simulations and
assessments that are required by the TPL Reliability Standards, and input from the Blue Ribbon Panel provides additional expertise necessary to
develop the directed modifications.
Organization
Northeast Power Coordinating
Council
November 1, 2010
Yes or No
Question 6 Comment
No
Requirement R5 states that the Planning Coordinator will determine which facilities below 200kV are critical to
the reliability of the Bulk Electric System by applying criteria defined in Attachment B, which is to be
developed. Therefore, respondents cannot comment on Attachment B. Respondents reserve the right to
38
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 6 Comment
comment when Attachment B is available for review. Because the document has been presented to the
industry without Attachment B, how will Attachment B be presented to the industry? Regarding subrequirement 5.3, it must be revised to clarify that the Planning Coordinator will provide the list of facilities
subject to the Standard to all of the TOs, GOs, and DPs registered in its footprint, not just to those entities that
have facilities on the list.5.2 refers to “Part 1”. As commented on previously in Question 5 and elsewhere,
Part or Sub-requirement should be used for consistency.
Bonneville Power Administration
No
Requirement R5 is okay, but Part 5.1 adds an additional and useless extra burden to the applicable entities.
The process that the Planning Coordinator is required by this part to have would almost certainly be to simply
apply the criteria in Attachment B to lines and transformers operated below 200kV to determine if they are
critical to the BES. Requiring documentation for such a trivial process results in increased paper work,
additional preparation for an audit, and is a waste of everyone’s time. We suggest deleting Part 5.1.
IRC Standards Review
Committee
No
We disagree with modifying the requirement until the criteria is identified. Modifying the requirement now
presumes the criteria will have no impact to the requirement. Contrarily, we believe that the criteria may
cause some change to the requirement as well. The criteria in Attachment B along with any necessary
modifications to the associated requirement should be developed by a full standards drafting team. Only the
full standards drafting team could identify equally effective alternatives to the Commission’s directives as they
have made clear they allow in this Order and many others.
MRO's NERC Standards Review
Subcommittee
No
As noted in Q1 above, a response would be conditional and depend on whether the criteria that will be
established within Attachment B (see R5.1) are reasonable and apply to properly qualified faculties below 200
kV.In addition, the R5 requirement should include wording that limits the scope of the transmission facilities
(line and transformer circuits) to be evaluated to only those transmission facilities that can be tripped by the
relay settings subject to requirement R1. Requirement R5 should also qualify that only the transmission
facilities that are “known” to be associated with the relay settings subject to requirement R1 need to be
evaluated. If the SDT wants to better assure that the Planning Coordinator knows about all of the pertinent
transmission facilities, then they should add a requirement that obligates Transmission Owners, Generator
Owners, and Distribution Providers to provide the Planning Coordinator with a list of the transmission facilities
that are associated with the relay setting subject to requirement R1.
E.ON U.S. LLC
No
See comments for item #1.
Transmission Access Policy
Study Group
No
The proposed method of identifying facilities to which the standard will apply may be reasonable, though we
cannot comment definitively until a draft of Attachment B is available. The standard should not be applicable
to DPs, however. TAPS has been unable to find or think of an example in which a DP would have a load-
November 1, 2010
39
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 6 Comment
responsive transmission phase protection system, aside from a DP that is also a TO and has such a phase
protection system because of its TO function. There is thus no reason to include DPs as potentially
applicable entities.If the SDT retains DPs on the list of potentially applicable entities, it should at minimum
clarify Requirement R5.3 to state that the Planning Coordinator will provide the list of facilities subject to the
standard to all of the TOs, GOs and DPs registered in its footprint, not just to the entities who have facilities
on the list. It is important that DPs who do not have facilities on the list have documentation from the
Planning Coordinator demonstrating that fact.
American Transmission
Company
No
As noted in Q1 above, an affirmative response would be conditional and depend on whether the criteria that
will be established within Attachment B (see R5.1) are reasonable and apply to properly qualified facilities
below 200 kV.In addition, the R5 requirement should include wording that limits the scope of the transmission
facilities (line and transformer circuits) to be evaluated to only those transmission facilities that can be tripped
by the relay settings subject to requirement R1. Requirement R5 should also qualify that only the transmission
facilities that are “known” to be associated with the relay settings subject to requirement R1 need to be
evaluated. If the SDT wants to better assure that the Planning Coordinator knows about all of the pertinent
transmission facilities, then they should add a requirement that obligates Transmission Owners, Generator
Owners, and Distribution Providers to provide the Planning Coordinator with a list of the transmission facilities
that are associated with the relay setting subject to requirement R1.
TSGT System Planning Group
No
While we agree that the purpose of Requirement R5 is beneficial, there is much confusion about registration
and responsibilities of Planning Coordinators. Though the FERC order proposes that planning coordinators
perform the test developed herein, there is also flexibility in how NERC can achieve the same result. We
believe that the Regional Entity (or the Reliability Coordinator, as was included in the System Protection and
Control Task Force recommendation) should be the responsible functional entity for determining which
elements operated at less than 200 kV need to meet Requirement R1. The Region was responsible for
determining operationally significant facilities during the “Beyond Zone 3” process.
NV Energy
No
This approach is not yet an acceptable and effective method of meeting the directive of paragraph 69.
Whether it becomes an acceptable and effective method of meeting the directive will depend on the content of
Attachment B. I’ll reserve specific judgment and concerns until Attachment B is available for comment.
NPPD
No
Attachment B has not even been developed.
Idaho Power - System Protection
No
It is not acceptable or effective until Attachment B is completed and available for review.
Kansas City Power & Light
No
Do not agree with the approach in R5 and R5.1. This proposes to establish the criteria by which Reliability
November 1, 2010
40
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 6 Comment
Coordinators will determine facilities critical to the reliability of the BES. There are a variety of differing, and
often complex, operating conditions that dictate the need for transmission facilities. The TPL standards
require extensive studies of the transmission system be performed under steady state and dynamic
conditions to understand and identify sensitive areas of the transmission system and enable Reliability
Coordinators to identify flowgates in their respective regions. In light of the Reliability Coordinators
awareness of transmission sensitivities through these studies, it seems unnecessary to dictate to the
Reliability Coordinators additional criteria.In addition, in R5.3, do not agree that the Regional Entity be
included as a recipient of the list of transmission facilities. By NERC definition, the Regional Entity is the
Compliance Monitor and Enforcement Authority for the NERC Reliability Standards and is not an operating
entity. It is inappropriate to include Regional Entities as an entity to provide this information outside of the
audit process established by the NERC Rules of Procedure. By definition, in the NERC Reliability
Terminology, the Regional Entity is a compliance enforcement agent and not an operating organization of the
Bulk Power System, and, therefore, has no operating reason to obtain this information. See definition
below:Regional Entity - The term ‘regional entity’ is defined in Section 215 of the Federal Power Act means an
entity having enforcement authority pursuant to subsection (e)(4) [of Section 215]. A regional entity (RE) is an
entity to which NERC has delegated enforcement authority through an agreement approved by FERC. There
are eight RE’s. The regional entities were formed by the eight North American regional reliability organizations
to receive delegated authority and to carry out compliance monitoring and enforcement activities. The
regional entities monitor compliance with the standards and impose enforcement actions when violations are
identified.
Independent Electricity System
Operator
No
We are unable to assess its acceptability and effectiveness until Attachment B is developed.
Utility Services
No
The proposed method of identifying facilities to which the standard will apply may be reasonable, though we
cannot comment definitively until a draft of Attachment B is available. The standard should not be applicable
to DPs, however. We have been unable to find or think of an example in which a DP would have a loadresponsive transmission phase protection system , aside from a DP that is also a TO and has such a phase
protection system because of its TO function. There is thus no reason to include DPs as potentially
applicable entities.If the SDT retains DPs on the list of potentially applicable entities, it should at minimum
clarify Requirement R5.3 to state that the Planning Coordinator will provide the list of facilities subject to the
standard to all of the TOs, GOs and DPs registered in its footprint, not just to the entities who have facilities
on the list. It is important that DPs who do not have facilities on the list have documentation from the
Planning Coordinator demonstrating that fact.
Long Island Power Authority
No
LIPA understands the drafting team’s rationale, however, believes that the proposed method in Attachment B
November 1, 2010
41
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 6 Comment
should be developed before providing comments.
Ameren
No
See our response to Question 1
American Electric Power
No
Please refer to our comment under question number 1. AEP reserves the right to provide additional
comments once Attachment B has been drafted and supplied for industry review.
ERCOT ISO
No
ERCOT ISO respectfully asserts that the changes in this standard need more thorough discussion. This
standard is incomplete without the Attachment B and the intent of the requirements is not explicitly clear. A
standard drafting team (not a SAR SDT) needs to develop Attachment B through discussion of the entire
process that will meet Order 733 directives. Attachment B is a critical component needed to assess R5 and
provide further feedback. Requirement 5 needs to be reworded for clarity. The standard drafting team
assigned to this project needs to work closely with the Reliability Coordination SDT (Project 2006-06), which
is tasked with defining critical facilities or identifying criteria for developing a list of critical facilities.ERCOT
ISO disagrees with the use of the phrase ‘facilities that are critical’ in this requirement. A requirement to
create a list of critical facilities should not be addressed in this standard.
Duke Energy
No
We don’t have Attachment B yet, and the standard development timeline has the standard being submitted to
FERC in March of 2011, which we believe is an unreasonable timeline.
Pepco Holdings, Inc - Affiliates
Yes
While philosophically we do not agree that this standard should apply to facilities below 100kV (i.e. facilities
that are not defined as BES facilities) we believe that as long as a sound engineering methodology is
developed and applied uniformly to identify those facilities critical to the reliability of the BES, then the revised
wording is acceptable. Our response, however, is qualified based on being granted an opportunity to
comment and vote on the methodology contained in Attachment B once it is developed.
FirstEnergy
Yes
Although we agree that R5 is the appropriate requirement to reference the criteria to be used, it is still to be
determined if we agree with the criteria since it is still being developed.
Consumers Energy
Yes
We are concerned about the criteria still undergoing development, and will offer any relevant comments on
that criteria when it is published.
Arizona Public Service Company
Yes
Dominion Electric Market Policy
Yes
November 1, 2010
42
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
PacifiCorp
Yes
Southern Company
Yes
ComEd
Yes
Manitoba Hydro
Yes
ISO New England Inc.
Yes
ITC Holdings
Yes
Question 6 Comment
Yes
Xcel Energy
Wisconsin Electric
November 1, 2010
Yes
No comment
43
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
7.
Attachment A has been modified to address the directive in Paragraph 264 of Order no. 733. Do you agree that this is an acceptable
and effective method of meeting this directive? If not, please explain.
Summary Consideration:
Three-fourths of commenters believe the addition of section 1.6 in Attachment A is not an acceptable and effective method of meeting this
directive. More than one-half of commenters believe that addressing the directive in the proposed manner will have a negative impact on reliability
of the bulk electric system. The SDT agrees that addressing the directive in the manner proposed in the first posting will have the unintended
consequence of impacting the dependability and security of certain protection systems. The SDT has revised the draft standard to address the
following concerns noted by commenters.
•
More than one-half of commenters noted that the proposed modification would require overcurrent fault detectors applied to supervise
distance (impedance) elements to meet the relay loadability requirements which would have a detrimental impact on reliability. Setting these
fault detectors to meet PRC-023 would restrict the ability of some distance elements to trip for end-of-zone faults, particularly on weak source
systems. Eliminating the fault detector to avoid this concern would have the negative impact of making the protection system susceptible to
undesired tripping during close-in faults on adjacent elements. Some commenters further noted that many microprocessor relays have
inherent overcurrent supervision of impedance elements which cannot be disabled.
•
Several commenters noted that the standard should apply to protective systems and not to individual components of protective systems and
that compliance should be based on the ability of the protective system as a whole to meet the performance criteria established by the
standard. Some commenters also noted that a clarification is required that “protective functions” applies only to those protective relay
elements that would respond to non-fault or load conditions and could issue a direct trip.
•
Some commenters noted their belief that the modification goes well beyond the Commission’s concern and they proposed alternatives they
believe would be equally effective and efficient approaches to addressing the Commission’s reliability concerns.
In response to these concerns, in particular the negative impact on reliability associated with the proposed modification, the SDT has modified
section 1.6 to include “1.6.
Supervisory elements associated with current based communication assisted schemes where the scheme is
capable of tripping for loss of communications.” The SDT also modified the second bulleted item in section 2.1 to add the clause, “except as noted
in section 1.6 above.”
Some commenters expressed concern that the proposed modifications would require the overcurrent element in a switch-on-to-fault (SOTF)
scheme to be subject to the relay loadability criteria, in conflict with the SPCTF technical paper that indicates there is no suggested loadability
criterion if the voltage arming threshold is set low enough. Some commenters expressed concern that the proposed modification could negatively
jeopardize reliability by resulting in an operational decision to open breakers upon loss-of-potential to a protection system. These commenters
note that it would be preferable to leave the element in-service with fast tripping enabled for a fault until the loss-of-potential condition can be
diagnosed and corrected. The SDT believes that the modifications to section 1.6 noted above remove the unintended consequence of the original
modifications that could have required overcurrent functions in all SOTF schemes and overcurrent functions used to supervise distance elements
to meet Requirement R1.
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
One commenter proposed that the requirement for setting supervising relays be 115 percent of the facility rating nearest to a 4-hour duration
rather than the 150 percent threshold established for other phase protective relay settings that may limit transmission system loadability. The SDT
believes that with the modifications to section 1.6 noted above the same setting requirements are appropriate for all protective functions listed
under section 1 of Attachment A. The SDT believes this is appropriate and necessary to meet the reliability objective of this standard.
One commenter noted that this directive needs to be addressed by a full standard drafting team to adequately address this directive and identify
equally effective alternatives to the Commission’s directives. Another commenter recommended that the NERC System Protection and Control
Subcommittee (SPCS) be engaged to investigate this issue and produce a white paper or other document describing any unintended
consequences of implementing the FERC directive. The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been
reconvened to address the directed modifications to the standard. The SDT believes that the issues indentified in Order No. 733 can be
addressed adequately by this SDT with industry stakeholder input through the NERC Standard Development Process. The NERC SPCS will be
consulted to address the potential for unintended consequences associated with the proposed modifications to implementing the directives from
Order No. 733.
Organization
Pepco Holdings, Inc - Affiliates
November 1, 2010
Yes or No
Question 7 Comment
No
We do not agree with the proposed wording of Section 1.6 of Attachment A which makes the standard apply
to “Protective functions that supervise operation of other protective functions in 1.1 through 1.5”. The
standard should apply to “protective systems” not individual components of protective systems. Compliance
should be based on the ability of the “protective system” as a whole to meet the performance criteria
established by the standard. Delving into the details of individual scheme designs and supervising element
operation goes well beyond the purpose and scope of this standard.In paragraph 251 of Order 733 the
Commission “expressed concern that section 3.1 could be interpreted to exclude certain protection systems
that use communications to compare current quantities and directions at both ends of a transmission line,
such as pilot wire protection or current differential protection systems supervised by fault detector relays” and
requested comment on “whether it should direct the ERO to modify section 3.1 to clarify that it does not
exclude from the requirements of PRC-023-1 pilot wire protection or current differential protection systems
supervised by fault detector relays.” The Commission reiterated again in paragraphs 266, 268, and 270 their
concern with not including supervising elements associated with “current differential schemes” to prevent
them for operating on loss of communications. That being said, the proposed revision to Attachment A to
include supervising elements for all protective functions in 1.1 through 1.5 goes well beyond addressing the
Commission’s concern. We believe the Commission’s concern could be addressed by simply modifying
Attachment A by deleting proposed section 1.6 and adding a new section 1.5.5 “Line current differential
schemes, including supervising overcurrent elements”. The SDT’s current proposed wording for Section 1.6
would require the overcurrent element in a switch-on-to-fault scheme to be subject to the loadability criteria.
However, the NERC SPCTF in their June 7, 2006 technical paper “Switch-on-to-Fault Schemes in the Context
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 7 Comment
of Line Relay Loadability” indicated there is no suggested loadability criterion if the voltage arming threshold is
set low enough. Similarly, fault detectors which supervise distance elements would be subject to the
loadability standard. However, there are no criteria established on how to set these elements, particularly on
weak source systems, or zone 3 applications, where in order to reliably detect faults at the end of the zone of
protection may require setting the supervising fault detector below 150% of line rating. The NERC SPCTF in
their June 7, 2006 technical paper “Methods to Increase Line Relay Loadability” provided recommendations to
increase loadability of distance elements through various techniques, such as the use of load encroachment
elements or blinders, but does not specifically address setting of supervising elements. In fact, at present,
there is no reliability standard requiring the use of supervising elements, and some newer microprocessor
relays do not even employ supervising fault detectors on their distance elements. FERC in their Order 733
stated “As with our other directives in this Final Rule, we do not prescribe this specific change as an exclusive
solution to our reliability concerns regarding the exclusion of supervising relay elements. As we have stated,
the ERO can propose an alternative solution that it believes is an equally effective and efficient approach to
addressing the Commission’s reliability concerns.”In summary, we believe that addressing the Commission’s
concern regarding supervising elements on current differential schemes, as described in our second
paragraph above, would satisfy the intent of Order 733, while not imposing unnecessary additional restrictions
on what has proven historically to be extremely reliable protection practices.
PSEG Companies
No
In attachment A was added a new requirement, item 1.6. We not agree with this. Sometimes these elements
have to be set lower than the criteria. As long as the protection system as a whole does not trip the line, then
that should meet the criteria. Individual elements that supervise tripping element should NOT be part of the
standard.
Bonneville Power Administration
No
Here we have a situation where the standard is being compromised to satisfy FERC’s misunderstanding of
what a supervising relay is. In Paragraph 266, FERC gives an example of how a line differential relay works
in an attempt to demonstrate why supervisory elements must not operate for load, but instead they clearly
demonstrate their misunderstanding of the details of differential relay operation and what a supervisory relay
is. Modern differential relays will disable the differential function upon loss of communications. If an
overcurrent element is present, it would be used for backup protection, not as a supervisory element. If an
overcurrent element were used to supervise a differential element, the sensitivity of the differential relay would
be lost and the result would be a simple overcurrent relay. FERC’s misunderstanding has resulted in the
improper addition of supervisory relays in Attachment A, Section 1. Sometimes supervisory relays must be
set below maximum loading to obtain the purpose they were intended for. For example, it is often necessary
to set overcurrent supervision of distance relays below the maximum load current of the line so that they will
operate for remote faults. This modification to Attachment A would prohibit that action and make it impossible
to set the supervisory relays to comply with the standard and still provide adequate protection. The
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 7 Comment
modification to Attachment A is unacceptable.
FirstEnergy
No
FirstEnergy supports applying PRC-023 to certain supervising relays, such as overcurrent relays that are
enabled only when another (usually communications based) scheme is out of service, or overcurrent relays
that are ANDed with current differential elements that can trip by themselves if the communications path used
by the current differential scheme is compromised. However, it is not clear that a 150% factor is the correct
one to use in this case. Our understanding is that 150% is a combination of an error factor (widely utilized by
industry) of 15% plus a 35% margin to approximate a 15 minute interval rating to give operators time to react
to adverse system conditions. It is unclear that this extra 35% margin is needed for these supervising relays,
when the reliability goal is to prevent relays being continuously picked-up. We recommend that the standard
utilize a 115% margin (rating duration nearest 4 hours) for these types of supervising relays and that this
would be adequate to meet the Commission's stated reliability concerns.However, there are several other
types of schemes that utilize supervising relays where applying PRC-023 would be detrimental to the
reliability of the bulk power system. One widely used case is the supervision of an impedance relay when
there is no communications scheme involved. There are cases where an impedance element/relay which is
set per PRC-023, correctly operates for a fault it is intended to see, but that the actual current value will be on
the order of the line rating, which will result in the scheme not operating if the supervising relay is set as the
commission proposes. The alternative for these types of schemes is to remove the supervision from the
scheme, which will result in the scheme operating purely on the impedance element, which is exactly the
reliability concern that the Commission is trying to address with this directive. However, many microprocessor
relays have inherent overcurrent supervision of impedance elements which cannot be disabled, adding to the
complexity of the issue. Since this is a fairly complex theoretical/technical issue, we recommend that the
NERC System Protection and Control Subcommittee (SPCS) investigate this issue and produce a white
paper or other document describing any unintended consequences of implementing the FERC directive. The
work of the SPCS could also consider equally effective alternatives to meeting the Commission’s directive.
IRC Standards Review
Committee
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise
language is crafted to adequately address the directive. Furthermore, we believe only the full standards
drafting team could identify equally effective alternatives to the Commission’s directives as they have made
clear they allow in this Order and many others.
MRO's NERC Standards Review
Subcommittee
No
In Order 733, the Commission cites in footnote 186 (p. 161) the definitions of dependability and security, two
components of reliability for protective relays. The Commission did not recognize that the two tend to be
mutually exclusive. Raising dependability (making sure breakers trip during a fault) can sacrifice some
degree of security (tripping more than is needed).Historically, protection engineers have been biased toward
dependability to ensure the safety of people and equipment. The exclusions allow that to happen. These are
contingency scenarios where protective schemes are compromised. For a second contingency, the
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 7 Comment
dependability is at risk if fast tripping is not employed. By removing the exclusion, reliability could be
negatively jeopardized. For example, an operational decision to open breakers will be needed for loss of
potential. The corollary would be leaving the element in service with fast tripping enabled for a fault until the
loss of potential condition can be diagnosed and corrected.
Dominion Electric Market Policy
No
Dominion disagrees with the directive to the ERO to revise section1 to include supervising relays for example,
the fault detectors that we have in electromechanical distance schemes. The impedance relays are set to
meet Reliability Standard PRC-023-1 while the overcurrent fault detector does not trip the transmission line
breaker(s) independently of the impedance relays. Simultaneously meeting full allowance of the line terminal
emergency loading limit and providing adequate sensitivity for detecting line faults with this fault detector will
simply not be achievable for many of our lines.
E.ON U.S. LLC
No
E.ON U.S. requests a clarification of “protective functions” such that it applies only to those protective relay
elements that would respond to non-fault or load conditions, and could issue a direct trip, upon operation,
during a loss of communication or loss of potential condition.
American Transmission
Company
No
In Order 733, the Commission cites in footnote 186 (p. 161) the definitions of dependability and security, two
components of reliability for protective relays. The Commission did not recognize that the two tend to be
mutually exclusive. Raising dependability (making sure breakers trip during a fault) can sacrifice some
degree of security (tripping more than is needed).Historically, protection engineers have been biased toward
dependability to ensure the safety of people and equipment. The exclusions allow that to happen. These are
contingency scenarios where protective schemes are compromised. For a second contingency, the
dependability is at risk if fast tripping is not employed. By removing the exclusion, reliability could be
negatively jeopardized. For example, an operational decision to open breakers will be needed for loss of
potential. The corollary would be leaving the element in service with fast tripping enabled for a fault until the
loss of potential condition can be diagnosed and corrected
PacifiCorp
No
Paragraph No. 264 directs a revision to Section 1 of Attachment A in order to include supervising relay
elements. This change as currently written requires further clarification to meet this directive. For example, a
Distance element is commonly supervised by a phase overcurrent element (Fault detector). If this change
suggests that the overcurrent element has to be set above maximum load, then PacifiCorp disagrees with the
modification. The fault detector will not trip the line by itself; it operates to qualify the distance element
assertion. It is our standard practice to set this element above load where possible, but without restricting the
reach of the distance element. This means that if the fault current at the maximum reach of the distance
element is below load, setting the fault detector above load will restrict the reach of the distance element- this
would compromise the protection scheme. In microprocessor relays where Load encroachment is used this is
even more critical. The Load encroachment function will prevent the distance element from operating in the
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 7 Comment
load region and a fault detector setting that is sensitive enough can be used safely without the need to set it
above load current to enhance the distance element reach.
Southern Company
No
The language that has been added to PRC-023 related to the inclusion of protection elements (fault
detectors) supervising protection functions that are subject to the PRC-023-2 requirements is not appropriate
and will likely decrease the reliability of the BES for the following reasons:The tripping logic utilizing
these elements is an AND function, it takes distance element AND the fault detector (FD) to trip. Since all
distance elements meet the loadability criteria, it is not necessary to also ensure FD meet hese
requirements.Setting FD above nominal load point would unnecessarily reduce sensitivity of distance
element and in many cases eliminate the distance element’s ability to protect the very system element it is
designed and intended to protectIt would require very expensive communications based relay
schemes to replicate this lost protection if it is even possible to do so; a long radial line is one instance where
it would not be possibleEliminating the FD would actually reduce Security and Dependability in
electromechanical schemesThere is a whole generation of microprocessor based relays that it is not
possible to eliminate the FD; to effectively take it out of service, one would have to set it to the most sensitive
setting which would violate the loadability criteriaRelays at terminals with high SIR, a weak source
system, and line with large conductors where the far end fault current may be smaller than maximum line
current (similar to Exception 6 of the Relay Loadability Exceptions: Determination and Applications of
Practical Relaying Loadability Ratings, Version 1.1 published November 2004 by the System Protection and
Control Task Force of NERC)Faults with low power factor could present a similar magnitude of line
current as normal high power factor load currents
NPPD
No
Please remove Attachment A, R1.6. "Protective functions that supervise operation of other protection
functions in 1.1 through 1.5.". If you do not remove R1.6 you must provide a detailed explanation of what
supervise operation means and give examples. Utilities have thousands of relays that have imbedded fault
detective supervision overcurrents for phase distance elements that are set at 0.5 amps or some similar
value. This can not be changed. From your requirement these utilities would have to replace all of these
relays or we would have to lower the Facality rating to 0.5 amp secondary/150%. You are also stating that if
we have an external phase overcurrent fault detector that supervises a phase distance relay that this fault
detector must now have to meet Requirement 1. This is an unacceptable requirement if this is your intent.
You are putting the system at risk if this is your intent. We must set our relays to protect the line. We must
also set fault detectors to pickup for all faults considering N-1 conditions at a minimum where the strongest
source must be remove and the relays must still clear the fault. Please do not lose focus of the purpose:
"Protective relay settings shall be set to reliably detect all fault conditions and protect the electrical network
from these faults". If you have questions on my comments feel free to contact me. Steve Wadas, NPPD, 402
563 5917 Wk.
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 7 Comment
Consumers Energy
No
The supervising elements addressed within this change may fundamentally be unable to be set in accordance
with the requirements of PRC-023, while still permitting the Protection System to function properly for fault
conditions. The supervising element is usually present to assure that a distance element does not operate
inadvertently for close-in zero-voltage faults near the relay location in the non-trip direction, but does not, by
itself, produce a trip. We appreciate that NERC must respond to this directive, but believe that the change, as
expressed, will be detrimental to reliability.
ComEd
No
1) Certain relay elements may be thought to be “supervising relay elements”, when their function is specific
and more limited. A very common example would be a phase overcurrent relay that is required to actuate
along with a phase distance relay to cause a trip. In many applications, the phase overcurrent relays function
is only to assure that the phase distance relay will not cause a trip when a line is taken out of service and no
potential restraint is applied to the phase distance relay. Thus, loadability of the phase overcurrent relay is
not a concern. Raising the level of the overcurrent element may negatively impact the fault detecting ability of
the two relays. This is perhaps a limited function supervising relay element. It is complementary to the phase
distance relay which provides the necessary loadability.
2) Although we don’t employ out of step tripping, it would seem that the argument for the overcurrent element
of an out of step tripping scheme would be the same as for the phase distance element.
3) Are there supervisory elements for switch onto fault schemes that could limit loadability?
4) In our experience, relays that supervise overcurrent relays are typically specifically designed to provide
loadability in order to allow the overcurrent relay to provide greater sensitivity without worrying about its
loadability. Thus this requirement would limit the use of such a scheme.
5) FERC’s main example seems to refer to an old style of current differential relaying scheme that is likely not
very widely applied. Most modern current differential schemes use digital communications and will not trip on
loss of communications regardless of the settings of any elements that may be considered to be supervisory
relay elements. The drafting team should consider modifying 1.6 of Attachment A to clarify and more
specifically address the FERC concern. Three suggestions are as follows: 1) 1.6. Protective functions that
supervise operation of other protective functions in 1.5. This is required for communications aided protection
schemes in 1.5 only when those schemes require communication channel integrity to maintain scheme
loadability. 2) 1.6. Protective functions that supervise operation of other protective functions in 1.2 through
1.5. This is required for communications aided protection schemes in 1.5 only when those schemes require
communication channel integrity to maintain scheme loadability. 3) 1.6. Protective functions that supervise
operation of other protective functions in 1.2 through 1.5.
Manitoba Hydro
November 1, 2010
No
Item 1.6 in Attachment A is not necessary. If the protection functions in 1.1 through 1.5 already meet all the
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 7 Comment
loadability requirements, the facility would not trip under heavy load condition by the supervising protection
element alone. The directive in paragraph 264 of Order 733 seems to deal with the supervising protection
element on the current differential scheme only. It is still arguable whether it is better to allow tripping of the
line or restrain from tripping during loss communication and heavy loading condition.
Wisconsin Electric
No
We strongly disagree with this change. Applying the loadability requirement to supervisory functions in
protection system will have an extremely negative effect on BES reliability. With this change, protection
systems will be less dependable, resulting in increased probability of a failure to detect a system fault. This
change should not be implemented.
Long Island Power Authority
No
LIPA believes that the new wording in 1.6 Attachment A is unnecessary since the existing wording already
complies with the FERC order p.264. Supervisory functions are already part of the protective functions 1.1
through 1.5. Also, this new wording will be subject to varied interpretation and create more confusion.
Ameren
No
In attachment A - 1.6 is not a tripping function - it’s a supervisory function - it in itself does not trip which is the
description of ‘1’ therefore needs to be elsewhere if kept.
American Electric Power
No
AEP requests some clarifying information regarding what is envisioned for 1.6 of Attachment A.
ITC Holdings
No
It appears from the new 1.6 (Attachmnt A) that fault detectors must meet loadability requirements. These do
not trip and must not be included in PRC023. We will not be able to adequately protect longer lines in weak
areas with this requirement in place.
No
Removal of exclusion 3.1 in Att. A, will lead to reduced reliability because an operational decision to open
breakers will be needed for loss of potential conditions. The corollary would be leaving the element in service
with fast tripping enabled for a fault until the loss of potential condition can be diagnosed and corrected.
South Carolina Electric and Gas
No
Item 1.6 of Attachment A needs to be clarified. If the intent is to include protective functions such as fault
detectors then this could possibly lead to relay sensitivity problems when switching contingencies create
weaker systems than normal and a line is faulted. It is unclear why supervisory functions are considered if the
protective functions they supervise will operate in compliance with R1
Xcel Energy
No
Xcel Energy disagrees with the inclusion of the supervising functions in part 1.6 of Section 1 in Attachment A.
Supervising functions in protection schemes provide security for non-power system fault events and are not
the principal elements for scheme operation. Only principal elements should be considered in the
requirements of the PRC‑023 standard.Functions such as overcurrent fault detectors provide security in the
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 7 Comment
event of a failed potential source or blown secondary fusing. Fault detectors must be set below the minimum
end-of-zone fault with a single system contingency in effect. It is common industry practice to set these
functions at 60‑80% of these minimum fault levels and may necessitate a setting that is below the Facility
Rating of a circuit.Increasing the setpoint of an overcurrent fault detector above the Facility Rating will limit the
coverage of the protection system and may impact the system’s ability to protect the electrical network from
Faults. An alternative is to limit the Facility Rating as allowed in Requirement R1.12. However limiting this
Facility Rating places an arbitrary constraint on the circuit and is not justifiable for a non-principal function.
Eliminating the fault detector is not possible in the case of some microprocessor-based relays and if it is
possible, reduces the security of the protective scheme.
Duke Energy
No
Attachment A has added 1.6 stating “Protective functions that supervise operation of other protective
functions” is included in the standard. We would argue that it is not reasonable to include overcurrent fault
detectors used to supervise distance elements or breaker failure schemes. These relays provide security to
the protection scheme, such as for loss of potential conditions, and do not trip on their own. If these relays
would be set per the standard, it would render the schemes ineffective for many fault conditions. In the case
of electromechanical schemes, the supervising relay could be removed from service which could make the
protection scheme misoperate. In the case of microprocessor relays, the supervising relay is embedded in
logic and can’t be removed.
TSGT System Planning Group
Yes
As we interpret the changes to Attachment A they are acceptable. However, there appears to be uncertainty
about the intent of the drafting team. We interpret the change to 1.6, in conjunction with 2.1, to allow setting
impedance relay fault detector supervisory elements at levels below load current levels. This understanding
comes from the realization that the fault detector elements by themselves do not “trip with or without time
delay, on load current,” a requirement described in 1. The fault detector elements can cause tripping on their
own, but only for conditions of loss of potential or loss of communications, which are both excluded from the
loadability requirements as steted in 2.1.If Tri-State’s interpretation of the intent of Attachment A, Sections 1,
1.6, and 2.1 is incorrect, then we do not agree that this is an acceptable and effective method of meeting this
directive. There are many protection system locations in our system that require the fault detector supervision
elements to be set below load current levels in order for backup impedance relays to operate securely in the
event of loss of potential and to operate dependably for remote faults that inherently have low fault current
magnitudes.
Idaho Power - System Protection
Yes
The order has been met, but there is significant concern about the inclusion of supervisory elements in
protective systems. A supervisory element is not performing a tripping function. As stated in Attachment A
“This standard includes any protective functions which could trip with or without time delay, on load current,
including but not limited to:...”. Supervisory elements, used properly, do not trip for load current.
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Northeast Power Coordinating
Council
Yes
Arizona Public Service Company
Yes
NV Energy
Yes
Kansas City Power & Light
Yes
Independent Electricity System
Operator
Yes
ISO New England Inc.
Yes
November 1, 2010
Question 7 Comment
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
8.
Do you agree that the SDT has addressed the remaining directives: Paragraph 284 to remove the footnote and Paragraph 283 to
modify the implementation plan for sub-100 kV facilities (by revising the Effective Date section of the standard)?
Summary Consideration:
The SDT agrees with several commenters about the proposed language for Effective Dates and has changed the language to the following:
5.1. Requirement R1: the first day of the first calendar quarter after applicable regulatory approvals, except as noted below.
5.1.1
For the addition to Requirement R1, criterion 10, to set transformer fault protection relays and transmission line relays on transmission
lines terminated only with a transformer such that the protection settings do not expose the transformer to fault level and duration that
exceeds its mechanical withstand capability, the first day of the first calendar quarter 12 months after applicable regulatory approvals.
5.1.2
For supervisory elements as described in Attachment A, section 1.6, the first day of the first calendar quarter following 24 months after
applicable regulatory approvals.
5.2. Requirements R2 and R3: the first day of the first calendar quarter after applicable regulatory approvals.
5.3. Requirements R4 and R5: the first day of the first calendar quarter following 24 months after applicable regulatory approvals.
5.4. Requirement R6: the first day of the first calendar quarter 18 months after applicable regulatory approvals.
5.5. Requirement R7: the first day of the first calendar quarter after applicable regulatory approvals.
One comment addressed the issue of a reliability standard superseding previous agreements between registered entities and NERC. The SDT
believes that, by removing the footnote, the standard does not supersede previous agreements because the latest due date for mitigation of
temporary exceptions under the Beyond Zone 3 review was December 31, 2008. Removal of the footnote has no bearing on previous agreements
given that all temporary exceptions have expired.
To address the need for entities to meet the requirements of the standard for facilities identified by the Planning Coordinator in the future, the SDT
added a new requirement (R7).
Organization
Pepco Holdings, Inc - Affiliates
November 1, 2010
Yes or No
Question 8 Comment
No
We agree with the removal of the footnote regarding temporary exceptions. However, there appears to be a
contradiction between the effective dates for sub 200kV facilities noted in section 5.1.2 (39 months following
regulatory approvals) and 5.1.3 (24 months after being notified by its Planning coordinator). If the planning
coordinator takes the full 18 months to determine the R5 list (per effective date section 5.2) and the TO has
24 months after that to comply, that would be 42 months following regulatory approval, which is in conflict with
the 39 month requirement in 5.1.2. Since the list of sub 200kV facilities may change from year to year, it
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 8 Comment
would seem prudent to make the effective date for those facilities always tied to a defined interval following
being notified by the Planning Coordinator and eliminate the 39 month requirement for sub 200kV facilities
from 5.1.2. Also, since the Attachment B methodology has not yet been determined, it is unclear how many
sub 200kV facilities may fall under these requirements. As such, one cannot yet determine if the proposed 24
months would be sufficient. We propose at least a 36 month interval until the methodology is finalized and
the magnitude of the scope better defined. In addition, if supervising elements are included in the standard
in some form, an implementation schedule (i.e. appropriate effective dates) need to be developed based on
this significant increase in scope and number of facilities to be reviewed.
Bonneville Power Administration
5.1.2 and 5.1.3 both apply to the same systems and should be combined into one sub-requirement. Also,
since the date of the applicable regulatory approval is now established, please consider replacing the cryptic
phrase “at the beginning of the first calendar quarter 39 months following applicable regulatory approval” with
an actual date.
IRC Standards Review
Committee
No
While we agree removing the footnote is straight forward and addresses one Commission directive, we
believe the other directives need to be addressed by a full standards drafting team to ensure the precise
language is crafted to adequately address the directives. Furthermore, we believe only the full standards
drafting team could identify equally effective alternatives to the Commission’s directives as they have made
clear they allow in this Order and many others. In particular, we believe that only a full drafting team could
adequately assess if any additional time will be needed to comply with the standard for sub-100 kV facilities
particularly when we consider there are some outstanding issues including a regional entity’s critical facilities
list identified in Question 1. Also, we are unable to assess if the two directives are fully addressed absent a
proposed implementation plan.
Kansas City Power & Light
No
It is inappropriate for this standard to supersede any other agreements and the provisions of those
agreements that have been established between NERC and Registered Entities. The footnote made it clear
those agreements would continue to be honored. Recommend the SDT reinstate the principles established
by the footnote directly into the Effective Dates section to recognize the authority of those agreements.Agree
with the effective dates of 18 months after applicable approvals for R5 and for 24 months after notification by
the Planning Coordinator of a new critical facility.
Independent Electricity System
Operator
No
We are unable to comment on this in the absence of a proposed implementation plan.
E.ON U.S. LLC
No
Cannot assess the impact until Attachment B is developed and commented sections above are clarified.
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 8 Comment
Manitoba Hydro
No
Even though this version of the standard does seem to have addressed Paragraph 284 of Order 733, we still
do not agree with the uniform effective date without taking into consideration how many critical circuits or
equipment could be added for an individual utility.
American Electric Power
No
It is unclear how much time a TO, GO, or DP would have to implement the changes based on the results of
the analysis by the Planning Coordinator. In addition, the Effective Date section is a one-time event upon
regulatory approval. What are the on-going implementation expectations? There should be some allowed
lead beyond initial implementation after facilities are identified by the Planning Coordinator.
ITC Holdings
No
The new effective dates for 5.1.2 will for the most part be ok. Some of these below 200 kV lines will have to
be reconstructed to be able to have adequate protection and meet the required loadability. It will be difficult to
do this in 39 months. We suggest a mitigation program be required for those lines that will be difficult to meet
the 39 month deadline.
Duke Energy
No
Until we see the criteria for Attachment B, we can’t agree that 39 months is sufficient time.
ISO New England Inc.
No
While we agree removing the footnote is straight forward and addresses one Commission directive. In
particular, we believe that only a full drafting team could adequately assess if any additional time will be
needed to comply with the standard for sub-100 kV facilities particularly when we consider there are some
outstanding issues a regional entities critical facilities list identified in Question 1. Also, we are unable to
assess if the two directives are fully addressed absent a proposed implementation plan.
Long Island Power Authority
No
Northeast Power Coordinating
Council
Yes
FirstEnergy
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Dominion Electric Market Policy
Yes
American Transmission
Yes
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 8 Comment
Company
Southern Company
Yes
TSGT System Planning Group
Yes
NV Energy
Yes
NPPD
Yes
Consumers Energy
Yes
Idaho Power - System Protection
Yes
ComEd
Yes
Ameren
Yes
Xcel Energy
Yes
Wisconsin Electric
November 1, 2010
No comment
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
9.
Do you agree that the scope of the proposed standards action addresses the directive or directives?
Summary Consideration:
The SAR shows the directive from P. 162 as part of Phase I to be implemented by March 18, 2011. However, some commenters
indicated this directive should be included in Phase III since it deals with the subject of relay operations due to power swings.
The SDT reviewed the SAR and determined a modification to the SAR is unnecessary because the SDT already has considered
“islanding” strategies that achieve the fundamental performance for all islands as part of Phase I, although following this
consideration the SDT agrees islanding strategies are best addressed as part of the new standard that will be developed in
Phase III of the project.
Several commenters indicated that the directive from P. 224 is missing from the detailed section of the SAR, but is included in
the table in the back of the SAR. This was an error in the SAR and the SDT has added this directive to the detailed section of
the SAR for Phase I. The new Requirement R5 will support collection of the data necessary for the ERO to address the directive.
The ERO will provide the data upon request, but outside of PRC-023.
Organization
FirstEnergy
Yes or No
No
Question 9 Comment
i.
The SAR shows the directive from P. 162 as part of Phase I to be implemented by March 18, 2011.
However, this directive should be included in Phase III since it deals with the subject of relay
operations due to power swings.
ii.
The directive from P. 224 is missing from the detailed section of the SAR, but is included in the table
in the back of the SAR.
iii.
As mentioned in our response to Question 7, we do not agree with how the project is proposing to
address the P. 264 directive.
Response: The SDT reviewed the SAR and determined a modification to the SAR regarding P.162 is unnecessary because the SDT already has
considered “islanding” strategies that achieve the fundamental performance for all islands as part of Phase I, although following this consideration the
SDT agrees islanding strategies are best addressed as part of the new standard that will be developed in Phase III of the project.
The reference to P.224 was omitted from the detailed section of the SAR by error. The SDT has added this directive to the detailed section of the SAR
for Phase I. The new Requirement R5 will support collection of the data necessary for the ERO to address the directive. The ERO will provide the data
upon request, but outside of PRC-023.
Please see our response above to your comment regarding P.264
IRC Standards Review
November 1, 2010
No
We largely believe the scope will allow the drafting team to address the directives. However, we request that
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Committee
Question 9 Comment
the scope be modified to make clear that the drafting team may use equally effective alternatives to address
the Commission’s directives per the Commission in this order and other orders such as Order 693.There is a
discrepancy between the entities listed in the Applicability Section and those checked off in the SAR. The
latter indicates that the SAR is also applicable to the Reliability Coordinator, which we do not believe is
appropriate.
Response: The Standards Process Manual states that a Standard Authorization Request (SAR) is the form used to document the scope and reliability
benefit of a proposed project for one or more new or modified standards or the benefit of retiring one or more approved standards. This SAR is
specific to addressing regulatory directives in Order No. 733. The SAR should only contain the scope and not include how the directives will be met as
it is understood that the directives may be met in an equally effective alternative.
The SDT notes that the SAR contains a list of entities that could potentially be included in the standard, but it is not necessary that the SDT include
each entity in the applicability section of the standard.
MRO's NERC Standards Review
Subcommittee
No
It addresses the directives per the letter of the order; however, it is not necessarily improving reliability.
No
See commented sections above. Also, the directive identified in Paragraph 224 was not included in the
detailed description or highlighted in Attachment 1 of the SAR. However it was included in the proposed
modifications as R4.
Response: Thank you for your input.
E.ON U.S. LLC
Response: The reference to P.224 was omitted from the detailed section of the SAR by error. The SDT has added this directive to the detailed section
of the SAR for Phase I. The new Requirement R5 will support collection of the data necessary for the ERO to address the directive. The ERO will
provide the data upon request, but outside of PRC-023. Requirement R5 does not address the directive in P.224 directly as this is a directive to the
ERO to provide data upon request. Since the data is subject to audit, the SDT interprets this to mean that the ERO must gather and have continuously
available a list of facilities using Requirement R1 criterion 12. Requirement R5 ensures that the data is available.
TSGT System Planning Group
No
As stated in our earlier comments, we believe that some proposals exceed the directives. It is also not clear
how p 162 was addressed in PRC-023-2 as indicated on SAR-3.
Response: The SDT notes that this directive is not addressed in PRC-023-2. The SDT considered “islanding” strategies that achieve the fundamental
performance for all islands as part of Phase I, although following this consideration the SDT agrees islanding strategies are best addressed as part of
the new standard that will be developed in Phase III of the project.
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
NPPD
No
American Electric Power
No
Question 9 Comment
Refer to our comment under question 1.
Response: Please see our response above to your comment on Question 1.
Pepco Holdings, Inc - Affiliates
Yes
While the scope of the proposed standards action addresses the directive(s) outlined in FERC Order 733 we
believe that there are two significant issues that need to be much more thoroughly investigated before being
included. Those areas are the inclusion of supervising elements in the existing relay loadability standard and
the development of any new standard that would “require the use of protective relay systems that can
differentiate between faults and stable power swings and when necessary phase out protective relay systems
that cannot meet this requirement.”
Response: In response to industry concerns regarding supervisory elements, in particular the negative impact on reliability associated with the
proposed modification, the SDT has modified section 1.6 to state: “1.6.
Supervisory elements associated with current based communication
assisted schemes where the scheme is capable of tripping for loss of communications.” The SDT also modified the second bulleted item in section
2.1 to add the clause, “except as noted in section 1.6 above.” The NERC SPCS will be consulted to address the potential for unintended consequences
associated with the proposed modifications to implementing the directives from Order No. 733.
The issues related to power swings will be addressed in Phase III of this project according to the SAR, and the NERC System Protection and Control
Subcommittee (SPCS) and Transmission Issues Subcommittee (TIS) are jointly developing a paper, Issues Related to Protective System Response to
Power Swings.
American Transmission
Company
Yes
It addresses the directives per the letter of the order; however, it is not necessarily improving reliability.
Yes
Agree that the SDT has made revisions that attempted to address the FERC directives. Do not agree with all
the proposals by the SDT as indicated by the comments regarding questions 1 through 8.
Response: Thank you for your input.
Kansas City Power & Light
Response: Please see our responses above to your comment on Questions 1 through 8.
Independent Electricity System
Operator
November 1, 2010
Yes
As indicated in our comment submitted under Q1, there is a discrepancy between the entities listed in the
Applicability Section and those checked off in the SAR. The latter indicates that the SAR is also applicable to
the RC, which we do not believe is required.
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 9 Comment
Response: The SDT notes that the SAR contains a list of entities that could potentially be included in the standard, but it is not necessary that the SDT
include each entity in the applicability section of the standard.
Northeast Power Coordinating
Council
Yes
Bonneville Power Administration
Yes
Dominion Electric Market Policy
Yes
Arizona Public Service Company
Yes
PacifiCorp
Yes
Southern Company
Yes
NV Energy
Yes
Consumers Energy
Yes
Idaho Power - System Protection
Yes
ComEd
Yes
Manitoba Hydro
Yes
ISO New England Inc.
Yes
Long Island Power Authority
Yes
ITC Holdings
Yes
Yes
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Duke Energy
Yes
Wisconsin Electric
November 1, 2010
Question 9 Comment
No comment
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
10. Can you identify an equally efficient and effective method of achieving the reliability intent of the directive or directives?
Summary Consideration:
Many comments were offered regarding the directives in Paragraph 150 of Order 733 that NERC “develop a Reliability Standard that
requires the use of protective relay systems that can differentiate between faults and stable power swings and, when necessary, phases
out protective relay systems that cannot meet this requirement,” and suggested that this subject either needs to be addressed via
modification to TPL-001 or that it needs further study. It is notable that this issue is to be addressed in Phase III of this project
according to the SAR, and that the SPCS and TIS are jointly developing a paper, Issues Related to Protective System Response to
Power Swings.
Many other commenters repeated comments that were offered in response to other questions.
Organization
Yes or No
American Electric Power
Question 10 Comment
No
Not at this time, but AEP would like to consider all viable options throughout the standard development
process.
No
Regarding the directive of Par. 264, since this is a fairly complex theoretical/technical issue, we recommend
that the NERC System Protection and Control Subcommittee (SPCS) investigate this issue and produce a
white paper or other document describing any unintended consequences of implementing the FERC directive.
The work of the SPCS could also consider equally effective alternatives to meeting the Commission’s
directive.
Response: Thank you for your input.
FirstEnergy
Response: The NERC SPCS will be consulted to address the potential for unintended consequences associated with the proposed modifications to
implementing the directives from Order No. 733.
IRC Standards Review
Committee
No
We are not prepared at this time to offer equally efficient and effective alternatives. Rather, we believe this is
the purpose for convening a full drafting team and that the drafting team should propose their alternatives.
Response: The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been reconvened to address the directed modifications to the
standard. The SDT believes that the issues identified in Order No. 733 can be addressed adequately by this SDT with industry stakeholder input
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 10 Comment
through the NERC Standard Development Process.
Dominion Electric Market Policy
No
Since there is no question that asks if there are other concerns with this draft, I will add one here..... R2
should be modified to read “The Each Transmission Owner, Generator Owner, or and Distribution Provider
that uses a circuit capability with the practical limitations described in Requirement R1, Settings1.6, R1.7,
R1.8, R1.9, R1.12, or R1.13 shall use the calculated circuit capability as the Facility Rating of the circuit and
shall forward this information to the Planning Coordinator, Transmission Operator, and Reliability Coordinator.
The burden for acknowledging agreement or specifying reasons for disagreement should reside with the
Planning Coordinator, Transmission Operator, and Reliability Coordinator. Suggest SDT develop additional
requirements similar to those in FAC-008 @ R2 and R3.
Response: This proposal is outside the scope of the SAR that is intended to limit the project to addressing the directives in Order No. 733. This
suggestion could be made when the standard is reviewed during the required 5-year review of the standard.
ISO New England Inc.
No
We are not prepared at this time to offer equally efficient and effective alternatives. Rather, we believe this is
the purpose for convening a full drafting team and that the drafting team should propose their alternatives.
Response: The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been reconvened to address the directed modifications to the
standard. The SDT believes that the issues indentified in Order No. 733 can be addressed adequately by this SDT with industry stakeholder input
through the NERC Standard Development Process.
NV Energy
No
NERC's proposed Phase I, II, II process seems reasonable.
Response: Thank you for your support.
ComEd
No
No, other than the comments provided for question 7.
Response: Please see our responses above to your comment on Question 7.
Dominion Electric Market Policy
No
PacifiCorp
No
Southern Company
No
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
NPPD
No
Idaho Power - System Protection
No
Kansas City Power & Light
No
ITC Holdings
No
Question 10 Comment
No other comments.
No
Northeast Power Coordinating
Council
No
Duke Energy
No
Bonneville Power Administration
No
TSGT System Planning Group
Yes
We included specific proposals in our comments to questions 2, 4, 5, and 6.
Response: Please see our responses above to your comment on Questions 2, 4, 5, and 6.
Manitoba Hydro
Yes
The effective date can be dependent upon how many critical circuits or equipment are identified for each
individual company.
Response: The SDT considered this possibility in developing effective dates for each requirement in the standard.
Consumers Energy
Yes
NERC should, again, oppose the FERC directive in paragraph 264, since, as explained above, this directive is
both unnecessary and detrimental to reliability.
Response: In response to industry concerns, in particular the negative impact on reliability associated with the proposed modification, the SDT has
modified section 1.6 to state: “1.6. Supervisory elements associated with current based communication assisted schemes where the scheme is
capable of tripping for loss of communications.” The SDT also modified the second bulleted item in section 2.1 to add the clause, “except as noted in
section 1.6 above.”
November 1, 2010
65
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Long Island Power Authority
Yes or No
Question 10 Comment
Yes
Involving industry working groups such as IEEE, EPRI, etc who have proven technical experts will also help in
effectively achieving reliability.
Response: The NERC System Protection and Control Subcommittee (SPCS) will be consulted to address the potential for unintended consequences
associated with the proposed modifications to implementing the directives from Order No. 733.
Pepco Holdings, Inc - Affiliates
Yes
Regarding the response of protective relay systems to stable power swings, Draft 5 of TPL-001-2
Requirement R4 (stability assessment) section 4.3.1 requires a contingency analysis be performed which
includes “tripping of transmission lines and transformers where transient swings cause protection system
operation based on generic or actual relay models.” Therefore the impact of power swings on relay operation
is already addressed in TPL-001. If the tripping of a line is identified during this study phase the impact of the
line trip is assessed to ensure the system meets the performance criteria identified in Table 1. If not,
mitigating measures would be required, such as modifying that protection scheme to prevent its operation
during a stable power swing. However, this would be done on a case by case basis when identified. This
seems a much more prudent approach than to require “all protection systems be modified to prevent
operation during stable power swings.” That would be similar to requiring the re-conductoring all lines so that
they could never experience an overload. Also, Appendix F of the “PJM Relay Subcommittee Protective
Relaying Philosophy and Design Standards” employs a methodology to address relay response during power
swings by calculating a transient load limit for the relay instead of just the steady state limit identified in PRC023. The relay loadability is evaluated at the maximum projection along the +R axis (the most susceptible
point for swings to enter) rather than at a 30 degree load angle. Various multiplying factors are used to
account for the relay operating time delay. This methodology of calculating relay transient loadability limits,
which was developed by the PJM Relay Subcommittee over 30 years ago, has worked extremely well in
eliminating relay operations during stable power swings. In summary, there are other methods to evaluate
and improve the performance of protection systems during power swings short of hardware replacements. All
options should be evaluated
Response: The issues related to power swings will be addressed in Phase III of this project according to the SAR, and the NERC System Protection
and Control Subcommittee (SPCS) and Transmission Issues Subcommittee (TIS) are jointly developing a paper, Issues Related to Protective System
Response to Power Swings.
MRO's NERC Standards Review
Subcommittee
Yes
On the topic of ‘adding in’ - listing and evaluating the transmission facilities below 200 kV, we propose the
inclusion of qualifications that prevent the consideration and evaluation of irrelevant facilities (e.g. facilities
that are not tripped by the applicable relay settings).
Response: The SDT believes the proposed criteria in Attachment B defining the test Planning Coordinators will use to determine which facilities must
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 10 Comment
comply with PRC-023 will address the commenters concerns.
American Transmission
Company
Yes
On the topic of ‘adding in’ - listing and evaluating the transmission facilities below 200 kV, we propose the
inclusion of qualifications that prevent the consideration and evaluation of irrelevant facilities (e.g. facilities
that are not tripped by the applicable relay settings).
Response: The SDT believes the proposed criteria in Attachment B defining the test Planning Coordinators will use to determine which facilities must
comply with PRC-023 will address the commenters concerns.
ERCOT ISO
ERCOT ISO thinks a standard drafting team can evaluate the Order 733 directives, work in conjunction with
other Standard Drafting Teams already addressing some aspects of critical facilities, may be able to more
succinctly arrive at an equally efficient and effective method of achieving the intent of the directive(s). The
coordination between teams is vital to avoid confusion and possible overlap.
Response: The SDT has addressed the specific comment regarding coordination with the Reliability Coordination SDT (Project 2006-06) by modifying
the standard to replace the phrase “critical to the reliability of the bulk electric system” with “that must comply with this standard.” The SDT believes
that the directed modifications to PRC-023-1 contained in Order No. 733 are unique to this standard and do not require coordination with other SDTs.
E.ON U.S. LLC
Wisconsin Electric
November 1, 2010
Yes
No comment
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
11. Do you agree with the scope of the proposed standards action?
Summary Consideration:
Several commenters indicated that they do not agree with the scope of the proposed standards action based on the technical
comments submitted against many of the proposed actions submitted in response to the original FERC NOPR on PRC-023. In
response, the SDT indicated that FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued
directives in Order No. 733 that the SDT must address.
Several commenters indicated that the scope of the SAR should be modified to make clear that the drafting team may use
equally effective alternatives to address the Commission’s directives per the Commission in this order and other orders such as
Order 693. In response the SDT cited the Standards Process Manual. The Standards Process Manual states that a Standard
Authorization Request (SAR) is the form used to document the scope and reliability benefit of a proposed project for one or
more new or modified standards or the benefit of retiring one or more approved standards. This SAR is specific to addressing
regulatory directives in Order No. 733. The SAR should only contain the scope and not include how the directives will be met as
it is understood that the directives may be met in an equally effective alternative.
Many comments received indicated that the proposed modifications to PRC-023 reach beyond the directives without specifying
which particular modifications are problematic. The SDT worked carefully to not go beyond the directives.
A commenter indicated that the scope should address apparent conflicts in timing of requirements posed by the standard. A
newly proposed implementation plan will be proposed in the formal posting of PRC-023 that allows transition time for entities to
become compliant with the modified requirements. The SDT agrees that a revised implementation plan is necessary and will
post it for review by the industry during the next posting of the standard.
Some commenters suggested that several parts of the standard go too far (Appendix A R1.10) and will require documenting
faults and clearing times to prove the fault duty of transformer connections. They also suggested the requirements to deal with
out of step blocking relays should go in phase 3 and not in this standard. The SDT believes that evidence such as coordination
curves or summaries of calculations are sufficient to demonstrate that relays set per criterion 10 do not expose the transformer
to fault levels and durations beyond those indicated in the standard. The potential for out-of-step blocking protection elements
to assert due to system load conditions already is addressed in PRC-023-1. Moving this subject from Attachment A to an
explicit requirement in PRC-023-2 does not alter the requirement that already exists for Transmission Owners, Generator
Owners, and Planning Coordinators. The SDT also notes that operation of out-of-step blocking elements due to system load
conditions is outside the scope of Phase III of this project which is to address the directive regarding protection system
operation during power swings.
Some commenters noted believe that removal of exclusion 3.1 in Att. A, will lead to reduced reliability because an operational
decision to open breakers will be needed for loss of potential conditions. The SDT has modified section 1.6 in response to
concerns that applying the standard to elements such as fault detectors that supervise directional distance elements could have
November 1, 2010
68
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
a negative impact on reliability. The SDT has modified section 1.6 to include “Supervisory elements associated with current
based communication assisted schemes where the scheme is capable of tripping for loss of communications.” The SDT also
modified the second bulleted item in section 2.1 (formerly 3.1) to add the clause, “except as noted in section 1.6 above.”
Organization
Pepco Holdings, Inc - Affiliates
Yes or No
No
Question 11 Comment
We do not agree with the scope of the proposed standards action for numerous reasons. The documented
responses to the original FERC NOPR on PRC-023 from numerous sources, including NERC and EEI,
together make a rather convincing technical argument against many of these proposed actions. We support
these technical arguments, which for the sake of brevity will not be repeated here. In addition, we have
provided comments and objections on specific portions of the proposed standards action in our responses to
questions 1 through 10 above.
Response: FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued directives in Order No. 733 that the SDT
must address.
MRO's NERC Standards Review
Subcommittee
No
We agree that the topics of generator relay loadability and power swing protective relaying should be referred
to in other separate standards. While we acknowledge that it is in everyone’s best interest to respond to the
FERC directives, there are numerous technical flaws that need to be resolved in their request. Forming a
team and spending considerable resources will not gain industry acceptance to these directives.
Response: FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued directives in Order No. 733 that the SDT
must address.
American Transmission
Company
No
We agree that the topics of generator relay loadability and power swing protective relaying should be referred
to in other separate standards. While we acknowledge that it is in everyone’s best interest to respond to the
FERC directives, there are numerous technical flaws that need to be resolved in their request. Forming a
team and spending considerable resources will not gain industry acceptance to these directives.
Response: FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued directives in Order No. 733 that the SDT
must address.
PacifiCorp
No
It is very difficult to comment on test parameters that have not been determined.
Response: The criteria that Planning Coordinators will use to determine which facilities must comply with PRC-023 were posted on September 23 for a
November 1, 2010
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 11 Comment
20-day informal comment period. The SDT has reviewed Requirement R5 and the criteria in Attachment B and has made conforming changes to ensure
no conflicts exist. The full standard with Attachment B will be posted for a 45-day formal comment period.
Kansas City Power & Light
No
Do not agree with all the proposals by the SDT as indicated by the comments regarding questions 1 through
8.
Response: Thank you for your comments. Please see the summary considerations above.
ISO New England Inc.
No
We largely believe the scope will allow the drafting team to address the directives. However, we request that
the scope be modified to make clear that the drafting may use equally effective alternatives to address the
Commission’s directives per the Commission in this order and other orders such as Order 693.
Response: The Standards Process Manual states that a Standard Authorization Request (SAR) is the
form used to document the scope and reliability benefit of a proposed project for one or more new or
modified standards or the benefit of retiring one or more approved standards. This SAR is specific to
addressing regulatory directives in Order No. 733. The SAR should only contain the scope and not
include how the directives will be met as it is understood that the directives may be met in an equally
effective alternative.
The scope should address apparent conflicts in the timing of requirements posed by the standard. It is our
understanding that, based on the final date afforded NERC to develop the criteria for the determination of
sub-200 kV facilities,a newly proposed implementation plan will be offered to allow the Planning Coordinators
an appropriate time frame to apply the criteria to determine the “critical” facilities below 200 kV. The
implementation plan should cause the effective date for circuits described in 4.1.2 and 4.1.4 to be changed
from “39 months following applicable regulatory approvals” to a date linked to the Planning Coordinators
schedule to provide a list to its TOs, GOs and DPs.
Response: The SDT modified the implementation schedule for those requirements that the SDT has
modified to address a FERC directive in Order No. 733. In addition, the SDT added a requirement, now
Requirement R7, that requires the Transmission Owners, Generator Owners, and Distribution
Providers to implement Requirement R1, Requirement R2, Requirement R3, and Requirement R4, and
Requirement R5 for each facility that is added to the Planning Coordinator’s list of facilities that must
comply with this standard pursuant to Requirement R6, Part 6.12 by the later of the first day of the
second calendar quarter after 24 months following notification by the Planning Coordinator of a
facility’s inclusion on such a list, or the first day of the first calendar quarter of the year in which
criterion B6 first applies.
Duke Energy
November 1, 2010
No
o The SAR states that Paragraph 162 is part of Phase I, but the new standard addressing stable power
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Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 11 Comment
swings is Phase III.
Response: The SAR shows the directive from P. 162 as part of Phase I to be implemented by March 18, 2011. However, this directive should be
included in Phase III since it deals with the subject of relay operations due to power swings. The SDT reviewed the SAR and determined to leave this in
Phase I because the directive says to consider “islanding” strategies that achieve the fundamental performance for all islands in developing the new
Reliability Standard addressing stable power swings but agrees that a new standard will be developed for this in Phase III of the project.
ITC Holdings
No
Several parts of the standard go too far (Appendix A R1.10) and will require us to document faults and
clearing times to prove the fault duty of transformer connections. Also the requirements to deal with out of
step blocking relays should go in phase 3 and not in this standard.
Response: This is part of the existing, approved standard and the SDT cannot change this part of the standard since it is not associated with a
directive in Order No. 733. The SDT removed out-of-step blocking from Requirement R1. The requirement pertaining to evaluation of out-of-step
blocking protection has been moved to a separate requirement (now Requirement R2) to more clearly delineate this requirement from assessment of
relay loadability of phase protective relays. Phase III of this project will address protective relays operating unnecessarily due to stable power swings
and is not intended to address out of step blocking relays.
No
Removal of exclusion 3.1 in Att. A, will lead to reduced reliability because an operational decision to open
breakers will be needed for loss of potential conditions. The corollary would be leaving the element in service
with fast tripping enabled for a fault until the loss of potential condition can be diagnosed and corrected.
Response: The SDT has modified section 1.6 in response to concerns that applying the standard to elements such as fault detectors that supervise
directional distance elements could have a negative impact on reliability. The SDT has modified section 1.6 to include “Supervisory elements
associated with current based communication assisted schemes where the scheme is capable of tripping for loss of communications.” The SDT also
modified the second bulleted item in section 2.1 (formerly 3.1) to add the clause, “except as noted in section 1.6 above.”
E.ON U.S. LLC
No
NPPD
No
FirstEnergy
Yes
We agree that this standards action is necessary to meet the FERC directives, but have some concerns as
we have stated in previous responses above.
Response: Thank you for your comments. Please see the summary considerations above.
November 1, 2010
71
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
TSGT System Planning Group
Yes or No
Yes
Question 11 Comment
We agree that the scope meets the FERC directive, but some of the proposals in the proposed standard
reach beyond the directive.
Response: Without additional details, the SDT cannot address the issues that the commenter has with the specific modifications to PRC-023-2
intended to address the FERC directives.
Independent Electricity System
Operator
Yes
We general agree with the proposed action but there are detailed changes that we have comments on, which
are noted in our comments under Q1 to Q8
Response: Thank you for your comments. Please see the summary considerations above.
ComEd
Yes
Yes, given that we assume that NERC must address all the FERC directives whether or not NERC or the
industry agrees with them.
Response: FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued directives in Order No. 733 that the SDT
must address.
Long Island Power Authority
Yes
LIPA agrees with the scope in general. Please consider our comments above for answers to specific issues.
Response: Thank you for your comments. Please see the summary considerations above.
Northeast Power Coordinating
Council
Yes
Bonneville Power Administration
Yes
Dominion Electric Market Policy
Yes
Arizona Public Service Company
Yes
Southern Company
Yes
NV Energy
Yes
November 1, 2010
72
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Consumers Energy
Yes
Idaho Power - System Protection
Yes
Manitoba Hydro
Yes
American Electric Power
Yes
Wisconsin Electric
November 1, 2010
Question 11 Comment
No comment
73
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
12. Are you aware of any regional variances that we should consider with this SAR?
Summary Consideration:
The majority of the commenters did not identify variances for consideration in the SAR. However, several commenters did point out
that each Regional Entity has its own definition for BES and should be considered when addressing sub-100 kV facilities. In response,
the SDT indicated that Attachment B to the standard will define criteria that Planning Coordinators must apply to determine if a
facility must comply with the standard. In addition, FERC issued a BES NOPR on March 18, 2010 proposing a consistent approach to
defining BES that (i) provides a 100 kV threshold for facilities that are included in the BES; and (ii) eliminates the currently-allowed
discretion of a Regional Entity to define BES within its system without NERC or Commission oversight. In the NOPR, the
Commission proposes that a Regional Entity must seek NERC and Commission approval before it exempts a transmission facility
rated at 100 kV or above from compliance with mandatory Reliability Standards. In response to the NOPR, NERC submitted
comments that supports the Commission’s objectives of ensuring a common understanding and consistent application of the definition
of BES across the regions. NERC also supports the Commission’s objective that variations to application of the BES definition should
be justified on the basis of reliability. To ensure these objectives are accomplished in a technically and legally appropriate manner,
NERC proposed that the Commission should rely on the NERC Reliability Standards Development Process to consider, develop and
implement new processes that may be needed, or to enhance existing processes. An Order on the matter has not been issued.
One commenter indicated concern that utilities with long lines and in weak areas will have difficulty protecting their lines and meeting
the required loadability. Regions where there are very rural systems will want to write standards that allow adequate protection for
their systems. Requirement R1 part 13 states that: “Where other situations present practical limitations on circuit capability, set the
phase protection relays so they do not operate at or below 115% of such limitations.” This was included in the standard for such cases
where additional criteria are necessary.
Organization
IRC Standards Review
Committee
Yes or No
No
Question 12 Comment
We are not aware of any regional variances per se. However, each regional entity has its own definition for
BES and this needs to be considered when addressing sub-100 kV facilities.
Response: Attachment B to the standard will define criteria that Planning Coordinators must apply to determine if a facility must comply with the
standard. In addition, FERC issued a BES NOPR on March 18, 2010 proposing a consistent approach to defining BES that (i) provides a 100 kV
November 1, 2010
74
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 12 Comment
threshold for facilities that are included in the BES; and (ii) eliminates the currently-allowed discretion of a Regional Entity to define BES within its
system without NERC or Commission oversight. In the NOPR, the Commission proposes that a Regional Entity must seek NERC and Commission
approval before it exempts a transmission facility rated at 100 kV or above from compliance with mandatory Reliability Standards. In response to the
NOPR, NERC submitted comments that support the Commission’s objectives of ensuring a common understanding and consistent application of the
definition of BES across the regions. NERC also supports the Commission’s objective that variations to application of the BES definition should be
justified on the basis of reliability. To ensure these objectives are accomplished in a technically and legally appropriate manner, NERC proposed that
the Commission should rely on the NERC Reliability Standards Development Process to consider, develop and implement new processes that may be
needed, or to enhance existing processes. An Order on the matter has not been issued.
ISO New England Inc.
No
We are not aware of any regional variances per se. However, each regional entity has its own definition for
BES and this needs to be considered when addressing sub-100 kV facilities.
Response: Attachment B to the standard will define criteria that Planning Coordinators must apply to determine if a facility must comply with the
standard. In addition, FERC issued a BES NOPR on March 18, 2010 proposing a consistent approach to defining BES that (i) provides a 100 kV
threshold for facilities that are included in the BES; and (ii) eliminates the currently-allowed discretion of a Regional Entity to define BES within its
system without NERC or Commission oversight. In the NOPR, the Commission proposes that a Regional Entity must seek NERC and Commission
approval before it exempts a transmission facility rated at 100 kV or above from compliance with mandatory Reliability Standards. In response to the
NOPR, NERC submitted comments that support the Commission’s objectives of ensuring a common understanding and consistent application of the
definition of BES across the regions. NERC also supports the Commission’s objective that variations to application of the BES definition should be
justified on the basis of reliability. To ensure these objectives are accomplished in a technically and legally appropriate manner, NERC proposed that
the Commission should rely on the NERC Reliability Standards Development Process to consider, develop and implement new processes that may be
needed, or to enhance existing processes. An Order on the matter has not been issued.
Long Island Power Authority
Yes
NPCC BPS definition based on A10 criteria is a regional variance.
Response: Attachment B to the standard will define criteria that Planning Coordinators must apply to determine if a facility must comply with the
standard. In addition, FERC issued a BES NOPR on March 18, 2010 proposing a consistent approach to defining BES that (i) provides a 100 kV
threshold for facilities that are included in the BES; and (ii) eliminates the currently-allowed discretion of a Regional Entity to define BES within its
system without NERC or Commission oversight. In the NOPR, the Commission proposes that a Regional Entity must seek NERC and Commission
approval before it exempts a transmission facility rated at 100 kV or above from compliance with mandatory Reliability Standards. In response to the
NOPR, NERC submitted comments that support the Commission’s objectives of ensuring a common understanding and consistent application of the
definition of BES across the regions. NERC also supports the Commission’s objective that variations to application of the BES definition should be
justified on the basis of reliability. To ensure these objectives are accomplished in a technically and legally appropriate manner, NERC proposed that
the Commission should rely on the NERC Reliability Standards Development Process to consider, develop and implement new processes that may be
needed, or to enhance existing processes. An Order on the matter has not been issued.
November 1, 2010
75
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
ITC Holdings
Question 12 Comment
Utilities with long lines and in weak areas will have difficulty protecting their lines and meeting the required
loadability. Regions where there are very rural systems will want to write standards that allow adequate
protection for their systems.
Response: Requirement R1 part 13 states that: “Where other situations present practical limitations on circuit capability, set the phase protection
relays so they do not operate at or below 115% of such limitations.” This was included in the standard for such cases where additional criteria are
necessary.
Northeast Power Coordinating
Council
No
Pepco Holdings, Inc - Affiliates
No
PSEG Companies
No
Bonneville Power Administration
No
FirstEnergy
No
MRO's NERC Standards Review
Subcommittee
No
Dominion Electric Market Policy
No
E.ON U.S. LLC
No
Arizona Public Service Company
No
American Transmission
Company
No
PacifiCorp
No
Southern Company
No
November 1, 2010
76
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
TSGT System Planning Group
No
NV Energy
No
NPPD
No
Consumers Energy
No
Idaho Power - System Protection
No
Kansas City Power & Light
No
Independent Electricity System
Operator
No
ComEd
No
Manitoba Hydro
No
Wisconsin Electric
No
Ameren
No
American Electric Power
No
Question 12 Comment
No
Duke Energy
November 1, 2010
No
77
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
13. Are you aware of any associated business practices that we should consider with this SAR?
Summary Consideration:
Commenters did not indicate that there are any business practices that the team should consider with the SAR.
One commenter suggested that R2 should be modified to read “The Each Transmission Owner, Generator Owner, or and Distribution
Provider that uses a circuit capability with the practical limitations described in Requirement R1, Settings1.6, R1.7, R1.8, R1.9, R1.12,
or R1.13 shall use the calculated circuit capability as the Facility Rating of the circuit and shall forward this information to the
Planning Coordinator, Transmission Operator, and Reliability Coordinator. The burden for acknowledging agreement or specifying
reasons for disagreement should reside with the Planning Coordinator, Transmission Operator, and Reliability Coordinator. The
commenter suggested that the SDT develop additional requirements similar to those in FAC-008 @ R2 and R3. This proposal is
outside the scope of the SAR that is intended to limit the project to addressing the directives in Order No. 733. This suggestion could
be made when the standard is reviewed during the required 5-year review of the standard.
Organization
Yes or No
Northeast Power Coordinating
Council
No
Pepco Holdings, Inc - Affiliates
No
PSEG Companies
No
Bonneville Power Administration
No
FirstEnergy
No
IRC Standards Review
Committee
No
MRO's NERC Standards Review
No
November 1, 2010
Question 13 Comment
78
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Question 13 Comment
Subcommittee
E.ON U.S. LLC
No
Arizona Public Service Company
No
American Transmission
Company
No
PacifiCorp
No
Southern Company
No
TSGT System Planning Group
No
Consumers Energy
No
Idaho Power - System Protection
No
Kansas City Power & Light
No
Independent Electricity System
Operator
No
ComEd
No
Manitoba Hydro
No
Wisconsin Electric
No
ISO New England Inc.
No
Long Island Power Authority
No
November 1, 2010
79
Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Yes or No
Ameren
No
American Electric Power
No
ITC Holdings
No
Question 13 Comment
No
Duke Energy
No
NPPD
Yes
November 1, 2010
See Question 7.
80
PRC-026-1 — Relay Performance During Stable Power Swings
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SAR posted for comment from August 19, 2010 through September 19, 2010.
2. SC authorized moving the SAR forward to standard development on August 12, 2010.
3. SC authorized initial posting of draft 1 on April 24, 2014.
Description of Current Draft
The Protection System Response to Power Swings Standard Drafting Team (PSRPS SDT) is
posting Draft 1 of PRC-026-1 – Relay Performance During Stable Power Swings for a 45-day
initial comment period and concurrent/parallel initial ballot in the last ten days of the comment
period.
Anticipated Actions
Anticipated Date
45-day Formal Comment Period with Concurrent/Parallel Initial Ballot
April 2014
45-day Formal Comment Period with Concurrent/Parallel Additional
Ballot
July 2014
Final Ballot
September 2014
BOT Adoption
November 2014
Version History
Version
Date
1.0
TBD
Action
Effective Date
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
Change
Tracking
New
Page 1 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Glossary of Terms Used in Reliability Standards are not repeated here.
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.
Term: None.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
Page 2 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
When this standard has received ballot approval, the text boxes will be moved to the Application
Guidelines Section of the Standard.
A. Introduction
1.
Title:
Relay Performance During Stable Power Swings
2.
Number:
PRC-026-1
3.
Purpose: To ensure that load-responsive protective relays do not trip in response to
stable power swings during non-Fault conditions.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Generator Owner that applies load-responsive protective relays at the
terminals of the Elements listed in Section 4.2, Facilities.
4.1.2
Planning Coordinator.
4.1.3
Reliability Coordinator.
4.1.4
Transmission Owner that applies load-responsive protective relays at the
terminals of the Elements listed in Section 4.2, Facilities.
4.1.5
Transmission Planner.
4.2. Facilities: The following Bulk Electric System (BES) Elements:
5.
4.2.1
Generators.
4.2.2
Transformers.
4.2.3
Transmission lines.
Background:
This is Phase 3 of a three-phased standard development that is focused on developing a
new Reliability Standard, PRC-026-1 – Relay Performance During Stable Power
Swings, to address protective relay operations due to stable power swings. The March
18, 2010, FERC Order No. 733, approved Reliability Standard PRC-023-1 –
Transmission Relay Loadability. In this Order, FERC directed NERC to address three
areas of relay loadability that include modifications to the approved PRC-023-1,
development of a new Reliability Standard to address generator protective relay
loadability, and a new Reliability Standard to address the operation of protective relays
due to stable power swings. This project’s SAR addresses these directives with a threephased approach to standard development.
Phase 1 focused on making the specific modifications to PRC-023-1 and was
completed in the approved Reliability Standard PRC-023-2, which became mandatory
on July 1, 2012.
Phase 2 focused on developing a new Reliability Standard, PRC-025-1 – Generator
Relay Loadability, to address generator protective relay loadability; PRC-025-1 is
currently awaiting regulatory approval.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
Page 3 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
This Phase 3 of the project focuses on developing a new Reliability Standard, PRC026-1 – Relay Performance During Stable Power Swings, to address protective relay
operations due to stable power swings. This Reliability Standard will establish
requirements aimed at preventing protective relays from tripping unnecessarily due to
stable power swings by requiring each Transmission Owner and Generator Owner to
assess the security of protective relay systems that are susceptible to operation during
power swings, and take actions to improve security for stable power swings where such
actions would not compromise dependable operation for faults and unstable power
swings.
6.
Effective Date:
First day of the first full calendar year that is twelve months beyond the date that this
standard is approved by applicable regulatory authorities, or in those jurisdictions
where regulatory approval is not required, the standard becomes effective on the first
day of the first full calendar year that is twelve months beyond the date this standard is
approved by the NERC Board of Trustees, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities.
B. Requirements and Measures
R1. Each Planning Coordinator, Reliability Coordinator, and Transmission Planner shall,
within the first month of each calendar year, identify and provide notification to the
respective Generator Owner and Transmission Owner of each Element that meets one
or more of the following criteria, if any: [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning, Long-term Planning]
Criteria:
1. An Element that is located or terminates at a generating plant, where a generating
plant stability constraint exists and is addressed by an operating limit or a Special
Protection System (SPS) (including line-out conditions).
2. An Element that is associated with a System Operating Limit (SOL) that has been
established based on stability constraints identified in system planning or operating
studies (including line-out conditions).
3. An Element that has formed the boundary of an island within an angular stability
planning simulation where the system Disturbance(s) that caused the islanding
condition continues to be a credible event.
4. An Element identified in the most recent Planning Assessment where relay tripping
occurred for a power swing during a Disturbance.
M1. Each Planning Coordinator, Reliability Coordinator, and Transmission Planner shall
have dated evidence that demonstrates identification and the respective notification of
the Element(s), if any, which meet one or more of the criteria in Requirement R1.
Evidence may include, but is not limited to, the following documentation: emails,
facsimiles, records, reports, transmittals, lists, or spreadsheets.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
Page 4 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
Rationale for R1: The Planning Coordinator, Reliability Coordinator, and Transmission
Planner are in positions to identify Elements which meet the criteria, if any. The criterionbased approach is consistent with the NERC System Protection and Control Subcommittee
(SPCS) technical document Protection System Response to Power Swings, August 2013,
which recommended a focused approach to determine an at-risk Element. Requirements R1,
R2, and R3 collectively form an annual assessment. Identification of the Element(s) in the first
month of the calendar year allows the remaining time in the calendar year for the relay owners
to evaluate Protection Systems (Requirement R3).
R2. Each Generator Owner and Transmission Owner shall, once each calendar year,
identify each Element for which it applies a load-responsive protective relay at a
terminal of an Element that meets either of the following criteria, if any: [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning, Long-term Planning]
Criteria:
1. An Element that has tripped since January 1, 2003, due to a power swing during an
actual system Disturbance where the Disturbance(s) that caused the trip due to a
power swing continues to be credible.
2. An Element that has formed the boundary of an island since January 1, 2003,
during an actual system Disturbance where the Disturbance(s) that caused the
islanding condition continues to be credible.
M2. Each Generator Owner and Transmission Owner shall have dated evidence that
demonstrates identification of the Element(s), if any, which meet either of the criteria
in Requirement R2. Evidence may include, but is not limited to, the following
documentation: emails, facsimiles, records, reports, transmittals, lists, or spreadsheets.
Rationale for R2: The Generator Owner and Transmission Owner are in positions to identify
which load-responsive protective relays have tripped due to power swings, if any. The
criterion-based approach is consistent with the NERC System Protection and Control
Subcommittee (SPCS) technical document Protection System Response to Power Swings,
August 2013, which recommended a focused approach to determine an at-risk Element.
Requirements R1, R2, and R3 collectively form an annual assessment. The time period in
Requirement R2 and R3 allows the relay owners to allocate time during the calendar year to
identify the Element(s) and to evaluate Protection Systems based on their particular
circumstances.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
Page 5 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
R3. Each Generator Owner and Transmission Owner shall, once each calendar year,
perform one of the following for each Element identified pursuant to Requirement R1
or R2: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Longterm Planning]
Demonstrate that the existing Protection System is not expected to trip in response
to a stable power swing based on the criterion below.
Demonstrate that the existing Protection System is not expected to trip in response
to a stable power swing because power swing blocking is applied.
Develop a Corrective Action Plan (CAP) to modify the Protection System so that
the Protection System is not expected to trip in response to a stable power swing
based on the criterion below or by applying power swing blocking.
If none of the options above results in dependable fault detection or dependable
out-of-step tripping:
a. obtain agreement from the respective Planning Coordinator, Reliability
Coordinator, and Transmission Planner of the Element that the existing
Protection System design and settings are acceptable, or
b. obtain agreement from the respective Planning Coordinator, Reliability
Coordinator, and Transmission Planner of the Element that a modification
of the Protection System design, settings, or both are acceptable, and
develop a CAP for this modification of the Protection System.
Criterion:
A distance relay impedance characteristic, used for tripping, that is completely
contained within the lens characteristic formed in the impedance (R-X) plane
that connects the endpoints of the total system impedance by varying the
sending end and receiving end voltages from 0 to 1.0 per unit, while
maintaining a constant system separation angle across the total system
impedance where:
1. The system separation angle is:
At least 120 degrees where power swing blocking is not applied, or
An angle less than 120 degrees as agreed upon by the Planning
Coordinator, Reliability Coordinator, and Transmission Planner
where power swing blocking is not applied.
2. All generation is in service and all transmission Elements are in their
normal operating state.
3. Sub-transient reactance is used for all machines.
M3. Each Generator Owner and Transmission Owner shall have dated evidence that
demonstrates one of the options was performed according to Requirement R3.
Evidence may include, but is not limited to, the following documentation: apparent
impedance characteristic plots, email, design drawings, facsimiles, R-X plots, software
output, records, reports, transmittals, lists, settings sheets, or spreadsheets.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
Page 6 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
Rationale for R3: Performing one of the options in Requirement R3 assures that the
reliability goal of this standard will be met. The first option ensures that the Generator Owner
and Transmission Owner protective relays are secure from tripping in response to stable power
swings having a system separation angle of up to 120 degrees. The second option allows the
Generator Owner and Transmission Owner to exclude protective relays that have power swing
blocking applied. The third option allows the Generator Owner and Transmission Owner,
where possible, to modify the Protection System to meet the criterion or apply power swing
blocking. The fourth option allows the Generator Owner and Transmission Owner to maintain
a balance between Protection System security and dependability for cases where tripping on
stable power swings may be necessary to maintain the ability to trip for unstable power swings
or faults; however, agreement is required by others to ensure that tripping for a stable power
swing is acceptable. Protection System modifications may be necessary to achieve acceptable
performance. A time period of once each calendar year allows time to evaluate the Protection
System, develop a CAP, or obtain necessary agreement.
R4. Each Generator Owner and Transmission Owner shall implement each CAP developed
pursuant to Requirement R3, and update each CAP if actions or timetables change,
until all actions are complete. [Violation Risk Factor: Medium][Time Horizon:
Operations Planning, Long-Term Planning]
M4. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates implementation of each CAP according to Requirement R4, including
updates to actions or timetables. Evidence may include, but is not limited to, the
following documentation: corrective action plans, maintenance records, settings sheets,
project or work management program records, or work orders.
Rationale for R4: Implementation of the CAP must accomplish all identified actions to be
complete to achieve the desired reliability goal. During the course of implementing a CAP,
updates may be necessary for a variety of reasons such as new information, scheduling
conflicts, or resource issues. Documenting changes and completion of activities provides
measurable progress and confirmation of completion.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
Page 7 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
1.2. Evidence Retention
The following evidence retention periods 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 CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The Generator Owner, Planning Coordinator, Reliability Coordinator,
Transmission Owner, and Transmission Planner shall keep data or evidence to
show compliance as identified below unless directed by its CEA to retain specific
evidence for a longer period of time as part of an investigation.
The Planning Coordinator, Reliability Coordinator, and Transmission
Planner shall retain evidence of Requirements R1, Measures M1 for three
calendar years.
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R2 and R3, Measures M2 and M3 for three calendar years.
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R4, Measures M4 for 12 calendar months following
completion of each CAP.
If a Generator Owner, Planning Coordinator, Reliability Coordinator,
Transmission Owner, or Transmission Planner is found non-compliant, it shall
keep information related to the non-compliance until mitigation is complete and
approved, or for the time specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
Page 8 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
Table of Compliance Elements
R#
R1
Time
Horizon
Operations
Planning,
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The responsible entity
identified an Element
and provided
notification in
accordance with
Requirement R1, but
was less than or equal
to 30 calendar days
late.
Moderate VSL
High VSL
Severe VSL
The responsible entity
identified an Element
and provided
notification in
accordance with
Requirement R1, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The responsible entity
identified an Element
and provided
notification in
accordance with
Requirement R1, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The responsible entity
identified an Element
and provided
notification in
accordance with
Requirement R1, but
was more than 90
calendar days late.
OR
The responsible entity
failed to identify an
Element or to provide
notification in
accordance with
Requirement R1.
R2
Operations
Planning,
Long-term
Planning
Medium The responsible entity
identified Element in
accordance with
Requirement R2, but
was less than or equal
to 30 calendar days
late.
The responsible entity
identified Element in
accordance with
Requirement R2, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
The responsible entity
identified Element in
accordance with
Requirement R2, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The responsible entity
identified Element in
accordance with
Requirement R2, but
was more than 90
calendar days late.
OR
Page 9 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
R#
Time
Horizon
Violation Severity Levels
VRF
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity
failed to identify an
Element in accordance
with Requirement R2.
R3
Operations
Planning,
Long-term
Planning
Medium The responsible entity
performed one of the
options in accordance
with Requirement R3,
but was less than or
equal to 30 calendar
days late.
The responsible entity
performed one of the
options in accordance
with Requirement R3,
but was more than 30
calendar days and less
than or equal to 60
calendar days late.
The responsible entity
performed one of the
options in accordance
with Requirement R3,
but was more than 60
calendar days and less
than or equal to 90
calendar days late.
The responsible entity
performed one of the
options in accordance
with Requirement R3,
but was more than 90
calendar days late.
OR
The responsible entity
failed to perform one
of the options in
accordance with
Requirement R3.
R4
Operations
Planning,
Long-term
Planning
Medium The responsible entity
implemented, but
failed to update a
CAP, when actions or
timetables changed, in
accordance with
Requirement R4.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
N/A
N/A
The responsible entity
failed to implement a
CAP in accordance
with Requirement R4.
Page 10 of 25
PRC-026-1 — Relay Performance During Stable Power Swings
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
IEEE Power System Relaying Committee WG D6. Power Swing and Out-of-Step
Considerations on Transmission Lines. July 2005.
Kundar, Prabha. Power System Stability and Control. 1994. Palo Alto: EPRI, McGraw Hill,
Inc.
NERC System Protection and Control Subcommittee. Protection System Response to Power
Swings. August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf.
Reimert, Donald. Protective Relaying for Power Generation Systems. 2006. Boca Raton: CRC
Press.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
Guidelines and Technical Basis
Introduction
The NERC System Protection and Control Subcommittee technical document, Protection System
Response to Power Swings, August 20131 (“PSRPS Report” or “report”) was specifically prepared
to support the development of this NERC Reliability Standard. The report provided a historical
perspective on power swings as early as 1965 up through the approval of the report by the NERC
Planning Committee. The report also addresses reliability issues regarding trade-offs between
security and dependability of protection systems, considerations for this NERC Reliability
Standard, and a collection of technical information about power swing characteristics and varying
issues with practical applications and approaches to power swings. Of these topics, the PSRPS
Report suggests an approach for this NERC Reliability Standard (“standard” or “PRC-026-1”)
which is consistent with addressing two of the three regulatory directives in the FERC Order No.
733. The first directive concerns the need for “…protective relay systems that differentiate
between faults and stable power swings and, when necessary, phases out protective relay systems
that cannot meet this requirement.”2 Second, is “…to develop a Reliability Standard addressing
undesirable relay operation due to stable power swings.”3 The third directive “…to consider
“islanding” strategies that achieve the fundamental performance for all islands in developing the
new Reliability Standard addressing stable power swings”4 was considered during development of
the standard.
The development of this NERC Reliability Standard implements the majority of the approach
suggested by the PSRPS Report. These guidelines include a narrative of any deviation in the
report’s approach.
Burden to Entities
The PSRPS Report provides a technical basis and approach for focusing on Protection Systems
which are susceptible to power swings while achieving the reliability objective. The approach
reduces the number of relays for which the requirements would apply by first identifying the Bulk
Electric System (BES) Element(s) that need to be evaluated. The first step uses criteria to identify
a BES Element on which a Protection System is expected to be challenged by power swings. Of
those BES Elements, the second step is to identify the Element(s) that apply a load-responsive
protective relay. Rather than requiring the Transmission Planner to perform simulations to obtain
information for each identified Element(s), the Generator Owner and Transmission Owner will
reduce the need for simulation by comparing the load-responsive protective relay characteristic to
a specific criterion.
1
NERC System Protection and Control Subcommittee technical document, Protection System Response to Power
Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20
Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
2
Transmission Relay Loadability Reliability Standard, Order No. 733, P.150 FERC ¶ 61,221 (2010).
3
Ibid. P.153.
4
Ibid. P.162.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
Applicability
The standard is applicable to the Generator Owner, Planning Coordinator, Reliability Coordinator,
Transmission Owner, and Transmission Planner entities. More specifically, the Generator Owner
and Transmission Owner entities are applicable when applying load-responsive protective relays
at the terminals of the applicable BES Elements. All the entities have a responsibility to identify
the Elements which meet specific criteria. The standard is applicable to the following BES
Elements: generators, transmission lines, and transformers. The Distribution Provider was
considered for inclusion in the standard; however, it is not subject to the standard because this
entity by functional registration would not own generators, transmission lines, or transformers
other than load serving.
Requirement R1
In the first month of each calendar year this requirement initiates the identification of the Elements
that meet specific criteria known by the Planning Coordinator, Reliability Coordinator, and the
Transmission Planner.
Because the dynamic studies performed by the Planning Coordinator and the Transmission Planner
vary by region, it is important for both of these entities to have a reliability requirement to identify
such Elements. The Reliability Coordinator is also included because of its wide-area awareness of
the BES and its unique potential to identify Elements susceptible to tripping due to power swings.
The first criterion involves Elements that are located at or terminate at a generating plant where an
existing stability constraint has been established and is managed by either a specific operating limit
or a Special Protection System (SPS). For example, assume a generating plant contains two 500
MW generating units, one connected to a 345 kV bus and one connected to a 230 kV bus. Assume
a single transformer connects the 345 kV bus to the 230 kV bus, and that the plant is connected to
the rest of the BES through a single 345 kV transmission circuit and two 230 kV circuits. Assume
a stability constraint exists that limits the output of the plant to 700 MW for an outage of the 345
kV transmission line, and that a SPS exists to run back the output of the generating plant to 700
MW for a loss of the 345 kV transmission line. For this hypothetical example, both generating
units would be included as Elements meeting the criterion. Furthermore, the generator step-up
(GSU) transformers, the generator interconnection, the 345-230 kV power transformer, and the
two 230 kV transmission circuits would be identified as Elements meeting the criterion. The 345
kV transmission circuit would not be identified as meeting the criterion since the event that
triggered the stability constraint is a loss of the 345 kV transmission circuit.
The second criterion involves Elements that have an established System Operating Limit (SOL)
based on a stability limit or issue driven by one or more specific events. For example, if two long
parallel 500 kV transmission lines have a combined SOL of 1,200 MW, and this limit is based on
angular instability resulting from a fault and subsequent loss of one of the two circuits, then both
circuits would be identified as an Element meeting the criterion.
The third criterion involves the Element that has formed the boundary of an island within an
angular stability planning simulation. While the island may form due to various transmission
circuits tripping for a combination of reasons, such as stable and unstable power swings, faults,
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
and excessive loading, the criterion requires that all lines that tripped in simulation to form the
island be identified as meeting the criterion.
The last criterion allows the Planning Coordinator and Transmission Planner to include any other
Elements revealed in Planning Assessments.
Requirement R2
The approach of Requirement R2 requires the Generator Owner and Transmission Owner to
identify Elements once each calendar year that meet the focused criteria specific to these entities.
The only Elements that are in scope are Elements that meet the criteria and apply a load-responsive
protective relay at the terminal of the Element. Using the criteria focuses the reliability concern on
the Element that is at-risk.
The first criterion involves Elements that have tripped for actual power swings, regardless of
whether the power swing was stable or unstable. In order to ensure previous trips due to power
swings are considered, the entity must consider Disturbances since January 1, 2003 in order to
capture the August 14, 2003 Blackout.5 In consideration that BES topologies change, the
Requirement includes a provision to exclude the Element where a historical Disturbance is no
longer credible; meaning the Disturbance is no longer capable of occurring in the future due to
actual changes to the BES.
The second criterion involves the formation of an island based on an actual Disturbance. While
the island may form due to various transmission circuits tripping for a combination of reasons,
such as power swings (stable or unstable), faults, or excessive loading, the criterion requires that
all lines that tripped to form the island be identified as meeting the criterion. This criterion also
has an exception similar to the first criterion. Any event that caused an actual island to form since
August 1, 2003 that is no longer credible due to actual changes to the BES is not required be used
to identify Elements as meeting the criterion.
For example, assume eight lines connect an area containing generation and load to the rest of the
BES, and five of the lines terminate on a single straight bus. Assume a forced outage of the straight
bus in the past caused an island by tripping open the five lines connecting to the straight bus, and
subsequently causing the other three lines into the area to trip on power swings or excessive
loading. If the BES is reconfigured such that the five lines into the straight bus are now divided
between two different substations, a single Disturbance that caused the five lines to open is no
longer a credible event; therefore, these Elements should not be identified as meeting the criterion
based on this particular event. If any other event remains credible for the Element, then it would
be identified under the criterion.
Requirement R3
The purpose of Requirement R3 is to provide alternatives for a Generator Owner or Transmission
Owner to demonstrate that Protection Systems on identified Elements are not susceptible to
tripping in response to power swings meeting specified conditions. It also provides alternatives for
5
http://www.nerc.com/pa/rrm/ea/pages/blackout-august-2003.aspx
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
the Generator Owner or Transmission Owner to obtain agreement from its Planning Coordinator,
Reliability Coordinator, and Transmission Planner that an existing or modified Protection System
is acceptable when providing security for the specified conditions would compromise dependable
tripping for faults or unstable power swings.
The first option in Requirement R3 allows the Generator Owner or Transmission Owner to
evaluate Elements identified in Requirements R1 or R2 to determine if load-responsive protective
relays at the terminals of each identified Element are susceptible to tripping in response to a stable
power swing. Specific criteria and system conditions are provided to analyze the characteristic of
the load-responsive protective relays of each Element.
The second option in Requirement R3 allows the Generator Owner or Transmission Owner to
exclude protective relays if they are blocked from tripping by power swing blocking (PSB). If PSB
is applied, it is expected that the relays were set in consultation with the Transmission Planner to
verify maximum slip rates, so that proper PSB settings can be applied. It is expected that Elements
utilizing PSB relays have been evaluated for susceptibility to tripping in response to stable power
swings, and thus can be excluded.
The third option in Requirement R3 allows the Generator Owner or Transmission Owner to modify
its Protection System to achieve the desired goal of reducing the likelihood of tripping on a stable
power swing. The Generator Owner or Transmission Owner may achieve this goal by meeting the
criterion used in the first option or by applying power swing blocking. Modifications to the
Protection System could include revising settings or logic, or replacing the Protection System. A
Corrective Action Plan (CAP) is employed to allow an entity the flexibility to identify the actions
and timetable to make the necessary adjustments. A CAP allows for outage scheduling, time for
design, procurement, and installation of new relaying or the application of new settings. The
amount of detail regarding the listing of the actions required to make the necessary changes to the
Protection System is left to the discretion and management of the entity.
The fourth option in Requirement R3 allows the Generator Owner or Transmission Owner for the
situation where making the Protection System secure for stable power swings, either through
modified settings or replacement, will either significantly decrease the dependability for tripping
for faults within its zone of protection or for tripping for out-of-step conditions. To ensure the risks
due to tripping for stable power swings are balanced against the risk due to the reduction in
dependability, and that reasonable effort to find viable Protection System modifications has been
made, the applicable Generator Owner and Transmission Owner must obtain agreement from the
Planning Coordinator, Reliability Coordinator, and Transmission Planner that tripping for a stable
power swing is acceptable. The entities may agree that the existing or modified Protection System
design and settings are acceptable. This option allows for cases where the existing Protection
System design and settings are not acceptable, but modifications that do not meet the criterion in
the first option result in an acceptable balance between dependability and security. In these cases,
a CAP is employed to allow an entity the flexibility to identify the actions and timetable to make
the necessary adjustments. A CAP allows for outage scheduling, time for design, procurement,
and installation of new relaying or the application of new settings. The amount of detail regarding
the listing of the actions required to make the necessary changes to the Protection System is left to
the discretion and management of the entity.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
Application to Transmission Owners
The criterion describes a lens characteristic formed in the impedance (R-X) plane that connects
the endpoints of the total system impedance together by varying the sending and receiving end
system voltages from 0 to 1.0 per unit, while maintaining a constant system separation angle across
the total system impedance (Figures 1 and 2). The total system impedance is determined by
summing the sending end source impedance, the line impedance in parallel with the Thévinen
equivalent transfer impedance, and the receiving end source impedance (Figure 3). This total
system source impedance is minimized to create a conservative, worst-case condition by including
all transmission Elements that represent a “normal” system configuration with generation set at
the value reported to the Transmission Planner. Further, sub-transient generator reactances are
used since they are smaller than the transient or synchronous reactances, and result in a smaller
source impedance and smaller separation angle in the graphical analysis (Figures 4 and 5).
The source impedances can be obtained by a number of different methods using commercially
available short circuit calculation tools.6 Most short circuit tools have a network reduction feature
that allows the user to select the local and remote terminal buses to retain. The first method reduces
the system to one that contains two buses, an equivalent generator at each bus (representing the
source impedance at the sending and receiving ends), and two parallel lines; one being the line
impedance of the protected line with relays being analyzed, the other being the transfer impedance
representing all other combinations of lines that connect the two buses together (Figure 3). Another
conservative method is to open both ends of the line in question, and apply a three-phase bolted
fault at each bus. The resulting source impedance at each end will be less than or equal to the actual
source impedance calculated by the network reduction method. Either method can be used to
develop the system source impedances at both ends.
The first two bullets of criterion 1, identify the system separation angles to be used to identify the
shape and size of the power swing stability boundary used to test load-responsive impedance relay
elements. Both bullets test impedance relay elements that are not supervised by power swing
blocking. The first bullet evaluates a system separation angle of at least 120 degrees that is held
constant while varying the sending and receiving end source voltages from 0 to 1.0 per unit, thus
creating a power swing stability boundary shaped like a lens about the system impedance. This
lens characteristic is compared to the tripping portion of the distance relay characteristic, that is,
the portion that is not supervised by load encroachment logic, or some other form of supervision
that restricts the distance element from tripping for heavy, balanced load conditions. If the
impedance characteristics are completely contained within the lens characteristic, the Element
passes the evaluation (Figures 6 and 7). A system separation angle of 120 degrees was chosen for
the evaluation where PSB is not applied because it is generally accepted in the industry that
recovery for a swing beyond this angle is unlikely to occur.7
6
Appendix in Out-Of-Step Protection Fundamentals and Advancements, by Demetrios A. Tziouvaras and Daqing
Hou, available at https://www.selinc.com (April 17, 2014).
7
“The critical angle for maintaining stability will vary depending on the contingency and the system condition at the
time the contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is
marginal and 120 degrees is generally accepted as an appropriate basis for setting out‐of‐step protection. Given the
importance of separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
The second bullet evaluates impedance relay elements at a system separation angle of less than
120 degrees, similar to the first criterion bullet described above. The angle evaluated must be
agreed upon by the Planning Coordinator, Reliability Coordinator, and Transmission Planner, and
tripping of the distance elements for stable power swings should not occur at this angle, as shown
by system planning or operating studies.
Figure 1. Graphical output showing the plotted R-X coordinates of the calculated lens
characteristic (orange plot) with a constant angle of 120 degrees and varying source voltages.
The equal EMF (VS = VR, where N = VS / VR = 1) coordinate is shown.
proper balance between dependable tripping for unstable power swings and secure operation for stable power
swings.” PSRPS Report at p. 28.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
Figure 2. Mathematical calculations for R-X coordinate plot in Figure 1.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
Figure 3. Calculation of total system impedance given sending-end source impedance ZS,
receiving-end source impedance ZR, line impedance ZL, and transfer impedance ZTR.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
Figure 4. A strong-source system with a line impedance of ZLine = 16 ohms is shown. This
represents a heavily-loaded system, using a maximum generation profile and using generator
sub-transient reactance. The zone 2 mho circle (set at 125% of ZLine) extends into the power
swing stability boundary (orange lens characteristic). Using the strongest source system is more
conservative because it shrinks the power swing stability boundary, bringing it closer to the mho
circle.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
Figure 5. A weak-source system with a line impedance of ZLine = 16 ohms is shown. This
represents a lightly-loaded system, using a minimum generation profile and/or using generator
transient reactance instead of using generator sub-transient reactance. The zone 2 mho circle
(set at 125% of ZLine) does not extend into the power swing stability boundary (orange lens
characteristic). Using a weaker source system expands the power swing stability boundary away
from the mho circle.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
Figure 6. The pilot zone 2 element (blue) is completely contained within the power swing
stability boundary (orange). This Element passes the Requirement R3 evaluation.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
Figure 7. The tripping portion (not blocked by load encroachment) of the pilot zone 2 element
(blue) is not completely contained within the power swing stability boundary (orange). This
Element does not pass the Requirement R3 evaluation.
Application to Generator Owners
Generators have a variety of load responsive protection relays that protect the generator from
abnormal operation and are subject to incorrect operation caused by stable power swings. They
include protective relays that operate on current or an impedance function. Specific relays are time
overcurrent, voltage controlled/restrained overcurrent, loss of field, and distance relays.
Impedance Type Relays
The determination of the apparent impedance at the generator terminals is complex, especially for
cases where there are multiple generators connected to a high-voltage bus. There are various
quantities that are interdependent as the disturbance progresses through the time domain whether
it is a stable or unstable power swing. These variances include changes in machine internal voltage,
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
speed governor action, voltage regulator action, the reaction of other local generators, and the
reaction of other interconnected transmission Elements. A transient stability program is used to
determine the apparent impedance for best results, especially for relays that are used for
transmission line backup protection. Distance and out-of-step relays that are subject to power
swings are connected at generator terminals and/or on the high-voltage side of the generator stepup (GSU) transformer. The loss of field relay(s) is connected at the generator terminals.
The electrical center will be in the transmission system for cases where the generator is connected
through a weak transmission system (high external system source impedance). Other cases where
the generator is connected through a strong transmission system, the electrical center will be inside
the unit connected zone. In either case, impedance relays connected at the generator terminals or
at the high-voltage side of the GSU may be subject to operation in response to stable power swings.
Impedance relays used to back-up transmission protection usually have a time delay trip and are
coordinated with local transmission line distance relay protection. Out-of-step relaying subject to
a stable power swing may not operate correctly if the settings are not properly applied. If it is
anticipated that the electrical center will be in the unit connected zone or the apparent impedance
would challenge the relay operation, the Transmission Planner must perform transient stability
studies to validate the existence of a power swing condition that a generator may experience. The
Generator Owner uses the apparent impedance plot in a time domain to verify correct settings.
The simplified method used in the Application to Transmission Owners section is also used here
to provide a helpful understanding of a stable power swing on load-responsive protective relays
for those cases where the generator is connected to the transmission system and there are no infeed
effects to be considered. For cases where infeed affects the apparent impedance (multiple unit
connected generators connected to a transmission switchyard), the Generator Owner will provide
the unit and relay data to the Transmission Planner for analysis. The quantities used to determine
the apparent impedance characteristics are the generator unsaturated generator X"d, GSU
impedance, transmission line impedance, and the system equivalent. A voltage range of 0.65 to
1.5 should be considered to cover the delay of internal voltage for generators under manual or
automatic voltage control.
Requirement R4
This requirement ensures that any Corrective Action Plan (CAP) developed in the previous
requirement is implemented through completion. Having such a requirement allows the entity’s
work toward making protection scheme adjustments measurable given the variability of the
timetables of each CAP.
To achieve the stated purpose of this standard, which is to ensure that relays do not operate in
response to stable power swings during non-fault conditions, the responsible entity is required to
implement and complete a CAP that addresses the relays that are at risk of tripping during a stable
power swing for the applicable Elements on the BES. Protection System owners are required in
the implementation of a CAP to update it when actions or timetable change, until completed.
Accomplishing this objective is intended to reduce the risk of the relays unnecessarily tripping
during stable power swings, thereby improving reliability and reducing risk to the BES.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Application Guidelines
The following are examples of actions taken to complete CAPs for a relay responding to a stable
power swing where a setting change was determined to be acceptable (without diminishing the
ability of the relay to protect for faults within its zone of protection).
Example R4a: Actions: Settings were issued on 6/02/2014 to reduce the zone 3 reach of
the KD-10 relay from 30 ohms to 25 ohms so that the relay characteristic is completely
contained within the lens characteristic identified by the criterion. The settings were
applied to the relay on 6/25/2014. CAP completed on 06/25/2014.
Example R4b: Actions: Settings were issued on 6/02/2014 to enable out-of-step blocking
on the SEL-321 relay to prevent tripping in response to stable power swings. The setting
changes were applied to the relay on 6/25/2014. CAP completed on 06/25/2014.
The following is an example of actions taken to complete a CAP for a relay responding to a stable
power swing that required the addition of an out-of-step blocking relay.
Example R4c: Actions: A project for the addition of an out-of-step blocking relay (KS) to
supervise the zone 3 (KD-10) relay was initiated on 6/5/2014 to prevent tripping in
response to stable power swings. The relay installation was completed on 9/25/2014. CAP
completed on 9/25/2014.
The following is an example of actions taken to complete a CAP with a timetable that required
updating for the replacement of the relay.
Example R4d: Actions: A project for the replacement of the KD-10 relays at both
terminals of line X with GE L90 relays was initiated on 6/5/2014 to prevent tripping in
response to stable power swings. The completion of the project was postponed due to line
outage rescheduling from 11/15/2014 to 3/15/2015. Following the timetable change, the
KD-10 relay replacement was completed on 3/18/2015. CAP completed on 3/18/2015.
The CAP is complete when all the documented actions to resolve the specific problem (i.e.,
unnecessary tripping during stable power swings) are completed.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 25, 2014)
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Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power
Swings
Requested Approvals
PRC-026-1 – Relay Performance During Stable Power Swings
Requested Retirements
None.
Prerequisite Approvals
None.
General Considerations
There are a number of factors that influence the determination of an implementation period for the
new proposed standard. The following factors may be specific to one or more of the applicable entities
listed below.
1. The effort and resources for all applicable entities to develop or modify internal processes
and/or procedures.
2. The effort and resources for all applicable entities to identify the Element(s) according to the
criterion in the Requirements.
3. The need for the Generator Owner or Transmission Owner to secure resources (e.g., availability
of consultants, if needed) to evaluate each load-responsive protective relay’s response to a
stable power swing for identified Elements.
4. The need for the Generator Owner or Transmission Owner to obtain agreement from the
Planning Coordinator, Reliability Coordinator, and Transmission Planner where necessary.
5. The amount of work that the Generator Owner or Transmission Owner will need from a
Planning Coordinator or Transmission Planner to perform simulations.
6. The period of time for a Generator Owner or Transmission Owner to take an Element outage, if
necessary, to modify the Protection System is driven through the Corrective Action Plan (CAP)
and is independent of the standard’s implementation period. The CAP includes its own
timetable which is at the discretion of the entity.
Applicable Entities
Generator Owner
Planning Coordinator
Reliability Coordinator
Transmission Owner
Transmission Planner
Effective Date
First day of the first full calendar year that is twelve months beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where regulatory approval is
not required, the standard becomes effective on the first day of the first full calendar year that is
twelve months beyond the date this standard is approved by the NERC Board of Trustees, or as
otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.
Justification
The implementation plan based on the general considerations above provides a minimum of one full
calendar year for the Generator Owner, Planning Coordinator, Reliability Coordinator, Transmission
Owner, and Transmission Planner to begin the annual cycle of becoming compliant with standard
regardless of the approval timing by the applicable NERC Board of Trustees or ERO governmental
authorities. For example, if the standard is adopted or approved on September 1, 2015, the standard
would become effective on January 1, 2017.
Implementation Plan (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings| April 25, 2014
2
Unofficial Comment Form
Project 2010-13.3 – Relay Loadability: Stable Power Swings
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard. The electronic comment form must be completed by 8 p.m. Eastern Monday,
June 9, 2014.
If you have questions please contact Scott Barfield-McGinnis, Standards Developer via email or by
telephone at (404) 446-9689.
The project page may be accessed by clicking here
Background Information
This posting is soliciting formal comment.
This is Phase 3 of a three-phased standard development that is focused on developing a new Reliability
Standard, PRC-026-1 – Relay Performance During Stable Power Swings, to address protective relay
operations due to stable power swings. The March 18, 2010, FERC Order No. 733, approved Reliability
Standard PRC-023-1 – Transmission Relay Loadability. In this Order, FERC directed NERC to address three
areas of relay loadability that include modifications to the approved PRC-023-1, development of a new
Reliability Standard to address generator protective relay loadability, and a new Reliability Standard to
address the operation of protective relays due to stable power swings. This project’s SAR addresses these
directives with a three-phased approach to standard development.
Phase 1 focused on making the specific modifications to PRC-023-1 and was completed in the approved
Reliability Standard PRC-023-2, which became mandatory on July 1, 2012. Phase 2 focused on developing
a new Reliability Standard, PRC-025-1 – Generator Relay Loadability, to address generator protective relay
loadability; Phase 2 is currently awaiting regulatory approval. This Phase 3 of the project focuses on
developing a new Reliability Standard, PRC-026-1 – Relay Performance During Stable Power Swings, to
address protective relay operations due to stable power swings. This Reliability Standard will establish
requirements aimed at preventing protective relays from tripping unnecessarily due to stable power
swings by requiring the Transmission Owners and Generator Owners to assess the security of protective
relay systems that are susceptible to operation during power swings, and take actions to improve security
for stable power swings where such actions would not compromise dependable operation for faults and
unstable power swings.
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Questions
1. Do you agree with the focused approach using the criteria (see R1 & R2) which came from
recommendations in the PSRPS technical document 1 (pg. 21 of 61)? If not, please explain why or
why not (e.g., the approach should be more narrow or more broad, and if so, the basis for a
different approach).
Yes
No
Comments:
1
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf
Unofficial Comment Form (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings (April 25, 2014)
2
2. Do you agree that the Planning Coordinator, Reliability Coordinator, and Transmission Planner are
the appropriate entities to identify the Elements that meet the criteria in Requirement R1? If not,
please explain why an entity is not appropriate and/or suggest an alternative that should identify
the Elements according to the criteria.
Yes
No
Comments:
3. Do you agree that the Generator Owner and Transmission Owner are the appropriate entities to
identify the Elements that meet the criteria in Requirement R2? If not, please explain why an
entity is not appropriate and/or suggest an alternative that should identify the Elements according
to the criteria.
Yes
No
Comments:
4. Do you agree with the approach in Requirement R3 to ensure that load-responsive protective
relays do not trip in response to stable power swings during non-Fault conditions for an identified
Element? If not, please explain.
Yes
No
Comments:
5. Do you agree with the proposed Violation Risk Factors (VRF) and Violation Severity Levels (VSL) for
the proposed requirements? If not, please provide a basis for revising a VRF and/or what would
improve the clarity of the VSLs.
Yes
No
Comments:
6. Does PRC-026-1, Application Guidelines and Technical Basis provide sufficient guidance, basis for
approach, and examples to support performance of the requirements? If not, please provide
specific detail that would improve the Guidelines and Technical Basis.
Yes
No
Comments:
Unofficial Comment Form (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings (April 25, 2014)
3
7. Do you agree with implementation period of the proposed standard based on the considerations
listed in the Implementation Plan? If not, please provide a justification for changing the proposed
implementation period.
Yes
No
Comments:
8. If you are aware of any conflicts between the proposed standard and any regulatory function, rule,
order, tariff, rate schedule, legislative requirement, or agreement please identify the conflict here:
Yes
No
Comments:
9. If you are aware of the need for a regional variance or business practice that should be considered
with this phase of the project, please identify it here:
Yes
No
Comments:
10. If you have any other comments on this Standard that you haven’t already mentioned above,
please provide them here:
Comments:
Unofficial Comment Form (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings (April 25, 2014)
4
Violation Risk Factors and
Violation Severity Level Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
(PRC-026-1 – Relay Performance During Stable Power Swings)
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: PRC-004-3 — Protection
System Misoperations.
Each primary requirement is assigned a VRF and a set of one or more VSLs. 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 ERO
Sanction Guidelines.
The Protection System Misoperations Standard Drafting Team applied the following NERC
criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this
project.
NERC Criteria - Violation Risk Factors
High R isk R equirem ent
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
M edium R isk R equirem ent
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric 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 electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
Low er R isk R equirem ent
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 electric system, or the
ability to effectively monitor and control the bulk electric 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 electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
The standard drafting team (SDT) also considered consistency with the FERC Violation Risk Factor
Guidelines for setting VRFs: 1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors 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: 2
•
•
•
•
•
•
•
•
•
•
•
•
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
Guideline (2) — Consistency within a Reliability Standard
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
2
Id. at footnote 15.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
2
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk
Factor 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.
NERC Criteria - Violation Severity Levels
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.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets
the full intent of the
requirement.
Moderate
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
High
Severe
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
3
FER C Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the
following four guidelines for determining whether to approve VSLs:
Guideline 1: Violation Severity Level Assignm ents Should Not Have the Unintended
Consequence of Low ering the Current Level of Com pliance
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 Assignm ents Should Ensure Uniform ity and
Consistency in the Determ ination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe
noncompliant performance.
Guideline 3: Violation Severity Level Assignm ent Should Be Consistent w ith the
Corresponding R equirem ent
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignm ent Should Be Based on A Single
Violation, Not on A Cum ulative Num ber 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 and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
4
VRF and VSL Justifications – PRC-026-1, R1
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a normal
condition.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area. However, violation of this requirement is unlikely to under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This requirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
5
VRF and VSL Justifications – PRC-026-1, R1
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The requirement is consistent with Reliability Standards FAC-014-2, R6 (“…Planning Authority shall identify
the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a normal
condition.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area. However, violation of this requirement is unlikely to under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
6
VRF and VSL Justifications – PRC-026-1, R1
Proposed VSL
Lower
Moderate
High
The responsible entity identified
an Element and provided
notification in accordance with
Requirement R1, but was more
than 60 calendar days and less
than or equal to 90 calendar days
late.
Severe
The responsible entity
identified an Element and
provided notification in
accordance with Requirement
R1, but was less than or equal
to 30 calendar days late.
The responsible entity
identified an Element and
provided notification in
accordance with Requirement
R1, but was more than 30
calendar days and less than or
equal to 60 calendar days late.
The responsible entity identified
an Element and provided
notification in accordance with
Requirement R1, but was more
than 90 calendar days late.
OR
The responsible entity failed to
identify an Element or to provide
notification in accordance with
Requirement R1.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is Element-driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the requirement is new.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a:
This requirement is not binary; therefore, this criterion does not apply.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
7
VRF and VSL Justifications – PRC-026-1, R1
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 VSL uses similar terminology to that used in the corresponding requirement, and is
therefore consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-026-1, R2
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
8
VRF and VSL Justifications – PRC-026-1, R2
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a normal
condition.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area. However, violation of this requirement is unlikely to under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This requirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
9
VRF and VSL Justifications – PRC-026-1, R2
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The requirement is consistent with Reliability Standards FAC-014-2, R6 (“…Planning Authority shall identify
the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a normal
condition.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area. However, violation of this requirement is unlikely to under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
10
VRF and VSL Justifications – PRC-026-1, R2
Proposed VSL
Lower
Moderate
High
The responsible entity identified
Element in accordance with
Requirement R2, but was more
than 60 calendar days and less
than or equal to 90 calendar days
late.
Severe
The responsible entity
identified Element in
accordance with Requirement
R2, but was less than or equal
to 30 calendar days late.
The responsible entity
identified Element in
accordance with Requirement
R2, but was more than 30
calendar days and less than or
equal to 60 calendar days late.
The responsible entity identified
Element in accordance with
Requirement R2, but was more
than 90 calendar days late.
OR
The responsible entity failed to
identify an Element in accordance
with Requirement R2.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is Element-driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the requirement is new.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
Guideline 2a:
This requirement is not binary; therefore, this criterion does not apply.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
11
VRF and VSL Justifications – PRC-026-1, R2
"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 VSL uses similar terminology to that used in the corresponding requirement, and is
therefore consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-026-1, R3
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to ensure the Protection System will not trip in response to a stable power swing for an identified
Element could in the planning time frame, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly and adversely affect the electrical state or capability of the bulk
electric system, or the ability to effectively monitor, control, or restore the bulk electric system. However,
violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading
failures, nor to hinder restoration to a normal condition.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
12
VRF and VSL Justifications – PRC-026-1, R3
If a Protection System is less secure during stable power swings, it increases the risk of tripping should the
Protection System be challenged by a power swing; However, violation of this requirement is unlikely to
lead to bulk electric system instability, separation, or cascading failures.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This requirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This requirement is consistent with Reliability Standard FAC-002-1, R1.3 (“…Evidence that the parties
involved in the assessment have coordinated and cooperated on…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure to ensure the Protection System will not trip in response to a stable power swing for an identified
Element could in the planning time frame, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly and adversely affect the electrical state or capability of the bulk
electric system, or the ability to effectively monitor, control, or restore the bulk electric system. However,
violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
13
VRF and VSL Justifications – PRC-026-1, R3
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading
failures, nor to hinder restoration to a normal condition.
If a Protection System is less secure during stable power swings, it increases the risk of tripping should the
Protection System be challenged by a power swing; However, violation of this requirement is unlikely to
lead to bulk electric system instability, separation, or cascading failures.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
Moderate
High
The responsible entity
performed one of the options
in accordance with
Requirement R3, but was less
than or equal to 30 calendar
days late.
The responsible entity
performed one of the options
in accordance with
Requirement R3, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is driven by exception. For example, each
Element that requires further review must be provided to the Transmission Planner for simulation to
determine the apparent impedance characteristics.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
The proposed VSL does not lower the current level of compliance because the requirement is new.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
The responsible entity performed
one of the options in accordance
with Requirement R3, but was
more than 60 calendar days and
less than or equal to 90 calendar
days late.
Severe
The responsible entity performed
one of the options in accordance
with Requirement R3, but was
more than 90 calendar days late.
OR
The responsible entity failed to
perform one of the options in
accordance with Requirement R3.
14
VRF and VSL Justifications – PRC-026-1, R3
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments 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
Guideline 2a:
This requirement is not binary; therefore, this criterion does not apply.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the corresponding requirement, and is
therefore consistent with the requirement.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
15
VRF and VSL Justifications – PRC-026-1, R4
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for a Protection System of an identified Element could in
the planning time frame, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. However, violation of a
medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by
the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage. However, violation of this requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This requirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
16
VRF and VSL Justifications – PRC-026-1, R4
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The requirement is consistent with Reliability Standards PRC-016-0.1, R2 (“…shall take corrective actions
to avoid future Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”),
FAC-003, R5 (“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure
continued vegetation management”) all of which have a VRF of Medium.
FERC VRF G4 Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for a Protection System of an identified Element could in
the planning time frame, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. However, violation of a
medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by
the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage. However, violation of this requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
The responsible entity
implemented, but failed to
update a CAP, when actions or
timetables changed, in
accordance with Requirement
R4.
Moderate
N/A
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
High
N/A
Severe
The responsible entity failed to
implement a CAP in accordance
with Requirement R4.
17
VRF and VSL Justifications – PRC-026-1, R4
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is driven by exception. For example, each
Element that requires further review must be provided to the Transmission Planner for simulation to
determine the apparent impedance characteristics.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the requirement is new.
FERC VSL G2
Violation Severity Level
Assignments 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
Guideline 2a:
This requirement is not binary; therefore, this criterion does not apply.
FERC VSL G3
Violation Severity Level
Assignment Should Be
The proposed VSL uses similar terminology to that used in the corresponding requirement, and is
therefore consistent with the requirement.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
18
VRF and VSL Justifications – PRC-026-1, R4
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
19
Table of Issues and Directives
Project 2010-13.3 – Relay Loadability: Stable Power Swings
Table of Issues and Directives Associated with PRC-026-1
Source
FERC Order
733
1
Issue or Directive Language
(including Para. #)
150. We will not direct the ERO to
modify PRC-023-1 to address stable
power swings. However, because both
NERC and the Task Force have
identified undesirable relay operation
due to stable power swings as a
reliability issue, we direct the ERO to
develop a Reliability Standard that
requires the use of protective relay
systems that can differentiate between
faults and stable power swings and,
when necessary, phases out protective
Section and/or
Requirement(s)
All requirements
Consideration of Issue or Directive
The PRC-026-1 standard is responsive to this
directive because it applies a focused approach to
identify BES Elements according to Requirement R1
for the Planning Coordinator, Reliability Coordinator,
and Transmission Planner. Similarly in Requirement
R2 for the Generator Owner and Transmission
Owner. The criterion used to identify a BES Element
is based on the PSRPS technical document (“PSRPS
Report”). 1
Requirement R3 is responsive to the directive by
requiring the Generator Owner and Transmission
Owner to perform one of the listed options in
Requirement R3.
NERC System Protection and Control Subcommittee technical document, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
Consideration of Issue or Directive
relay systems that cannot meet this
requirement.
The following is a summary of what each option
achieves:
We also direct the ERO to file a report
no later than 120 days of this Final Rule
addressing the issue of protective relay
operation due to power swings. The
report should include an action plan
and timeline that explains how and
when the ERO intends to address this
issue through its Reliability Standards
development process.
-Ensures that the Protection System without power
swing blocking (PSB) applied is not expected to trip in
response to a stable power swing.
AND
153. While we recognize that
addressing stable power swings is a
complex issue, we note that more than
six years have passed since the August
2003 blackout and there is still no
Reliability Standard that addresses
relays tripping due to stable power
swings. Additionally, NERC has long
identified undesirable relay operation
Table of Issues and Directives (PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
-Ensures that the Protection System is not expected
to trip in response to a stable power swing because
(PSB) is applied.
-Ensures a Corrective Action Plan (CAP) is developed
to modify the Protection System or apply power
swing blocking so that the Protection System is not
expected to trip in response to a stable power swing.
-Ensures that where earlier options do not result in
dependable fault detection or dependable out-ofstep tripping that the Generator Owner and
Transmission Owner: (a) obtain the agreement of the
Planning Coordinator, Reliability Coordinator, and
Transmission Planner that the existing Protection
System design and settings are acceptable, or (b) )
obtain the agreement of the Planning Coordinator,
Reliability Coordinator, and Transmission Planner
2
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
due to stable power swings as a
reliability issue. Consequently, pursuant
to section 215(d)(5) of the FPA, we find
that undesirable relay operation due to
stable power swings is a specific matter
that the ERO must address to carry out
the goals of section 215, and we direct
the ERO to develop a Reliability
Standard addressing undesirable relay
operation due to stable power swings.
162. The PSEG Companies also assert
that the Commission’s approach to
stable power swings should be inclusive
and include “islanding” strategies in
conjunction with out-of-step blocking
or tripping requirements. We agree
with the PSEG Companies and direct
the ERO to consider “islanding”
strategies that achieve the fundamental
performance for all islands in
Consideration of Issue or Directive
that a modification of the Protection System design,
settings, or both are acceptable, and develop a CAP
to implement the modification.
Requirement R4 requires the entity to implement
each developed CAP to modify the Protection
System.
Requirement R1, Criterion 3
and Requirement R2, Criterion
2.
Table of Issues and Directives (PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
Islanding strategies were considered during the
development of the proposed standard. It was
determined that consideration of islanding strategies
does not comport with the purpose of the proposed
standard. The proposed standard’s purpose is to
ensure that load-responsive protective relays do not
trip in response to stable power swings during nonFault conditions, not to determine where the
transmission system Elements should form island
boundaries.
3
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
developing the new Reliability Standard
addressing stable power swings.
Consideration of Issue or Directive
With respect to considering the islanding concern,
the proposed standard does require that an Element
that was part of a boundary that formed an island
since January 1, 2003 be identified as an that is
within the scope of the proposed standard.
Any identified Element(s) require the Generator
Owner and Transmission Owner entities to
determine whether its load-responsive protective
relays applied at the terminal of such an Element, if
any, are susceptible to tripping in response to a
stable power swing. If so, the Generator Owner and
Transmission Owner is required to take specific
action according to the requirements to reduce the
risk that its load-responsive protective relays would
trip in response to stable power swings during nonFault conditions.
Issue(s)
None.
Table of Issues and Directives (PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25, 2014
4
Protection System
Response to Power Swings
System Protection and Control Subcommittee
August 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
NERC | Protection System Response to Power Swings | March 6, 2013
404-446-2560 | www.nerc.com
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NERC’s Mission
The North American Electric Reliability Corporation (NERC) is an international regulatory authority established to enhance
the reliability of the Bulk‐Power System in North America. NERC develops and enforces Reliability Standards; assesses
adequacy annually via a ten‐year forecast and winter and summer forecasts; monitors the Bulk‐Power System; and
educates, trains, and certifies industry personnel. NERC is the electric reliability organization for North America, subject to
oversight by the U.S. Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada.1
NERC assesses and reports on the reliability and adequacy of the North American Bulk‐Power System, which is divided into
eight Regional areas, as shown on the map and table below. The users, owners, and operators of the Bulk‐Power System
within these areas account for virtually all the electricity supplied in the U.S., Canada, and a portion of Baja California Norte,
México.
NERC Regional Entities
Note: The highlighted area between SPP RE and
SERC denotes overlapping Regional area
boundaries. For example, some load serving
entities participate in one Region and their
associated transmission owner/operators in
another.
FRCC
Florida Reliability
Coordinating Council
SERC
SERC Reliability Corporation
MRO
Midwest Reliability
Organization
SPP RE
Southwest Power Pool
Regional Entity
NPCC
Northeast Power
Coordinating Council
TRE
Texas Reliability Entity
RFC
ReliabilityFirst Corporation
WECC
Western Electricity
Coordinating Council
1
As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce Reliability
Standards with all U.S. users, owners, and operators of the Bulk‐Power System, and made compliance with those standards mandatory
and enforceable. In Canada, NERC presently has memorandums of understanding in place with provincial authorities in Ontario, New
Brunswick, Nova Scotia, Québec, and Saskatchewan, and with the Canadian National Energy Board. NERC standards are mandatory and
enforceable in Ontario and New Brunswick as a matter of provincial law. NERC has an agreement with Manitoba Hydro making Reliability
Standards mandatory for that entity, and Manitoba has recently adopted legislation setting out a framework for standards to become
mandatory for users, owners, and operators in the province. In addition, NERC has been designated as the “electric reliability
organization” under Alberta’s Transportation Regulation, and certain Reliability Standards have been approved in that jurisdiction; others
are pending. NERC and NPCC have been recognized as standards‐setting bodies by the Régie de l’énergie of Québec, and Québec has the
framework in place for Reliability Standards to become mandatory. NERC’s Reliability Standards are also mandatory in Nova Scotia and
British Columbia. NERC is working with the other governmental authorities in Canada to achieve equivalent recognition.
NERC | Protection System Response to Power Swings | August 2013
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Table of Contents
NERC’s Mission ............................................................................................................................................................................ 2
Table of Contents ......................................................................................................................................................................... 3
Executive Summary ..................................................................................................................................................................... 5
Introduction ................................................................................................................................................................................. 6
Issue Statement ....................................................................................................................................................................... 6
Chapter 1 – Historical Perspective ............................................................................................................................................... 7
November 9, 1965 ................................................................................................................................................................... 7
1965 Northeast Blackout Conclusions ................................................................................................................................. 8
July 13, 1977 New York Blackout ............................................................................................................................................. 8
1977 New York Blackout Conclusions .................................................................................................................................. 8
July 2‐3, 1996: West Coast Blackout ........................................................................................................................................ 8
July 2‐3, 1996: West Coast Blackout Conclusions ................................................................................................................ 9
August 10, 1996 ..................................................................................................................................................................... 10
August 10, 1996 Conclusions ............................................................................................................................................. 10
August 14, 2003 ..................................................................................................................................................................... 10
Perry‐Ashtabula‐Erie West 345 kV Transmission Line Trip ................................................................................................ 11
Homer City – Watercure and Homer – City Stolle Rd 345 kV Transmission Line Trips ...................................................... 13
Southeast Michigan Loss of Synchronism .......................................................................................................................... 15
2003 Northeast Blackout Conclusion ................................................................................................................................. 16
September 8, 2011 Arizona‐California Outages .................................................................................................................... 17
Other Efforts from the 2003 Blackout Affecting Relay Response to Stable Power Swings ................................................... 17
Overall Observations from Review of Historical Events ........................................................................................................ 17
Chapter 2 – Reliability Issues ..................................................................................................................................................... 18
Dependability and Security .................................................................................................................................................... 18
Trade‐offs Between Security and Dependability ................................................................................................................... 18
Chapter 3 – Reliability Standard Considerations ....................................................................................................................... 20
Need for a Standard ............................................................................................................................................................... 20
Applicability ........................................................................................................................................................................... 20
Identification of Circuits with Protection Systems Subject to Effects of Power Swings .................................................... 20
Benefits of Defining Applicability for Specific Circuit Characteristics ................................................................................ 21
Requirements ........................................................................................................................................................................ 21
Conclusions ................................................................................................................................................................................ 23
Recommendations ..................................................................................................................................................................... 24
Appendix A – Overview of Power Swings .................................................................................................................................. 25
General Characteristics .......................................................................................................................................................... 25
Impedance Trajectory ........................................................................................................................................................ 25
Appendix B – Protection Systems Attributes Related to Power Swings .................................................................................... 29
Desired Response .................................................................................................................................................................. 29
Response of Distance Protection Schemes ............................................................................................................................ 29
Power Swing Without Faults .............................................................................................................................................. 29
Appendix C – Overview of Out‐of‐Step Protection Functions ................................................................................................... 34
NERC | Protection System Response to Power Swings | August 2013
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Power Swing and Out‐of‐Step Phenomenon ......................................................................................................................... 34
Basic Phenomenon Using the Two‐Source Model ............................................................................................................. 34
Representation of Power Swings in the Impedance Plane ................................................................................................ 34
Rate of Change of the Positive‐Sequence Impedance ....................................................................................................... 35
Out‐of‐Step Protection Functions .......................................................................................................................................... 36
Power Swing Detection Methods ...................................................................................................................................... 37
Out‐of‐Step Tripping Function ........................................................................................................................................... 42
Issues Associated With the Concentric or Dual‐Blinder Methods ..................................................................................... 45
OOS Relaying Philosophy ................................................................................................................................................... 46
References ............................................................................................................................................................................. 47
Appendix D – Potential Methods to Demonstrate Security of Protective Relays ...................................................................... 48
IEEE PSRC WG D6 Method ..................................................................................................................................................... 48
Calculation Methods based on the Graphical Analysis Method ............................................................................................ 48
Method 1 ........................................................................................................................................................................... 49
Method 2 ........................................................................................................................................................................... 50
Voltage Dip Screening Method .............................................................................................................................................. 53
Discussion of the Results ................................................................................................................................................... 56
Practical Power System Example ....................................................................................................................................... 56
Appendix E – System Protection and Control Subcommittee ................................................................................................... 59
Appendix F – System Analysis and Modeling Subcommittee .................................................................................................... 60
Appendix G – Additional Contributors ....................................................................................................................................... 61
This technical document was approved by the NERC Planning Committee on August 19, 2013.
NERC | Protection System Response to Power Swings | August 2013
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Executive Summary
After the August 14, 2003 Northeast Blackout, the Federal Energy Regulatory Commission (FERC) raised concerns regarding
performance of transmission line protection systems during power swings. These concerns resulted in issuance of a
directive in FERC Order No. 733 for NERC to develop a Reliability Standard that requires the use of protective relay systems
that can differentiate between faults and stable power swings and, when necessary, phases out protective relay systems
that cannot meet this requirement. In the order, FERC stated that operation of zone 3 and zone 2 relays during the August
2003 blackout contributed to the cascade, and that these relays operated because they were unable to distinguish between
a dynamic, but stable power swing and an actual fault. FERC further cited the U.S.‐Canada Power System Outage Task Force
as identifying dynamic power swings and the resulting system instability as the reason why the cascade spread. While FERC
did direct development of a Reliability Standard, FERC also noted that it is not realistic to expect the ERO to develop
Reliability Standards that anticipate every conceivable critical operating condition applicable to unknown future
configurations for regions with various configurations and operating characteristics. Further, FERC acknowledged that relays
cannot be set reliably under extreme multi‐contingency conditions covered by the Category D contingencies of the TPL
Reliability Standards.
In response to the FERC directive, NERC initiated Project 2010‐13.3 – Phase 3 of Relay Loadability: Stable Power Swings to
address the issue of protection system performance during power swings. To support this effort, and in response to a
request for research from the NERC Standards Committee, the NERC System Protection and Control Subcommittee (SPCS),
with support from the System Analysis and Modeling Subcommittee (SAMS), has developed this report to promote
understanding of the overall concepts related to the nature of power swings; the effects of power swings on protection
system operation; techniques for detecting power swings and the limitations of those techniques; and methods for
assessing the impact of power swings on protection system operation.
As part of this assessment the SPCS reviewed six of the most significant system disturbances that have occurred since 1965
and concluded that operation of transmission line protection systems during stable power swings was not causal or
contributory to any of these disturbances. Although it might be reasonable, based on statements in the U.S.‐Canada Power
System Outage Task Force final report, to conclude this was a causal factor on August 14, 2003, subsequent analysis clarifies
the line trips that occurred prior to the system becoming dynamically unstable were a result of steady‐state relay
loadability. The causal factors in these disturbances included weather, equipment failure, relay failure, steady‐state relay
loadability, vegetation management, situational awareness, and operator training. While tripping on stable swings was not
a causal factor, unstable swings caused system separation during several of these disturbances. It is possible that the scope
of some events may have been greater without dependable tripping on unstable swings to physically separate portions of
the system that lost synchronism.
Based on its review of historical events, consideration of the trade‐offs between dependability and security, and recognizing
the indirect benefits of implementing the transmission relay loadability standard (PRC‐023), the SPCS concludes that a NERC
Reliability Standard to address relay performance during stable power swings is not needed, and could result in unintended
adverse impacts to Bulk‐Power System reliability.
The SPCS came to this conclusion in the course of responding to the Standards Committee request for research. During this
process the SPCS evaluated several alternatives for addressing the concerns stated in Order No. 733. While the SPCS
recommends that a Reliability Standard is not needed, the SPCS recognizes the directive in FERC Order No. 733 and the
Standards Committee request for research to support Project 2010‐13.3. Therefore, the SPCS provides recommendations
for applicability and requirements that can be used if NERC chooses to develop a standard. The SPCS recommends that if a
standard is developed, the most effective and efficient use of industry resources would be to limit applicability to
protection systems on circuits where the potential for observing power swings has been demonstrated through system
operating studies, transmission planning assessments, event analyses, and other studies, such as UFLS assessments, that
have identified locations at which a system separation may occur. The SPCS also proposes, as a starting point for a standard
drafting team, criteria to determine the circuits to which the standard should be applicable, as well as methods that entities
could use to demonstrate that protection systems on applicable circuits are set appropriately to mitigate the potential for
operation during stable power swings.
NERC | Protection System Response to Power Swings | August 2013
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Introduction
Issue Statement
After the August 14, 2003 Northeast Blackout, the Federal Energy Regulatory Commission (FERC) raised concerns regarding
performance of transmission line protection systems during power swings. These concerns resulted in issuance of a
directive in FERC Order No. 733 for NERC to develop a Reliability Standard that requires the use of protective relay systems
that can differentiate between faults and stable power swings and, when necessary, phases out protective relay systems
that cannot meet this requirement. In the order, FERC stated that operation of zone 3 and zone 2 relays during the August
2003 blackout contributed to the cascade, and that these relays operated because they were unable to distinguish between
a dynamic, but stable power swing and an actual fault. FERC further cited the U.S.‐Canada Power System Outage Task Force
as identifying dynamic power swings and the resulting system instability as the reason why the cascade spread. While FERC
did direct development of a Reliability Standard,2 FERC also noted that it is not realistic to expect the ERO to develop
Reliability Standards that anticipate every conceivable critical operating condition applicable to unknown future
configurations for regions with various configurations and operating characteristics. Further, FERC acknowledged that relays
cannot be set reliably under extreme multi‐contingency conditions covered by the Category D contingencies of the TPL
Reliability Standards.
In response to the FERC directive, NERC initiated Project 2010‐13.3 – Phase 3 of Relay Loadability: Stable Power Swings to
address the issue of protection system performance during power swings. To support this effort, and in response to a
request for research from the NERC Standards Committee, the NERC System Protection and Control Subcommittee (SPCS),
with support from the System Analysis and Modeling Subcommittee (SAMS), has developed this report to promote
understanding of the overall concepts related to the nature of power swings; the effects of power swings on protection
system operation; techniques for detecting power swings and the limitations of those techniques; and methods for
assessing the impact of power swings on protection system operation. The SPCS also proposes, as a starting point for a
standard drafting team, criteria to determine the circuits to which the standard should be applicable, as well as methods
that entities could use to demonstrate that protection systems on applicable circuits are appropriately set to mitigate the
potential for operation during stable power swings.
The SPCS recognizes there are many documents available in the form of textbooks, reports, and transaction papers that
provide detailed background on this subject. Therefore, in this report, the SPCS has intentionally limited information on
subjects covered elsewhere to an overview of the issues and has provided references that can be consulted for additional
detail. The subject matter unique to this report discusses the issues that must be carefully considered, to avoid unintended
consequences that may have a negative impact on system reliability, when addressing the concerns stated in Order No.
733.
2
Transmission Relay Loadability Reliability Standard, 130 FERC 61,221, Order No. 733 (2010) (“Order No. 733”) at P.152.
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Transient conditions occur following any system perturbation that upsets the balance of power on the interconnected
transmission system, such as changes in load, switching operations, and faults. The resulting transfer of power among
generating units is oscillatory and often is referred to as a power swing. The presence of a power swing does not necessarily
indicate system instability, and in the vast majority of cases, the resulting power swing is a low‐magnitude, well‐damped
oscillation, and the system moves from one steady‐state operating condition to another. In such cases the power swings
are of short duration and do not result in the apparent impedance swinging near the operating characteristic of protective
relays. Examples of this behavior occurred on August 14, 2003, when there were ten occurrences of transmission lines
tripping due to heavy line loading. Each line trip resulted in a low‐magnitude, well‐damped transient and the transmission
system reaching a new stable operating point; however, due to the heavy line loading the apparent impedance associated
with the new operating point was within a transmission line relay characteristic.3 Secure operation of protective relays for
these conditions is addressed by NERC Reliability Standards PRC‐023 – Transmission Relay Loadability and PRC‐025 –
Generator Relay Loadability.4
Power swings of sufficient magnitude to challenge protection systems can occur during stressed system conditions when
large amounts of power are transferred across the system, or during major system disturbances when the system is
operating beyond design and operating criteria due to the occurrence of multiple contingencies in a short period of time.
During these conditions the angular separation between coherent groups of generators can be significant, increasing the
likelihood that a system disturbance will result in higher magnitude power swings that exhibit lower levels of damping. It is
advantageous for system reliability that protective relays do not operate to remove equipment from service during stable
power swings associated with a disturbance from which the system is capable of recovering. Secure operation of protective
relays for these conditions is the subject of a directive in Order No. 733, and is the subject of Project 2010‐13.3 – Phase 3 of
Relay Loadability: Stable Power Swings.
Under extreme operating conditions a system disturbance may result in an unstable power swing of increasing magnitude
or a loss of synchronism between portions of the system. It is advantageous to separate the system under such conditions,
and operation of protection systems associated with system instability is beyond the scope of the standard directed in
Order No. 733. However, it is important that actions to address operation during stable power swings do not have the
unintended consequence of reducing the dependability of protection systems to operate during unstable power swings.
Six major system disturbances are described below, including a discussion of the relationship between power swings and
protection system operation and whether operation of protective relays during stable swings was causal or contributory to
the disturbance.
November 9, 1965
The November 1965 blackout, which occurred in the Northeastern United States and Ontario, provides an example of
steady‐state relay loadability being causal to a major blackout.
The event began when 230 kV transmission lines from a hydro generating facility were heavily loaded due to high demand
of power from a major load center just north of the hydro generating facility. Heavy power transfers prior to the
disturbance resulted from the load center area being hit by cold weather, coupled with an outage of a nearby steam plant.
The transmission line protection included zone 3 backup relays, which were set to operate at a power level well below the
capacity of the lines. The reason for the setting below the line capacity was to detect faults beyond the next switching point
from the generating plant. From the time the relays were initially set, the settings remained unchanged while the loads on
the lines steadily increased.
Under this circumstance a plant operator, who was apparently unaware of the installed relay setting limitation, attempted
to increase power transfer on one of the 230 kV lines. As a result, the load impedance entered the operating characteristics
3
Informational Filing of the North American Electric Reliability Corporations in Response to Order 733‐A on Rehearing, Clarification, and
Request for an Extension of Time, Docket No. RM08‐13‐000 (July 21, 2011) (“NERC Informational Filing”), at p. 4.
4
PRC‐025‐1 is presently in development under Project 2010‐13.2 Phase 2 of Relay Loadability: Generation.
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of the zone 3 line backup relay. The relay operated and tripped the line breaker. Subsequently, the rest of the lines became
overloaded. As it happened, each line breaker was tripped by the zone 3 line backup relay one‐by‐one over a period of
approximately 2.7 seconds.
When all five lines tripped, the hydro generators accelerated rapidly due to the initial reduction of connected electrical
load. The resulting drop in generation at this hydro plant and the rapid build‐up of generation in the interconnected system
resulted in large power swings that resulted in a loss of synchronism between two portions of the system. This incident
initiated a sequence of events across the power system of the northeastern seaboard. The resulting massive outage lasted
from a few minutes in some locations to more than a few days in others and encompassed 80,000 square miles, directly
affecting an estimated 30 million people in the United States and Canada. This was the largest recorded blackout in history
at the time.
1965 Northeast Blackout Conclusions
Relays tripping due to stable power swings were not contributory or causal factors in this blackout. Relays applied to 230 kV
transmission lines tripping due to load and a lack of operator knowledge of relay loadability limitations caused and
contributed to this outage. The Bulk‐Power System is protected against a recurrence of this type of event by the
requirements in NERC Reliability Standard PRC‐023‐2.
July 13, 1977 New York Blackout
This disturbance resulted in the loss of 6,000 MW of load and affected 9 million people in New York City. Outages lasted for
up to 26 hours. A series of events triggering the separation of the Consolidated Edison system from neighboring systems
and its subsequent collapse began when two 345 kV lines on a common tower in northern Westchester County were struck
by lightning and tripped out. Over the next hour, despite Consolidated Edison (Con Edison) dispatcher actions, the system
electrically separated from surrounding systems and collapsed. With the loss of imports, generation in New York City was
not sufficient to serve the load in the city.
Major causal factors were:
Two 345 kV lines experienced a phase B‐to‐ground fault caused by a lightning strike.
A nuclear generating unit was isolated due to the line trips and tripped due to load rejection. Loss of the ring bus
also resulted in the loss of another 345 kV line.
About 18.5 minutes later, two more 345 kV lines tripped due to lightning. One automatically reclosed and one
failed to reclose isolating the last Con Edison interconnection to the northwest.
The resulting surge of power caused another line to trip due to a relay with a bent contact.
About 23 minutes later, a 345 kV line sagged into a tree and tripped out. Within a minute a 345/138 kV
transformer overloaded and tripped.
The tap‐changing mechanism on a phase‐shifting transformer carrying 1150 MW failed, causing the loss of the
phase‐shifting transformer.
The two remaining 138 kV ties to Con Edison tripped on overload isolating the system. Insufficient generation in the
isolated system caused the Con Edison island to collapse.
1977 New York Blackout Conclusions
Relays tripping due to stable power swings were not contributory or causal factors in this blackout. A series of line and
transformer trips due to weather, equipment failure, relay failure, and overloads caused and contributed to this outage.
July 2-3, 1996: West Coast Blackout
On July 2, 1996 portions of the Western Interconnection were unknowingly operated in an insecure state. The July 2
disturbance was initiated at 14:24 MST by a line‐to‐ground fault on the Jim Bridger – Kinport 345 kV line due to a flashover
to a tree. A protective relay on the Jim Bridger – Goshen 345 kV line misoperated due to a malfunctioning local delay timer,
de‐energizing the line and initiating a remedial action scheme which tripped two units at the Jim Bridger generating station.
The initial line fault, subsequent relay misoperation, inadequate voltage support, and unanticipated system conditions led
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to cascading outages causing interruption of service to several million customers and the formation of five system islands.
Customer outages affected 11,850 MW of load in the western United States and Canada, and Baja California Norte in
Mexico. Outages lasted from a few minutes to several hours.
Major causal factors were:
A 345 kV line sagged due to high temperatures and loading causing a flashover to a tree within the right‐of‐way
and the line was de‐energized properly. A second line simultaneously tripped incorrectly due to a protective relay
malfunction.
Output of a major generating plant was reduced by design due to the two line trips. Two of four generating units at
that plant were correctly tripped via a Remedial Action Scheme. The trips of these units caused frequency in the
Western Interconnection to decline.
About 2 seconds later, the Round Up – LaGrand 230 kV line tripped via a failed zone 3 relay.
About 13 seconds later a couple of small units tripped via field excitation overcurrent.
About 23 seconds later, the Anaconda – Amps (Mill Point) 230 kV line tripped via a zone 3 relay due to high line
loads.
Over the next 12 seconds, numerous lines tripped due to high loads, low voltage at line terminals, or via planned
operation of out‐of‐step relaying. Low frequency conditions existed in some areas during many of these trips.
The Western Interconnection separated into five planned islands designed to minimize customer outages and
restoration times. The separation occurred mostly by line relay operation with three exceptions: Utah was
separated from Idaho by the Treasureton Separation Scheme, Southern Utah separated by out‐of‐step relaying,
and Nevada separated from SCE by out‐of‐step relaying.
On July 3, 1996, at 2:03 p.m. MST a similar chain to the July 2, 1996 events began. A line‐to‐ground fault occurred on the
Jim Bridger – Kinport 345 kV line due to a flashover to a tree. A protective relay on the Jim Bridger – Goshen 345 kV line
misoperated due to a malfunctioning local delay timer, de‐energizing the line and initiating a remedial action scheme (RAS)
which tripped two units at the Jim Bridger generating station. Scheduled power limits were reduced on the California –
Oregon Intertie (COI) north‐to‐south pending the results of technical studies being conducted to analyze the disturbance of
the previous day. The voltage in the Boise area declined to about 205 kV over a three minute period. The area system
dispatcher manually shed 600 MW of load over the next two minutes to arrest further voltage decline in the Boise area,
containing the disturbance and returning the system voltage to normal 230 kV levels. All customer load was restored within
60 minutes.
The Western Systems Coordinating Council Disturbance Report For the Power System Outages that Occurred on the
Western Interconnection on July 2, 1996 and July 3, 1996 approved by the WSCC Operations Committee on September 19,
1996 includes numerous recommendations one of which is the following:
The WSCC Operations Committee shall oversee a review of out‐of‐step tripping and out‐of‐step blocking within the
WSCC region to evaluate adequacy. This includes:
1.
Out‐of‐step relays that operated;
2.
Out‐of‐step relays that did not operate but should have; and
3.
Out‐of step conditions that caused operation of impedance relays.
Work by C.W. Taylor5 following the disturbance report recommended the review of the use of zone 3 relays which
was a contributing factor to the severity of this disturbance.
July 2-3, 1996: West Coast Blackout Conclusions
Relays tripping due to stable power swings was not causal or contributory to the July 2‐3 West Coast Blackout. Out‐of‐step
relaying did play a role as a safety net designed to limit the extent and duration of customer outages and restoration times.
5
Taylor, C.W., Erickson, Dennis C., IEEE Computer Applications in Power, Vol. 10, Issue 1, 1997.
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Unstudied system conditions including unexpectedly high transfer conditions coupled with a series of line trips due to
vegetation intrusion, relay malfunctions, and relay loadability issues caused and contributed to this outage.
August 10, 1996
At 15:48 PST on August 10, 1996, a major system disturbance separated the Western Interconnection into four islands,
interrupting service to 7.5 million customers, with total load loss of 30,390 MW. The interruption period ranged from
several minutes to nearly nine hours.
The pre‐event system conditions in the Western Interconnection were characterized by high north‐to‐south flows from
Canada to California. At 15:42:37, the Allston – Keeler 500 kV line sagged close to a tree and flashed over, additionally
forcing the Pearl – Keeler 500 kV line out of service due to 500/230 kV transformer outage and breaker replacement work
at Keeler. The line was tripped following unsuccessful single‐pole reclosure. The 500 kV line outage caused overloading and
eventual tripping of several underlying 115 kV and 230 kV lines, also in part due to reduced clearances. System voltages
sagged partly because several plants were operated in var regulation mode. At 15:47:37, sequential tripping of all units at
McNary began due to excitation protection malfunctions at high field voltage as units responded to reduced system
voltages.
Bonneville Power Administration (BPA) automatic generation control (AGC) further aggravated the situation by increasing
generation in the upper Columbia area (Grand Coulee and Chief Joseph) to restore the generation‐load imbalance following
McNary tripping. As a result of the above outages and shift of generation northward, sustained power oscillations
developed across the interconnection. The magnitude of power and voltage oscillations further increased, as Pacific HVdc
Intertie controls started participating in the oscillation. These oscillations were a major factor leading to the separation of
the California – Oregon Intertie and subsequent islanding of the Western Interconnection system.
Ultimately, the magnitude of voltage and current oscillations caused opening of two COI 500 kV lines (Malin – Round
Mountain #1 and #2 500 kV lines) by switch‐onto‐fault relay logic. The third COI 500 kV line tripped 170 ms later. Some of
the power that was flowing into northern California surged east and then south through Idaho, Utah, Colorado, Arizona,
New Mexico, Nevada, and southern California. Numerous transmission lines in this path subsequently tripped due to out‐
of‐step conditions and low system voltage. Because at that time the Northeast – Southeast separation scheme was kept out
of service when all COI lines were in operation, the Western Interconnection experienced uncontrolled islanding. Fifteen
large thermal and nuclear plants in California and the desert southwest failed to ride through the disturbance and tripped
after the system islanding, thereby delaying the system restoration.
August 10, 1996 Conclusions
Relays tripping due to stable power swings were not causal or contributory to the August 10th West Coast Blackout. System
operation was unknowingly in an insecure state prior to the outage of the Keeler‐Allston 500 kV line due to reduced
clearances resulting from a season of rapid tree growth and stagnant atmospheric conditions. Outage of the Keeler‐Allston
500 kV line precipitated the overloading and tripping of underlying parallel 230 kV and 115 kV lines, causing undesirable
tripping of key hydro units, voltage drops, and subsequent increasing of power oscillations, all of which led to tripping of
the COI and other major transmission lines separating the Western Interconnection into four islands. The result was
widespread uncontrolled outage of generation and the interruption of service to approximately 7.5 million customers.
August 14, 2003
Similar to a number of the disturbances discussed above, the disturbance on August 14, 2003 concluded with line trips
during power swings that were preceded by many outages due to other causes. The progression of cascading outages on
August 14, 2003 was initially caused by lines contacting underlying vegetation (the basis for Blackout Recommendation 46
and FAC‐003), followed by a series of lines tripping due to steady‐state relay loadability issues (the basis for Blackout
Recommendation 8a7 and PRC‐023). After the system was severely weakened by these outages, line trips occurred in
response to power swings.
6
7
Approved by the NERC Approved by the Board of Trustees, February 10, 2004.
Ibid.
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In the days and hours preceding the early afternoon of August 14 the power system experienced a number of generation
and transmission outages that resulted in increased transfers of power between portions of the system. During the early
afternoon a number of lines tripped, first due to contact with underlying vegetation and then due to load encroaching into
the operating characteristics of phase distance relays. The events occurred over a period of hours, with sufficient time
between events for the system to find a new steady‐state condition after each event.
In Order No. 733 and Order No. 733‐A FERC discussed tripping of fourteen transmission lines to support the directive
pertaining to conditions in which relays misoperate due to stable power swings. FERC cited the Blackout Report8, stating the
system did not become dynamically unstable until at least the Thetford – Jewell 345 kV line tripped at 16:10:38 EDT. FERC
noted that up until this point, with each dynamic, but stable, power swing, the transmission system recovered and
appeared to stabilize. However, as the power swings and oscillations increased in magnitude, zone 3, zone 2, and other
relays on fourteen key transmission lines reacted as though there was a fault in their protective zone even though there
was no fault. These relays were not able to differentiate the levels of currents and voltages that the relays measured,
because of their settings, and consequently operated unnecessarily.9 The Commission’s directive pertains to conditions in
which relays misoperate due to stable power swings that were identified as propagating the cascade during the August
2003 Blackout.10
NERC subsequently clarified that the fourteen lines did not trip due to stable power swings; ten of these lines tripped in
response to the steady‐state loadability issue addressed by Reliability Standard PRC‐023, while the last four lines tripped in
response to dynamic instability of the power system. Although the Blackout Report states that the system did not become
dynamically unstable until at least after the Thetford – Jewell 345 kV transmission line trip11, subsequent analysis indicates
that the system became dynamically unstable following tripping of the Argenta – Battle Creek and Argenta – Tompkins 345
kV transmission lines, about two seconds earlier than stated in the Blackout Report. The operations not associated with
faults, up to and including the initial trips of Argenta – Battle Creek and Argenta – Tompkins lines, are associated with the
steady‐state loadability issue addressed by Reliability Standard PRC‐023.12
As the cascade accelerated, 140 discrete events occurred from 16:05:50 to 16:36. The last transmission lines to trip as result
of relay loadability concerns were the Argenta –Battle Creek and Argenta – Tompkins 345 kV transmission lines in southern
Michigan at 16:10:36. Upon tripping of these lines the disturbance entered into a dynamic phase characterized by
significant power swings resulting in electrical separation of portions of the power system. Within the time delay associated
with high‐speed reclosing (500 ms) the angles between the terminals of these lines reached 80 degrees and 120 degrees
respectively prior to unsuccessful high‐speed reclosing of these lines.
The next line trips in the sequence of events occurred as a result of power swings. These trips occurred on the Thetford –
Jewell and Hampton – Pontiac 345 kV transmission lines north of Detroit at 16:10:38. These lines tripped as the result of
apparent impedance trajectories passing through the directional comparison trip relay characteristics at both terminals of
each line. All subsequent line trips occurred as the result of power swings. All but two of these trips occurred during
unstable power swings. A few of the events relevant to this subject are discussed below.
Perry-Ashtabula-Erie West 345 kV Transmission Line Trip
The Perry – Ashtabula – Erie West 345 kV line is a three‐terminal line between Perry substation in northeast Ohio and Erie
West substation in northwest Pennsylvania, with a 345‐138 kV autotransformer tapped at the Ashtabula substation in
northeast Ohio. This transmission line trip is interesting because the line tripped at the Perry terminal by its zone 3 relay.
Typically zone 3 line trips are associated with relay loadability issues, as the zone 3 time delay typically is set longer than the
time it would take for a power swing to traverse the relay trip characteristic. The fact that the protection system trip was
initiated by the zone 3 relay raises questions as to whether the power swing was stable or unstable. The rate‐of‐change of
an apparent impedance trajectory typically is used as a discriminant to identify unstable swings, based on the assumption
that higher rates‐of‐change are associated with unstable swings. In this case the speed of the apparent impedance
8
U.S.‐Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes
and Recommendations (Apr. 2004) (“Blackout Report”).
9
Transmission Relay Loadability Reliability Standard, 134 FERC 61,127, Order No. 733‐A (2011) (“Order No. 733‐A”). Order No. 733‐A at
P.110.
10
Id, P.111.
11
Blackout Report at p. 82.
12
NERC Informational Filing, at p. 6.
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trajectory was relatively slow, as it would need to be to remain within the zone 3 characteristic long enough to initiate a
trip. Dynamic simulation of the event confirmed that while this swing was slow to develop, had the line not been tripped by
its zone 3 relay the swing eventually would have entered the zone 1 relay characteristic at the Erie West terminal followed
by a loss of synchronism condition.
Figure 1 presents the simulated apparent impedance trajectory observed from the Perry line terminal. This figure shows
that the apparent impedance swing was moving away from the relay characteristic up to the time of the Argenta – Battle
Creek and Argenta – Tompkins 345 kV line trips, at which time the trajectory reversed direction and entered the zone 3
relay characteristic from the second quadrant. The apparent impedance remained in the relay characteristic long enough to
initiate a zone 3 trip.
120
Apparent Reactance (Primary Ohms)
Argenta‐Battle Creek and
Argenta‐Tompkings trips
90
60
30
0
‐15
45
75
Apparent Resistance (Primary Ohms)
Figure 1: Apparent Impedance Trajectory for Perry – Ashtabula 345 kV Line on August 14, 2003
‐30
‐75
‐45
‐15
Figure 2 presents the simulated apparent impedance observed from the Erie West terminal. The first (green) apparent
impedance trajectory is the simulated trajectory with the zone 3 trip at Perry simulated. With the 345 kV path from Erie
West to Perry interrupted, the decreased flow on the line from Erie West into the 345‐138 kV transformer at Ashtabula
resulted in the apparent impedance moving to a new trajectory further from the Erie West terminal. The apparent
impedance trajectory was resimulated with tripping of the Perry terminal blocked. The second (blue) trajectory
demonstrates that the next swing would have been unstable, passing through the zone 1 relay characteristic and eventually
crossing the system impedance indicative of a loss of synchronism condition with the system angle increasing beyond 180
degrees.
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120
Simulation without Perry terminal trip
Apparent Reactance (Primary Ohms)
90
Simulation with Perry terminal trip
60
30
0
Perry terminal trip
75
‐15
45
Apparent Resistance (Primary Ohms)
Figure 2: Apparent Impedance Trajectory for Erie West – Ashtabula 345 kV Line on August 14, 2003
‐30
‐75
‐45
‐15
In addition to the Perry – Ashtabula – Erie West trip demonstrating that the apparent impedance trajectory of a power
swing can result in a time delayed trip, it also demonstrates that for severely stressed system conditions with a rapid
succession of events exciting multiple dynamic modes, the resulting apparent impedance trajectories may vary significantly
from the traditional textbook trajectories that are based on two‐machine system models. This points to the difficulty of
establishing standardized applications to address out‐of‐step conditions that are both secure and dependable for all
possible system conditions.
Homer City – Watercure and Homer – City Stolle Rd 345 kV Transmission Line Trips
These two transmission lines connect the Homer City generating plant in central Pennsylvania to the Watercure and Stolle
Rd substations in western New York. As the power swing traveled across the system, this was the next place the swing was
observable: along the interface between New York and the PJM Interconnection. These two transmission lines were tripped
by their respective zone 1 relays at Homer City.
The recorded and simulated powerflow across this interface are presented in Figure 3 below. Following the separation in
southern Michigan, two swings occurred between the New York and PJM systems. The first swing occurred at
approximately 16:10:39.5 corresponding to tripping of the Homer City – Watercure and Homer City – Stolle Road 345 kV
transmission lines. The second swing occurred approximately 4 seconds later corresponding with the New York‐PJM
separation completed by the Branchburg – Ramapo 500 kV line trip.
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Chapter 1 – Historical Perspective
5000
Real Power (MW)
3000
1000
Simulated
‐1000
Recorded
‐3000
16:10:48
16:10:52
16:10:44
Time (EST)
Figure 3: PJM-New York Interface Flow on August 14, 2003
‐5000
16:10:32
16:10:36
16:10:40
Since only two transmission lines between the PJM Interconnection and the New York system tripped during the first swing,
it raises the question as to whether these lines tripped on a stable swing, and if so, would these two portions of the system
have remained synchronized if all lines comprising the PJM‐New York interface had been in service at the time of the
second power swing.
The dynamic simulation was run twice for this time‐frame: once with the Homer City line trips modeled and once with the
Homer City line trips blocked. Figure 4 presents the apparent impedance for the Homer City terminal of the Homer City –
Watercure transmission line for each simulation.
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300
Apparent Reactance (Primary Ohms)
220
Simulation with Homer City
line trips simulated
Simulation with Homer City
line trips blocked
140
60
‐20
200
40
120
Apparent Resistance (Primary Ohms)
Figure 4: Apparent Impedance Trajectory for Homer City – Watercure 345 kV Line on
August 14, 2003
‐100
‐200
‐120
‐40
The first (green) apparent impedance trajectory shows the apparent impedance entering the zone 1 relay characteristic and
the line tripping (represented in the plot by the apparent impedance “jumping” to the origin. The second (blue) trajectory
representing the simulation with line tripping blocked demonstrates that the first swing was stable with the trajectory
turning around just after entering the zone 1 relay characteristic. On the next swing, occurring about 4 seconds later, it is
clear that the swing is unstable and the apparent impedance exits the relay characteristic through the second quadrant. The
plot shows that with tripping of these lines blocked that these two portions of the system lose synchronism and slip poles
as long as the two systems remain physically connected.
The blackout investigation team concluded that while these two lines did trip on a stable swing, these trips were not
contributory to the blackout since the lines would have tripped four seconds later on the next swing, which was unstable.
The blackout investigation team further concluded that since the protection systems on these lines did demonstrate the
potential for tripping on stable swings, the Transmission Owners should investigate changes that could be made to improve
the security of protection system operation on the Homer City 345 kV transmission lines to Watercure and Stolle Road. The
Transmission Owners have performed extensive testing of the out‐of‐step tripping and power swing blocking functions on
new protection systems using simulated power swings from the August 14, 2003 blackout investigation. This testing has
identified susceptibility of some protection systems to misoperate, which highlights the difficulty of providing both
dependable and secure operation for every conceivable critical operating condition, particularly when considering
conditions well beyond the N‐1 or N‐2 conditions for which power systems typically are designed and when considering
more complex swings with multiple modes and time‐varying voltage..
Southeast Michigan Loss of Synchronism
Following the Michigan East‐West separation and Perry – Ashtabula – Erie West trip, the power flow from Ontario to
Michigan and from Michigan to Ohio increased. During this time voltages in southeast Michigan began to drop rapidly. In
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response to the decreased voltage and corresponding drop in load, the generating units south of Detroit began to
accelerate rapidly and slipped two poles.
The system conditions associated with the generating units slipping two poles resulted in turbine trips on many of these
generating units. As mechanical power to the turbines was reduced, the generators slowed down and frequency in
southern Detroit began to decline. Many of these generating units rely on a reverse power relay to trip the generator after
the turbine is tripped and mechanical power is reduced. Since these units lost synchronism with the rest of the system the
electrical power on these units changed direction with each pole slip and the reverse power condition was not sustained
long enough for the reverse power relay to trip the unit. As a result, the southeast Michigan portion of the system operated
asynchronously while connected through the two 120 kV lines. Figure 5 illustrates the effect of the out‐of‐step conditions
on system voltage. The first trace (blue) is the recorded voltage at the Keith substation in southern Ontario which shows
five voltage swings of approximately 0.8 per unit corresponding to each pole slip until the mechanical input to the turbines
was tripped. This plot illustrates the voltage stress on equipment when two systems operate asynchronously without
dependable tripping for out‐of‐step conditions. Generating units may experience corresponding shaft stress during each
pole slip.
400
Simulated
320
Voltage (kV)
Recorded
240
160
80
16:10:48
16:10:52
16:10:44
Time (EST)
Figure 5: Keith Voltage During Southern Michigan Loss-of-Synchronism
0
16:10:32
16:10:36
16:10:40
2003 Northeast Blackout Conclusion
Relays tripping due to stable power swings were not contributory or causal factors in this blackout. Although it is
reasonable to conclude this was a causal factor based on statements in the Blackout Report and cited in FERC Order No. 733
and subsequent FERC orders, subsequent analysis cited in the NERC Informational filing clarifies that only two 345 kV lines
tripped in response to stable power swings, and these two trips occurred well into the cascading portion of the disturbance.
Simulations confirm that if the relays had not tripped these lines on the stable power swing, the relays would have tripped
on an unstable swing a few seconds later, with no significant difference in the subsequent events or the magnitude and
duration of the resulting outages. Recorded and simulated data also demonstrate the adverse effect of not having
dependable tripping for unstable power swings.
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Chapter 1 – Historical Perspective
September 8, 2011 Arizona-California Outages
This disturbance is well documented in the April 2012 FERC/NERC Staff Report on the September 8, 2011 Blackout, available
on the NERC website. Twenty seven findings and recommendations were made in this report. Relays tripping due to stable
power swings were not cited in any of the recommendations from the NERC/FERC report. Relays tripping due to stable
power swings were not contributory or causal factors in this blackout.
Other Efforts from the 2003 Blackout Affecting Relay Response to
Stable Power Swings
The August 14, 2003 northeast blackout spawned the effort that raised the bar on relay loadability. Efforts included the
“Zone 3” and “Beyond Zone 3” relays reviews that preceded development of the PRC‐023 Transmission Relay Loadability
standard. The SPCTF report, Protection System Review Program – Beyond Zone 3, dated December 7, 2006 identified that
22 percent of the 11,499 EHV relays reviewed required changes to meet the NERC Recommendation 8a criterion or a
Technical Exception (equivalent to the criteria under Requirement R1 of PRC‐023‐2). Methods used to attain the greater
loadability typically included limiting relay reaches or changing relay characteristic shapes or both. These relay changes
affected relays with the largest distance zones susceptible to tripping on stable power swings such as the Perry – Ashtabula
– Erie West zone 3 trip discussed above. In many cases these relay changes also affected distance zones that trip high‐speed
such as zone 2 functions that are part of communication‐assisted protection systems, and in some cases even zone 1 relays
that trip without intentional time delay. While it is not possible to quantify the extent to which these modifications
improved security against tripping for stable power swings, reducing the resistive reach of phase distance protection
functions does increase the power system angular separation necessary to enter the relay characteristic. Thus, these
changes increased security throughout North America for relays susceptible to tripping on stable power swings.
Overall Observations from Review of Historical Events
Relays tripping on stable power swings were not causal or contributory in any of the historical events reviewed. Causal
factors in the events included lines sagging into trees, lines tripping via relay action due to high loads, lines tripping due to
relay malfunctions, and other causes. These causes have been addressed in several NERC Reliability Standards.
Relays tripping on unstable swings occurred in several of the historical events reviewed. The tripping was not causal or
contributory as tripping on unstable swings occurs after the system has reached the point of instability, cascading, or
uncontrolled separation. However, it is possible that the scope of some events may have been greater without dependable
tripping on unstable swings to physically separate portions of the system that lost synchronism.
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Chapter 2 – Reliability Issues
Dependability and Security
When considering power swings, both facets of protection system reliability are important to consider. To support power
system reliability it is desirable that protection systems are secure to prevent undesired operation during stable power
swings. It also is desirable to provide dependable means to separate the system in the event of an unstable power swing.
Protection system security during stable swings is important to maintaining reliable power system operation. Unnecessary
tripping of transmission lines during stable power swings may lead to cascade tripping due to increased loading on parallel
circuits or may lead directly to power system instability by increasing the apparent impedance between two portions of the
system.
Ensuring that dependable means are available to separate portions of the system that have lost synchronism is essential to
maintaining reliable power system operation. Failing to physically separate portions of the system that have lost
synchronism will result in adverse impacts due to the system slipping poles, resulting in significant voltage and power flow
deviations occurring at the system slip frequency. Near the electrical center of the power swing the voltage deviations will
have amplitude of nearly 1 per unit, stressing equipment insulation. Rapid changes in power flow also stress equipment, in
particular rotating machines that are participating in the swings.
Trade-offs Between Security and Dependability
Secure and dependable operation of protection systems are both important to power system reliability. While methods for
discriminating between stable and unstable power swings have improved over time, ensuring both secure and dependable
operation for all possible system events remains a challenge. Testing out‐of‐step functions using simulated power system
swings from the August 14, 2003 blackout investigation has identified susceptibility of some protection systems to
misoperate, which highlights the difficulty of providing both dependable and secure operation for every conceivable critical
operating condition, particularly when considering conditions well beyond the N‐1 or N‐2 conditions for which power
systems typically are designed and when considering more complex swings with multiple modes and time‐varying voltage.
While the directive in Order No. 733 is focused on protective relays operating unnecessarily due to stable power swings, it
is important that focusing on this aspect of security does not occur to the detriment of system reliability by producing the
unintended consequence of decreasing ability to dependably identify unstable swings and separate portions of the system
that have lost synchronism.
It certainly is possible to provide transmission line protection that can discriminate between fault and power swing
conditions. Current‐based protection systems such as current differential or phase comparison can be utilized to provide a
high degree of security against operation for stable power swings. However, application of such protection systems in
locations where the system may be prone to unstable power swings does not provide a dependable means of separating
portions of the system that lose synchronism. In such cases it would be necessary to install out‐of‐step protection to initiate
system separation, which reintroduces the need to discriminate between stable and unstable power swings. Installing
current‐based protection systems does not remove the need to install impedance‐based back up protection, which
reintroduces the need to discriminate between stable and unstable power swings.
Recognizing that no one protection system design can provide security and dependability for all possible power swings
under all possible system conditions, two questions must be considered: (1) for what conditions must protection systems
operate reliably, and (2) under conditions for which reliable operation cannot be assured, should protection system design
err on the side of security or dependability. The trade‐offs between secure and dependable operation in response to
system faults are discussed much more frequently than the trade‐offs in response to power swings; however, there are
similarities when comparing fault and power swing conditions. In both cases, a lack of dependability is more likely to result
in an undesirable outcome. For a fault condition, a failure to trip will result in increased equipment damage and
acceleration of rotating machines that may result in system instability. For an unstable power swing, a failure to trip will
result in portions of the system slipping poles against each other and resultant increased equipment stress and an increased
probability of system collapse.
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Chapter 2 – Reliability Issues
By comparison, tripping an additional circuit in response to a fault may lead to unacceptable system performance; however,
the potential for equipment damage or instability is less than for a failure to trip, particularly in highly networked systems.
In theory tripping a circuit for a stable power swing may lead to cascade tripping of power system circuits; however,
analysis of historical events supports that the probability of undesirable system performance is less than for a failure to trip
for an unstable swing.
Given the relative risks associated with a lack of dependable operation for unstable power swings and the lack of secure
operation for stable swings, over‐emphasizing secure operation for stable powers swings could be detrimental to Bulk‐
Power System reliability. It therefore is preferable to emphasize dependability over security when it is not possible to
ensure both for all possible system conditions.
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Chapter 3 – Reliability Standard Considerations
Need for a Standard
Based on its review of historical events, consideration of the trade‐offs between dependability and security, and recognizing
the indirect benefits of implementing the transmission relay loadability standard (PRC‐023), the SPCS concludes that a NERC
Reliability Standard to address relay performance during stable swings is not needed, and could result in unintended
adverse impacts to Bulk‐Power System reliability.
In the course of coming to this conclusion, however, the SPCS has developed recommendations for implementing a
standard. Given the directive in FERC Order No. 733 and the Standards Committee request for research to support Project
2010‐13.3, the SPCS recommends that if a standard is developed it should include the following applicability and
requirements.
Applicability
Two options exist for developing requirements for secure operation of protection systems during power swings: (i) develop
requirements applicable to protection systems on all circuits, or (ii) identify the circuits on which a power swing may affect
protection system operation and develop requirements applicable to protection systems on those specific circuits. The
effort to assess every protection system to assure it will not operate during stable power swings would be significant. An
equally effective and more efficient approach would be to identify the types of circuits on which protection systems would
be challenged by power swings, and limit the applicability of a new standard to these circuits.
During development of this report the SPCS explored the possibility of recommending a standard applicable to all circuits
and requiring that entities verify for each circuit that either a power swing will not pass through the circuit or that the
protection system on the circuit would not operate for a stable power swing. The SPCS investigated several different
approaches including the analytical assessment and system study approaches described in Appendix D. Analysis of the
various approaches indicated that applying one or more of these approaches to each circuit would be a significant effort
with varying results that are dependent on the system topology and the assumptions specified for the analysis. Extreme
system topologies are often present during actual relay trips during power swings. These topologies would be very difficult
to anticipate in a study. The historical evidence supports taking a more efficient approach to limit burden on responsible
entities given the limited role that undesired tripping in response to stable power swings has played in major disturbances.
Such an approach is consistent with taking a risk‐based approach to Reliability Standards by focusing the applicability to
circuits on which protection systems are most likely to be affected during power swings.
This section recommends an approach for identifying those power system circuits on which protection systems are
susceptible to operation for stable power swings. Although past system disturbances do not provide specific input on which
circuits are most at risk, past disturbances demonstrate it is not necessary for a Reliability Standard to apply to all lines. In
the absence of direct input from past disturbances, the SPCS believes it is reasonable to recommend an approach that uses
information from existing planning and operating studies and experience, and physical attributes of power systems. This
approach provides the opportunity to effectively identify circuits of concern without requiring extensive, and in many cases
duplicative, studies. The recommended approach is an effective and efficient manner that can be used to limit the number
of circuits for which entities are required to evaluate and provide a basis for protection system response during power
swings.
Identification of Circuits with Protection Systems Subject to Effects of Power Swings
Power system swings, stable or unstable, are caused by the relative motion of generators with respect to each other. These
power swings manifest themselves as swings in the apparent impedance “seen” by protective relays due to the variations in
voltages and currents which occur during these swings. Power swings are classified as local mode or inter‐area mode. Local
mode oscillations are characterized by units at a generating station swinging with respect to the rest of the system. This is
in contrast to inter‐area mode oscillations, where a coherent group13 of generating stations in one part of the system is
swinging against another coherent group of generators in a different part of the system.
13
In this context, the generators in a coherent group exhibit similar waveforms for their rotor‐angle response to a system disturbance.
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Chapter 3 – Reliability Standard Considerations
The electrical center of a local mode swing tends to remain relatively close to the generating station that is causing the
swing. The electrical center of an inter‐area mode oscillation will occur between the two coherent groups of generators.
Therefore, it can be concluded that stable power swings are most likely to challenge protective relays on lines terminating
at generating stations or on lines between coherent groups of generators. This is a useful filter in identifying transmission
lines on which protective relays should be subject to the Reliability Standard.
The electrical center of a power swing is determined by physical characteristics of the system. The electrical center may
vary depending on the dispatch of generators and status of transmission equipment making it difficult to assure that all
possible power swings are identified. This is particularly true when considering power swings that may occur during major
system disturbances after a number of circuits have tripped. However, it is possible to identify the most likely locations of
electrical centers of power swings and focus attention on protections systems applied on the circuits where the electrical
centers exist. In the case of local mode oscillations the electrical center is most likely to occur in the generator step‐up
(GSU) transformer or on a transmission line connected to the bus on the high‐side of the GSU transformer. In the case of an
inter‐area oscillation the electrical center is more difficult to predict; however, the electrical center already will have been
identified if any planning or operating studies have identified the need to apply a System Operating Limit (SOL) based on
stability constraints, or if other studies or event analyses have identified the potential for tripping during a system
disturbance that includes power swings.
The standard drafting team should consider the following criteria in establishing the applicability of the Reliability Standard
to limit applicability to only those transmission lines on which protective relays are most likely to be challenged during
stable power swings.
Lines terminating at a generating plant, where a generating plant stability constraint is addressed by an operating
limit or Special Protection System (SPS) (including line‐out conditions).
Lines that are associated with a System Operating Limit (SOL) that has been established based on stability
constraints identified in system planning or operating studies (including line‐out conditions).
Lines that have tripped due to power swings during system disturbances.
Lines that form a boundary of the Bulk Electric System that may form an island.14
Lines identified through other studies, including but not limited to, event analyses and transmission planning or
operational planning assessments.
Benefits of Defining Applicability for Specific Circuit Characteristics
Limiting the applicability of a Reliability Standard provides a number of benefits.
Efforts may be more focused, creating the possibility to include dynamic simulations assessing a greater number of
fault types and system configurations.
It may be possible, subject to relay model availability, to model specific relay settings in the dynamic simulation
software, to more precisely identify the likelihood of a stable swing entering the relay characteristic. Including
relay models in transient stability simulations could be used to monitor security of settings and identify potential
concerns. Present software and computing developments are reducing limitations that historically have prevented
such modeling, as well as practical limits to managing the volume of data. However, models are not presently
available for all tripping relay characteristics, such as when load encroachment features are used to limit the trip
characteristic to meet relay loadability requirements.
Requirements
The following requirements should be applicable to the circuits identified in the preceding section to mitigate the risk of
protection systems operating during stable power swings.
A requirement for each Reliability Coordinator and Planning Coordinator to identify lines that meet the criteria in
the applicability section and notify the owners of applicable circuits.
14
See NERC Reliability Standard PRC‐006‐1 – Automatic Underfrequency Load Shedding, Requirement R1.
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Chapter 3 – Reliability Standard Considerations
A Functional Model entity with a wide‐area view should have responsibility for identifying the circuits to which the
standard is applicable. This approach promotes consistent application of the criteria and assures that facility
owners are aware of their responsibilities, given that a facility owner may not be aware of all relevant system
studies. It is most appropriate to assign this responsibility to the Reliability Coordinator and the Planning
Coordinator given their wide‐area view and awareness of reliability issues. Both entities should be involved since
stability issues may be identified in both operating and planning studies. The standard should require periodic
review to assure the list of applicable circuits is up‐to‐date.
A requirement for each facility owner to document its basis for applying protection to each of its applicable circuits
(as identified above), and provide this information to its Reliability Coordinator, Planning Coordinator, and
Transmission Planner.15
There are multiple ways for a facility owner to mitigate the potential of protection systems tripping for stable
power swings. In some cases conventional impedance‐based protection may be acceptable (e.g., on a short line a
mho characteristic may not be susceptible to tripping for stable swings), in other cases a modified protection
characteristic may be suitable, in some cases it may be appropriate to supervise the protection to enable or to
block tripping during power swings, and in some cases the consequences of failing to trip for an unstable swing
may be so significant that a risk of tripping for some stable swings is deemed in the best interest of Bulk‐Power
System reliability. Decisions whether to apply out‐of‐step protection should be made between the facility owner
who has knowledge of the protection system design and the Reliability Coordinator, Planning Coordinator, and
Transmission Planner who have knowledge of the characteristics of the power system performance. The
documented basis should include rationale for whether out‐of‐step protection is needed, and if so, whether out‐
of‐step tripping or power swing blocking is applied. Although this requirement is focused on documentation, this
information is necessary for Reliable Operation of the Bulk‐Power System. Entities responsible for operating and
planning the Bulk‐Power System need this information to understand how protection systems may respond during
extreme system conditions.
Entities may find the information presented in the appendices of this report useful in developing a basis for
applying protection to each applicable line.
The SPCS discussed additional requirements related to modeling the tripping functions of phase protection systems
responsive to power swings. Modeling these protective functions in transient stability simulations could be an effective
method of verifying that protection systems will not operate on stable power swings. Default phase distance relay models
exist in simulation software that can be used to monitor apparent impedance and identify lines and conditions where relay
operation is possible, as well as explicit models for many typical trip function characteristics. However, existing models do
not address some of the unique features, such as load encroachment, that many entities have utilized to meet the
transmission relay loadability requirements. The SPCS supports use of existing relay models in operating studies and
transmission planning assessments; however, the SPCS believes is not possible to implement a measurable requirement
until explicit models are available. NERC, through its technical committees, could monitor the availability of relay models
and provide further recommendations at an appropriate time.
Modeling the tripping functions of phase protection systems responsive to power swings would enable the Reliability
Coordinator, Planning Coordinator, and Transmission Planner to identify cases for which the protection systems applied are
susceptible to tripping on stable power swings. Simulation results could provide important feedback since it is not practical
to consider every potential power swing at the time settings are applied to a protection system. Given the difficulty of
identifying all potential power swings, it is important that any information obtained through actual events and system
studies is evaluated by the facility owner. In some cases this new information may identify the need to modify a protection
system design or its settings. Decisions to modify a protection system, or not, should be made between the facility owner
who has knowledge of the protection system design and the Reliability Coordinator, Planning Coordinator, and
Transmission Planner who have knowledge of the characteristics of both the power system performance and protection
system design. Decisions whether to modify a protection system should consider the need for dependable tripping during
unstable power swings in addition to the objective of secure operation for stable power swings.
15
This and subsequent requirements should include all entities responsible for assessing dynamic performance of the Bulk‐Power System.
The Reliability Coordinator has responsibility for operating studies and the Planning Coordinator and Transmission Planner have
responsibility for transmission planning assessments.
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Conclusions
Operation of transmission line protection systems was not causal or contributory to six of the most significant system
disturbances that have occurred since 1965. System separation during several of these disturbances did occur due to
unstable power swings, and it is likely that the scope of some events and potential for equipment damage would have been
greater without dependable tripping on unstable swings to physically separate portions of the system that lost
synchronism.
Given the relative risks associated with a lack of dependable operation for unstable power swings and the lack of secure
operation for stable swings, it is generally preferable to emphasize dependability over security when it is not possible to
ensure both for all possible system conditions. Prohibiting use of certain types of relays may have unintended negative
outcomes for Bulk‐Power System reliability.
Efforts to improve transmission relay loadability subsequent to the August 14, 2003 northeast blackout had a secondary
effect of reducing the susceptibility of some protection systems to tripping on stable power swings. While it is not possible
to quantify the extent to which these modifications improved security against tripping for stable power swings, reducing
the resistive reach of phase distance protection functions does increase the power system angular separation necessary to
enter the relay characteristic.
Although current‐only‐based protection is immune to operating during power swings, exclusive use of current‐only‐based
protection is not practical and would reduce dependability of tripping for system faults and unstable power swings. A
power system with no remote backup protection is susceptible to uncleared faults and the inability to separate during
unstable power swings during extreme system events. Although current‐only‐based protection is secure for stable power
swings and can be used on lines which require tripping on out‐of‐step conditions, additional separate out‐of‐step protection
is required. Application of impedance‐based backup protection and, where necessary, out‐of‐step protection, reintroduces
the need to discriminate between stable and unstable power swings.
Although many new algorithms exist to discriminate between stable and unstable swings, testing out‐of‐step functions
using actual power system swings has identified susceptibility of some protection systems to misoperate, which highlights
the difficulty of providing both dependable and secure operation.
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Recommendations
Based on its review of historical events, consideration of the trade‐offs between dependability and security, and recognizing
the indirect benefits of implementing the transmission relay loadability standard (PRC‐023), the SPCS concludes that a NERC
Reliability Standard to address relay performance during stable swings is not needed, and could result in unintended
adverse impacts to Bulk‐Power System reliability.
While the SPCS recommends that a Reliability Standard is not needed, the SPCS recognizes the directive in FERC Order No.
733 and the Standards Committee request for research to support Project 2010‐13.3. Therefore, the SPCS provides
recommendations for applicability and requirements that can be used if NERC chooses to develop a standard.
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Appendix A – Overview of Power Swings
General Characteristics
An electric power grid, consisting of generators connected to loads via transmission lines, is constantly in a dynamic state as
generators automatically adjust their output to satisfy real and reactive power demand. During steady‐state operating
conditions, a balance exists between the power generated and the power consumed, with the absolute differences in the
voltages between buses typically maintained within 5 percent and frequency within 0.02 Hz of nominal. In the balanced
system state, each generator in the system maintains its voltage and internal machine rotor angle at an appropriate
relationship with the other generators as dictated by required power flow conditions in the system.
Sudden changes in electrical power caused by power system faults, line switching, generator disconnection, or the loss or
connection of large blocks of load, disturb the balance between the mechanical power into and the required electrical
power out of generators, causing acceleration or deceleration of the generating units because the mechanical power input
responds more slowly than the generator electrical power. Such system disturbances cause the machine rotor angles of the
generators to swing or oscillate with respect to one another in the search for a new equilibrium state. During this period,
transmission lines will experience power swings, which can be stable or unstable, depending of the severity of the
disturbance. In a stable swing, the power system will return to a new equilibrium state where the generator machine rotor
angle differences are within stable operating range to generate power that is balanced with the load. In an unstable swing,
the generation and load do not find a balance and the machine rotor angles between coherent groups of generators
continue to increase, eventually leading to loss of synchronism between the coherent groups of generators. The location at
which loss of synchronism occurs is based on the physical attributes of the system and is unlikely to correspond to
boundaries between neighboring utilities. When synchronism is lost among areas of a power system, the areas should be
separated quickly to avoid equipment damage and to avoid possible collapse of the entire power system. Ideally, the
system is separated at predetermined locations into self‐contained areas, each of which can maintain a generation/load
balance, where the attainment of the balance may require appropriate generation or load shedding.
Impedance Trajectory
The dynamic state of the power system can be represented by the impedance “seen” at a bus in the power system. The two
machine equivalent shown in Figure 6 can be used to illustrate the concept, where the source voltages at the two ends of
the system, EG and EH, are constant magnitudes behind their transient impedances, ZG and ZH.
Figure 6: Two-Machine Equivalent of a Power System
Figure 7, the geometrical interpretation of the power equation for this simple two source system, shows the R‐X diagram
with a mho characteristic of the relay at Bus A, set to a typical zone 1 setting for protection of the line (line impedance is ZL).
The total impedance across the system is represented by Points G to H, where ZG extends from the origin to point G in the
third quadrant and ZH extends from the tip of ZL to Point H in the first quadrant.
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Appendix A – Overview of Power Swings
Figure 7: Illustration of Electrical Center of the Equivalent Power System
With EG and EH of equal magnitude and with a phase angle difference of (EG leading) the apparent impedance during a
swing will fall on a straight line perpendicular to and bisecting the total system impedance between G and H. As source EG
moves ahead of source EH in angle during a swing (with magnitudes of EG and EH equal), the angle increases. On the R‐X
diagram, the angle formed by the intersection of lines PG and PH at P is the angle of separation between the source
voltages EG and EH. Point P on the R‐X diagram of Figure 7 is the apparent impedance seen at Bus A. When = 90º, the
impedance lies on the circle whose diameter is the total impedance (GH) across the system. This is the point of maximum
load transfer between G and H. When reaches 120º, and beyond, the systems are not likely to recover.16 When the locus
intersects the total system impedance line GH, is 180º and the systems are completely out of phase. This point is called
the electrical center (at the mid‐point of the total system impedance when EG and EH are of equal magnitude). The voltage
is zero at this point and, therefore, it is equivalent to a three‐phase fault at the electrical center. As the impedance locus
moves to the left of impedance line GH, increases beyond 180º and eventually the systems will be in phase again. If the
systems are not separated, source EG continues to move ahead of source EH, and the cycle repeats itself. When the
impedance locus reaches the starting point of the swing, one slip cycle has been completed.
16
Application of Out‐of‐Step Blocking and Tripping Relays, John Berdy.
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Power (p.u)
Appendix A – Overview of Power Swings
Figure 8: Power Angle Curve
Figure 8 plots the power angle equation and shows the theoretical power transfer across a simplified transmission system
such as that shown in Figure 6 for various values of where is the angular difference between the voltages at the two
ends of the system. Normally, systems and transmission lines operate at low angles that are perhaps 30 degrees or less
(longer lines and weaker systems may operate at higher angles and shorter lines and stronger systems operate at lower
angles).
Transmission of power in actual power systems is more complex than in the simple two source model discussed above. Two
systems of coherent generators are typically connected by several lines of varying voltages. The plot of the power angle
equation will vary with system conditions. An example is illustrated in Figure 9. This example illustrates conditions that may
exist during a severe destabilizing fault and its aftermath. Prior to the fault, the system is stable, transmitting an amount of
power P1 from one system to the other. When the severe fault occurs, the transfer capability of the system is reduced. The
power delivered by the generators is less than the input from their prime movers, which causes the sending generators to
accelerate, increasing the angle between the systems. When the faulted line is cleared, the transfer capability is increased,
but to a lower level than the prefault level, due to the loss of the faulted line. The power delivered by the accelerated
generators at this angle is greater than the input from their prime movers, which causes the generators to decelerate. For
this condition, the system angle will continue to increase as the generators decelerate. If the angle is greater than 90
degrees, then the angle increases as the power delivered is lowered and the deceleration rate is reduced. If the angle
reaches 120 degrees and is still increasing, it is likely that the system will not reach equilibrium (the decelerating area A2
equals the accelerating area A1) before the power delivered by the generators decreases below the prime mover inputs. If
that occurs, the generators will accelerate again and pull out of synchronism.
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Appendix A – Overview of Power Swings
Figure 9: Power Angle Curve for Various Conditions
At any given relay location, it is impossible to predict all possible system configurations and power transfer capabilities. The
critical angle for maintaining stability will vary depending on the contingency and the system condition at the time the
contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is marginal and 120
degrees is generally accepted as an appropriate basis for setting out‐of‐step protection.17 Given the importance of
separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a proper balance between
dependable tripping for unstable power swings and secure operation for stable power swings.
17
Ibid.
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Appendix B – Protection Systems Attributes Related to Power
Swings
Desired Response
A transmission line protection system is required to detect line faults and trip appropriately. This applies during swing
conditions where, in addition, the following also applies:
(a) If the power swing is stable, from which the system will recover, a line protection should not operate because the
unnecessary loss of lines could exacerbate the power swing to the extent that a stable swing becomes unstable.
Hence, in this case, the relevant protections should be set to not operate on detection of a power swing. This may
be achievable by selection of the protection system operating characteristics and settings, or may require
dedicated logic to block operation.
(b) If the power swing is unstable, also referred to as an out‐of‐step condition, separation at predetermined locations
is desirable, as previously mentioned. To this end, line protection systems that should not trip on the out‐of step
condition should be blocked, while protection systems on lines that have been identified as the desired separation
points should have out‐of‐step tripping capability.
The blocking requirements set out in (a) and (b) above create a condition where if an internal fault occurs during the power
swing, the line protection is unable to perform its protection function, unless the blocking is removed. The challenge is the
manner in which the blocking can be reliably removed. Methods that have been used to address this condition are
discussed in the IEEE Power System Relaying Committee Working Group WG D6 report, Power Swing and Out‐of‐Step
Considerations on Transmission Lines, July 2005..
Response of Distance Protection Schemes
Power Swing Without Faults
Distance Elements
While it is evident from the illustration in Figure 7 that a swing locus can cause the apparent impedance to enter the relay
element characteristic, resulting in operation of the element, the performance of distance elements is dependent to some
extent on the relative magnitudes of system and line impedances. For example, if the line impedance is small compared to
the system impedances, it is likely that the various distance zones will trip only on swings from which the system will not
recover. This is illustrated in Figure 10 for the relay at Bus A (with three zones), showing that the swing locus will only enter
the distance relay characteristics when the angular separation between sources EG and EH exceeds 120º. In the case
illustrated, the angle must significantly exceed 120º . If the swing locus does not traverse zone 1 but traverses zone 2, the
response of the line protection depends on the scheme used, as discussed in the sections below.
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Appendix B – Protection Systems Attributes Related to Power Swings
Figure 10: Line Impedance is Small Compared to System Impedances
When the line impedance is large compared to the system impedances, the distance relay elements could operate for
swings from which the system could recover. This is illustrated in the example shown in Figure 11, where two zones are
shown for clarity. It is evident that zone 2 will operate before the angular separation of the systems exceeds 90º, while zone
1 will operate before angular separation of 120º is reached. In this case the protection system is susceptible to tripping on a
stable power swing unless the relay characteristic is modified or some form of blocking is provided to prevent tripping.
Time delayed zone 2 relays in a step distance scheme will trip if the locus resides within the characteristic for a time
exceeding the delay setting.
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Appendix B – Protection Systems Attributes Related to Power Swings
Figure 11: Line Impedance is Large Compared to System Impedances
Distance Relay Based Pilot Scheme Response to Power Swings
Figure 12 Shows impedance elements as they are typically applied in directional comparison pilot schemes. The green
characteristics represent zone 2 tripping elements. The tripping elements are used in both Directional Comparison Blocking
(DCB) schemes, and Permissive Over Reaching (POR) schemes. The red characteristics represent blocking elements. They
are used in all DCB schemes and many variations of POR schemes. Depending on the path of the impedance locus, power
swings will affect the performance of DCB and POR schemes differently.
To cause a POR scheme to open a line, the impedance locus must be within both zone 2 tripping characteristics
simultaneously. For POR schemes employing transient blocking functions, the locus must enter both tripping characteristics
within a short time of each other, usually within about a power cycle. A DCB scheme will open at least one line terminal any
time the locus enters either tripping characteristic, without also entering a blocking characteristic.
If the locus enters a blocking element, DCB schemes will transmit blocking signals, and POR terminals with blocking
elements will not respond to received permissive signals. If a fault occurs on the protected line subsequent to the power
swing locus entering the blocking element, a DCB scheme will trip. The performance of the POR terminal will depend on the
system strength behind the terminal and on details of the permissive scheme logic associated with the blocking function.
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Appendix B – Protection Systems Attributes Related to Power Swings
Figure 12: Directional Comparison Trip and Block
Response of Line Current Differential Protections
With recent advancements in digital communication systems, the current differential principle has been effectively applied
to line protection, providing good sensitivity for detection of line faults, including high resistance ground faults, while
maintaining high degree of selectivity between internal and external faults. Many of these characteristics apply during
power swing and out‐of‐step conditions. With the current differential principle measuring the current at one terminal of the
line and computing the differential current with the current levels transmitted from the other terminal(s), the protection
remains secure during a swing condition because the computed differential current remains below the threshold that
would signify a fault. With increasing angular separation between the swinging systems, the current levels at each of the
terminals increase beyond normal load levels, making the condition look like a through fault. Phase comparison protection
systems exhibit performance similar to current differential protection systems.
One shortcoming in the characteristics of these current‐only‐based protections is that during some portion of the power
swing, the protection could become insensitive to line faults. For example, if a line fault occurs at the electrical center of a
two‐terminal system when the angular separation between the swinging systems is 180, the current levels at the two
terminals are equal in magnitude and opposite in phase. This results in zero difference current, rendering the protection
blind to this fault condition. However, as the power swing moves away from the electrical center (i.e., as the angular
separation becomes different from 180), the difference current becomes non‐zero, re‐establishing the protection’s
sensitivity to detection of faults on the line being protected. Hence, the existence of the blind spot could delay the
detection of some faults, as the angular separation needs to move from a less favorable to a more favorable value. The
impact of this delay is system dependent, i.e., if the system slip is relatively fast, the delay could be minimal. For example, at
slip frequency of 5 Hz, angular separation of 180 takes place in 100 ms. so the blind spot could last for less than 10 ms. The
blind spot lasts for correspondingly longer periods of time when the slip frequency is reduced.
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The shortcoming discussed above may be inconsequential in many applications; however, current‐only‐based protection
systems have another shortcoming because backup protection is needed to address failures of the communication channel.
In practice, a second independent current‐based protection scheme could be applied to provide backup protection.
However, a power system with no remote backup protection is susceptible to uncleared faults unless back‐up protection is
applied. Although a current‐only‐based protection system is secure for stable power swings and can be used on lines which
require tripping on out‐of‐step conditions, an out‐of‐step tripping protection function is still required. Using an impedance‐
based back‐up protection or out‐of‐step tripping function reintroduces the need to discriminate between stable and
unstable power swings. The shortcomings of impedance‐based out‐of‐step tripping functions can be mitigated by applying
an integrated out‐of‐step tripping function that is supervised by non impedance‐based algorithms; however, testing out‐of‐
step tripping functions using simulated power system swings from the August 14, 2003 blackout investigation has identified
susceptibility of some such protection systems to misoperate.
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Appendix C – Overview of Out-of-Step Protection Functions
Power Swing and Out-of-Step Phenomenon
A power swing is a system phenomenon that is observed when the phase angle of one power source varies in time with
respect to another source on the same network. The phenomenon occurs following any system perturbation, such as
changes in load, switching operations, and faults, that alters the mechanical equilibrium of one or more machines. A power
swing is stable when, following a disturbance, the rotation speed of all machines returns to synchronous speed. A power
swing is unstable when, following a disturbance, one or more machines do not return to synchronous speed, thereby losing
synchronism with the rest of the system.
Basic Phenomenon Using the Two-Source Model
The simplest network for studying the power swing phenomenon is the two‐source model, as shown in Fig. 12. The left
source has a phase angle advance equal to θ, and this angle will vary during a power swing. The right source represents an
infinite bus, and its angle will not vary with time. This elementary network can be used to understand the behavior of more
complex networks, although it has limitations when considering swings with multiple modes and time‐varying voltages.
Figure 13: Two-source Equivalent Elementary Network
Representation of Power Swings in the Impedance Plane
Assuming the sources have equal impedance amplitude, for a particular phase angle θ, the location of the positive‐
sequence impedance (Z1) calculated at the left bus is provided by the following equation [1]:
Z1
V1S
ES
ZT •
– ZS
I1
ES – E R
(1)
In (1), ZT is the total impedance, as in:
ZT ZS ZL ZR
(2)
Assuming the two sources are of equal magnitude, the Z1 impedance locus in the complex plane is given by (3).
Z1
ZT
2
• 1 jcot ZS
2
(3)
When the angle θ varies, the locus of the Z1 impedance is a straight line that intersects the segment ZT orthogonally at its
middle point, as shown in Figure 14. The intersection occurs when the angular difference between the two sources is 180
degrees. When a generator torque angle reaches 180 degrees, the machine is said to have slipped a pole, reached an out‐
of‐step (OOS) condition, or lost synchronism.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Figure 14: Locus of the Z1 Impedance During a Power Swing with Sources of Equal Magnitude
When the two sources have unequal magnitudes such that n is the ratio of ES over ER, the locus of the Z1 impedance
trajectory will correspond to the circles shown in Figure 15. For any angle θ, the ratio of the two segments joining the
location of the extremity of Z1 (Point P) to the total impedance extremities A and B is equal to the ratio of the source
magnitudes.
n
ES PA
E R PB
(4)
The precise equation for the center and radius of the circles as a function of the ratio n can be found in [1].
X
PA
=n
PB
B
P
θ
n>1
Z1
n=1
R
A
n<1
Figure 15: Locus of the Z1 Impedance During a Power Swing with Sources of Unequal Magnitude
It should be noted that synchronous generators are not ideal voltage sources as represented in the equivalent two‐source
model. Furthermore, the impact of automatic voltage regulators must be considered. During a power swing, the ratio of
two power source magnitudes will not remain constant. Therefore, the resulting locus of the Z1 impedance will not follow a
unique circle, with the trajectory depending upon the instantaneous voltage magnitude ratio.
Rate of Change of the Positive-Sequence Impedance
Starting with (1) and assuming the two sources are of equal magnitude, the time derivative of the Z1 impedance is provided
by (5) [2].
dZ1
e j
jZ T •
dt
1 e j
2
•
d
dt
(5)
Assuming the phase angle has a linear variation with a slip frequency in radians per second given as:
d
dt
(6)
and using the identity:
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2
the rate of change of the Z1 impedance is finally expressed as:
1 e j 2 • sin
ZT
dZ1
•
dt
4 • sin 2
2
(7)
(8)
Equation (8) expresses the principle that the rate of change of the Z1 impedance depends upon the sources, transmission
line impedances, and the slip frequency, which, in turn, depend upon the severity of the power system disturbance.
As a consequence, any algorithm that uses the Z1 impedance displacement speed in the complex plane to detect a power
swing will depend upon the network impedances and the nature of the disturbance. Furthermore, the source impedances
vary during the disturbance and typically are not introduced into the relay settings so the relay cannot usually predict the
displacement speed.
Out-of-Step Protection Functions
The detection of power swings is performed with two fundamental functions: the power swing blocking (PSB) function and
the out‐of‐step tripping (OST) function [3]. The PSB function discriminates faults from stable or unstable power swings. The
PSB function blocks relay elements that are prone to operate during stable or unstable power swings to prevent system
separation in an indiscriminate manner. In addition, the PSB function unblocks previously blocked relay elements and
allows them to operate for faults, in their zone of protection, that occur during an out‐of‐step (OOS) condition.
The OST function discriminates stable from unstable power swings and initiates network islanding during loss of
synchronism. OST schemes are designed to protect the power system during unstable conditions, isolating unstable
generators or larger power system areas from each other with the formation of system islands, to maintain stability within
each island by balancing the generation resources with the area load.
To accomplish this, OST systems must be applied at preselected network locations, typically near the network electrical
center. The isolated portions of the system are most likely to survive when network separation takes place at locations that
preserve a close balance between load and generation. Since it is not always possible to achieve a load‐generation balance,
some means of shedding nonessential load or generation is necessary to avoid a collapse of the isolated portions of the
power system.
Many relay systems are prone to operate during an OOS condition, which may result in undesired tripping. Therefore, OST
systems may need to be complemented with PSB functions to prevent undesired relay system operations and to achieve a
controlled system separation. When transmission separation schemes trip before fault protective relays operate, it may be
desirable to not use the PSB function so that the fault protection can provide a last line of defense against asynchronous
conditions.
Typically, the location of OST relay systems determines the location where system islanding takes place during loss of
synchronism. However, it may be necessary in some systems to separate the network at a location other than the one
where OST is installed. This is accomplished with the application of a transfer tripping type of scheme.
Uncontrolled tripping during OOS conditions can cause damage to power system breakers due to high transient
overvoltages that appear across the breaker contacts when switching a line that contains the electrical center of a power
swing. The maximum transient recovery voltage occurs when the relative phase angle of the two systems is 180° during the
OOS condition. Circuit breaker opening angle should be considered in applying out‐of‐step protection for transmission
circuits because opening at angles greater than 120 degrees may cause excess voltage stress on the circuit breaker. When
selecting out‐of‐step relay settings it may be necessary to balance the potential breaker opening angle, the potential
adverse impact of transmission voltage dips associated with a loss of synchronism, and the need to avoid tripping for
recoverable swings.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Power Swing Detection Methods
There are many different methods that are used to detect power swings, each with its strengths and drawbacks [4]. This
section presents some of those detection methods.
Conventional Rate of Change of Impedance Methods
The rate of change of impedance methods are based on the principle that the Z1 impedance travels in the complex plane
with a relatively slow speed, whereas during a fault, Z1 switches from the load point to the fault location almost
instantaneously.
Blinder Schemes
Figure 16 shows an example of a single‐blinder scheme. This scheme detects an unstable power swing when the time
interval required to cross the distance between the right and left blinders exceeds a minimum time setting. The scheme
allows for the implementation of OST on the way out of the zone and cannot be used for PSB because the mho
characteristics will be crossed before the power swing is detected. This method is most commonly implemented in
conjunction with generator protection and not line protection.
Figure 16: Single-Blinder Characteristic
Figure 17 shows an example of a dual‐blinder scheme. During a power swing, the dual‐blinder element measures the time
interval T that it takes the Z1 trajectory to cross the distance between the outer and inner blinders. When this measured
time interval is longer than a set time delay, a power swing is declared. The set time delay is adjusted so that it will be
greater than the time interval measured during a fault and smaller than the time interval measured during the Z1 travel at
maximum speed. Using the dual‐blinder scheme, an OST scheme can be set up to either trip on the way into the zone or on
the way out of the zone.
Figure 17: Dual-Blinder Characteristic
Concentric Characteristic Schemes
Concentric characteristics for the detection of power swings work on the same principle as dual‐blinder schemes: after an
outer characteristic has been crossed by the Z1 impedance, a timer is started and the interval of time before the inner
characteristic is reached is measured. A power swing is detected when the time interval is longer than a set time delay.
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Characteristics with various shapes have been used, as shown in Figure 18. The dual‐quadrilateral characteristic
represented at the bottom right of Figure 18 has been one of the most popular.
Figure 18: Concentric Characteristic of Various Shapes
Nonconventional Power Swing Detection Methods
Continuous Impedance Calculation
The continuous impedance calculation consists of monitoring the progression in the complex plane (Figure 19) of three
modified loop impedances [5]. A power swing is declared when the criteria for all three loop impedances have been
fulfilled: continuity, monotony, and smoothness. Continuity verifies that the trajectory is not motionless and requires that
the successive R and X be above a threshold. Monotony verifies that the trajectory does not change direction by
checking that the successive R and X have the same signs. Finally, smoothness verifies that there are no abrupt changes
in the trajectory by looking at the ratios of the successive R and X that must be below some threshold.
Figure 19: Continuous Impedance Calculation
The continuous impedance calculation is supplemented by a concentric characteristic to detect very slow‐moving
trajectories.
One of the advantages of the continuous impedance calculation is that it does not require any settings and can handle slip
frequencies up to 7 Hz. It does not require, therefore, any power swing studies involving complex simulations.
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Continuous Calculation of Incremental Current
During a power swing, both the phase voltages and currents undergo magnitude variations. The continuous calculation of
the incremental current method computes the difference between the present current sample value and the value stored
in a buffer 2 cycles before (see Figure 20). This method declares a power swing when the absolute value of the measured
incremental current is greater than 5 percent of the nominal current and that this same condition is present for a duration
of 3 cycles [6].
I
I
Figure 20: Continuous Calculation of Incremental ΔI
The main advantage of the continuous calculation of incremental current is that it can detect very fast power swings,
particularly for heavy load conditions.
R-Rdot OOS Scheme
The R‐Rdot relay for OST was devised specifically for the Pacific 500 kV ac intertie and was installed in the early 1980s. The
R‐Rdot relay uses the rate of change of resistance to detect an OOS condition.
An impedance‐based control law for OOS detection is created by defining the following function [7‐8]:
dZ
(9)
dt
If we define a phase plane where the abscissa is the impedance magnitude and the ordinate is the rate of change of the
impedance magnitude, (9) represents a switching line. An OOS trip is initiated when the switching line is crossed by the
impedance trajectory from right to left. The effect of adding the impedance magnitude derivative is that the tripping will be
faster at a higher impedance changing rate. At a small impedance changing rate, the characteristic is equivalent to the
conventional OOS scheme.
In the R‐Rdot characteristic, the impedance magnitude is replaced by the resistance measured at the relay location and the
rate of change of the impedance magnitude is replaced by the rate of change of the measured resistance (see Figure 21).
The advantage of this latter modification is that the relay becomes less sensitive to the location of the swing center with
respect to the relay location.
U1 (Z – Z1 ) T1 •
dR
(10)
dt
In the R‐Rdot plane the switching line U1 is a straight line having slope T1. System separation is initiated when output U1
becomes negative. For low separation rates (small dR/dt), the performance of the R‐Rdot scheme is similar to the
conventional OST relaying schemes. However, higher separation rates (dR/dt) would cause a larger negative value of U1 and
initiate tripping much earlier. For a conventional OST relay without a rate of change of apparent resistance, augmentation is
just a vertical line in the R‐Rdot plane offset by the R1 relay setting parameter.
U1 (R – R1 ) T1 •
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R1
R1
Figure 21: R-Rdot OOS Characteristic in the Phase Plane
Rate of Change of Swing Center Voltage (SCV)
SCV is defined as the voltage at the location of a two‐source equivalent system where the voltage value is zero when the
angles between the two sources are 180 degrees apart. Figure 22 illustrates the voltage phasor diagram of a general two‐
source system, with the SCV shown as the phasor from origin o to the point o’.
Figure 22: Voltage Phasor Diagram of a Two-Source System
When a two‐source system loses stability and enters an OOS condition, the angle difference of the two sources, θ(t),
increases as a function of time [2]. We can represent the SCV with (11), assuming equal source magnitudes in a two‐source
equivalent system, E = |ES| = |ER|.
t
t
SCV t 2Esin t
• cos
2
2
(11)
SCV(t) is the instantaneous SCV that is to be differentiated from the SCV that the relay estimates. Equation (11) is a typical
amplitude‐modulated sinusoidal waveform. The first sine term is the base sinusoidal wave, or the carrier, with an average
frequency of ω + (1/2)(dθ/dt). The second term is the cosine amplitude modulation.
One popular approximation of the SCV obtained through the use of locally available quantities is as follows:
SCV VS • cos
(12)
where:
|VS| is the magnitude of locally measured voltage.
φ is the angle difference between VS and the local current, as shown in Figure 23.
The quantity of Vcosφ was first introduced by Ilar for the detection of power swings [9].
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Appendix C – Overview of Out‐of‐Step Protection Functions
Figure 23: Vcosφ is a Projection of Local Voltage, VS, onto Local Current, I
In Figure 23, we can see that Vcosφ is a projection of VS onto the axis of the current, I. For a homogeneous system with the
system impedance angles close to 90 degrees, Vcosφ approximates well the magnitude of the SCV. For the purpose of
power swing detection, it is the rate of change of the SCV that provides the main information of system swings. Therefore,
some difference in magnitude between the system SCV and its local estimate has little impact in detecting power swings.
We will, therefore, refer to Vcosφ as the SCV in the following discussion.
Using (11) and keeping in mind that the local SCV is estimated using the magnitude of the local voltage, VS, the relation
between the SCV and the phase angle difference, θ, of two source voltage phasors can be simplified to the following:
SCV1 E1• cos
2
(13)
In (13), E1 is the positive‐sequence magnitude of the source voltage, ES, shown in Figure 23 and is assumed to be also equal
to ER. The time derivative of SCV1 is given by (14).
d SCV1
E1 d
sin
dt
2
2 dt
(14)
Equation (14) provides the relationship between the rate of change of the SCV and the two‐machine system slip frequency,
dθ/dt. Equation (14) shows that the derivative of SCV1 is independent of power system impedances. Figure 24 is a plot of
SCV1 and the rate of change of SCV1 for a system with a constant slip frequency of 1 radian per second.
Figure 24: SCV1 and Its Rate of Change with Unity Source Voltage Magnitudes
Synchrophasor-Based OOS Relaying
Consider the two‐source equivalent network of Figure 13, and assume that the synchrophasors of the positive‐sequence
voltages are measured at the left and right buses as V1S and V1R.
The ratio of the two synchronized vectors is provided by the following equation:
ZS
Z
(1 – S ) • k E
V1S
ZT
ZT
V1R ZS ZL (1 – ZS ZL ) • k
E
ZT
ZT
(15)
where:
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kE is the ratio of the magnitudes of the source voltages:
kE
ES
ER
(16)
Assuming the source impedances are small with respect to the line impedance and the ratio kE is close to 1, the ratio of the
synchronized vectors can be approximated by unity for its magnitude and by the angle between the two sources for its
phase angle.
When using the two‐source network equivalent, the result of (15) indicates that the ratio of the synchrophasors measured
at the line extremities has a phase angle that can be approximated by the phase angle between the two sources. During a
disturbance, the trajectory of the phase angle between the two phasors replicates the variation of the phase angle between
the two machines. It is therefore possible to determine if an OOS condition is taking place when the measured phase angle
trajectory becomes unstable [10].
Reference 10 presents the implementation of three functions based on synchrophasor measurements, the purpose of
which is to trigger a network separation after a loss of synchronism has been detected. Positive‐sequence voltage‐based
synchrophasors are measured at two locations of the network, assuming that the two‐source equivalent can model the
network. Following the measurement of the synchrophasors, two quantities are derived: the slip frequency SR, which is the
rate of change of the angle between the two measurements, and the acceleration AR, which is the rate of change of the slip
frequency. The three functions are defined as follows:
Power swing detection is asserted when SR is not zero and is increasing, which indicates AR is positive and
increasing.
Predictive OST is asserted when, in the slip frequency against the acceleration plane, the trajectory falls in the
unstable region (see Figure 25) defined by the condition:
A R 78 _ Slope • SR A Offset
(17)
OOS detection asserts when the absolute value of the angle difference between the two synchrophasors becomes
greater than a threshold.
Figure 25: Predictive OST in the Slip-AccelerationPlane
A network separation or OST is initiated when the three functions are asserted.
Out-of-Step Tripping Function
The OST function protects the power system during unstable conditions by isolating unstable generators or larger power
system areas from each other by forming system islands. The main criterion is to maintain stability within each island. To
accomplish this, OST systems should be applied at preselected network locations, typically near the network electrical
center, to achieve a controlled system separation. The isolated portions of the system are most likely to survive when
network separation takes place at locations in the network that preserve a close balance between load and generation.
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Since it is not always possible to achieve a load‐generation balance, some means of shedding load or generation is
necessary to avoid a collapse of isolated portions of the power system.
OST systems may be complemented with PSB functions to prevent undesired relay system operations, equipment damage,
and the shutdown of major portions of the power system. In addition, PSB blocking may be applied at other network
locations to prevent system separation in an indiscriminate manner.
The selection of network locations for the placement of OST systems can best be obtained through transient stability
studies covering many possible operating conditions. The maximum rate of slip is typically estimated from angular change
versus time plots from stability studies. The stability study results are also used to identify the optimal location of OST and
PSB relay systems, because the apparent impedance measured by OOS relay elements is a function of the MW and Mvar
flows in transmission lines. Stability studies help identify the parts of the power system that impose limits on angular
stability, generators that are prone to go out of step during system disturbances and those that remain stable, and groups
of generators that tend to behave similarly during a disturbance.
Typically, the location of OST relay systems determines the location where system islanding takes place during loss of
synchronism. However, in some systems, it may be necessary to separate the network at a location other than the one
where OST is installed. This is accomplished with the application of a transfer tripping scheme. Current supervision may be
necessary when performing OST at a different power system location than the location of OST detection to avoid issuing a
tripping command to a circuit breaker at an unfavorable phase angle. Another important aspect of OST is to avoid tripping a
line when the angle between systems exceeds the circuit breaker capability. Tripping during this condition imposes high
stresses on the breaker and could cause breaker damage as a result of high recovery voltage across the breaker contacts,
unless the breaker is rated for out‐of‐phase switching [11].
Conventional OST Schemes
Conventional OST schemes are based on the rate of change of the measured positive‐sequence impedance vector during a
power swing. The OST function is designed to differentiate between a stable and an unstable power swing and, if the power
swing is unstable, to send a tripping command at the appropriate time to trip the line breakers. Traditional OST schemes
use distance characteristics similar to the PSB schemes shown in Figures 16, 17, and 18. OST schemes also use a timer to
time how long it takes for the measured impedance to travel between the two concentric characteristics. If the timer
expires before the measured impedance vector travels between the two characteristics, the relay declares the power swing
as an unstable swing and issues a tripping signal. Voltage supervision will increase the security of the OST scheme.
Figure 18 shows the dual‐quadrilateral characteristic used for the detection of power swings. When the positive‐sequence
impedance enters the outer zone, two OOS logic timers start (OSTD and OSBD). Figure 26 illustrates how these timers
operate.
There are two methods to implement out‐of‐step tripping. The first method is to trip on the way in (TOWI) when the OSTD
timer expires and the positive‐sequence impedance enters the inner zone. The second method is to select to trip on the
way out (TOWO) when the OSTD timer expires and the positive‐sequence impedance enters and then exits the inner zone.
TOWO has the advantage of tripping the breaker at a more favorable time during the slip cycle when the two systems are
close to an in‐phase condition.
TOWI is necessary in some systems to prevent severe voltage dips and potential loss of loads. TOWI is typically applied in
very large systems where the angular movement of one system with respect to another is very slow. It is also applied where
there is a risk that transmission line thermal damage will occur if tripping is delayed until a more favorable angle exists
between the two systems. However, it is necessary to evaluate potential trip conditions against the circuit breaker
capability because the relay issues the tripping command to the circuit breaker when the relative phase angles of the two
systems are approaching 180 degrees, which results in greater breaker stress than for OST applications that implement
TOWO.
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Appendix C – Overview of Out‐of‐Step Protection Functions
jX
Z1 Plane
Re (Z1)
–
R7
+
Re (Z1)
–
R6
+
Start
R6
R7
R
OSBD
OSTD
Block
Trip
Figure 26: Dual-Quadrilateral Timer Scheme
One of the most important and difficult aspects of an OST scheme is the calculation of proper settings for the distance relay
OST characteristics and the OST time‐delay setting. Detailed dynamic simulation studies are recommended for cases where
a transmission separation scheme is being developed for a specific disturbance scenario. These simulation studies can be
used to address issues such as the maximum recoverable swing impedance and the adverse impact of the transient voltage
dips associated with the swing. In some cases out of step settings may involve a tradeoff between minimizing transient
voltage dips and avoid separation for recoverable swings.
The other difficult aspect of OST schemes is determining the appropriate time at which to issue a trip signal to the line
breakers to avoid equipment damage and ensure personnel safety. To adequately protect the circuit breakers and ensure
personnel safety, it may be necessary to prevent uncontrolled tripping during an OOS condition by restricting operation of
the OST function to relative voltage angles between the two systems within the circuit breaker capability. Logic is included
to allow delayed OST on the way out to minimize the possibility of breaker damage.
Non-conventional OST Schemes
The previously discussed OST setting complexities and the need for stability studies can be eliminated if the OST function is
supervised by the output of a robust PSB function that makes certain that the network is experiencing a power swing and
not a fault [4]. Using a reliable bit from the SCV PSB function for example to supervise an SCV‐assisted OST function allows
the implementation of a TOWO OST scheme without the need to perform any stability studies, which is a major advantage
over traditional OST schemes.
The SCV‐assisted OST function tracks and verifies that the measured Z1 impedance trajectory crosses the complex
impedance plane from right to left, or from left to right, and issues a TOWO at a desired phase angle difference between
sources. Verifying that the Z1 impedance enters the complex impedance plane from the left or right side and making sure it
exits at the opposite side of the complex impedance plane ensures that the function operates only for unstable power
swings. On the contrary, traditional OST schemes that do not track the Z1 impedance throughout the complex impedance
plane may operate for a stable swing that was not considered during stability studies and happens to cross the inner OST
characteristic.
Four resistive and four reactive blinders are still used in the SCV‐assisted OST scheme, as shown in Figure 18. However, the
settings for these blinders are easy to calculate when applying TOWO. The outermost OST resistive blinders can be placed
around 80 to 90 degrees in the complex impedance plane, regardless of whether a stable power swing crosses these
blinders or whether the load impedance of a long, heavily loaded line encroaches upon them. The inner OST resistive
blinder can be set anywhere from 120 to 150 degrees. In addition, there are no OST timer settings involved in the SCV‐
assisted OST scheme.
To apply TOWI, stability studies are still required to ensure that no stable swings will cause the operation of the inner OST
characteristic.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Issues Associated With the Concentric or Dual-Blinder Methods
Impact of System Impedances
To guarantee enough time to carry out blocking of the distance elements after a power swing is detected, the inner
impedance of the blinder element must be placed outside the largest distance element for which blocking is required. In
addition, the outer blinder impedance element should be placed away from the load region to prevent PSB logic operation
caused by heavy loads, thus establishing an incorrect blocking of the line mho tripping elements. The previous requirements
are difficult to achieve in some applications, depending on the relative line impedance and source impedance magnitudes
(see Figure 27).
Figure 27a depicts a system in which the line impedance is large compared with system impedances (strong source), and
Figure 27b depicts a system in which the line impedance is much smaller than the system impedances (weak source).
We can observe from Figure 27a that the swing locus could enter the zone 2 and zone 1 relay characteristics during a stable
power swing from which the system could recover. For this particular system, it may be difficult to set the inner and outer
PSB blinder elements, especially if the line is heavily loaded, because the necessary PSB settings are so large that the load
impedance could establish incorrect blocking. To avoid incorrect blocking resulting from load, lenticular distance relay
characteristics, load encroachment, or blinders that restrict the tripping area of the mho elements have been applied in the
past. On the other hand, the system shown in Figure 27b becomes unstable before the swing locus enters the zone 2 and
zone 1 mho elements, and it is relatively easy to set the inner and outer PSB blinder elements.
Another difficulty with the blinder characteristic method is the separation between the inner and outer PSB blinder
elements and the timer setting that is used to differentiate a fault from a power swing. These settings are not difficult to
calculate, but depending on the system under consideration, it may be necessary to run extensive stability studies to
determine the fastest power swing and the proper PSB blinder element settings. The rate of slip between two systems is a
function of the accelerating torque and system inertias. In general, a relay cannot determine the slip analytically because of
the complexity of the power system. However, by performing system stability studies and analyzing the angular excursions
of systems as a function of time, it is possible to estimate an average slip in degrees per second or cycles per second. This
approach may be appropriate for systems where slip frequency does not change considerably as the systems go out of step.
However, in many systems where the slip frequency increases considerably after the first slip cycle and on subsequent slip
cycles, a fixed impedance separation between the blinder PSB elements and a fixed time delay may not be suitable to
provide a continuous blocking signal to the mho distance elements.
In a complex power system, it is very difficult to obtain the proper source impedances that are necessary to establish the
blinder and PSB delay timer settings [3]. The source impedances vary continuously according to network changes, such as
additions of new generation and other system elements. The source impedances could also change drastically during a
major disturbance and at a time when the PSB and OST functions are called upon to take the proper actions. Normally, very
detailed system stability studies are necessary to consider all contingency conditions in determining the most suitable
equivalent source impedance to set the PSB or OST functions.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Figure 27: Effects of Source and Line Impedances on the PSB Function
Impact of Heavy Load on the Resistive Settings of the Quadrilateral Element
References [3] and [4] recommend setting the concentric dual‐quadrilateral power swing characteristic inside the maximum
load condition but outside the maximum distance element reach desired to be blocked. In long‐line applications with a
heavy load flow, following these settings guidelines may be difficult, if not impossible. Fortunately, most numerical distance
relays allow some form of programming capability to address these special cases. However, in order to set the relay
correctly, stability studies are required; a simple impedance‐based solution is not possible.
The approach for this application is to set the power swing blinder such that it is inside the maximum load flow impedance
and the worst‐case power swing impedance. Using this approach can result in cutting off part of the distance element
characteristic. Reference [11] provides additional information and logic to address the issues of PSB settings on heavily
loaded transmission lines.
OOS Relaying Philosophy
There are many different power swing detection methods that can be used to protect a power system from OOS conditions,
each of which has its own benefits and drawbacks. While the OOS relaying philosophy is simple, it is often difficult to
implement in a large power system because of the complexity of the system and the different operating conditions that
must be studied.
The recommended approach for OOS relaying application is summarized below:
Perform system transient stability studies to identify system stability constraints based on many operating
conditions and stressed‐system operating scenarios. The stability studies will help identify the parts of the power
system that impose limits to angular stability, generators that are prone to go OOS during system disturbances,
and those that remain stable. The results of stability studies are also used to identify the optimal location of OST
and PSB protection relay systems.
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Appendix C – Overview of Out‐of‐Step Protection Functions
Determine the locations of the swing loci during various system conditions and identify the optimal locations to
implement the OST protection function. The optimal location for the detection of the OOS condition is near the
electrical center of the power system. However, it is necessary to determine that the behavior of the impedance
locus near the electrical center would facilitate the successful detection of OOS.
Determine the optimal location for system separation during an OOS condition. This will typically depend on the
impedance between islands, the potential to attain a good load/generation balance, and the ability to establish
stable operating areas after separation. High impedance paths between system areas typically represent
appropriate locations for network separation.
Establish the maximum rate of slip between systems for OOS timer setting requirements, as well as the minimum
forward and reverse reach settings required for successful detection of OOS conditions. The swing frequency of a
particular power system area or group of generators relative to another power system area or group of generators
does not remain constant. The dynamic response of generator control systems, such as automatic voltage
regulators, and the dynamic behavior of loads or other power system devices, such as SVCs and FACTS, can
influence the rate of change of the impedance measured by OOS protection devices.
References
[1]
C. R. Mason, The Art and Science of Protective Relaying. John Wiley & Sons, Inc., New York, 1956.
[2]
G. Benmouyal, D. Hou, and D. Tziouvaras, "Zero‐setting Power‐Swing Blocking Protection ", proceedings of the 31st
Annual Western Protective Relay Conference, Spokane, WA, October 2004.
[3]
D. Tziouvaras, and D. Hou, “Out‐of‐Step Protection Fundamentals and Advancements,” proceedings of the 30th
Annual Western Protective Relay Conference, Spokane, WA, October 2003.
[4]
N. Fischer, G. Benmouyal, Da. Hou, D. Tziouvaras, J. Byrne‐Finley, and B. Smyth, “Tutorial on Power Swing Blocking and
Out‐of‐Step Tripping,” proceedings of the 39th Annual Western Protective Relay Conference, Spokane, WA, October
2012.
[5]
J. Holbach, “New Blocking Algorithm for Detecting Fast Power Swing Frequencies,” proceedings of the 30th Annual
Western Protective Relay Conference, Spokane, WA, October 2003.
[6]
Q. Verzosa, “Realistic Testing of Power Swing Blocking and Out‐of‐Step Tripping Functions,” proceedings of the 38th
Annual Western Protective Relay Conference, Spokane, WA, October 2011.
[7]
C. W. Taylor, J. M. Haner, L. A. Hill, W. A. Mittelstadt, and R. L. Cresap, “A New Out‐of‐Step Relay With Rate of Change
of Apparent Resistance Augmentation,” IEEE Transactions on Power Apparatus and Systems, Vol. PAS‐102, No. 3,
March 1983.
[8]
J. M. Haner, T. D. Laughlin, and C. W. Taylor, “Experience with the R Rdot Out‐of‐Step Relay,” IEEE Transactions on
Power Delivery, Vol. 1, No. 2, April 1986.
[9]
F. Ilar, “Innovations in the Detection of Power Swings in Electrical Networks,” Brown Boveri Publication CH‐ES 35‐
30.10E, 1997.
[10] A. Guzmán, V. Mynam, and G. Zweigle, “Backup Transmission Line Protection for Ground Faults and Power Swing
Detection Using Synchrophasors,” proceedings of the 34th Annual Western Protective Relay Conference, Spokane,
WA, October 2007.
[11] J. Mooney and N. Fischer, “Application Guidelines for Power Swing Detection on Transmission Systems,” proceedings
of the 32nd Annual Western Protective Relay Conference, Spokane, WA, October 2005.
[12] W. A. Elmore, "The Fundamentals of Out‐of‐Step Relaying," proceedings of the 34th Annual Conference for Protective
Relay Engineers, Texas A&M University, College Station, TX, April 1981.
[13] IEEE Power System Relaying Committee, Working Group D‐6 Report, Power Swing and Out‐of‐Step Considerations on
Transmission Lines. Available: http://www.pes‐psrc.org/.
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Appendix D – Potential Methods to Demonstrate Security of
Protective Relays
IEEE PSRC WG D6 Method
Appendix A of the IEEE PSRC WG D6 paper on power swing considerations presents the process of reducing a complex
power system to a two source equivalent system connected by a single transmission line in parallel with a second line which
is the equivalent of the remaining transmission system connecting the two sources. The two source equivalent system will
be accurate for faults anywhere on the retained transmission line. It can also be used to determine whether the swing
center of the two systems lies within the retained transmission. The usefulness of the method of determining whether the
swing center is contained within the line depends on the probability of the actual power system to consist of two coherent
systems of generators connected by the modeled system.
This method was applied to a system in the northwest portion of the eastern interconnection. The system consists of a
double circuit ring of 345 kV lines around an underlying 115 kV system. Large generation stations are located at several
points around the ring. The 345 kV lines connect with other systems from the east, southeast, and southwest parts of the
ring. When applied to these connections, the method of Appendix A predicts that the swing center will pass through these
lines. In fact this system has been observed to have at least one of these swing centers, and the system of generators
around the ring will behave as a coherent set relative to the connected system across the ties.
The method also predicts that virtually every 115kV line within the 345kV ring will also contain the swing center when the
system is reduced to a two source equivalent. It is extremely unlikely to separate into two independent sets of coherent
generators within this ring. In his paper “The Fundamentals of Out‐Of‐Step Relaying”, Walt Elmore presents this method
and states, “When more than a line or two are to be analyzed, it is virtually impossible to use the method.”
When applied to the 345kV lines making up the double circuit ring, the method shows that for a majority of them the swing
center will not pass through them, but will fall just outside the line. For the most part, these lines are fairly short with many
interconnections. An assessment was not performed examining the effect of taking two or three lines out, but this likely
would result in bringing the center into one end of the line. With several of these lines out the possibility of two sets of
generators swinging relative to each other increases.
For the most part, the Appendix A method looks useful for identifying swing centers between relatively independent
systems connected by a small number of ties.
Calculation Methods based on the Graphical Analysis Method
A classical method to determine if a particular relay is subject to tripping during a power swing is discussed in Appendix A.
In this method, the system consists of the line where the relay is applied with a system equivalent generator and
impedance at each end of a particular line (see Figure 6). For this system, assuming equal voltage magnitudes for the
equivalent generator, a power swing traverses along the perpendicular bisector of the total system impedance. Figure 6
shows a graphical interpretation of this. In Figure 7, the dashed line is the path the impedance traverses during the power
swing and the angle delta is the angle between the two equivalent generator sources. The impedance seen at relay terminal
A is to the right of the relay’s impedance characteristic prior to the onset of the power swing. As a stable power swing
occurs, the angle between the two equivalent generators increases causing the impedance to move to the left along the
dashed line. When the system stabilizes, the power swing will switch directions (this can take a significant amount of time)
and move to the right along the dashed line, oscillate, and then end at a new stable operating point. Depending on the size
of the overall system impedance, the length of the line, and the reach of the impedance relay, the stable power swing may
or may not fall within the relay characteristic. For cases where the relay’s impedance characteristic intersects the electrical
center of the system, the power swing will enter the relay’s characteristic at some value of the angle delta. When the power
swing enters the relay’s characteristic, the relay will trip quickly if it is a zone 1 type relay. Because stable power swings may
be slower to reverse direction than it takes a typical time delayed relay to trip, time delayed zones must also be evaluated.
As stated in this report and many others it is generally accepted based on many power swing studies that if a power swing
traverses beyond an angle delta greater than or equal to 120 degrees, the power swing will not be stable. This 120 degree
angle is often called the “critical angle.” The logic behind the general acceptance of 120 degrees as the critical angle for
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
stability is discussed above in Appendix A. Two potential methods are presented to screen relays for susceptibility to stable
power swings based on the use of the 120 degree critical angle.
Method 1
The first method uses an equivalent circuit based on the system shown in Figure 28. A calculation is made of the impedance
seen at a relay terminal when the difference between the generator angles in the equivalent system described above is 120
degrees. If the impedance calculated does not fall within the relays impedance characteristic, it is not susceptible to
tripping for a stable power swing. The discussion that follows pertains to a mho type relay characteristic, but the same
process could be used for other characteristics.
Figure 28: Two-Machine Equivalent of a Power System
Since this calculation does not use a computer model, various parameters must be established:
It is a reasonable and conservative assumption to assume that the voltage at the equivalent generator terminals is
1.05 per unit even under these severe conditions.
The angle between the generator voltages is set to the 120 degree critical angle.
Line and equivalent generator impedance angles are set to 90 degrees. This causes minimal variation in the
calculation and simplifies the calculation.
The equivalent generator impedances can be calculated using a fault study program and calculated with the line
under study out of service.
Given these parameters the allowable impedance for the relay (circular mho type) at terminal A can be calculated as
follows. Referring to Figure 28:
VA = EG ‐ IA*ZG and
IA = (EG‐EH)/(ZG + ZL + ZH) and
ZA = VA/IA = ZAMAG@ZAang and
ZAallowable = ZAMAG/(cos(MTA – ZAang))
Similarly, the Zallowable at the B terminal can be calculated:
VB = EH ‐ IH*ZH and
IB = ‐IA
ZB = VB/IB = ZBMAG@ZBang and
ZBallowable = ZBMAG/(cos(MTA – ZBang))
An example of some Zallowable calculations using this method for a 345kV system is shown below:
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Table 1: Examples of Zallowable for a Sample 345 kV System Using Method 1
System
Angle
(degrees)
System and Line
Impedance (Ohms)
EG
EH
Z G
ZL
Z H
90º
MTA
85º
MTA
80º
MTA
75º
MTA
90º
MTA
85º
MTA
80º
MTA
75º
MTA
0
120
5
5
10
11.7
13.0
14.9
17.5
11.7
10.6
9.8
9.2
0
120
13
5
10
66.3
227.4
‐158.4
‐58.9
16.3
15.1
14.3
13.6
0
120
20
20
10
46.7
62.7
96.5
213.3
46.7
37.4
31.4
27.2
0
120
5
5
60
43.6
46.5
50.3
55.1
43.6
41.3
39.6
38.2
ZA allowable
ZB allowable
Note 1) A negative number means that no stable power swings will fall within the zone.
Note 2) If EG = 120 and EH = 0, then the ZA allowable impedances shown become the ZB allowable impedances and vice
versa.
This method is conservative for a number of reasons:
This simplified calculation assumes a large stable power swing with the system in a normal configuration. Tripping
for a stable power swing is more likely with the system weakened. Weakening the system increases the allowable
impedance for a given line.
This simplified calculation estimates the equivalent system impedances from the fault model which uses sub‐
transient reactances for generators. Power Swings are longer time phenomena and use transient reactances which
are larger (X’’d ~ 0.7X’d).
It does not include the effects of parallel paths to the line under test (i.e., it ignores the transfer impedance – see
Method 2). Including parallel paths allows for a higher distance zone setting. This method essentially assumes that
the line under test is the only line connecting two systems.
Some conclusions that are generally known can also be drawn from this method:
Shorter lines with shorter relay settings are less susceptible to tripping on power swings than longer lines with
larger settings.
Zone 1 relays on short lines (i.e. lines < ~ 40 miles at 345kV and probably greater) are basically immune to tripping
on stable power swings. Overreaching distance zones (zone 2, zone 3, etc.) with reaches equivalent to this short
line zone 1 reach are also basically immune to tripping on stable power swings. Note that distances vary
proportionally with voltage level (lower at lower voltages and higher at higher voltage levels).
As source impedances change due to system configuration changes, the susceptibility of a mho relay to trip for a
stable power swing can vary a great deal.
Depending on the direction of power flow during the stable swing (into or out of the relay terminal), the
susceptibility of a mho relay to trip for a stable power swing can vary a great deal.
This method will screen out backup zones in some cases, but does not screen out backup zones well, even on
highly connected systems where stable power swings are less likely or highly unlikely.
Method 2
The second method uses an equivalent circuit based on the system shown in Figure 29. A calculation of the impedance seen
at a relay terminal when the difference between the generator angles in the equivalent system described above is 120
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
degrees is made. If the impedance calculated does not fall within the relays impedance characteristic, it is not susceptible to
tripping for a stable power swing. The discussion that follows pertains to a mho type relay characteristic, but the same
process could be used for other characteristics.
Figure 29: Two-Machine Equivalent of a Power System with Parallel System Transfer Impedance
Since this calculation does not use a computer model, various parameters must be established:
It is a reasonable and conservative assumption to assume that the voltage at the equivalent generator terminals is
1.05 per unit even under these severe conditions.
The angle between the generator voltages is set to the 120 degree critical angle.
Line and equivalent generator impedance angles are set to 90 degrees. This causes minimal variation in the
calculation and simplifies the calculation.
The equivalent generator impedances and transfer impedances can be obtained from a fault study program.
Given these parameters the allowable impedance for the relay (circular mho type) at terminal A can be calculated as
follows. Referring to Figure 29:
VA = EG – ITOTAL*ZG and
ITOTAL = (EG‐EH)/(ZG + Zeq + ZH) where Zeq = (ZL*ZTR)/(ZL + ZTR) and
IA = ITOTAL*(ZTR/(ZTR + ZL))
ZA = VA/IA = ZAMAG@ZAang and
ZAallowable = ZAMAG/(cos(MTA – ZAang))
Similarly, the Zallowable at the B terminal can be calculated:
VB = EH ‐ IH*ZH and
IB = ‐IA
ZB = VB/IB = ZBMAG@ZBang and
ZBallowable = ZBMAG/(cos(MTA – ZBang))
An example of some Zallowable calculations using this method for a 345kV system is shown below:
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Table 2: Examples of Zallowable for a Sample 345 kV System Using Method 2
System Angles
System, Line, and Transfer
Impedances
ZA allowable
ZB allowable
EG
EH
Z G
Z H
ZTR
ZL
90º
MTA
85º
MTA
80º
MTA
75º
MTA
90º 85º 80º
MTA MTA MTA
75º
MTA
0
120
5
5
10
10
20.0
23.7
29.2
38.6
17.5
16.3
15.4
14.7
0
120
5
5
50
10
13.1
14.8
17.1
20.5
12.7
11.7
10.9
10.3
0
120
5
5
100
10
12.4
13.9
16.0
18.9
12.2
11.2
10.4
9.7
0
120
5
5
500
10
11.8
13.2
15.1
17.8
11.8
10.7
9.9
9.3
0
120
13
5
10
10
-61.8
-44.7
-35.2
-29.3
27.8
26.2
25.0
24.0
0
120
13
5
50
10
416.3
-139.7
-60.0
-38.4
18.5
17.3
16.4
15.6
0
120
13
5
100
10
123.9
-489.1
-82.4
-45.2
17.4
16.2
15.3
14.6
0
120
20
20
10
10
140.0
257.7
1696.9
-369.5
52.0
47.8
44.6
42.1
0
120
20
20
50
10
61.1
86.7
151.4
615.4
40.1
34.7
30.7
27.7
0
120
20
20
100
10
53.6
74.0
120.9
337.1
41.7
35.0
30.4
27.0
0
120
5
5
10
60
76.9
86.7
100.2
119.8
83.5
79.4
76.3
74.0
0
120
5
5
50
60
48.7
52.5
57.4
63.9
51.6
48.9
46.9
45.4
0
120
5
5
100
60
46.0
49.4
53.7
59.3
47.6
45.1
43.2
41.8
Note 1) A negative number means that no stable power swings will fall within the zone.
Note 2) If EG = 120 and EH = 0, then the ZA allowable impedances shown become the ZB allowable impedances and vice
versa.
This method is conservative for a number of reasons:
This simplified calculation assumes a large stable power swing with the system in a normal configuration. Tripping
for a stable power swing is more likely with the system weakened. Weakening the system increases the allowable
impedance for a given line.
This simplified calculation estimates the equivalent system impedances from the fault model which uses sub‐
transient reactances for generators. Power Swings are longer time phenomena and use transient reactances which
are larger (X’’d ~ 0.7X’d).
Some conclusions that are generally known can also be drawn from this method:
If the transfer impedance is high, this method is essentially the same as method 1. If the transfer impedance is
infinite, this method is equivalent to method 1.
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
If the transfer impedance is low as in a more interconnected system, this method shows that a greater relay reach
can be set before a relay will trip during a stable power swing versus method 1. This method is a more accurate
representation of the power system and hence is more accurate than method 1. However, as transfer impedances
change due to system configuration changes, the susceptibility of a mho relay to trip for a stable power swing also
changes.
Shorter lines with shorter relay settings are less susceptible to tripping on power swings than longer lines with
larger settings.
Zone 1 relays on short lines (i.e. lines < ~ 40 miles at 345kV and probably greater) are basically immune to tripping
on stable power swings. Overreaching distance zones (zone 2, zone 3, etc.) with reaches equivalent to this short
line zone 1 reach are also basically immune to tripping on stable power swings. Note that distances vary with
voltage level (lower at lower voltages and higher at higher voltage levels).
As source impedances change due to system configuration changes, the susceptibility of a mho relay to trip for a
stable power swing can vary a great deal.
Depending on the direction of power flow during the stable swing (into or out of the relay terminal), the
susceptibility of a mho relay to trip for a stable power swing can vary a great deal.
This method will screen out backup zones better than method 1.
Like the methods for loadability in PRC‐023, both method 1 and method 2 address a single impedance relay or a single relay
element. This method does not provide a calculation for a composite scheme like a Permissive Overreach with Transfer Trip
scheme where two relays may be required to pick up to cause a trip.
Voltage Dip Screening Method
Although there are number of successful power swing detection methods, the goal of the voltage dip method is to establish
a reliable screening tool easily applicable in transient stability planning studies. Transient stability planning studies evaluate
many contingencies and monitor performance of many variables of the Bulk‐Power System in order to demonstrate
compliance with applicable standards and criteria. Due to the comprehensive nature of the analysis, a practical screening
method that flags potential power swing problems is essential.
It is well known that the most accurate method of identifying stable/unstable power swing requires a model of the
protection system (susceptible to stable and unstable power swings) in place and detailed simulation of the event that
produces the power swing. A plot of apparent impedance trajectory during the system disturbance against an appropriate
relay characteristic determines the power swing status. In large scale transient stability planning studies where many
contingencies are considered, that approach requires an effort of modeling and maintaining many relay characteristics and
recording many apparent impedance channels. The proposed screening method seeks a reliable way of identifying potential
power swings with minimal burden on additional modeling as part of the analysis.
While the power swing is the result of angular separation between units or coherent groups of units that oscillate against
each other, finding the coherent groups requires multiple simulation runs. In power swing identification primary question is
whether the swing is stable or not and the subsequent question is to identify which units drive the power swing. As a result
of coherent units swings, the transmission voltage magnitude gets low near the center of the swing. Therefore, since
transmission voltages are monitored in transient stability planning studies and voltage performance is subject to planning
criteria in many areas (WECC Transmission planning standard and ISO‐NE voltage sag guidelines), post‐disturbance voltage
dips can be used as a potential screening tool for power swing identification.
In order to establish a theory behind the proposed method, a two‐source equivalent is examined first. Since the system has
only one path between two sources, the idea is to study a range of system conditions subject to the power swing and then
test the voltage dip criteria on the transmission line terminals. The two‐source system in Figure 30 is analyzed. The system
is assumed to be symmetrical (i.e., the source terminal voltages are equal in magnitude, |EG|=|EH|), during the power
swing, the electrical center occurs in the middle of the impedance between two sources.
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Figure 30:Two-source equivalent system
The following assumptions have been made regarding the system in Figure 30:
1) Source and line resistances are neglected
2) Distance relay characteristic is a circle with diameter equal to 100 percent of line reactance
3) Relay maximum torque angle is equal to line angle
4) For simplicity it will be assumed that XG+XL+XH=1 pu
5) Source voltage magnitudes are equal EG=EH=1.0 pu
6) EH0, represents an infinite bus
7) EG , with (0,180) swings against EH
8) Angle M represents angle of separation between sources G and H at which swing trajectory enters line relay
characteristic.
The equations used in numerical simulations of the system represented in Figure 30 are as follows.
The current between two sources is determined by:
I
EG E H 0
j( X G X L X H )
The voltage at the electrical center of the swing is:
VC E G j
XG XL XH
I
2
The complex voltages at the line ends A and B are:
V A EG jX G I
VB EH jX H I
The goal of the following analysis is that depending on different system conditions in terms of strength of systems and
length of the line, investigate values of different quantities of the two source system at the moment when power swing
locus enters the line relay characteristic (designated with angle M in Figure 30) and test whether power swing could be
identified based on voltage dip at the line terminals.
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Following system conditions are investigated.
1) Case 1: two strong systems connected with long line (i.e., XG = XH=0.1 pu and XL=0.8 pu)
2) Case 2: two weak systems connected with long line (XG = XH=0.3 pu and XL=0.4 pu)
3) Case 3: weak system G connected to strong system H with long line (XG = 0.3 XH=0.1pu and XL=0.6 pu)
4) Case 4: variation of case 3 with XG = 0.4 XH=0.2pu and XL=0.4 pu
Results of the analysis are summarized in Table 3 while power swing characteristics are plotted in Figures 31 and 32.
Table 3: Results
Case
XG [pu]
XL [pu]
XH [pu]
Zr [pudeg]
M
[deg]
VC [pu]
VA
A
[deg]
VB
B
[deg]
1
0.1
0.8
0.1
0.63951.5
103
0.622
0.883
96.7
0.883
6.33
2
0.3
0.4
0.3
0.53768.5
137
0.366
0.522
113.9
0.522
23.06
3
0.3
0.6
0.1
0.57261
122
0.485
0.598
96.8
0.851
5.72
4
0.4
0.4
0.2
0.52971
142
0.326
0.376
101.2
0.654
10.85
Figure 31: Case 1 and Case 2 Voltage Plots
NERC | Protection System Response to Power Swings | August 2013
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Figure 32: Case 3 and Case 4 Voltage Plots
Discussion of the Results
Case 1: sets the minimal angle M at which power swing trajectory enters the line relay characteristic. Voltage magnitudes
at line ends VA and VB are highest since they are electrically closer to sources than to the center of the swing. Figure 31a
illustrates the voltage magnitude plot for this scenario.
Case 2: If the systems are weak (high source reactance) angle M increases and voltage magnitudes at the line end get lower
(around 0.522 pu). The reason for lower line terminal voltages is its proximity to the electrical center of the swing. Fig. 30b
represents voltage plot for case 2 scenario.
Case 3: This case represents a weak system G that swings against strong system H. Angle M is around 120 and the line end
voltage VA that is closer to electrical center of the swing is below 0.6 pu. Figure 32a represents voltage plot for case 3
scenario.
Case 4: This case presents variation of Case 3. The weaker is the system G (higher reactance XG) the higher is the angle at
which power swing enters the line relay characteristic (M) which makes it difficult to set 120 as a threshold for stable
power swing detection. However, line terminal voltage closer to the electrical center gets very low; VA = 0.376 pu which
makes it more reliable indicator for a swing. Figure 32b represents voltage plot for case 4 scenario.
The cases considered in two‐source equivalent system indicate that voltage magnitude at the line terminal is a reliable
indication of the power swing.
Practical Power System Example
In order to make the proposed method practical for planning studies, and to establish potential voltage threshold for
identification of stable power swings, a few transient stability simulation with a known stable power swing were performed.
The first practical example is tested on New England’s bulk power system with three contingencies of increasing level of
severity. Voltage at the one terminal of the line subject to power swing and apparent impedance recorded by the relay at
the same line are monitored. Post disturbance apparent impedance and voltage magnitude performance for all three
contingencies are presented in Figure 33.
NERC | Protection System Response to Power Swings | August 2013
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Figure 33: Apparent Impedance and Voltage Dip Plots
From Figure 34 one can notice a strong coupling between voltage dip and minimum apparent impedance. It is also of
interest to confirm that the most severe contingency produces a stable power swing and the largest voltage dip. Since the
apparent impedance plot is not time dependent, an additional analysis is performed to correlate minimum voltage dip with
minimum apparent impedance during the power swing. Figure 34 presents such analysis with bold segments indicating
quantities during the same time interval.
Figure 34: Power Swing in the New England System
The second example presented in Figure 35 is the stable power swing simulation results in the Florida system.
NERC | Protection System Response to Power Swings | August 2013
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Appendix D – Potential Methods to Demonstrate Security of Protective Relays
Figure 35: Power Swing in the Florida System
Analysis conducted on the New England and Florida systems suggest a few important conclusions.
Apparent impedance and voltage magnitude are correlated, therefore for screening purposes in planning studies
voltage magnitude can be used.
Presented cases suggest that post disturbance voltage magnitude in the range of 0.5 and 0.6 pu might be used as a
screening tool for power swing identification.
Cases identified in the screening analysis require further detailed study.
Although theory and practice of the proposed voltage dip method are consistent, more test cases are needed in order to
establish voltage dip threshold and applicable margin.
NERC | Protection System Response to Power Swings | August 2013
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Appendix E – System Protection and Control Subcommittee
William J. Miller
Chair
Principal Engineer
Exelon Corporation
David Penney, P.E.
RE – TRE – Alternate
Senior Reliability Engineer
Texas Reliability Entity
Philip B. Winston
Vice Chair
Chief Engineer, Protection and Control
Southern Company
Baj Agrawal
RE – WECC
Principal Engineer
Arizona Public Service Company
Michael Putt
RE – FRCC
Manager, Protection and Control Engineering Applications
Florida Power & Light Co.
Forrest Brock
Cooperative
Station Services Superintendent
Western Farmers Electric Cooperative
Mark Gutzmann
RE – MRO
Manager, System Protection Engineering
Xcel Energy, Inc.
Miroslav Kostic
Federal/Provincial Utility
P&C Planning Manager, Transmission
Hydro One Networks, Inc.
Richard Quest
RE – MRO – Alternate
Principal Systems Protection Engineer
Midwest Reliability Organization
Sungsoo Kim
Federal/Provincial Utility
Section Manager – Protections and Technical Compliance
Ontario Power Generation Inc.
George Wegh
RE – NPCC
Manager – Transmission Protection and Controls Engineering
Northeast Utilities
Joe T. Uchiyama
Federal/Provincial Utility
Senior Electrical Engineer
U.S. Bureau of Reclamation
Quoc Le
RE – NPCC ‐‐ Alternate
Manager, System Planning and Protection
NPCC
Daniel McNeely
Federal/Provincial Utility ‐ Alternate
Engineer ‐ System Protection and Analysis
Tennessee Valley Authority
Jeff Iler
RE – RFC
Principal Engineer, Protection and Control Engineering
American Electric Power
Michael J. McDonald
Investor‐Owned Utility
Principal Engineer, System Protection
Ameren Services Company
Therron Wingard
RE – SERC
Principal Engineer
Southern Company
Jonathan Sykes
Investor‐Owned Utility
Manager of System Protection
Pacific Gas and Electric Company
David Greene
RE – SERC ‐‐ Alternate
Reliability Engineer
SERC Reliability Corporation
Charles W. Rogers
Transmission Dependent Utility
Principal Engineer
Consumers Energy Co.
Lynn Schroeder
RE – SPP
Manager, Substation Protection and Control
Westar Energy
Philip J. Tatro
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Samuel Francis
RE – TRE
System Protection Specialist
Oncor Electric Delivery
NERC | Protection System Response to Power Swings | August 2013
59 of 61
Appendix F – System Analysis and Modeling Subcommittee
John Simonelli
Chair
Director ‐ Operations Support Services
ISO New England
Hari Singh, Ph.D.
RE – WECC
Transmission Asset Management
Xcel Energy, Inc.
K. R Chakravarthi
Vice Chair
Manager, Interconnection and Special Studies
Southern Company Services, Inc.
Kent Bolton
RE – WECC – Alternate
Staff Engineer
Western Electricity Coordinating Council
G Brantley Tillis, P.E.
RE – FRCC
Manager, Transmission Planning Florida
Progress Energy Florida
Patricia E Metro
Cooperative
Manager, Transmission and Reliability Standards
National Rural Electric Cooperative Association
Kiko Barredo
RE – FRCC – Alternate
Manager, Bulk Transmission Planning
Florida Power & Light Co.
Paul McCurley
Cooperative – Alternate
Manager, Power Supply and Chief Engineer
National Rural Electric Cooperative Association
Thomas C. Mielnik
RE – MRO
Manager Electric System Planning
MidAmerican Energy Co.
Ajay Garg
Federal/Provincial Utility
Manager, Policy and Approvals
Hydro One Networks, Inc.
Salva R. Andiappan
RE – MRO – Alternate
Manager ‐ Modeling and Reliability Assessments
Midwest Reliability Organization
Amos Ang, P.E.
Investor‐Owned Utility
Engineer, Transmission Interconnection Planning
Southern California Edison
Donal Kidney
RE – NPCC
Manager, System Compliance Program Implementation
Northeast Power Coordinating Council
Bobby Jones
Investor‐Owned Utility
Project Manager, Stability Studies
Southern Company Services, Inc.
Quoc Le
RE – NPCC ‐‐ Alternate
Manager, System Planning and Protection
NPCC
Scott M. Helyer
IPP
Vice President, Transmission
Tenaska, Inc.
Eric Mortenson, P.E.
Investor‐Owned Utility
Principal Rates & Regulatory Specialist
Exelon Business Services Company
Digaunto Chatterjee
ISO/RTO
Manager of Transmission Expansion Planning
Midwest ISO, Inc.
Mark Byrd
RE – SERC
Manager ‐ Transmission Planning
Progress Energy Carolinas
Bill Harm
ISO/RTO
Senior Consultant
PJM Interconnection, L.L.C.
Gary T Brownfield
RE – SERC – Alternate
Supervising Engineer, Transmission Planning
Ameren Services
Steve Corey
ISO/RTO – Alternate
Manager, Transmission Planning
New York Independent System Operator
Jonathan E Hayes
RE – SPP
Reliability Standards Development Engineer
Southwest Power Pool, Inc.
Bob Cummings
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Kenneth A. Donohoo, P.E.
RE – TRE
Director System Planning
Oncor Electric Delivery
NERC | Protection System Response to Power Swings | August 2013
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Appendix G – Additional Contributors
John Ciufo, P.Eng.
Principal Engineer
Ciufo & Cooperberg Consulting, Inc.
Tom Gentile
Vice President Transmission
Quanta Technology
Bryan Gwyn
Senior Director, Protection and Control Asset Management
Quanta Technology
Kevin W. Jones
Principal Engineer, System Protection Engineering
Xcel Energy
Dmitry Kosterev
Bonneville Power Administration
Chuck Matthews
Bonneville Power Administration
John O’Connor
Principal Engineer
Progress Energy Carolinas
Slobodan Pajic
Senior Engineer, Energy Consulting
GE Energy Management
Fabio Rodriguez
Principal Engineer
Progress Energy Florida
Tracy Rolstad
Senior Power System Consultant
Avista Corporation
Joseph Seabrook
Consulting Engineer
Puget Sound Energy, Inc.
Demetrios Tziouvaras
Senior Research Engineer
Schweitzer Engineering Laboratories, Inc.
NERC | Protection System Response to Power Swings | August 2013
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Standards Announcement Reminder
Project 2010-13.3 Relay Loadability: Stable Power Swings
PRC-026-1
Ballot and Non-Binding Poll Now Open through June 9, 2014
Now Available
A ballot for PRC-026-1 – Relay Performance During Stable Power Swings and non-binding poll of the
associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) is open through 8 p.m.
Eastern on Monday, June 9, 2014.
If you have questions please contact Scott Barfield via email or by telephone at (404) 446-9689.
Background information for this project can be found on the project page.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
standard and non-binding poll of the associated VRFs and VSLs by clicking here.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and, if needed, make revisions to the standard.
If the comments do not show the need for significant revisions, the standard will proceed to a final
ballot.
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, or at 404-446-2560.
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 2010-13.3 Relay Loadability: Stable Power Swings
PRC-026-1
Formal Comment Period Now Open through June 9, 2014
Ballot Pools Forming Now through May 27, 2014
Now Available
A 45-day formal comment period for PRC-026-1 – Relay Performance During Stable Power Swings is
open through 8 p.m. Eastern on Monday, June 9, 2014.
If you have questions please contact Scott Barfield via email or by telephone at (404) 446-9689.
Background information for this project can be found on the project page.
Instructions for Commenting
Please use the electronic form to submit comments on the revised definition. If you experience any
difficulties in using the electronic form, please contact Wendy Muller. An off-line, unofficial copy of the
comment form is posted on the project page.
Instructions for Joining Ballot Pool
Ballots pools are being formed for Project 2010-13.3 – Relay Loadability: Stable Power Swings and the
associated non-binding poll on this project. Registered Ballot Body members must join the ballot pools to
be eligible to vote in the balloting and submittal of an opinion for the non-binding poll of the associated
Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs). Registered Ballot Body members may
join the ballot pools at the following page: Join Ballot Pool
During the pre-ballot window, members of the ballot pool may communicate with one another by using
their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using
the ballot pool list servers.) The list servers for this project are:
Initial Ballot: [email protected]
Non-Binding poll: [email protected]
Next Steps
An initial ballot for the standard and non-binding poll of the associated VRFs and VSLs will be
conducted May 30 – June 9, 2014.
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, or at 404-446-2560.
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 2010-13.3 Relay Loadability Stable Power Swings | April, 2014
2
Standards Announcement
Project 2010-13.3 Relay Loadability: Stable Power Swings
PRC-026-1
Formal Comment Period Now Open through June 9, 2014
Ballot Pools Forming Now through May 27, 2014
Now Available
A 45-day formal comment period for PRC-026-1 – Relay Performance During Stable Power Swings is
open through 8 p.m. Eastern on Monday, June 9, 2014.
If you have questions please contact Scott Barfield via email or by telephone at (404) 446-9689.
Background information for this project can be found on the project page.
Instructions for Commenting
Please use the electronic form to submit comments on the revised definition. If you experience any
difficulties in using the electronic form, please contact Wendy Muller. An off-line, unofficial copy of the
comment form is posted on the project page.
Instructions for Joining Ballot Pool
Ballots pools are being formed for Project 2010-13.3 – Relay Loadability: Stable Power Swings and the
associated non-binding poll on this project. Registered Ballot Body members must join the ballot pools to
be eligible to vote in the balloting and submittal of an opinion for the non-binding poll of the associated
Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs). Registered Ballot Body members may
join the ballot pools at the following page: Join Ballot Pool
During the pre-ballot window, members of the ballot pool may communicate with one another by using
their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using
the ballot pool list servers.) The list servers for this project are:
Initial Ballot: [email protected]
Non-Binding poll: [email protected]
Next Steps
An initial ballot for the standard and non-binding poll of the associated VRFs and VSLs will be
conducted May 30 – June 9, 2014.
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, or at 404-446-2560.
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 2010-13.3 Relay Loadability Stable Power Swings | April, 2014
2
Standards Announcement
Project 2010-13.3 Phase 3 of Relay Loadability:
Stable Power Swings
PRC-026-1
Ballot and Non-Binding Poll Results
Now Available
A ballot of PRC-026-1 – Relay Performance During Stable Power Swings and a non-binding poll of the
associated Violation Risk Factors and Violation Severity Levels concluded at 8 p.m. Eastern on Monday,
June 9, 2014.
This standard achieved a quorum but did not receive sufficient affirmative votes for approval. Voting
statistics are listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Ballot
Non-Binding Poll
Quorum / Approval
Quorum / Supportive Opinions
79.06% / 17.02%
77.71% / 17.88%
Background information for this project can be found on the project page.
Next Steps
The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard.
The Protection System Response to Power Swings Standard Drafting Team is meeting the week of June
16, 2014 in Denver, CO. Please see the dial-in information and links below to register for remote
participation.
Click here for
Click here for
Click here for
Click here for
Click here for
Webinar access on Monday, June 16
Webinar access on Tuesday, June 17
Webinar access on Wednesday, June 18
Webinar access on Thursday, June 19
Webinar access on Friday, June 20
Dial-in: 1.866.740.1260 | Participant Access Code: 1326651 | Security Code: 159357
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, or at 404-446-2560.
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 2010-13.3 Relay Loadability: Stable Power Swings
2
NERC Standards
Newsroom • Site Map • Contact NERC
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Ballot Results
Ballot Name: Project 2010-13.3 Relay Loadability Stable Power Swings PRC-026- 1
-Ballot Pools
-Current Ballots
-Ballot Results
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-Register
Home Page
Ballot Period: 5/30/2014 - 6/9/2014
Ballot Type: Initial
Total # Votes: 287
Total Ballot Pool: 363
Quorum: 79.06 % The Quorum has been reached
Weighted Segment
17.02 %
Vote:
Ballot Results: The ballot has closed
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
#
#
No
without a
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
1
2Segment
2
3Segment
3
4Segment
4
5Segment
5
6Segment
6
7Segment
7
8Segment
8
9Segment
104
1
8
0.114
62
0.886
0
8
26
9
0.6
0
0
6
0.6
0
2
1
76
1
5
0.091
50
0.909
0
8
13
26
1
4
0.211
15
0.789
0
2
5
79
1
6
0.113
47
0.887
0
6
20
52
1
6
0.146
35
0.854
0
4
7
2
0.2
1
0.1
1
0.1
0
0
0
4
0.4
0
0
4
0.4
0
0
0
2
0
0
0
0
0
0
0
2
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
NERC Standards
9
10 Segment
10
Totals
9
0.7
4
0.4
3
0.3
0
0
2
363
6.9
34
1.175
223
5.725
0
30
76
Individual Ballot Pool Results
Ballot
Segment
Organization
Member
1
Ameren Services
Eric Scott
Negative
1
American Electric Power
Paul B Johnson
Negative
1
American Transmission Company, LLC
Andrew Z Pusztai
1
Arizona Public Service Co.
Robert Smith
Negative
1
Associated Electric Cooperative, Inc.
John Bussman
Negative
1
ATCO Electric
Glen Sutton
Austin Energy
James Armke
1
Avista Utilities
Heather Rosentrater
1
Balancing Authority of Northern California
Kevin Smith
Negative
1
Baltimore Gas & Electric Company
Christopher J Scanlon
Negative
1
1
BC Hydro and Power Authority
Black Hills Corp
Patricia Robertson
Wes Wingen
Brazos Electric Power Cooperative, Inc.
Tony Kroskey
1
Bryan Texas Utilities
John C Fontenot
SUPPORTS
THIRD PARTY
COMMENTS (Ameren)
SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz
AEP)
Affirmative
1
1
NERC
Notes
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Standifur)
COMMENT
RECEIVED
COMMENT
RECEIVED
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)
Affirmative
1
CenterPoint Energy Houston Electric, LLC
John Brockhan
Negative
1
Central Electric Power Cooperative
Michael B Bax
Negative
1
Central Iowa Power Cooperative
Kevin J Lyons
Negative
1
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Chang G Choi
Negative
1
City of Tallahassee
Daniel S Langston
Negative
1
Clark Public Utilities
Jack Stamper
SUPPORTS
THIRD PARTY
COMMENTS (Oncor Electric
Delivery)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (CIPCO
supports the
comments and
suggestions
submitted by
ACES.)
SUPPORTS
THIRD PARTY
COMMENTS (Chris
Mattson)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
NERC Standards
1
Colorado Springs Utilities
Shawna Speer
Negative
1
Consolidated Edison Co. of New York
Christopher L de Graffenried
Negative
1
CPS Energy
Glenn Pressler
Negative
1
1
Dairyland Power Coop.
Deseret Power
Robert W. Roddy
James Tucker
1
Dominion Virginia Power
Larry Nash
Negative
1
Duke Energy Carolina
Doug E Hils
Negative
1
1
Empire District Electric Co.
Encari
Ralph F Meyer
Steven E Hamburg
Affirmative
Entergy Transmission
Oliver A Burke
Negative
1
FirstEnergy Corp.
William J Smith
Negative
1
Florida Keys Electric Cooperative Assoc.
Dennis Minton
Negative
1
1
Florida Power & Light Co.
Gainesville Regional Utilities
Mike O'Neil
Richard Bachmeier
1
Georgia Transmission Corporation
Jason Snodgrass
Negative
1
Great River Energy
Gordon Pietsch
Negative
1
Hydro One Networks, Inc.
Muhammed Ali
Negative
1
Hydro-Quebec TransEnergie
Martin Boisvert
Negative
1
Idaho Power Company
Molly Devine
Negative
Michael Moltane
Negative
Jim D Cyrulewski
Abstain
1
International Transmission Company
Holdings Corp
JDRJC Associates
SUPPORTS
THIRD PARTY
COMMENTS (PSEG by John
Seekle)
SUPPORTS
THIRD PARTY
COMMENTS (FirstEnergy
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Affirmative
1
JEA
Ted E Hobson
Negative
1
KAMO Electric Cooperative
Walter Kenyon
Negative
1
1
1
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Daniel Gibson
Stanley T Rzad
Larry E Watt
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Dominion)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Affirmative
1
1
THIRD PARTY
COMMENTS (Comments Group,
Colorado
Springs
Utilities)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC)
SUPPORTS
THIRD PARTY
COMMENTS (HQT's
(provided to
the DT) and
NPCC's
comments)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA
comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
NERC Standards
1
Lee County Electric Cooperative
John Chin
1
Los Angeles Department of Water & Power
faranak sarbaz
1
Lower Colorado River Authority
Martyn Turner
1
Manitoba Hydro
Jo-Anne M Ross
1
MEAG Power
Danny Dees
1
MidAmerican Energy Co.
1
Minnkota Power Coop. Inc.
Abstain
Negative
COMMENT
RECEIVED
Negative
COMMENT
RECEIVED
Terry Harbour
Negative
COMMENT
RECEIVED
Daniel L Inman
Abstain
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
National Grid USA
Michael Jones
Negative
1
NB Power Corporation
Alan MacNaughton
1
Nebraska Public Power District
Jamison Cawley
Negative
1
New York Power Authority
Bruce Metruck
Negative
1
Northeast Missouri Electric Power
Cooperative
Kevin White
Negative
1
Northeast Utilities
William Temple
Negative
1
1
Northern Indiana Public Service Co.
NorthWestern Energy
Julaine Dyke
John Canavan
1
Ohio Valley Electric Corp.
Scott R Cunningham
Negative
1
Oklahoma Gas and Electric Co.
Terri Pyle
Negative
1
Omaha Public Power District
Doug Peterchuck
Negative
1
Oncor Electric Delivery
Jen Fiegel
Negative
1
1
Otter Tail Power Company
Pacific Gas and Electric Company
Daryl Hanson
Bangalore Vijayraghavan
1
Peak Reliability
Jared Shakespeare
Negative
1
Platte River Power Authority
John C. Collins
Negative
1
1
Portland General Electric Co.
Potomac Electric Power Co.
John T Walker
David Thorne
Affirmative
Abstain
1
PPL Electric Utilities Corp.
Brenda L Truhe
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (National Grid
supports
NPCC's
comments.)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC and
NYPA)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
Abstain
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF
comments)
COMMENT
RECEIVED
Abstain
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (PSGE)
SUPPORTS
THIRD PARTY
COMMENTS (Refer to
comments
submitted on
behalf of PPL
NERC
Registered
Affiliates.)
NERC Standards
1
Public Service Company of New Mexico
Laurie Williams
1
Public Service Electric and Gas Co.
Kenneth D. Brown
1
Public Utility District No. 1 of Okanogan
County
Dale Dunckel
Negative
1
Puget Sound Energy, Inc.
Denise M Lietz
Negative
1
Rochester Gas and Electric Corp.
John C. Allen
Negative
1
Sacramento Municipal Utility District
Tim Kelley
Negative
1
1
Salt River Project
SaskPower
Robert Kondziolka
Wayne Guttormson
1
Seattle City Light
Pawel Krupa
1
Seminole Electric Cooperative, Inc.
Glenn Spurlock
1
Sho-Me Power Electric Cooperative
Denise Stevens
Negative
1
Snohomish County PUD No. 1
Long T Duong
Negative
1
South Carolina Electric & Gas Co.
Tom Hanzlik
Negative
1
South Carolina Public Service Authority
Shawn T Abrams
1
Southern California Edison Company
Steven Mavis
Negative
1
Southern Company Services, Inc.
Robert A. Schaffeld
Negative
1
Southern Illinois Power Coop.
William Hutchison
Negative
1
Southwest Transmission Cooperative, Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
Tampa Electric Co.
Beth Young
Negative
1
Tennessee Valley Authority
Howell D Scott
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Support
Comments
submitted on
behalf of
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Eleanor Ewry,
Puget Sound
Energy)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light's Paul
Haase's
comment)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
PSEG)
NERC Standards
1
Steven Powell
1
1
Trans Bay Cable LLC
Tri-State Generation & Transmission
Association, Inc.
Tucson Electric Power Co.
U.S. Bureau of Reclamation
1
United Illuminating Co.
Jonathan Appelbaum
1
Vermont Electric Power Company, Inc.
Kim Moulton
1
Tracy Sliman
Affirmative
John Tolo
Richard T Jackson
1
Westar Energy
Allen Klassen
1
1
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Lloyd A Linke
Michelle Clements
Negative
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Amy
Casuscelli, xcel
Energy)
1
Xcel Energy, Inc.
Gregory L Pieper
2
BC Hydro
Venkataramakrishnan
Vinnakota
2
California ISO
Rich Vine
Negative
2
Electric Reliability Council of Texas, Inc.
Cheryl Moseley
Negative
2
Independent Electricity System Operator
Leonard Kula
Negative
2
ISO New England, Inc.
Matthew F Goldberg
Negative
2
MISO
Marie Knox
2
New York Independent System Operator
Gregory Campoli
2
PJM Interconnection, L.L.C.
stephanie monzon
2
Southwest Power Pool, Inc.
Charles H. Yeung
Negative
3
AEP
Michael E Deloach
Negative
3
Alabama Power Company
Robert S Moore
Negative
3
Ameren Corp.
David J Jendras
Negative
3
APS
Sarah Kist
Negative
3
Associated Electric Cooperative, Inc.
Todd Bennett
Negative
3
Atlantic City Electric Company
NICOLE BUCKMAN
3
Avista Corp.
Scott J Kinney
3
BC Hydro and Power Authority
Pat G. Harrington
3
Central Electric Power Cooperative
Adam M Weber
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
Abstain
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz
of American
Electric Power)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric
Cooperative
Inc)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Heather
Rosentrater)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
NERC Standards
3
City of Austin dba Austin Energy
Andrew Gallo
3
3
3
City of Clewiston
City of Farmington
City of Green Cove Springs
Lynne Mila
Linda R Jacobson
Mark Schultz
Negative
Abstain
Abstain
3
City of Redding
Bill Hughes
Negative
3
City of Tallahassee
Bill R Fowler
Negative
3
Colorado Springs Utilities
Jean Mueller
Negative
3
ComEd
John Bee
Negative
3
Consolidated Edison Co. of New York
Peter T Yost
Negative
3
Consumers Energy Company
Gerald G Farringer
3
Cowlitz County PUD
Russell A Noble
Negative
3
CPS Energy
Jose Escamilla
Negative
3
Delmarva Power & Light Co.
Michael R. Mayer
SUPPORTS
THIRD PARTY
COMMENTS (SMUD &
PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (Group,
Colorado
Spirng Utilties)
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA &
PSEG)
Abstain
3
Dominion Resources, Inc.
Connie B Lowe
Negative
3
DTE Electric
Kent Kujala
Negative
3
FirstEnergy Corp.
Cindy E Stewart
Negative
3
Florida Keys Electric Cooperative
Tom B Anthony
Negative
3
Florida Municipal Power Agency
Joe McKinney
Negative
3
Florida Power & Light Co.
Summer C. Esquerre
3
Florida Power Corporation
Lee Schuster
Negative
3
Georgia System Operations Corporation
Scott McGough
Negative
3
Great River Energy
Brian Glover
Negative
3
Hydro One Networks, Inc.
Ayesha Sabouba
Negative
3
JEA
Garry Baker
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
THIRD PARTY
COMMENTS (Thomas
Standifur)
SUPPORTS
THIRD PARTY
COMMENTS (See
Dominion's
submitted
comments)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FirstEnergy
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC-RSC)
SUPPORTS
THIRD PARTY
NERC Standards
COMMENTS (FMPA)
3
Kansas City Power & Light Co.
Joshua D Bach
Affirmative
3
Lakeland Electric
Mace D Hunter
3
Lee County Electric Cooperative
David A Hadzima
3
Lincoln Electric System
Jason Fortik
Negative
3
Los Angeles Department of Water & Power
Mike Anctil
Negative
3
Louisville Gas and Electric Co.
Charles A. Freibert
Negative
3
Manitoba Hydro
Greg C. Parent
Negative
3
3
MEAG Power
MidAmerican Energy Co.
Roger Brand
Thomas C. Mielnik
3
Modesto Irrigation District
Jack W Savage
3
Muscatine Power & Water
John S Bos
Negative
Negative
3
National Grid USA
Brian E Shanahan
Negative
3
Nebraska Public Power District
Tony Eddleman
Negative
3
3
New York Power Authority
Northern Indiana Public Service Co.
David R Rivera
Ramon J Barany
Abstain
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
3
Ocala Utility Services
Randy Hahn
Negative
3
Oklahoma Gas and Electric Co.
Donald Hargrove
Negative
3
Omaha Public Power District
Blaine R. Dinwiddie
3
Orlando Utilities Commission
Ballard K Mutters
Negative
3
3
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Thomas T Lyons
John H Hagen
Affirmative
Affirmative
3
Platte River Power Authority
Terry L Baker
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Agency)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (comments
posted by PPL
NERC
Registered
Affiliates)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (I support
Southwest
Power Pool
(SPP)
comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (support
comments of
Florida
Municipal
Power Agency
(FMPA))
SUPPORTS
THIRD PARTY
COMMENTS (PSGE)
NERC Standards
3
3
3
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Michael Mertz
Thomas G Ward
Mark Yerger
Abstain
3
Public Service Electric and Gas Co.
Jeffrey Mueller
Negative
3
Puget Sound Energy, Inc.
Mariah R Kennedy
Negative
3
Sacramento Municipal Utility District
James Leigh-Kendall
Negative
3
3
Salt River Project
Santee Cooper
John T. Underhill
James M Poston
Affirmative
Abstain
3
Seattle City Light
Dana Wheelock
3
Seminole Electric Cooperative, Inc.
James R Frauen
3
Sho-Me Power Electric Cooperative
Jeff L Neas
Negative
3
Snohomish County PUD No. 1
Mark Oens
Negative
3
South Carolina Electric & Gas Co.
Hubert C Young
Negative
3
Southern California Edison Company
Lujuanna Medina
Negative
3
Tacoma Power
Marc Donaldson
Negative
3
Tampa Electric Co.
Ronald L. Donahey
3
Tennessee Valley Authority
Ian S Grant
3
Tri-State Generation & Transmission
Association, Inc.
Janelle Marriott
Negative
Negative
Westar Energy
Bo Jones
Negative
3
Xcel Energy, Inc.
Michael Ibold
Negative
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
Negative
4
Blue Ridge Power Agency
Duane S Dahlquist
Affirmative
City of Austin dba Austin Energy
Reza Ebrahimian
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light's Paul
Haase's
comment)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
SUPPORTS
THIRD PARTY
COMMENTS (SCE's
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Chris
Mattson)
SUPPORTS
THIRD PARTY
COMMENTS (Comments by
TVA)
Affirmative
3
4
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Eleanor Ewry)
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP Standard
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Xcel Energy's)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Standifur)
NERC Standards
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SMUD/PSEG)
Negative
COMMENT
RECEIVED
4
City of Redding
Nicholas Zettel
4
John Allen
4
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
4
Cowlitz County PUD
Rick Syring
Negative
4
DTE Electric
Daniel Herring
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
Georgia System Operations Corporation
Guy Andrews
Negative
4
Herb Schrayshuen
Herb Schrayshuen
4
Margaret Powell
Tracy Goble
4
Illinois Municipal Electric Agency
Bob C. Thomas
4
Indiana Municipal Power Agency
Jack Alvey
4
Madison Gas and Electric Co.
Joseph DePoorter
4
Modesto Irrigation District
Spencer Tacke
4
Ohio Edison Company
Douglas Hohlbaugh
4
4
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Ashley Stringer
Mark Ringhausen
Affirmative
Negative
Negative
Negative
Negative
4
Sacramento Municipal Utility District
Mike Ramirez
Negative
4
Seattle City Light
Hao Li
Negative
4
4
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Steven R Wallace
Steve McElhaney
4
Utility Services, Inc.
Brian Evans-Mongeon
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light's Paul
Haase's
comment)
Affirmative
Negative
5
Amerenue
Sam Dwyer
Negative
5
American Electric Power
Thomas Foltz
Negative
5
Arizona Public Service Co.
Scott Takinen
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
SUPPORTS
THIRD PARTY
COMMENTS (FirstEnergy
Commnents)
Abstain
John D Martinsen
Keith Morisette
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Public Utility District No. 1 of Snohomish
County
Tacoma Public Utilities
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power Agency,
and Public
Service
Enterprise
Group)
Abstain
4
4
SUPPORTS
THIRD PARTY
COMMENTS (Cowlitz PUD)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Aces Power
Marketing)
SUPPORTS
THIRD PARTY
COMMENTS (Chris
Mattson)
SUPPORTS
THIRD PARTY
COMMENTS (Ameren
comments)
COMMENT
RECEIVED
NERC Standards
5
Associated Electric Cooperative, Inc.
5
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
5
Matthew Pacobit
5
Bonneville Power Administration
Francis J. Halpin
5
5
Brazos Electric Power Cooperative, Inc.
City and County of San Francisco
Shari Heino
Daniel Mason
Negative
Abstain
Negative
5
City of Austin dba Austin Energy
Jeanie Doty
Negative
5
City of Redding
Paul A. Cummings
Negative
5
City of Tallahassee
Karen Webb
Negative
5
5
5
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management, LLC
Steve Rose
Stephanie Huffman
Mike D Hirst
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Standifur)
SUPPORTS
THIRD PARTY
COMMENTS (SMUD &
PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Affirmative
Abstain
5
Colorado Springs Utilities
Kaleb Brimhall
Negative
5
Con Edison Company of New York
Brian O'Boyle
Negative
5
Consumers Energy Company
David C Greyerbiehl
5
Cowlitz County PUD
Bob Essex
5
Dairyland Power Coop.
Tommy Drea
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Cowlitz PUD)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See
Dominion's
submitted
comments)
5
Dominion Resources, Inc.
Mike Garton
5
DTE Electric
Mark Stefaniak
5
Duke Energy
Dale Q Goodwine
Negative
5
Dynegy Inc.
Dan Roethemeyer
Negative
5
E.ON Climate & Renewables North America,
LLC
Entergy Services, Inc.
5
Exelon Nuclear
Mark F Draper
5
First Wind
John Robertson
5
FirstEnergy Solutions
Kenneth Dresner
Negative
5
Florida Municipal Power Agency
David Schumann
Negative
5
Great River Energy
Preston L Walsh
Negative
5
Hydro-Québec Production
Roger Dufresne
Negative
5
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Dana Showalter
Tracey Stubbs
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
Negative
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
NERC Standards
5
Ingleside Cogeneration LP
Michelle R DAntuono
Negative
5
JEA
John J Babik
Negative
5
Kansas City Power & Light Co.
Brett Holland
Affirmative
5
Kissimmee Utility Authority
Mike Blough
5
Lakeland Electric
James M Howard
5
Liberty Electric Power LLC
Daniel Duff
Negative
5
Lincoln Electric System
Dennis Florom
Negative
5
Los Angeles Department of Water & Power
Kenneth Silver
Negative
5
Lower Colorado River Authority
Dixie Wells
Negative
5
Luminant Generation Company LLC
Rick Terrill
Negative
5
Manitoba Hydro
Chris Mazur
Negative
5
5
5
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Muscatine Power & Water
Negative
Steven Grego
Mike Avesing
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (LDWP)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Nebraska Public Power District
Don Schmit
Negative
5
New York Power Authority
Wayne Sipperly
Negative
5
NextEra Energy
Allen D Schriver
Negative
5
North Carolina Electric Membership Corp.
Jeffrey S Brame
Negative
5
Northern Indiana Public Service Co.
Michael D Melvin
Abstain
5
Oglethorpe Power Corporation
Bernard Johnson
Negative
5
Oklahoma Gas and Electric Co.
Henry L Staples
Negative
5
5
Omaha Public Power District
Pacific Gas and Electric Company
Mahmood Z. Safi
Alex Chua
Abstain
5
Platte River Power Authority
Christopher R Wood
5
Portland General Electric Co.
Matt E. Jastram
PPL Generation LLC
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power Agency)
David Gordon
5
5
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA
comments)
Annette M Bannon
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC and
NYPA
submitted
comments)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (PSGE)
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
NERC Standards
5
PSEG Fossil LLC
Tim Kucey
5
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Steven Grega
5
Negative
Michiko Sell
5
Puget Sound Energy, Inc.
Lynda Kupfer
Negative
5
Sacramento Municipal Utility District
Susan Gill-Zobitz
Negative
5
5
Salt River Project
Santee Cooper
William Alkema
Lewis P Pierce
Seattle City Light
Michael J. Haynes
Negative
5
Snohomish County PUD No. 1
Sam Nietfeld
Negative
5
South Carolina Electric & Gas Co.
Edward Magic
5
Southern California Edison Company
Denise Yaffe
Negative
5
Southern Company Generation
William D Shultz
Negative
5
Tacoma Power
Chris Mattson
Negative
5
5
Tampa Electric Co.
Tenaska, Inc.
RJames Rocha
Scott M. Helyer
5
Tennessee Valley Authority
David Thompson
Negative
5
Tri-State Generation & Transmission
Association, Inc.
U.S. Army Corps of Engineers
5
USDI Bureau of Reclamation
Erika Doot
Negative
5
Westar Energy
Bryan Taggart
Negative
5
Xcel Energy, Inc.
Mark A Castagneri
Negative
6
AEP Marketing
Edward P. Cox
Negative
6
Ameren Missouri
Robert Quinlivan
Negative
6
APS
Randy A. Young
Negative
6
Associated Electric Cooperative, Inc.
Brian Ackermann
Negative
Mark Stein
Melissa Kurtz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Puget Sound
Energy Eleanor Ewry)
COMMENT
RECEIVED
Affirmative
Abstain
5
5
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG
(Seelke))
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase,
Seattle)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Patrick
Farrell)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group
comments)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz AEP)
SUPPORTS
THIRD PARTY
COMMENTS (Ameren)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS -
NERC Standards
6
Bonneville Power Administration
Brenda S. Anderson
Negative
6
City of Austin dba Austin Energy
Lisa Martin
Negative
6
City of Redding
Marvin Briggs
Negative
6
Cleco Power LLC
Robert Hirchak
6
Colorado Springs Utilities
Shannon Fair
Negative
6
Con Edison Company of New York
David Balban
Negative
6
Constellation Energy Commodities Group
David J Carlson
Negative
6
Dominion Resources, Inc.
Louis S. Slade
Negative
6
Duke Energy
Greg Cecil
Negative
6
FirstEnergy Solutions
Kevin Querry
Negative
6
Florida Municipal Power Agency
Richard L. Montgomery
Negative
6
Florida Municipal Power Pool
Thomas Washburn
Negative
6
6
6
6
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Silvia P Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
6
Lincoln Electric System
Eric Ruskamp
Negative
6
Lower Colorado River Authority
Michael Shaw
Negative
6
Luminant Energy
Brenda Hampton
Negative
6
Manitoba Hydro
Blair Mukanik
Negative
6
Modesto Irrigation District
James McFall
Negative
6
New York Power Authority
Shivaz Chopra
Negative
6
Northern Indiana Public Service Co.
Joseph O'Brien
Abstain
6
Oglethorpe Power Corporation
Donna Johnson
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
(AECI)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Standifur)
SUPPORTS
THIRD PARTY
COMMENTS (SMUD &
PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Sprigs
Utilities)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (See
Dominion's
submitted
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
SUPPORTS
THIRD PARTY
COMMENTS (FE's
Comments)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS -
NERC Standards
6
Oklahoma Gas and Electric Co.
Jerry Nottnagel
Negative
6
Omaha Public Power District
Douglas Collins
Negative
6
PacifiCorp
Sandra L Shaffer
Affirmative
6
Platte River Power Authority
Carol Ballantine
Negative
6
6
6
Portland General Electric Co.
Power Generation Services, Inc.
Powerex Corp.
Shawn P Davis
Stephen C Knapp
Gordon Dobson-Mack
PPL EnergyPlus LLC
Elizabeth Davis
Negative
6
PSEG Energy Resources & Trade LLC
Peter Dolan
Negative
6
Public Utility District No. 1 of Chelan County
Hugh A. Owen
Abstain
6
Sacramento Municipal Utility District
Diane Enderby
Negative
6
6
Salt River Project
Santee Cooper
William Abraham
Michael Brown
6
Seattle City Light
Dennis Sismaet
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
Negative
Snohomish County PUD No. 1
Kenn Backholm
Negative
6
Southern California Edison Company
Joseph T Marone
Negative
6
Southern Company Generation and Energy
Marketing
John J. Ciza
Negative
6
6
Tacoma Public Utilities
Tampa Electric Co.
Michael C Hill
Benjamin F Smith II
6
Tennessee Valley Authority
Marjorie S. Parsons
Negative
6
Westar Energy
Grant L Wilkerson
Negative
6
Western Area Power Administration - UGP
Marketing
Peter H Kinney
6
Xcel Energy, Inc.
Peter Colussy
Negative
7
Occidental Chemical
Venona Greaff
Negative
7
Siemens Energy, Inc.
Frank R. McElvain
Roger C Zaklukiewicz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
COMMENT
RECEIVED
Affirmative
Abstain
6
SUPPORTS
THIRD PARTY
COMMENTS (PSGE)
Affirmative
Abstain
6
8
(ACES)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (SCE's
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
Affirmative
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
NERC Standards
8
David L Kiguel
Negative
8
Massachusetts Attorney General
Frederick R Plett
Negative
8
Volkmann Consulting, Inc.
Terry Volkmann
Negative
9
9
10
10
Commonwealth of Massachusetts
Department of Public Utilities
New York State Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
COMMENTS (NPCC)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
Donald Nelson
Diane J Barney
Linda C Campbell
Russel Mountjoy
Affirmative
10
New York State Reliability Council
Alan Adamson
Negative
10
Northeast Power Coordinating Council
Guy V. Zito
Negative
10
10
10
ReliabilityFirst
SERC Reliability Corporation
Southwest Power Pool RE
Anthony E Jablonski
Joseph W Spencer
Bob Reynolds
10
Texas Reliability Entity, Inc.
Karin Schweitzer
10
Western Electricity Coordinating Council
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
Negative
Steven L. Rueckert
Legal and Privacy : 404.446.2560 voice : 404.467.0474 fax : 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2014 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=03e22c5a-38ff-4607-9f39-a3db70d1f032[6/13/2014 9:23:37 AM]
Non-Binding Poll Results
Project 2010-13.3 Phase 3 of Relay Loadability:
Stable Power Swings
PRC-026-1
Non-Binding Poll Results
Non-Binding Poll
Project 2010-13.3 Relay Loadability Stable Power Swings PRC-026-1
Name:
Poll Period: 5/30/2014 - 6/9/2014
Total # Opinions: 258
Total Ballot Pool: 332
77.71% of those who registered to participate provided an opinion or an
Ballot Results: abstention; 17.88% of those who provided an opinion indicated support
for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
1
1
1
Organization
Ameren Services
American Electric Power
Arizona Public Service Co.
Member
Eric Scott
Paul B Johnson
Robert Smith
1
Associated Electric Cooperative, Inc.
John Bussman
1
ATCO Electric
Glen Sutton
1
Austin Energy
James Armke
1
Avista Utilities
Heather Rosentrater
1
Balancing Authority of Northern California Kevin Smith
1
BC Hydro and Power Authority
Patricia Robertson
1
Brazos Electric Power Cooperative, Inc.
Tony Kroskey
1
1
Bryan Texas Utilities
John C Fontenot
CenterPoint Energy Houston Electric, LLC John Brockhan
1
Central Electric Power Cooperative
Michael B Bax
Opinions
NERC
Notes
Abstain
Abstain
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
Negative
COMMENT
RECEIVED
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
1
Central Iowa Power Cooperative
Kevin J Lyons
Negative
1
City of Tacoma, Department of Public
Chang G Choi
Utilities, Light Division, dba Tacoma Power
Negative
1
City of Tallahassee
Daniel S Langston
Negative
1
Clark Public Utilities
Jack Stamper
1
Colorado Springs Utilities
Shawna Speer
Negative
1
Consolidated Edison Co. of New York
Christopher L de
Graffenried
Negative
1
CPS Energy
Glenn Pressler
Negative
1
Dairyland Power Coop.
Robert W. Roddy
1
1
Deseret Power
Dominion Virginia Power
James Tucker
Larry Nash
1
Duke Energy Carolina
Doug E Hils
1
Empire District Electric Co.
Ralph F Meyer
1
Encari
Steven E Hamburg
SUPPORTS
THIRD PARTY
COMMENTS (Comments Group,
Colorado
Springs
Utilities)
COMMENT
RECEIVED
COMMENT
RECEIVED
Abstain
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Abstain
1
Entergy Transmission
Oliver A Burke
Negative
1
FirstEnergy Corp.
William J Smith
Negative
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (CIPCO
supports the
comments
submitted for
this standard
submitted by
ACES.)
SUPPORTS
THIRD PARTY
COMMENTS (Chris Mattson)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG by John
Seelke)
SUPPORTS
THIRD PARTY
COMMENTS (FirstEnergy
Comments)
2
1
Florida Keys Electric Cooperative Assoc.
Dennis Minton
1
Florida Power & Light Co.
Mike O'Neil
1
Gainesville Regional Utilities
Richard Bachmeier
Negative
Affirmative
1
Georgia Transmission Corporation
Jason Snodgrass
Negative
1
Great River Energy
Gordon Pietsch
Negative
1
Hydro One Networks, Inc.
Muhammed Ali
Negative
1
Hydro-Quebec TransEnergie
Martin Boisvert
Negative
1
Idaho Power Company
Molly Devine
Negative
1
1
International Transmission Company
Holdings Corp
JDRJC Associates
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC)
SUPPORTS
THIRD PARTY
COMMENTS (HQT's
(provided to the
DT) and NPCC's
comments)
COMMENT
RECEIVED
Michael Moltane
Jim D Cyrulewski
Abstain
1
JEA
Ted E Hobson
Negative
1
KAMO Electric Cooperative
Walter Kenyon
Negative
1
Kansas City Power & Light Co.
Daniel Gibson
Affirmative
1
Lakeland Electric
Larry E Watt
1
1
Lee County Electric Cooperative
John Chin
Los Angeles Department of Water & Power faranak sarbaz
1
Lower Colorado River Authority
Martyn Turner
1
Manitoba Hydro
Jo-Anne M Ross
1
MEAG Power
Danny Dees
1
MidAmerican Energy Co.
Terry Harbour
1
Minnkota Power Coop. Inc.
Daniel L Inman
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (FMPA
comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
Abstain
Negative
COMMENT
RECEIVED
Negative
COMMENT
RECEIVED
Abstain
3
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
National Grid USA
Michael Jones
Negative
1
NB Power Corporation
Alan MacNaughton
1
Nebraska Public Power District
Jamison Cawley
Abstain
1
New York Power Authority
Bruce Metruck
Negative
1
Northeast Missouri Electric Power
Cooperative
Kevin White
Negative
1
1
Northeast Utilities
Northern Indiana Public Service Co.
William Temple
Julaine Dyke
Negative
Abstain
1
NorthWestern Energy
John Canavan
1
Ohio Valley Electric Corp.
Scott R Cunningham
Oklahoma Gas and Electric Co.
Terri Pyle
Negative
1
Omaha Public Power District
Doug Peterchuck
Negative
1
Oncor Electric Delivery
Jen Fiegel
Negative
1
Otter Tail Power Company
Daryl Hanson
1
Pacific Gas and Electric Company
Bangalore Vijayraghavan
1
Peak Reliability
Jared Shakespeare
1
1
Platte River Power Authority
Portland General Electric Co.
John C. Collins
John T Walker
PPL Electric Utilities Corp.
Brenda L Truhe
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (NPCC and
NYPA)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
1
1
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (National Grid
supports
NPCC's
comments.)
SUPPORTS
THIRD PARTY
COMMENTS (SPP Comment)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF
comments)
COMMENT
RECEIVED
Abstain
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Refer to
comments
submitted on
behalf of PPL
NERC
4
Registered
Affiliates.)
1
Public Service Company of New Mexico
Laurie Williams
1
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Kenneth D. Brown
1
Abstain
Dale Dunckel
1
Puget Sound Energy, Inc.
Denise M Lietz
1
Rochester Gas and Electric Corp.
John C. Allen
1
Sacramento Municipal Utility District
Tim Kelley
1
Salt River Project
Robert Kondziolka
1
SaskPower
Wayne Guttormson
1
Seminole Electric Cooperative, Inc.
Glenn Spurlock
Negative
Abstain
Negative
1
Sho-Me Power Electric Cooperative
Denise Stevens
Negative
1
Snohomish County PUD No. 1
Long T Duong
Negative
1
South Carolina Electric & Gas Co.
Tom Hanzlik
Negative
1
South Carolina Public Service Authority
Shawn T Abrams
1
Southern California Edison Company
Steven Mavis
Negative
1
Southern Company Services, Inc.
Robert A. Schaffeld
Negative
1
Southern Illinois Power Coop.
William Hutchison
Negative
1
Southwest Transmission Cooperative, Inc. John Shaver
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (Eleanor Ewry,
Puget Sound
Energy)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
Abstain
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
5
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
Tampa Electric Co.
Beth Young
Negative
1
Tennessee Valley Authority
Howell D Scott
1
Trans Bay Cable LLC
Steven Powell
1
Tri-State Generation & Transmission
Association, Inc.
Tracy Sliman
1
Tucson Electric Power Co.
John Tolo
1
U.S. Bureau of Reclamation
Richard T Jackson
1
United Illuminating Co.
Jonathan Appelbaum
1
Vermont Electric Power Company, Inc.
Kim Moulton
Affirmative
Affirmative
1
Westar Energy
Allen Klassen
1
Western Area Power Administration
Lloyd A Linke
1
Wolverine Power Supply Coop., Inc.
Michelle Clements
2
BC Hydro
Venkataramakrishnan
Vinnakota
2
California ISO
Rich Vine
Negative
2
Electric Reliability Council of Texas, Inc.
Cheryl Moseley
Negative
2
Independent Electricity System Operator
Leonard Kula
2
ISO New England, Inc.
Matthew F Goldberg
2
2
MISO
New York Independent System Operator
Marie Knox
Gregory Campoli
2
PJM Interconnection, L.L.C.
stephanie monzon
2
3
Southwest Power Pool, Inc.
AEP
Charles H. Yeung
Michael E Deloach
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP Standards
Group)
Abstain
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Abstain
Abstain
Abstain
3
Alabama Power Company
Robert S Moore
Negative
3
Ameren Corp.
David J Jendras
Abstain
3
APS
Sarah Kist
Negative
3
Associated Electric Cooperative, Inc.
Todd Bennett
Negative
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS -
6
(Associated
Electric
Cooperative
Inc)
3
3
Avista Corp.
BC Hydro and Power Authority
Scott J Kinney
Pat G. Harrington
3
Central Electric Power Cooperative
Adam M Weber
3
City of Austin dba Austin Energy
Andrew Gallo
3
City of Clewiston
Lynne Mila
3
3
City of Farmington
City of Green Cove Springs
Linda R Jacobson
Mark Schultz
Abstain
Abstain
Negative
Abstain
Abstain
Abstain
3
City of Tallahassee
Bill R Fowler
Negative
3
Colorado Springs Utilities
Jean Mueller
Negative
3
Consolidated Edison Co. of New York
Peter T Yost
Negative
3
Consumers Energy Company
Gerald G Farringer
3
Cowlitz County PUD
Russell A Noble
Negative
3
CPS Energy
Jose Escamilla
Negative
3
Dominion Resources, Inc.
Connie B Lowe
Abstain
3
DTE Electric
Kent Kujala
Negative
3
FirstEnergy Corp.
Cindy E Stewart
Negative
3
Florida Keys Electric Cooperative
Tom B Anthony
Negative
3
Florida Municipal Power Agency
Joe McKinney
Negative
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (Group,
Colorado
Springs
Utilities)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA & PSEG
comments)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FirstEnergy
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
COMMENT
RECEIVED
7
3
Florida Power & Light Co.
Summer C. Esquerre
3
Florida Power Corporation
Lee Schuster
Negative
3
Georgia System Operations Corporation
Scott McGough
Negative
3
Great River Energy
Brian Glover
Negative
3
Hydro One Networks, Inc.
Ayesha Sabouba
Negative
3
JEA
Garry Baker
Negative
3
Kansas City Power & Light Co.
Joshua D Bach
3
Lakeland Electric
Mace D Hunter
3
Lee County Electric Cooperative
David A Hadzima
3
3
Lincoln Electric System
Jason Fortik
Los Angeles Department of Water & Power Mike Anctil
3
Louisville Gas and Electric Co.
Charles A. Freibert
3
Manitoba Hydro
Greg C. Parent
3
MEAG Power
Roger Brand
3
MidAmerican Energy Co.
Thomas C. Mielnik
3
Modesto Irrigation District
Jack W Savage
3
Muscatine Power & Water
John S Bos
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Agency)
Abstain
Abstain
Negative
COMMENT
RECEIVED
Abstain
3
National Grid USA
Brian E Shanahan
3
Nebraska Public Power District
Tony Eddleman
3
New York Power Authority
David R Rivera
3
Northern Indiana Public Service Co.
Ramon J Barany
Abstain
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC-RSC)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC
Group
comments)
Abstain
SUPPORTS
THIRD PARTY
8
3
Ocala Utility Services
Randy Hahn
Negative
3
Oklahoma Gas and Electric Co.
Donald Hargrove
Negative
3
Omaha Public Power District
Blaine R. Dinwiddie
3
3
3
3
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Platte River Power Authority
Ballard K Mutters
Thomas T Lyons
John H Hagen
Terry L Baker
3
PNM Resources
Michael Mertz
3
Portland General Electric Co.
Thomas G Ward
3
Public Service Electric and Gas Co.
Jeffrey Mueller
Abstain
Affirmative
Affirmative
Abstain
Abstain
3
Puget Sound Energy, Inc.
Mariah R Kennedy
Negative
3
Sacramento Municipal Utility District
James Leigh-Kendall
Negative
3
3
Salt River Project
Santee Cooper
John T. Underhill
James M Poston
3
Seminole Electric Cooperative, Inc.
James R Frauen
SUPPORTS
THIRD PARTY
COMMENTS (Eleanor Ewry)
COMMENT
RECEIVED
Affirmative
Abstain
3
Sho-Me Power Electric Cooperative
Jeff L Neas
Negative
3
Snohomish County PUD No. 1
Mark Oens
Negative
3
South Carolina Electric & Gas Co.
Hubert C Young
Negative
3
Southern California Edison Company
Lujuanna Medina
Negative
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
SUPPORTS
THIRD PARTY
COMMENTS (SCE's
comments)
9
3
Tacoma Power
Marc Donaldson
3
Tampa Electric Co.
Ronald L. Donahey
3
Tennessee Valley Authority
Tri-State Generation & Transmission
Association, Inc.
Ian S Grant
3
Janelle Marriott
Negative
Abstain
Affirmative
3
Westar Energy
Bo Jones
3
Xcel Energy, Inc.
Michael Ibold
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
Negative
4
4
Blue Ridge Power Agency
City of Austin dba Austin Energy
Duane S Dahlquist
Reza Ebrahimian
Affirmative
Abstain
4
City Utilities of Springfield, Missouri
John Allen
4
Consumers Energy Company
Tracy Goble
4
Cowlitz County PUD
Rick Syring
Negative
4
DTE Electric
Daniel Herring
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
Georgia System Operations Corporation
Guy Andrews
Negative
4
4
4
4
4
Herb Schrayshuen
Illinois Municipal Electric Agency
Indiana Municipal Power Agency
Madison Gas and Electric Co.
Modesto Irrigation District
Herb Schrayshuen
Bob C. Thomas
Jack Alvey
Joseph DePoorter
Spencer Tacke
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP Standards
Group)
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Cowlitz PUD)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)
Affirmative
Abstain
Abstain
Abstain
Affirmative
4
Ohio Edison Company
Douglas Hohlbaugh
Negative
4
Public Utility District No. 1 of Snohomish
County
John D Martinsen
Negative
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (Chris Mattson)
SUPPORTS
THIRD PARTY
COMMENTS (FirstEnergy
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
10
4
Sacramento Municipal Utility District
Mike Ramirez
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
4
South Mississippi Electric Power
Association
Steve McElhaney
4
Tacoma Public Utilities
Keith Morisette
4
Utility Services, Inc.
Brian Evans-Mongeon
5
5
5
5
Amerenue
American Electric Power
Arizona Public Service Co.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky
peak power plant project
Sam Dwyer
Thomas Foltz
Scott Takinen
Clement Ma
5
Bonneville Power Administration
Francis J. Halpin
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
City and County of San Francisco
Daniel Mason
5
City of Austin dba Austin Energy
Jeanie Doty
5
Negative
Affirmative
Negative
Mike D Kukla
Negative
Karen Webb
Negative
5
City Water, Light & Power of Springfield
Steve Rose
Affirmative
5
Cleco Power
Stephanie Huffman
5
Cogentrix Energy Power Management, LLC Mike D Hirst
Colorado Springs Utilities
Kaleb Brimhall
Negative
5
Con Edison Company of New York
Brian O'Boyle
Negative
5
Consumers Energy Company
David C Greyerbiehl
Cowlitz County PUD
Bob Essex
5
Dairyland Power Coop.
Tommy Drea
5
Dominion Resources, Inc.
Mike Garton
5
DTE Electric
Mark Stefaniak
Dale Q Goodwine
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Abstain
5
5
COMMENT
RECEIVED
Abstain
City of Tallahassee
Duke Energy
SUPPORTS
THIRD PARTY
COMMENTS (Chris Mattson)
Abstain
Abstain
Affirmative
Abstain
5
5
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Cowlitz PUD)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
11
5
Dynegy Inc.
Dan Roethemeyer
Negative
5
E.ON Climate & Renewables North
America, LLC
Dana Showalter
5
Entergy Services, Inc.
Tracey Stubbs
5
First Wind
John Robertson
5
FirstEnergy Solutions
Kenneth Dresner
Negative
5
Florida Municipal Power Agency
David Schumann
Negative
5
Great River Energy
Preston L Walsh
Negative
5
Hydro-Québec Production
Roger Dufresne
Negative
5
Ingleside Cogeneration LP
Michelle R DAntuono
Negative
5
JEA
John J Babik
Negative
5
Kansas City Power & Light Co.
Brett Holland
Affirmative
5
Kissimmee Utility Authority
Mike Blough
Negative
5
Liberty Electric Power LLC
Daniel Duff
Negative
5
5
Lincoln Electric System
Dennis Florom
Los Angeles Department of Water & Power Kenneth Silver
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)
COMMENT
RECEIVED
Abstain
Abstain
5
Lower Colorado River Authority
Dixie Wells
Negative
5
Luminant Generation Company LLC
Rick Terrill
Negative
5
Manitoba Hydro
Chris Mazur
Negative
5
Massachusetts Municipal Wholesale
Electric Company
David Gordon
5
MEAG Power
Steven Grego
5
Muscatine Power & Water
Mike Avesing
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
12
5
Nebraska Public Power District
Don Schmit
Abstain
5
New York Power Authority
Wayne Sipperly
Negative
5
NextEra Energy
Allen D Schriver
Negative
5
North Carolina Electric Membership Corp. Jeffrey S Brame
Negative
5
Northern Indiana Public Service Co.
Michael D Melvin
Abstain
5
Oglethorpe Power Corporation
Bernard Johnson
Negative
5
Oklahoma Gas and Electric Co.
Henry L Staples
Negative
5
Omaha Public Power District
Mahmood Z. Safi
5
5
Pacific Gas and Electric Company
Platte River Power Authority
Alex Chua
Christopher R Wood
5
Portland General Electric Co.
Matt E. Jastram
5
PPL Generation LLC
Annette M Bannon
5
PSEG Fossil LLC
Tim Kucey
5
Public Utility District No. 1 of Lewis County Steven Grega
5
Public Utility District No. 2 of Grant
County, Washington
SUPPORTS
THIRD PARTY
COMMENTS (NPCC and
NYPA submitted
comments)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Comments)
Abstain
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Abstain
Michiko Sell
5
Puget Sound Energy, Inc.
Lynda Kupfer
Negative
5
Sacramento Municipal Utility District
Susan Gill-Zobitz
Negative
5
5
5
Salt River Project
Santee Cooper
Seattle City Light
William Alkema
Lewis P Pierce
Michael J. Haynes
Affirmative
Abstain
Abstain
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (Puget Sound
Energy Eleanor Ewry)
COMMENT
RECEIVED
13
5
Snohomish County PUD No. 1
Sam Nietfeld
5
South Carolina Electric & Gas Co.
Edward Magic
Negative
5
Southern California Edison Company
Denise Yaffe
Negative
5
Southern Company Generation
William D Shultz
Negative
5
Tacoma Power
Chris Mattson
Negative
5
Tampa Electric Co.
RJames Rocha
5
Tenaska, Inc.
Scott M. Helyer
5
David Thompson
5
Tennessee Valley Authority
Tri-State Generation & Transmission
Association, Inc.
U.S. Army Corps of Engineers
5
USDI Bureau of Reclamation
Erika Doot
Negative
5
Xcel Energy, Inc.
Mark A Castagneri
Negative
6
6
AEP Marketing
Ameren Missouri
Edward P. Cox
Robert Quinlivan
Abstain
Abstain
6
APS
Randy A. Young
Negative
6
Associated Electric Cooperative, Inc.
Brian Ackermann
Negative
6
Bonneville Power Administration
Brenda S. Anderson
Negative
6
City of Austin dba Austin Energy
Lisa Martin
6
Cleco Power LLC
Robert Hirchak
5
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Patrick Farrell)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
Abstain
Mark Stein
Melissa Kurtz
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS - (
AECI)
COMMENT
RECEIVED
Abstain
6
Colorado Springs Utilities
Shannon Fair
Negative
6
Con Edison Company of New York
David Balban
Negative
6
Duke Energy
Greg Cecil
Negative
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Sprigs Utilities)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
14
6
FirstEnergy Solutions
Kevin Querry
Negative
6
Florida Municipal Power Agency
Richard L. Montgomery
Negative
6
Florida Municipal Power Pool
Thomas Washburn
Negative
6
Florida Power & Light Co.
Silvia P Mitchell
6
Great River Energy
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
6
Lakeland Electric
Paul Shipps
6
Lincoln Electric System
Eric Ruskamp
Affirmative
Affirmative
Abstain
6
Lower Colorado River Authority
Michael Shaw
6
Luminant Energy
Brenda Hampton
6
Manitoba Hydro
Blair Mukanik
Negative
6
Modesto Irrigation District
James McFall
Abstain
6
New York Power Authority
Shivaz Chopra
Negative
6
Northern Indiana Public Service Co.
Joseph O'Brien
Abstain
Negative
Oglethorpe Power Corporation
Donna Johnson
Negative
6
Oklahoma Gas and Electric Co.
Jerry Nottnagel
Negative
6
Omaha Public Power District
Douglas Collins
Negative
6
PacifiCorp
Sandra L Shaffer
Platte River Power Authority
Carol Ballantine
6
Portland General Electric Co.
Shawn P Davis
6
6
Power Generation Services, Inc.
Powerex Corp.
Stephen C Knapp
Gordon Dobson-Mack
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Abstain
6
6
COMMENTS (Duke Energy)
SUPPORTS
THIRD PARTY
COMMENTS (FE's
Comments)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PSGE)
Affirmative
Abstain
15
6
PPL EnergyPlus LLC
Elizabeth Davis
6
PSEG Energy Resources & Trade LLC
Peter Dolan
6
Sacramento Municipal Utility District
Diane Enderby
6
6
Salt River Project
Santee Cooper
William Abraham
Michael Brown
6
Seattle City Light
Dennis Sismaet
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
Negative
Abstain
Negative
Negative
Snohomish County PUD No. 1
Kenn Backholm
Negative
6
Southern California Edison Company
Joseph T Marone
Negative
6
Southern Company Generation and
Energy Marketing
John J. Ciza
Negative
6
Tacoma Public Utilities
Michael C Hill
6
Tampa Electric Co.
Benjamin F Smith II
6
Tennessee Valley Authority
Marjorie S. Parsons
Western Area Power Administration - UGP
Peter H Kinney
Marketing
7
8
David L Kiguel
Negative
8
Roger C Zaklukiewicz
Negative
8
Volkmann Consulting, Inc.
Frederick R Plett
Terry Volkmann
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke,
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (SCE's
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Affirmative
Negative
Massachusetts Attorney General
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase)
Abstain
Venona Greaff
8
Occidental Chemical
COMMENT
RECEIVED
Affirmative
Abstain
6
6
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
16
Enterprise
Group)
Commonwealth of Massachusetts
Department of Public Utilities
Donald Nelson
10
Florida Reliability Coordinating Council
Linda C Campbell
10
Midwest Reliability Organization
Russel Mountjoy
9
Affirmative
10
New York State Reliability Council
Alan Adamson
Negative
10
Northeast Power Coordinating Council
Guy V. Zito
Negative
10
10
10
10
ReliabilityFirst
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Anthony E Jablonski
Joseph W Spencer
Bob Reynolds
Karin Schweitzer
10
Western Electricity Coordinating Council
Steven L. Rueckert
Non-Binding Poll Results
Project 2010-13.3 Relay Loadbility: Stable Power Swings | June 2014
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
17
Individual or group. (70 Responses)
Name (46 Responses)
Organization (46 Responses)
Group Name (24 Responses)
Lead Contact (24 Responses)
Question 1 (49 Responses)
Question 1 Comments (56 Responses)
Question 2 (45 Responses)
Question 2 Comments (56 Responses)
Question 3 (47 Responses)
Question 3 Comments (56 Responses)
Question 4 (42 Responses)
Question 4 Comments (56 Responses)
Question 5 (39 Responses)
Question 5 Comments (56 Responses)
Question 6 (40 Responses)
Question 6 Comments (56 Responses)
Question 7 (39 Responses)
Question 7 Comments (56 Responses)
Question 8 (0 Responses)
Question 8 Comments (56 Responses)
Question 9 (0 Responses)
Question 9 Comments (56 Responses)
Question 10 (0 Responses)
Question 10 Comments (56 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
No
We agree with a focused approach as outlined in the technical document. However, we have the
following serious concerns with criteria in the requirements: 1. The term “credible event” should be
clearly defined. The basis to determine a credible event is missing from the requirement and
application guide. This basis should be provided in the standard requirement. 2. Why is the standard
focused on SOL rather than IROL? The basis for specifying SOL is not supported by the example in
the application guideline since the example did not show inter-area impact. 3. It is not clear in R1,
criteria number 4 whether the assessment should include relay tripping or just stable power swing or
both stable and unstable power swing. 4. In R2, it is unrealistic to require an entity to provide data
on an Element that had tripped since 2003. There is no existing NERC continent-wide disturbance
monitoring or misoperation standard that requires data be retained more than 12 months. We
recommend that this requirement be removed from the standard or include only Elements that were
tripped in the last calendar year. It must be noted that the standard is unsupported by the
Protection System Response to Power Swings, System Protection and Control Subcommittee,
August, 2013 document. Referring to p. 20, the “Need for a Standard” section, states “Based on its
review of historical events, consideration of the trade‐offs between dependability and security, and
recognizing the indirect benefits of implementing the transmission relay loadability standard (PRC‐
023), the SPCS concludes that a NERC Reliability Standard to address relay performance during
stable swings is not needed, and could result in unintended adverse impacts to Bulk‐Power System
reliability.” (Emphasis added). The following report references support the PSRPS document’s
conclusion that this standard is not needed: 1) Page 8 of 61, 1965 Northeast Blackout Conclusion,
first sentence “Relays tripping due …” 2) Page 8 of 61, 1977 New York Blackout Conclusions, first
sentence, “Relays tripping due…” 3) Page 9 of 61, July 2-3, 1996: West Coast Blackout Conclusions,
first sentence “Relays tripping due..” 4) Page 10 of 61, August 10, 1996 Conclusions, first sentence,
“Relays tripping due..” 5) Page 16 of 61, 2003 Northeast Blackout Conclusion, “Relays tripping
due…” 6) Page 17 of 61, Overall Observations from Review of Historical Events, first and second
sentences, “Relays tripping…” 7) Page 19 of 61, final paragraph, “Given the ….” NERC’s informational
filing in Docket No. RM08-13-000 dated July 21, 2011 concluded that there is a need for a standard
on stable power swings. The subsequently developed PSRPS document, which was developed by
industry experts and approved by the NERC Planning Committee, clearly refutes the FERC directive
in Order No. 773 (Docket No. RM08-13-000), that was subsequently affirmed in Order Nos. 773-A
and 773-B, that a standard is needed to ensure that load-responsive protective relays do not trip in
response to stable power swings during non-Fault conditions. We recommend that the NERC
Standards Committee explore means to utilize the more recent PSRPS document to obtain relief
from the aforementioned FERC directive that is driving this project.
No
Requirement R2 requires GOs and TOs to evaluate Disturbance records “since January 1, 2003,” a
time that will precede the effective date of this standard. A requirement CANNOT RELY UPON
RECORDS THAT PRECEDE THE EFFECTIVE DATE OF A STANDARD. As an example, PRC-005-1, which
was approved in Order 693, became effective on June 11, 2007, does not require a Registered Entity
to have maintenance records available for the period of time that preceded the effective date in
order to calculate the next maintenance interval for a relay. We recommend that this requirement be
removed from the standard or include only Elements that were tripped in the last calendar year.
No
The Purpose of the standard is “To ensure that load-responsive protective relays do not trip in
response to stable power swings during non-Fault conditions.” The last sentence of Background,
Section 5 implies that a protective relay, while blocking for a stable power swing also allows for
dependable operation for fault and unstable power swing. Requirement R3 Bullet #4 is contrary to
the Purpose of the standard. The sub-Parts of R3 Bullet 4 are “or”, which means that if there isn’t
dependable fault detection or dependable out-of-step tripping, agreement would just have to be
obtained from the respective Planning Coordinator, Reliability Coordinator, and Transmission Planner
of the Element that the existing Protection System design and settings are acceptable. The sub-Parts
of R3 Bullet should be an “and”. Item b under the fourth bullet in Requirement R3 is not stated using
clear and unambiguous language whereby responsible entities, using reasonable judgment, are able
to arrive at a consistent interpretation of the required performance. The R3 Rationale and the
Protection System Response to Power Swings technical document provide some clarity; however,
the fourth bullet is not clear and troublesome from a compliance perspective. Suggest to consider
revising the fourth bullet to ensure the responsible entity understands the balance between security
and dependability and how that is to be achieved by either sub-parts “a” or “b”. The standard does
not specify any time parameters for developing and correcting the conditions addressed by a CAP.
We suggest that time parameters for developing and correcting the conditions addressed by the CAP
be addressed within the requirements of the standard.
No
In the Application Guidelines, the wording under Requirement 2 for credible event is very ambiguous
and needs specificity.
No.
No.
Suggest that Associated Documents (at least those where there are no copyright concerns) be
included in the standard as attachments or appendices as we are concerned that cited URLs will
change over time. The information in the Criteria and Criterion in the standard should not be in the
requirements, but in the Rationale Boxes.
Individual
Steve Wickel
CHPD - Public Utility District No. 1 of Chelan County
R1.2 - Is this an SOL for the planning (FAC-010) or operating (FAC-011) horizon? This requirement
seems to be duplicating, at least in part, FAC-014 R6 (The Planning Authority shall identify the
subset of multiple contingencies (if any), from Reliability Standard TPL-003 which result in stability
limits.). SOLs are generally established to facilitate performance under a NERC TPL Category B
performance. Select NERC TPL category C and limited D criteria are added by the WECC regional
criteria. R1.3 - TPL studies require transient stability simulations, not angular stability simulations.
There is no standard that requires angular stability simulations. There is no mention of angular
stability simulations in FAC-010, FAC-011, or the new TPL-001-4 either. R1.4 - WECC is slowly
coming on board with this as a result of the San Diego outage and is adding overcurrent relays to
system models at this time. However, the relay tripping addressed in this proposed standard may
also occur by distance or other elements, which are not required to be modeled in WECC at this time
in its base case process. There is also a lack of a performance category for these reporting
requirements (such as for Category B and C events). Performance issues may show up for extreme
Category D events in the assessment, but in the language as it stands, these must also be identified
and the GO and TO notified even for category D extreme events. This is a significant departure from
traditional practice, which emphasizes category B and C issue communication. In the existing TPL
standards, severe power swings are considered a Category D.14 event.
R1.1 – There should be a clarification or definition of a line-out condition. The meaning and intent of
this note is not clear.
Individual
Rick Terrill
Luminant Generation Company LLC
No
The focused approach is too narrow for Generation Owners in that it restricts to the Transmission
Planner and Generation Owner to events that have occurred and not a Planning Assessment
transient stability study results that indicate load responsive relay operation is challenged. Item #4
in Requirement R1 may not capture all power system swings since it is focused on previous events.
Luminant recommends that the Transmission Planner be responsible for transient stability studies
and reporting the information to the Generation Owner for locations where load responsive relays
are challenged. The date of 2003 needs to be removed from the standard as it prefaces compliance
on data that predates the approval of the standard. Also, the Generation Owner and Transmission
Owner (in cases where the Transmission Planner and Transmission Owner are not the same entity)
do not have the tools to determine if the BES is configured such that a Disturbance event is still
credible. Luminant believes that R2 criteria 1 and 2 need to be modified as follows: “1. An Element
that load responsive relaying has tripped during the past calendar year due to a power swing during
an actual system Disturbance. “ “2. An Element that has formed the boundary of an island during
the past calendar year during an actual system Disturbance. “
Yes
No
See the response to Question 1. If R2 were modified as proposed in Question 1, then Luminant
would agree that these are the appropriate entities.
No
Requirement R3 focuses on a method commonly used for transmission application. Generator
Owners will not be able to use this method for elements that satisfy the criteria in Requirement R1
and R2 for impedance relays used at the generator terminals or at the high voltage side of the
Generator Step-up Transformer. Transmission Planners have the tools and data to perform these
studies. A requirement should be added for Transmission Planners to provide the data to the
Generation Owners for elements that have stable power swings that challenge the relay. Luminant
recommends the following additional requirement. “Each Planning Coordinator, Reliability
Coordinator, and Transmission Planner shall, within the first quarter month of each calendar year
provide to the identified Generator Owner or Transmission Owner pursuant to R1, the stable power
swing characteristics (i.e. R-X vs time, current vs time plots, voltage and current vs time) and
identified event information.” In addition, the criterion in Requirement R3 considers distance relays
which is a subset of load responsive relays used in Generating Facilities. Protective relays such as
loss of field, time overcurrent, and voltage controlled overcurrent relays should be excluded and
listed in an Attachment similar to PRC-023.
Yes
No
The Application Guide should include examples for Generator Owners using distance relays. The
example should provide illustrations of transient stability R-X plots in the time domain provided by
the Transmission Planner in a format that allows the Transmission Owner and Generation Owner to
plot distance relay settings.
Yes
NERC standards requirements should not reference data that predates the approval of the standard;
therefore, rendering the Requirement R2 January 2003 date unenforceable.
The Attachments to the standard should include a listing of the specific load responsive relays that
are included in the scope of the standard.
Individual
Michelle R. D'Antuono
Ingleside Cogeneration LP
No
Ingleside Cogeneration LP (“ICLP”) believes that the drafting team has generally captured the intent
of FERC Order 733 by specifying the planning and operations criteria used to identify susceptible
Elements. Clearly those load responsive relays that protect Elements that have a stability constraint
or are tripped in response to a stable power swing should be in scope. However, we do not agree
that those Elements that form the boundary of an island during planning assessments or as a result
of an actual Disturbance should be subject to PRC-026-1. Our assertion is based upon a reading of
the FERC directive in Order 733, which responds to a stakeholder suggestion that islanding
strategies are a reasonable approach to limit the effect of a relay that improperly reacts to a stable
power swing. Instead, the project team has interpreted the ruling as a means to identify susceptible
Elements – adding an unnecessary burden to every relay owner and planner in the annual
assessment process. In our view, the item should be re-positioned as a bullet point in R3, which
allows the TO or GO to show that an islanding scheme sufficiently protects the greater BES against
instability. This would be similar to the acknowledgement that power swing blocking limits the effect
of a load relay trip – essentially another mitigation strategy that may be used address a situation
where the relay settings themselves cannot be changed for some reason.
Yes
Yes
No
ICLP agrees that the Transmission Owner and Generator Owner is in the best position to provide the
equipment models and relay settings necessary to perform an adequate assessment. However, the
application guidelines contain several statements that infer that the Transmission Planner must be
involved in the process (e.g.; the TP must be consulted to validate the slip rates of power swing
blocking schemes or if infeed affects the apparent impedance). In our view, there must be a
mandatory means to engage the TP when such coordination is required. Otherwise, a TP could
refuse to support the analysis for any reason, leaving the TO or GO to look for other less sufficient
alternatives. Even if the Transmission Planner’s reasons are justified, the Element owner may be
found in violation of R3 due to circumstances out of their control. ICLP suggests that the same
situation was addressed in the generator validation standards – which also requires GO/TP
coordination to evaluate local system performance – and could be applied in PRC-026-1.
Yes
Yes
Yes
ICLP believes that the findings by NERC’s System Protection and Control Subcommittee (SPCS)
compellingly demonstrate that the initial findings from the 2003 Northeastern blackout were flawed.
There is no doubt some load responsive relays did trip during the event when unusual, but nonthreating transients manifested themselves as a result of a downstream Fault. However, the SPCS
found that in every case, a subsequent unstable power swing followed within seconds – and the
relay would have tripped anyways. Furthermore, planning simulations confirmed that had the stable
power swing in question had taken place under N-1 and N-2 contingencies – the norm to which the
electric system is designed – those relays would not have reacted. Even more concerning, the report
goes on to say that “over-emphasizing secure operation for stable powers swings could be
detrimental to Bulk‐Power System reliability” (see page 19). This means that FERC Order 733, which
relies heavily on the 2003 investigative task force recommendations, may actually increase the
threat of wide-area instability or Cascading. ICLP does not question FERC’s authority to order the
development of a Reliability Standard – and we agree the subject matter is ultra-complex.
Nevertheless, FERC should be operating to the best information available, which may have changed
over time. There are far too many other pressing priorities for Registered Entities, CEAs, and even
the Commission to expend this much effort on one that has little or even negative benefit. At the
very least, we would like NERC or the SPCS to request a Technical Conference on the subject. Other
such conferences in the past seem to have resulted in effective, yet reasonable, approaches to
similarly complex issues.
Individual
Venona Greaff
Occidental Chemical Corporation
Individual
John Seelke
Public Service Enterprise Group
No
The entire standard is unsupported by the PSRPS document. See p. 20 in the “Need for a Standard”
section, which states “Based on its review of historical events, consideration of the trade‐offs
between dependability and security, and recognizing the indirect benefits of implementing the
transmission relay loadability standard (PRC‐023), THE SPCS CONCLUDES THAT A NERC
RELIABILITY STANDARD TO ADDRESS RELAY PERFORMANCE DURING STABLE POWER SWINGS IS
NOT NEEDED, AND COULD RESULT IN UNINTENDED ADVERSE IMPACTS TO BULK-POWER SYSTEM
RELIABILITY." (Emphasis added by CAPITALIZATION.) See the specific report references below that
support the PSRPS document’s conclusion that this standard is not needed: 1) Page 8 of 61, 1965
Northeast Blackout Conclusion, first sentence “Relays tripping due …” 2) Page 8 of 61, 1977 New
York Blackout Conclusions, first sentence, “Relays tripping due…” 3) Page 9 of 61, July 2-3, 1996:
West Coast Blackout Conclusions, first sentence “Relays tripping due..” 4) Page 10 of 61, August 10,
1996 Conclusions, first sentence, “Relays tripping due..” 5) Page 16 of 61, 2003 Northeast Blackout
Conclusion, “Relays tripping due…” 6) Page 17 of 61, Overall Observations from Review of Historical
Events, first and second sentences, “Relays tripping…” 7) Page 19 of 61, final paragraph, “Given the
….” The PSRPS document, developed by industry experts and approved by the NERC Planning
Committee, clearly disputes the FERC directive in Order No. 773 (Docket No. RM08-13-000), that
was subsequently affirmed in Order Nos. 773-A and 773-B, that a standard is needed to ensure that
load-responsive protective relays do not trip in response to stable power swings during non-Fault
conditions. NERC’s informational filing in Docket No. RM08-13-000 dated July 21, 2011 concluded
that there is a need for a standard on stable power swings. This conclusion is the opposite of what
the PSRPS document concluded. We recommend that the NERC Standards Committee explore
means to utilize the more recent PSRPS document to obtain relief from the aforementioned FERC
directive that is driving this project.
No
We disagree with the need for this standard.
No
We disagree with the need for this standard. However, this requirement is so egregious with regard
to one item that we offer these comments so that similar language may never appear in any future
standards. R2 requires GOs and TOs to evaluate Disturbance records “since January 1, 2003,” a time
that will precede the effective date of this standard. A requirement cannot rely upon records that
precede the effective date of a standard. As an example, PRC-005-1, which was approved in Order
693, became effective on June 11, 2007, does not require a Registered Entity to have maintenance
records available for the period of time that preceded the effective date in order to calculate the next
maintenance interval for a relay.
No
We disagree with the need for this standard.
No
We disagree with the need for this standard.
No
We disagree with the need for this standard.
No
We disagree with the need for this standard.
Individual
Jared Shakespeare
Peak Reliability
Yes
No
The TP’s relationship to the PC is synonymous with the TOP’s relationship with the RC, so leaving the
TOP out as an applicable entity creates a reliability gap. The TOP is responsible for establishing
SOLs.
No
Peak Reliability disagrees with the assignment of the multiple VSL’s for Requirements R1, R2 and R3
because the proposed VSLs simply increase the penalty for tardiness. Any delay in identifying and
element is a reliability concern. Recommend changing the VSL as follows: R1 Lower VSL: The
responsible entity identified an Element and provided notification in accordance with Requirement
R1, but was late by less than or equal to 7 calendar days. R1 Severe VSL: The responsible entity
failed to identify an Element or to provide notification in accordance with Requirement R1 or was late
by more than 7 calendar days. R2 Lower VSL: The responsible entity identified Element in
accordance with Requirement R2, but was late by less than or equal to 7 calendar days. R2 Severe
VSL: The responsible entity failed to identify an Element in accordance with Requirement R2 or was
late by more than 7 calendar days. R3 Lower VSL: The responsible entity performed one of the
options in accordance with Requirement R3, but was less than or equal to 7 calendar days late. R#
Severe VSL: The responsible entity performed one of the options in accordance with Requirement
R3, but was more than 7 calendar days late or the responsible entity failed to perform one of the
options in accordance with Requirement R3.
No
• The expectations of the RC need to be clarified, and until they are clarified, it is unclear whether
the implementation period is reasonable. It is unclear whether the annual list of Elements provided
by the RC is intended to be a result of a new and different one-time analysis performed by the RC or
TOP, or if the list of Elements is intended to be compiled over time as a result of ongoing operations
planning analyses and real-time assessments already being performed. The RC performs many
assessments throughout the Operations Planning horizon, Same-Day horizon, and Real-time
horizons for expected and actual operating conditions. As related to the RC specifically, is the intent
of R1 for the RC to continuously add to this list of Elements based on the results from all of these RC
studies performed throughout the year, and to report this compiled list to the GOs and TOs once per
calendar year? This approach would seem to add the most reliability benefit.
Individual
Daniel Duff
Liberty Electric Power
R2 requires Generator Operators to possess evidence prior to the enforcement date of the
Standards, and prior to the passage of the Energy Act of 2005. No standard should be written which
requires an entity to possess, analyze, or have knowledge of an event prior to the effective date of
the standard. The beginning date of analysis should be the first full calander year after the FERC
approval date of the standard.
Individual
Mauricio Guardado
Los Angeles Department of Water and Power
No
LADWP opposes the criteria from Requirement 2 that proposed looking back on Elements since
2003. Requirements cannot be applied retroactively.
Yes
Yes
LADWP is voting “Negative” on PRC-026-1 for the reason that the reference document entitled
“Protection System Response to Power Swings” (the PSRPS document) used to justify the standard
does not support the need for a reliability standard.
Individual
Brenda Hampton
Luminant Energy Company, LLC
Group
PacifiCorp
Sandra Shaffer
Yes
R1, which states “Any Element that is located or terminates at a generating plant, where a
generating plant stability constraints exists and is addressed by an operating limit or a Special
Protection System (SPS) (including line-out condition)”…. raises concerns. In WECC region, a SPS or
RAS has to be redundant. Language needs to be added to make a redundant system an exemption
from this requirement.
Yes
No
These functions would be more appropriate assigned to the GOP and TOP.
Yes
No comment
Yes
Yes
Individual
Ayesha Sabouba
Hydro One
Individual
Frederikc R Plett
Masschusetts Attorney General
No
R2 requires GOs and TOs to evaluate Disturbance records “since January 1, 2003,” a time that will
precede the effective date of this standard. A requirement cannot rely upon records that precede the
effective date of a standard.
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Rob Robertson
First Wind
Individual
Ronnie C. Hoeinghaus
City of Garland
Group
MRO NERC Standards Review Forum
Joe DePoorter
Yes
Yes
Yes
No
The NSRF requests that the SDT provide additional details on how the Lens characteristic is derived
and examples of its use with the system parameters that were calculated from the example.
Yes
No
The NSRF believes there is some significant discussion in the guidelines and technical basis.
However, we recommend that the SDT provide more clear explanation of all of the important
parameters.
No
The NSRF believes there may be many elements, questions or unexpected problems in preparing for
the first compliance deadline. Therefore, 24 months may be more reasonable than 12 months.
The NSRF recommends the SDT consider the following changes to add clarity to the Standard: a.
Applicability (Section 4.1.1 and 4.1.4), Requirement R2 – Replace “load responsive” protective
relays with “impedance based” protective relays. b. Requirement R1 – The NSRF questions the
necessity of performing the identification and notification in any particular month. Why does the
requirement stipulate “within the first month of each calendar year”? THE NSRF believes that it
should be sufficient to use wording like, “at least once each calendar year”. c. Requirements R.1.1,
R1.2 – What is meant by “stability constraints” (e.g. steady state voltage, transient voltage, steady
state angle, transient angle)? The NSRF recommends that the SDT use descriptive adjectives before
“stability constraint” to clarify which one, or ones, are intended. d. Requirements R1.3, R1.4 – What
is meant by “Disturbances” (e.g. Category B, Category C, P1-P7)? THE NSRF recommends that the
SDT use descriptive adjectives before “Disturbances” to clarify which one, or ones, are intended. e.
Requirements R1.3, R2.1, R2.2 – What is meant by the term “credible” when discussing
Disturbances (e.g. Disturbances associated with islands that were selected through R2 of PRC-0061)? THE NSRF suggests developing proposed alternate language like, “relevant”, which is easier to
demonstrate simply with power flow analysis, rather than valid statistical analysis. f. Requirement
R1.4 – What is meant by “most recent Planning Assessment”? (e.g. TPL-002/TPL-003 annual
assessment, FAC-002-1 interconnection assessment) ? THE NSRF recommends to specify which
type, or types, are intended. g. Requirements R2.1, R2.2 – The NSRF questions the inclusion of the
statement “since January 1, 2003”. THE NSRF believes that a specific historical time frame would be
more appropriate, such as “in the past 10 years”. Referring to “since January 1, 2003” makes an
ever expanding historical time frame, which at some point, should no longer be relevant. h. R3 –
The “Criterion” text only applies to bullet 1 and 3 only, but due to the indentation appears to be a
sub element of bullet 4. Therefore, THE NSRF suggests that the “Criterion” be moved more to the
left move to avoid the appearance of only applying to bullet 4. The NSRF has concerns about not
having data back to 1 Jan 2003. R2 needs to have “if available prior to the effective date ”. The SDT
is looking for data before the effective date of the proposed Standard. We believe the intention of
having the data but we did not know that the required data was needed to be saved from 1 Jan
2003. From the effective date of this Standard is another approach in retaining the required data.
Individual
Terry Harbour
MidAmerican Energy Company
No
The approach for R2 is incorrect. NERC standards cannot require compliance prior to the effective
date of the standard itself. All references to 2003 should be deleted from the requirements and any
guidance. Deleting the references to 2003 would make the requirement effective upon the effective
date of the standard.
Yes
Yes
No
While the reliability concept of preventing unnecessary overtripping is understood, the NERC white
paper supporting the PRC-026 standard indicated that tripping due to stable power swings neither
contributed to blackouts or increased the severity of blackouts since 1965. The NERC standards
drafting team should consider limiting the scope in R1 and R3 to out-of-step transmission related
protection systems specifically designed and installed to monitor weak ties between areas or islands.
These systems would open tie-lines in predetermined locations between areas in an attempt to
balance load and generation between groups of generators that swing together during the identified
power swings.
Yes
Yes
Yes
MidAmerican has concerns about the actual reliability benefit the proposed PRC-026 standards would
provide versus the incremental compliance analysis work. There is also the potential for scope creep
and the industry needs to focus on appropriate risks. The criteria specified under R1 could be broad.
Criterion 4 seems susceptible to significant scope creep stating, “An Element identified in the more
recent Planning Assessment where relay tripping occurred for a power swing during a disturbance."
Planning Assessments are performed regularly in the TPL standards. The new TPL-001-4 planning
standard and R3.1.1 requires the simulated “removal of all elements that the Protection System and
other automatic controls are expected to disconnect for each Contingency without operator
intervention”. At a minimum, this will require generic protection models for each BES line,
generator, and transformer. If the Planning assessment shows a protection model trip, will that
element require a PRC-026 analysis? Many entities are performing stability studies for existing TOP
standards on a short-term to nearly daily basis to verify that entities are not entering and “unknown
state”. While such studies aren’t a traditional “Planning Assessments”, could short-term TOP related
dynamic analyses that show potential trippling (such as exceeding a protection setting limit) be
forced to prove tripping wasn't due to stable power swings in PRC-026? Will the criteria in R1
inappropriately identify suggested islands required by PRC-006? The NERC PRC-006 UFLS standards
require entities to identify and simulate islands. Will PRC-026 inappropriately identify PRC-006
islands (which may not have a real UFLS event as a basis) because PRC-006 required an island be
developed and a simulation be performed by a powerflow stability simulation which considers
angular stability? Criterion 3 mentions both island boundaries and angular stability. There is a
qualifier of a credible event. But entities will construct reasonable events for PRC-006. Are
reasonable and credible the same?
Individual
Kayleigh Wilkerson
Lincoln Electric System
Although appreciative of the drafting team’s efforts in developing PRC-026-1, LES questions whether
the development of a Reliability Standard is necessary for addressing relay performance during
stable power swings. Further consideration should instead be given to the recommendations of the
System Protection and Control Subcommittee which noted that “a NERC Reliability Standard to
address relay performance during stable power swings is not needed, and could result in unintended
adverse impacts to Bulk Power System reliability”. In lieu of the standards development process,
LES suggests communicating to FERC an alternative to a Reliability Standard such as an industry
guidance or reference document.
Group
Seattle City Light
Paul Haase
The Standard is very complicated and confusing. It appears to be a lot like FERC Order 754 effort
that we recently went through, which required two or three rounds of submissions before industry
was providing the information envisioned by the framers of the process. Proposed PRC-026 involves
considerable new interaction between the Planning and Protection groups. The Application
Guidelines, while somewhat helpful, need to include much more explicit examples. A flow chart, or
something similar, is necessary to fully delineate the steps in the process. Much more guidance is
definitely needed before the Standard can be implemented. This draft of the Standard represents a
work in progress, at best. Before any such untried process be mandated as a Standard (if it is
ultimately deemed necessary that a Standard is required) Seattle City Light recommends a nonmandatory trial period of at least two years, long enough to work the bugs out of the system and
ensure that entities understand and are able to perform the activities as envisioned and required.
Perhaps such a trail could be conducted as a NERC request for data under Section 1600 Rules of
Procedure.
Individual
Thomas Foltz
American Electric Power
Yes
We agree with the focused approach. We would recommend qualifying the term “stability,” in R1.2 in
particular, as “transient or oscillatory stability” so that voltage or steady-state stability, which would
not cause power swings, are not mistakenly construed by an auditor. TPL-001-4 permits use of
generic relay models in dynamic simulation planning studies, so the reference in R1.4 to relay
tripping in planning assessments may not end up being based on the relays actually installed.
No
Generator Owners may not have the information or expertise needed to determine if their Element
formed the boundary of an island (R2 Criteria 2) or if the Disturbance that caused a trip or islanding
condition remains to be credible. It is unclear how the operation of Automatic Load Rejection (ALR)
on a power generation unit during a system event affects applicability to R2 of the standard. The
proper operation of a unit’s ALR controls should not result in its automatic inclusion. Clarity is
needed in this standard so that only those relays that operated for the observed or simulated power
swings in R1 or R2 are applicable to R3.
No
In reference to R3, bullet point four, sub items a and b, we do not believe it is necessary to obtain
further agreement with the PC, RC and TP, as there is no benefit to reliability (since it was not
possible to achieve dependability) and represents an unnecessary administrative burden. Rather, the
TO should be required only to *notify* the PC, RC, and TP. The bullet points of R3 should be revised
to replace “Demonstrate that the existing protection system is not expected to trip…” with
“Demonstrate that the existing Protection System satisfies the criteria…”. This would prevent the GO
or TO from being found non-compliant if they were to set the relaying in accordance with the
criterion, but unforeseen events caused a relay to operate. We agree with the approach, but do not
believe that R3 would need to be executed annually. It should only need to be done once per relay
until something about the relay in question or the transmission system in the immediate vicinity
changes.
No
The severe VSL for R1 and R2 could be interpreted that a lack of applicable elements would be a
violation. It should be revised so that it is clear that the entity owns an element that should have
been identified, but did not identify that element.
No
The Application Guidelines and Technical Basis section makes a number of assumptions and
expectations, which would be difficult to prove. For example, “If PSB is applied, it is expected that
the relays were set in consultation with the Transmission Planner to verify maximum slip rates.”
Does such a quote imply an obligation to prove such consultation took place? This section should not
imply or specify any obligations not contained elsewhere in the requirements.
No
The implementation plan only allows the GO/TO 11 months to complete their initial R3 study of all
Elements identified in R1. We believe the time allowed is too short for the initial implementation of
the standard, as the GO/TO will need to research all Elements, not just those incrementally added
from the previous year’s planning analysis. The implementation plan should be revised to guarantee
the GO/TO a minimum of at least 36 months to complete their initial R2 and R3 studies. The timing
of the sequence as proposed in the standard is acceptable after the initial implementation. However,
as currently written, the initial implementation plan does not guarantee adequate time for the
applicable Entities to become compliant.
AEP supports the proposed standard’s scope and overall direction, but has chosen to vote negative
based on the various concerns expressed in our response. AEP envisions voting in the affirmative
once sufficient concerns have been addressed in future drafts. R2 should be revised to be forward-
looking only. Generator Owners and Transmission Owners were not required in the past to keep
comprehensive records of these events and cannot be expected to know all applicable Elements as
implied by the standard. If after the initial standard implementation period, an Entity identifies an
applicable Element based on a Disturbance occurring between 1/1/2003 and the standard effective
date, the Entity could be found non-compliant with R2 and R3. If the drafting team feels it is
absolutely necessary to go back to 2003, the standard should be revised to allow an Entity to remain
fully compliant with R2 and R3 at any time an Element is identified based on a Disturbance occurring
between 1/1/2003 and the effective date of the standard. This could be accomplished by adding
wording to bring newly identified Elements into scope of R2 and R3 during the first full calendar year
after they are identified. The R2 criterion assumes that registered entities have had a process in
place to flag events due to power swings and retain information related to them. We do not believe
that industry should be required to identify and provide information on events that have occurred in
the past. There has been no established standard requirement to capture this information, so there
is no way to reliably conclude that all events caused by power swings have been identified. In the
event such historical information *is* required, the standard should explicitly state that such
information is needed only once rather than once every calendar year. The standard should require
the Transmission Owner to make the system impedance available to the Generator Owner annually
or within 30 days of a written request. The Generator Owner would not normally have this
information, but will need it in order to meet their obligations under R3. It is not clear why R3 will
require the TO/GO’s Elements to be studied annually. A study’s result should remain valid until
either the relay setting changes or the impedance changes significantly. The standard should be
revised to only require a study be repeated if the relay setting is changed or if the generator, GSU or
system impedances change by 10% or more. The standard should not require the study of voltage
controlled/restrained overcurrent relays or loss of field relays. In stable power swings, the voltage
should remain above the threshold that allows these voltage controlled/restrained overcurrent relays
to operate. Failure to set the relay appropriately should be reported and corrected under the
requirements of PRC-004. Loss of field relays are installed as part of the generator protection and
should be permitted to trip when necessary to protect the generator, regardless of whether the
power swing is stable or unstable.
Individual
Chris de Graffenried
Consolidated Edison, Inc.
No
We agree with a focused approach as outlined in the technical document. However, we have the
following serious concerns with criteria in the requirements: 1. The term “credible event” should be
clearly defined. The basis to determine a credible event is missing from the requirement and
application guide. This basis should be provided in the standard requirement. 2. Why is the standard
focused on SOL rather than IROL? The basis for specifying SOL is not supported by the example in
the application guideline since the example did not show inter-area impact. 3. It is not clear in R1,
criteria number 4 whether the assessment should include relay tripping or just stable power swing or
both stable and unstable power swing. 4. In R2, it is unrealistic to require an entity to provide data
on an Element that had tripped since 2003. There is no existing NERC continent-wide disturbance
monitoring or misoperation standard that requires data be retained more than 12 months. We
recommend that this requirement be removed from the standard or include only Elements that were
tripped in the last calendar year.
Yes
Yes
See comment #4 under Question #1. In R2, it is unrealistic to require an entity to provide data on
an Element that had tripped since 2003. There is no existing NERC continent-wide disturbance
monitoring or misoperation standard that requires data be retained more than 12 months. We
recommend that this requirement be removed from the standard or include only Elements that were
tripped in the last calendar year.
No
The purpose of the standard is “to ensure that load responsive relay do not trip in response to stable
power swing during non-fault condition.” The last sentence of Background, Section 5 implies that
protective relay while blocking for a stable power swing also allows for dependable operation for
fault and unstable power swing. Bullet #4 in R3 indicates that the GO and TO must obtain
agreement if dependable protection or dependable out-of-step tripping is not provided by a
protection system that is immune to a stable power swing. Bullet #4 seems to imply that the
purpose of the standard is to ensure blocking for a stable power swing and dependable tripping for
unstable power swing. The drafting team needs to be very clear in the standard what the intention
is. For instance, a line current differential scheme is immune to stable and unstable power swing and
will provide dependable tripping for fault. The criteria as written implies that this type of scheme will
need to be modified or an agreement will need to be obtained from the PC, RC and TP to deploy
since it does not provide dependable out-of-step tripping.
Yes
No
1. In the Application Guidelines, the wording under Requirement 2 for “credible event” is very openended. 2. An example of how line differential protection would be treated with respect to
Requirement 3 would be helpful. See the comment above in Question 4.
Yes
No
No
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
No
The time periods in the requirements are unnecessarily restrictive, particularly R1, which essentially
requires the work to be done in January of each year. There does not appear to be a reliability
reason to have the work completed in January as long as the GO and TO perform the necessary
actions in R3 in a timely manner. We suggest taking an approach similar to PRC-023 R6. In this case
R1 would begin: “Each Planning Coordinator, Reliability Coordinator, and Transmission Planner shall
conduct an assessment at least once each calendar year, with no more than 15 months between
assessments…” R2 through R4 could use a similar approach. The identification of Elements in R1
seems to be unnecessarily redundant between the applicable entities for some criteria and
inappropriate for other criteria. ERCOT suggests splitting R1 into two separate requirements based
on the responsible entity: one requirement for the Planning Coordinator to identify elements per
criteria 2, 3, and 4; and one requirement for the Reliability Coordinator to identify elements per
criterion 1. The Transmission Planner should be removed from the Applicability of the standard,
including removal from R3.
No
See our comments to Q1.
Yes
ERCOT agrees with the NERC System Protection and Control Subcommittee August 2013 report
titled Protection System Response to Power Swings which states: “Based on its review of historical
events, consideration of the trade-offs between dependability and security, and recognizing the
indirect benefits of implementing the transmission relay loadability standard (PRC-023), the SPCS
concludes that a NERC Reliability Standard to address relay performance during stable power swings
is not needed, and could result in unintended adverse impacts to Bulk-Power System reliability.”
Accordingly, ERCOT recommends that the standard not move forward. If the standard does move
forward ERCOT recommends that requirements R1, R2, and R3 be changed from an annual
requirement to once every 60 months in order to minimize unintended adverse impacts to BulkPower System reliability.
Individual
Amy Casuscelli
Xcel Energy
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
Yes
Yes
Yes
No
ATC requests that the SDT provide additional details on how the Lens characteristic is derived and
examples of its use with the system parameters that were calculated from the example.
Yes
No
ATC believes there is some significant discussion in the guidelines and technical basis, however,
recommends that the SDT provide more clear explanation of all of the important parameters.
No
ATC believes there may be many elements, questions or unexpected problems in preparing for the
first compliance deadline. Therefore, 24 months may be more reasonable than 12 months.
ATC recommends the SDT consider the following changes to add clarity to the Standard: a.
Applicability (Section 4.1.1 & 4.1.4), Requirement R2 – Replace “load responsive” protective relays
with “impedance based” protective relays. b. Requirement R1 – ATC questions the necessity of
performing the identification and notification in any particular month. Why does the requirement
stipulate “within the first month of each calendar year”? ATC believes that it should be sufficient to
use wording like, “at least once each calendar year”. c. Requirements R.1.1, R1.2 – What is meant
by “stability constraints” (e.g. steady state voltage, transient voltage, steady state angle, transient
angle)? ATC recommends that the SDT use descriptive adjectives before “stability constraint” to
clarify which one, or ones, are intended. d. Requirements R1.3, R1.4 – What is meant by
“Disturbances” (e.g. Category B, Category C, P1-P7)? ATC recommends that the SDT use descriptive
adjectives before “Disturbances” to clarify which one, or ones, are intended. e. Requirements R1.3,
R2.1, R2.2 – What is meant by the term “credible” when discussing Disturbances (e.g. Disturbances
associated with islands that were selected through R2 of PRC-006-1)? ATC suggests developing
proposed alternate language like, “relevant”, which is easier to demonstrate simply with power flow
analysis, rather than valid statistical analysis. f. Requirement R1.4 – What is meant by “most recent
Planning Assessment”? (e.g. TPL-002/TPL-003 annual assessment, FAC-002-1 interconnection
assessment) ? ATC recommends to specify which type, or types, are intended. g. Requirement R2,
Criteria 1 and 2 – ATC has concerns about requiring entities to refer to data on power swings and
forming an island back to 1 Jan 2003. ATC recommends additional text in the Criteria such as “if
available prior to the effective date ” immediately after “since January 1, 2003”. Retaining this data
prior 1 Jan 2003 was not required as implied by the proposed Standard. Another approach for SDT
consideration would be to require retention of data from the effective date of the Standard. h.
Requirements R2.1, R2.2 – ATC questions the inclusion of the statement “since January 1, 2003”.
ATC believes that a specific historical time frame would be more appropriate, such as “in the past 10
years”. Referring to “since January 1, 2003” makes an ever expanding historical time frame, which
at some point, should no longer be relevant. i. R3 – The “Criterion” text only applies to bullet 1 and
3 only, but due to the indentation appears to be a sub element of bullet 4. Therefore, ATC suggests
that the “Criterion” be moved more to the left move to avoid the appearance of only applying to
bullet 4.
Individual
Jo-Anne
Ross
Yes
Yes
Yes
Yes
Yes
Yes
Yes
1) In R1, please clarify what you mean by “Stability constrained”, does it mean the constraint for
angular stability only or does it include other stability concerns such as transient voltage violations?
2) Also in R1, does “Line-out conditions” mean “N-1” condition? 3) What definition of an island is
used in the standard? 4) In R1 through R4, why is long-term planning included in the time horizon?
The standard is not clear that an assessment of the 10-year planning horizon is expected. It seems
the assessment is more based on the current system or at most plans proposed to be implemented
in the next year, which makes this applicable to Operations Planning only. The Table of compliance
elements discussing notification deadlines of 30-90 days is more applicable to an Operations
Planning time horizon. If we see an issue in 2020, due to a new proposed Facility, why do we have
to notify anyone within 30 days today in order to be compliant with the standard? We have time to
investigate alternatives, new settings etc. If the problem still exists in the operations horizon, this
standard is applicable.
Individual
Mark Wilson
Independent Electricity System Operator
No
The criteria used to limit the applicability of the transmission lines are unclear. Specifically, •
Regarding Criteria 1 in Requirement 1, entities’ may employ SPS to avoid tripping of any Element for
stable power swings under all normal recognized contingencies included in the TPL standards. Given
that the SPS is used as a mitigation measure, should this proposed standard be applicable to those
elements that are susceptible to trip for stable power swings, when a failure of the SPS is
considered? • Similar to the above, for Criteria 2 in Requirement 1, entities’ may establish an SOL to
avoid tripping of any Element for stable power swings under all normal recognized contingencies
included in TPL standards. Given that SOL is used as a mitigation measure, should those elements
susceptible to trip for stable power swings, when the SOL is exceeded (and which is not allowed in
normal operation conditions) be applicable to this proposed standard? • Requirement 1 stipulates
that the responsible entity notify the facility owner of an Element that meets Criteria 2 (i.e., an
Element associated with a System Operating Limit (SOL) that has been established based on
stability constraints). It is not clear whether the Element is the contingent Element or the monitored
Element or both. This needs to be clarified/specified in the standard/requirement. • Requirement 1
stipulates that the responsible entity notify the facility owner of an Element that meets Criteria 3
(i.e., has formed the boundary of an island within an angular stability planning simulation where the
system Disturbance(s) that caused the islanding condition continues to be a credible event. The term
“credible event” is hard to determine since the Disturbance could be caused by one of those events
listed in the TPL standards, or could be one that is beyond those listed, such as natural phenomena.
• We realize that the Application Guideline provides some general guidance on assessing the
creditability of a Disturbance, but we do not agree that a Disturbance is no longer credible when it is
deemed no longer capable of occurring in the future due to actual changes to the BES. Changes to
the BES may reduce the possibility of the same Disturbance, but such Disturbances (e.g. loss of
right of way or an entire station) may still occur due to other means. If the SDT should continue to
hold the position that the criteria for excluding a Disturbance is that BES changes are made to
mitigate (but not totally eliminate) the recurrence, then it should be clearly stated in the
requirement itself. • In short, the basis with which to deem a Disturbance “credible” is missing from
the requirements, which needs to be provided/clarified in the standard/requiremen
Yes
Yes
We agree that the Generator Owner and Transmission Owner are the appropriate entities to identify
the Elements that meet the criteria in Requirement R2. However, we question the relevance or need
to trace back to 2003 for Disturbances that caused an Element to trip due to a power swing or which
formed the boundary of an island. Further, the term credible Disturbance needs clarification. Please
see our comment under Q1, above.
No
R3 and its bulleted items need to be clarified that they apply to the load-responsive relays only, to
be consistent with the purpose and scope of the standard, not the Protection System which could
include other protective relays or components. However, if the standard is to ensure that Elements
do not trip in response to stable power swings during non-Fault conditions, then all references to
Protection Systems should be replaced with load-responsive relays. Bullet number four requires to
prove dependable out-of-step tripping. However the entity may decide to use selective tripping when
out- of-step conditions are detected. Studies show that in case of severe disturbance selective
tripping when out-of step conditions are detected can increase the chance of creating successfully
islands. We suggest changing the wording from “dependable out-of-step tripping” to “dependable
out-of-step detection”.
Yes
Yes
No
Individual
David Kiguel
n/a
No
1. The second criterion in R1 refers to "An Element that is associated with a System Operating Limit
(SOL)." Clarification is necessary to specify the meaning of "associated." Does it refer to an Element
in the SOL itself or monitored and protected but outside the SOL (or both)? 2. The draft repeatedly
uses the term “credible event.” In some instances, e.g. past disturbance(s) it might be subject to
interpretation. In general, without a probabilistically quantified criterion, the term "credible" is
subjective and subject to interpretation, thus should be avoided in this context. 3. Clarification is
required in regards to load-responsive relays in a Protection System. It is unclear as to what
relays/components should not trip during power swing. 4. R2 requires GOs and TOs to evaluate
Disturbance records “since January 1, 2003,” a time that will precede the effective date of this
standard. A requirement cannot rely upon records that precede the effective date of a standard.
Yes
Yes
Yes
Yes
Yes
The PSRPS document, developed by industry experts and approved by the NERC Planning
Committee, clearly disputes the FERC directive in Order No. 773 (Docket No. RM08-13-000), that
was subsequently affirmed in Order Nos. 773-A and 773-B, that a standard is needed to ensure that
load-responsive protective relays do not trip in response to stable power swings during non-Fault
conditions. NERC’s informational filing in Docket No. RM08-13-000 dated July 21, 2011 concluded
that there is a need for a standard on stable power swings. This conclusion is the opposite of what
the PSRPS document concluded. The SPCS concludes that a NERC Reliability Standard to address
relay performance during stable swings is not needed, and could result in unintended adverse
impacts to Bulk‐Power System reliability. I support the recommendation that the NERC Standards
Committee explore means to utilize the more recent PSRPS document to obtain relief from the
aforementioned FERC directive that is driving this project.
Group
SMUD/BANC
Joe Tarantino
No
(1) Collected data and subsequent analysis has not identified tripping during stable power swings.
This phenomenon is rare if at all. Any tripping during stable power swings would more appropriately
included as a mis-operation and addressed as such. (2) The requirement R2 is particularly
unacceptable as it requires data for pre June 18, 2007; effective date of Order 693 standards.
No
Collected data and subsequent analysis has not identified tripping during stable power swings. This
phenomenon is rare if at all. Any tripping during stable power swings would more appropriately
included as a mis-operation and addressed as such.
No
The requirement R2 is particularly unacceptable as it requires data for pre June 18, 2007; effective
date of Order 693 standards.
YES! The requirement R2 is particularly unacceptable as it requires data for pre June 18, 2007;
effective date of Order 693 standards.
Individual
Richard
Vine
No
As “line-out conditions” used in Requirement R1 Criteria 1 and 2 is not a defined term, please clarify
the intent of “line-out conditions”, particularly addressing if “line-out conditions” are expected to go
beyond the TPL Standard(s) of what the Planning Coordinator and Transmission Planner already
study.
Individual
Chris Mattson
Tacoma Power
No
Tacoma Power supports PSEG’s response to Question 1. Setting aside the previous comment (that
is, assuming FERC does not provide reflief from its directive to develop this standard), Tacoma
Power supports a narrower approach. That is, the screening criteria should be refined and made
simpler. For example, PRC-023 applies relatively straightforward screening criteria, yet PRC-023
addresses a greater reliability risk than the proposed PRC-026-1. Presently, PRC-026-1 Requirement
R1 (and R2) could pose a greater burden on entities than PRC-023 for screening to identify
applicable Facilities. Alternatives might be to conduct a data request to collect better information so
that Requirements R1 and R2 could be consolidated and then provide more refined and simpler
criteria. Setting aside the previous comment, Criterion 4 needs more clarification. What is the
technical basis in Requirement R1 for identification and notification to occur in January of each year?
No
See Tacoma Power’s response to Question 9. At least in WECC, not all of these entities may be
appropriate to lead the identification effort.
No
Tacoma Power disagrees with the need for this standard.
No
Tacoma Power disagrees with the need for this standard. However, assuming FERC does not provide
reflief from its directive to develop this standard, the transient, rather than sub-transient,
impedance may represent a better model. Granted, as noted in the Application Guidelines, the subtransient impedance would yield a more conservative assessment.
No
Tacoma Power disagrees with the need for this standard. In particular, Tacoma Power has significant
concerns with Requirements R1 and R2. It is therefore difficult to provide additional feedback on the
VRFs and VSLs at this time.
No
: Tacoma Power disagrees with the need for this standard. In particular, Tacoma Power has
significant concerns with Requirements R1 and R2. The Application Guidelines and Technical Basis do
not provide sufficient clarification related to these two requirements.
No
Tacoma Power disagrees with the need for this standard. In particular, Tacoma Power has significant
concerns with Requirements R1 and R2.
Tacoma Power disagrees with the need for this standard. However, assuming FERC does not provide
reflief from its directive to develop this standard, a regional variance should be considered, at least
for WECC. The footprint of a typical Planning Coordinator or Transmission Planner in WECC may not
be large enough to adequately perform the desired assessments in the planning horizon. Instead, it
may be more effective to perform this analysis more regionally. The Reliability Coordinator may
have a large enough vantage, but most of their focus is in the operating horizon.
Tacoma Power supports the spirit of PSEG’s response to Question 3. Furthermore, Tacoma Power
has the following, additional comments related to the January 1, 2003, date. 1) Not all Generator
Owners and Transmission Owners may be required to retain records going back to January 1, 2003.
2) Apart from including the 2003 Northeast Blackout, no other technical justification has been
provided for why the January 1, 2003, date was selected. Alternatives might be to indicate specific
disturbances for which documentation likely exists or to conduct a data request to collect better
information so that Requirements R1 and R2 could be consolidated and then provide more refined
and simpler criteria. Setting aside the previous comment, does Requirement R2 Criterion 2 add any
value beyond that provided by Criterion 1? If so, the term ‘island’ may need to be better defined.
What is the technical basis in Requirement R2 for identification to occur in January of each year?
Individual
David Jendras
Ameren
No
(1) Along with our comments we agree with and adopt the Public Service Enterprise Group (PSEG)
Comments by reference. (2) If this standard does proceed, we generally can accept the focused
approach, but believe it should be narrower. We believe that R2 reaching all the way back to
1/1/2003 creates an ex post facto compliance obligation. (3) In our opinion R1 needs to limit the
Criteria 3 and 4 time horizon to Operations Planning to be consistent with R3 which deals with the
existing Protection System. We believe that resetting an existing relay for a future, but not present,
stability issue could harm present reliability. Although, we do understand the benefits of identifying a
future stability concern, and a future need to possibly alter relaying schemes or reset relays in an
orderly fashion is important; we believe that such activity is part of the planning process and need
not be governed by this standard. However, if the SDT intended that the R3 CAP (3rd bullet) apply
to future scenarios, then please add the timing of such an example in the Application Guidelines. (4)
We ask the drafting team to include a broader explanation of changed conditions that would
discontinue credibility in R2, item 2 (“…during an actual system Disturbance where the
Disturbance(s) that caused the islanding condition continues to be credible.”). Include items such as
completed PRC-004 CAPs that have fixed a contributing cause, and procedures to avoid a unique
maintenance switching topology that was causal.
No
We believe that even if these are the right entities, it is unclear who is driving the identification
process or if they even agree. Please change to ‘Each Transmission Planner with the Planning
Coordinator’s and Reliability Coordinator’s concurrence shall, within the first month of each calendar
year, identify and provide notification to the respective Generator Owner and Transmission Owner of
each Element that meets one or more of the following criteria…’ In most cases, we believe the TP
would identify these with their studies and therefore should take the lead.
Yes
No
Even though we may be able to accept and appreciate the SDT’s approach; our recommended
changes to this approach are as follows: (1) Change 1st sentence of Criterion to “Only load
sensitive, high speed distance relays are within scope (e.g. zone 1 phase distance, pilot zone phase
distance). For such a distance relay impedance characteristic, used for tripping, that is
completely….” which adds the first sentence for clarity. We believe that this comment is consistent
with the SDT’s answers in NERC’s 5/12/2014 webinar. (2) Change Criterion #3 to transient
reactance, because it aligns better with power swing time constants (see Reimert text pages 40,
289, 291, and particularly bottom of page 302). (3) Change ‘once each calendar year’ to ‘within 2
calendar years of initial identification, and once every 5 calendar years thereafter’ because once
each calendar year is too frequent.
No
These are generally well written considering this complex situation that we feel is very rare, but we
do have the following recommendations for the drafting team: (1) The variables in Figure 2 need to
be defined; (2) The issue of aligning the planning assessment time horizon with present Protection
System settings (see our 2nd comment Q1) needs to be clarified; (3) On page 24 change “the
generator unsaturated generator X"d,” to “the generator saturated generator transient reactance
X’d,” because transient time constant aligns better with power swing timeframe, and faults most
often are the triggering event in such power swing scenarios (also see Reimert text pages 40, 289,
291, and particularly bottom of page 302). (4) On page 23 add “Overcurrent relays usually have
long enough time delays that they can be excluded from consideration.” at the end of the
‘Application to Generator Owners’ section. (5) To clarify when the simplified method instead of
transient stability simulations can be used on page 24 in the last paragraph of the ‘Impedance Type
Relays’ section change ‘is’ to ‘can’ and add “only” in the third line so it reads “The simplified method
used in the Application to Transmission Owners section can also be used here to provide a helpful
understanding of a stable power swing on load-responsive protective relays for only those cases
where the generator is connected to the transmission system and there are no infeed effects to be
considered.”
No
(1) We request that the SDT provide a 1 year implementation period for R1 and R2 combined,
followed by a 2 year implementation period for R3. (2) We believe that this standard poses a
considerable burden on the TO and GO and the first pass may be a significant amount of work.
Group
Tennessee Valley Authority
Dennis Chastain
Yes
Yes
Yes
No
1) Every year is too often for this requirement. We recommend changing this to every 5 years. 2)
We believe that the criterion is too specific for a regulatory document. It should allow entities to use
their preferred methods for determining if a line is likely to trip during a stable power swing.
Recommend changing the first bullet to: "...in response to a stable power swing based on either the
criterion below or by another industry accepted method.” 3) At the end of the fourth bullet it states
“dependable out-of-step tripping”. We recommend changing this to “dependable unstable power
swing tripping”.
Yes
Yes
Yes
Group
SPP Standards Review Group
Robert Rhodes
Yes
Establishing criteria that determine which Elements must be assessed according to Requirements R1
and R2 reduce the compliance burden on Generator Owners and Transmission Owners. This is the
right approach. That said, we concur with AEP in that the SDT should limit the use of the term
‘stability’ in the standard to oscillatory and transient stability in order to avoid confusion with voltage
and steady state stability.
No
The Reliability Coordinator may not be aware of Elements identified in Criteria 3 and 4, since that
knowledge is based upon the Planning Coordinator or the Transmission Planner notifying the
Reliability Coordinator of the situation. Yet the Reliability Coordinator is held accountable for the
identification and notification ‘…of each Element that meets one or more…’ of the criteria. Similarly,
there may be situations where the Planning Coordinator or Transmission Planner may not be aware
of Elements identified by the Reliability Coordinator yet they are also held accountable for
identification and notification of each Element. There should be one, single list of all the Elements
that satisfy the criteria but the responsible entities may not, individually, reach the same conclusions
regarding the make-up of that list. Their individual lists may not contain all the Elements to be
identified but a composite of all their lists should result in the one, true list of all Elements. The
requirement needs to be modified to include this consideration.
Yes
No
We question the need for the annual assessment required in Requirement R3. PRC-005-2
satisfactorily covers the routine maintenance and testing of protective relays and this requirement
would be redundant with those requirements. Additionally, only system changes (topology changes,
load/generation changes, etc.) would impact the application of the relays applicable to this
requirement. Thus they should only need to be reviewed or re-assessed if those types of changes
occurred on the system. We suggest that the 4th bullet under Requirement R3 be made a
notification rather than the existing agreement. As stated, the requirement for agreement places
unintended risk on the Planning Coordinator, Reliability Coordinator and Transmission Planner. While
we agree that if there is no dependable fault detection or out of step tripping the Planning
Coordinator, Reliability Coordinator and Transmission Planner would need to be notified, we are
unclear how these registered functional entities would have the knowledge of each applicable
entity’s protection systems to be able to agree to a correct relay setting. Would the fact that the
Planning Coordinator, Reliability Coordinator and Transmission Planner accepted the settings place
the responsibility of a cascading event due to the undependable fault detection or out of step
tripping on the shoulders of these entities? This risk should be solely placed with the experts that
design and maintain protection systems. Both a. and b. under the last bullet of Requirement R3
require the Generator Owner and Transmission Owner to obtain agreement with the Planning
Coordinator, Reliability Coordinator and Transmission Planner yet nothing in the standard requires
the Planning Coordinator, Reliability Coordinator or Transmission Planner to provide that agreement.
Generator Owner and Transmission Owner compliance may hinge on that agreement but there is no
incentive for the Planning Coordinator, Reliability Coordinator or Transmission Planner to reach that
agreement. We concur with AEP in that rather than requiring agreement, the requirement should
only require notification of the Planning Coordinator, Reliability Coordinator and Transmission
Planner by the Generator Owner and Transmission Owner.
No
The VSLs for Requirement R1 should be changed in consideration to the point we made in our
response to Question 2. Insert an ‘an’ between ‘identified’ and ‘Element’ in the VSLs for Requirement
R2. References to 30-, 60-, and 90-calendar days should be hyphenated in the VSLs for
Requirements R1, R2 and R3.
No
Requirement R2 calls for the responsible entities to identify Elements based on performance since
January 1, 2003 which is before the effective date of the standard. During the webinar, the SDT
indicated that although this requirement was included in the standard, it was not the intent of the
SDT to hold the responsible entities accountable for this data. This exception should be included in
the Application Guideline and especially in the RSAW. One-line diagrams for the examples in the
explanations for Requirements R1 and R2 would be helpful. In the 3rd paragraph on Page 15, the
SDT attempts to clarify the 2nd option under Requirement R3. The 1st sentence in the paragraph
does just that. However, the next two sentences seem to go beyond the requirement by expanding
the scope of the requirement. We propose to delete these last two sentences.
No
We would prefer to see the twelve months increased to twenty-four months to allow adequate time
to complete all the studies and analyses that will be needed to comply with the standard.
We are not aware of any conflicts between the proposed standard and any regulatory function, rule,
order, tariff, rate schedule, legislative requirement, or agreement.
We are not aware of any need for a regional variance or business practice.
We note that the SPCS concluded that this standard was not needed based on their review and
analysis of past disturbances. They went on to say that such a standard ‘…could result in unintended
adverse impacts to Bulk‐Power System reliability.’ Given their conclusion, has NERC and/or the SDT
given any consideration to requesting FERC reconsider their directive to develop this standard? The
following are comments on the draft RSAW. We recommend that a specific reference be made to the
question of providing evidence based on experience prior to the effective date of the standard.
Please see our response to Question 6 above. The industry needs assurances from NERC Compliance
that auditors will not be holding responsible entities accountable for providing data on events that
occurred prior to the effective date of the standard. The 1st and 2nd cells of the Evidence Requested
and Compliance Assessment Approach tables for both Requirements R1 and R2 insert additional
requirements that are not contained in the requirements in the standard. These items request
evidence/documentation on the methodology and the utilization of that methodology by the
responsible entity in the identification of the Elements called for in the two requirements. Neither
Requirement R1 nor Requirement R2 mention anything about requiring the responsible entity to 1)
have a methodology for performing that identification and 2) use the methodology in the
identification process. These items need to be deleted from the RSAW along with the Note to Auditor
under the Registered Entity Response for both Requirements R1 and R2. These notes refer to these
two items. In the Note to Auditor under the Compliance Assessment Approach Specific to PRC-0261, R2 replace the ‘all’ at the end of the 3rd line with ‘a’. Still within this section, does the SDT concur
with the interpretation of the example at the top of Page 9? If not, we ask that the SDT inform the
RSAW developers.
Group
Southern Company: Southern Company Services, Inc.; Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi Power Company; Southern Company Generation;
Southern Company Generation and Energy Marketing
Wayne Johnson
Yes
Yes, in part. Addressing situations and occurrences of undesired relay operations is an appropriate
method to minimize future undesired operations. The review period should be a rolling time period
(previous 5 years) rather than > 10 years ago, as many entities will not have historical records to
validate potential mis-operations. Entities were not required to keep such records to the date
specified in R1 and R2. R1 #4 and R2 #1 should specify the inclusion of Elements that trip due to
"stable power swings" instead of all power swings.
Yes
The PC, RC and TP, or some combination is the appropriate entity to identify elements that meet the
criteria in Requirement R1. R1 should allow collaboration between the PC, RC and TP to produce a
single list of Elements that will satisfy compliance for all three entities.
No
The TOs and GOs are the owners of the protection systems whose operation is being addressed, but
the GO does not have a system view of stable power swings. Requiring the GO and TO to look back
to 2003 every year as specified by R2 is unreasonable. Looking backwards to consider problems
known to have occurred is understandable, but requiring this every year is not reasonable. These
trip investigations have been occurring in the industry long before the mandated PRC-004 operation
reviews. Most responsible utilities have addressed undesirable protection system misoperations to
maximize availability - the market forces have long driven utilities to correct undesirable relay
operations so they can be available to the market.
No
The method defined in R3 should be an option for determining susceptibility of a given relay, but the
requirement should be for the responsible entity to develop criteria to determine susceptibility of a
given relay to tripping for stable power swings and then other requirements to demonstrate the
adherence to and compliance with those criteria. If the prescriptive method of R3 remains in the
standard, R3, bullet #4 (b), should explicitly state that it is acceptable for the modifications specified
in the CAP not to result in meeting the criteria of R3.
Yes
The requirement language should be finalized before establishing VRFs, VSLs. and measures.
Yes
Yes, provided the R2 review period begins with the enforcement date of the stantard looking
forward.
We are not aware of any conflicts.
We are not aware of any needs for exceptions.
a) The phrase "continues to be credible" in R2 needs explanation. Is the intended meaning either 1)
the trip was believed to be caused by the Disturbance, 2) a repeat trips susceptibility continues to be
possible or likely, or 3) something else? b) Is the consequence of R2/M2 having to analyze and
document every relay operation (trip) which occurs for determination of if it was caused by a system
Disturbance? Also, do all system Disturbances have to be reviewed for possible relay (trip)
operations, for subsequent validation of desired operation? The NERC glossary definition of a
Disturbance is very much open-ended and not specifically defined in part 2: "2. Any perturbation to
the electric system." Is this requirement duplicative of PRC-004 relay mis-operation determination?
Does PRC-026 subject entities to possible violation of two standards for a single possible (lack of)
action? c) An annual requirement for R1, R2, and R3 seems excessive. Extended periodicity intervals
or triggers from system topographic changes should be considered rather than annual reviews. For
example, PRC-006 and PRC-010 prescribe evaluation intervals of 5 years for UVLS and UFLS. Five
years seems to be a reasonable interval for this analysis. d) Does any specific item on the Identified
Element list ever get removed from the list? The resolution of a review in a previous year should
eliminate it from future reviews.
Group
ISO RTO Council Standards Review Committee
Greg Campoli
No
Conditions (2) and (3) are unclear. Condition (2) stipulates that the responsible entity notify the
facility owner of an Element that is associated with a System Operating Limit (SOL) that has been
established based on stability constraints. It’s not clear whether the Element is the contingent
Element or the monitored Element or both. This needs to be clarified/specified in the
standard/requirement. Condition (3) stipulates that the responsible entity notify the facility owner of
an Element that has formed the boundary of an island within an angular stability planning simulation
where the system Disturbance(s) that caused the islanding condition continues to be a credible
event. The term “credible event” is hard to determine since the Disturbance could be caused by one
of those events listed in the TPL standards, or could be one that is beyond those listed, such as
natural phenomena. We realize that the Application Guideline provides some general guidance on
assessing the credibility of a Disturbance, but we do not agree that a Disturbance is no longer
credible when it is deemed no longer capable of occurring in the future due to actual changes to the
BES. Changes to the BES may reduce the possibility of the same Disturbance, but such Disturbances
(e.g. loss of right of way or an entire station) may still occur due to other means. If the SDT should
continue to hold the position that the criteria for excluding a Disturbance is that BES changes are
made to mitigate (but not totally eliminate) the recurrence, then it should be clearly stated in the
requirement itself. In short, the basis with which to deem a Disturbance “credible” is missing from
the requirements, which needs to be provided/clarified in the standard/requirement.
No
These three entities are appropriate for the R1 requirement. However, there should be a
requirement that only one of the three is deemed responsible to provide notice to the facility owner.
Every facility that falls under the R1 criteria is under the authority of all three entities. It would be
repetitious and redundant to require all three entities to provide the same information to the same
facility owner. However, if the intent of the requirement is that the Reliability Coordinator will
address the Operations Planning Horizon, while the Planning Coordinator and Transmission Planner
will address the Long-Term Planning Horizon, then it may not be repetitious nor redundant to
require these entities to address Requirement R1. Also, the entity who is registered as the RC may
differ from the entity who is registered as the PC and TP. For example, in the Western
Interconnection, Peak Reliability is the RC, the CAISO is the PC for much of California (but not all),
and the Participating Transmission Owners are registered as the TP. In CAISO’s case, the three
registered entities of RC, PC, and TP are represented by different entities.
No
We ask whether the TO or GO, especially a GO, will have access to studies and fault analysis reports
that will determine if the Disturbance remains credible. There seems to be an assumption in R2 that
a fault analysis study was performed that documents the Disturbance and system conditions at the
time. There must be a requirement in some NERC standard that obligates appropriate entities are
notified of these results. We are unclear on the relevance or need to trace back to 2003 for
Disturbances that caused an Element to trip due to a power swing or which formed the boundary of
an island. Further, the term credible Disturbance needs clarification. Please see our comment under
Q1, above. This requirement should not be written with a date specific start point. Over time, this
date would be meaningless and inappropriate for applying the standard. Instead this requirement
could be written in a rolling calendar basis, e.g. – “prior twelve months”.
No
R3 and its bulleted items need to be clarified that they apply to the load-responsive relays only, to
be consistent with the purpose and scope of the standard, not the Protection System which could
include other protective relays or components. However, if the standard is to ensure that Elements
do not trip in response to stable power swings during non-Fault conditions, then all references to
Protection Systems should be replaced with load-responsive relays. We are concerned that holding
relay engineers to limit load-responsive protection schemes to meet these settings in order to be
compliant may not always be in the best interest of bulk power system reliability. Although it is good
practice to see that facilities can withstand transients that are expected to dissipate and not pose a
recurring threat to the grid, requiring these settings to always be adhered to takes away the ability
for the relay engineer to apply engineering judgment if there are conflicting needs to allow for
tripping the load-responsive relays in order to protect from another more imposing system threat.
These relays are primarily to protect from a specific condition identified by studied and credible
faults. This setting may be inside the trip circle identified by the stable power swing. In these cases,
the relay engineer makes a best judgment to ensure a balance between which threat is more
relevant or immediate to make the appropriate setting. The standard should allow for entities to
provide technical evidence that a load-responsive relay may have to be set within a trip circle of a
stable power swing, if there is no other protection scheme available to mitigate the primary threat.
Group
Dominion
Mike Garton
Yes
Yes
Yes
No
Item b under the 4th bullet in Requirement R3 is not stated using clear and unambiguous language
whereby responsible entities, using reasonable judgment, are able to arrive at a consistent
interpretation of the required performance. The R3 rationale and the Protection System Response to
Power Swings technical document provide some clarity; however, the simple fact is the 4th bullet is
not clear and troublesome from a compliance perspective. Dominion suggest revising the 4th bullet
to ensure the responsible entity understands the balance between security and dependability and
how that is to be achieved by either sub-parts a or b.
Yes
Yes
Yes
No
No
Dominion suggests that Associated Documents (at least those where there are no copyright
concerns) be included in the standard as attachments or appendices as we are concerned that cited
URLs will change over time. Requirement R2 Criteria 1 and 2 require review of Disturbances since
January 1, 2003. While Dominion recognizes the desire to consider Disturbances since January 1,
2003 in order to capture the August 14, 2003 Blackout, it is important to note that NERC Reliability
Standards were not mandatory at that point and data may or may not be available. Dominion
recommends changing the criteria dates to June 18, 2007 to be consistent with the establishment of
mandatory and enforceable Reliability Standards.
Individual
Scott Langston
City of Tallahassee
Individual
Bob Thomas
Illinois Municipal Electric Agency
Individual
Bill Fowler
City of Tallahassee
Individual
John Pearson
ISO New England
No
ISO New England recommends that requirements R1, R2, and R3 be changed from an annual
requirement to once every 60 months. We also think that the approach should be narrower. •
Criteria 1 should be limited to IROL’s and read as follows: 1. An Element that is located or
terminates at a generating plant, where a generating plant stability constraint exists and is
addressed by an IROL. • Criteria 2 should be deleted. This criteria appears to be redundant to
Criteria 1. • In Criteria 3, Disturbance is too broad. It should be limited to single or multiple
contingencies but not extreme contingencies. Criteria 3 should read as follows: 3. An Element that
has formed the boundary of an island within an angular stability planning simulation where the
system Disturbance(s) that caused the islanding is a single or multiple contingency but not an
extreme contingency. • Criteria 4 should be narrower in scope and read as follows: 4. An Element
identified in the most recent Planning Assessment where relay tripping occurred for a power swing
during a Disturbance caused by a single or multiple contingency but not an extreme contingency.
Again, Disturbance is too broad. It should be limited to single or multiple contingencies but not
extreme contingencies.
Yes
No
In R2, it is unrealistic to require an entity to provide data on an Element that had tripped since
2003. There is no existing NERC continent-wide disturbance monitoring or misoperation standard
that requires data be retained more than 12 months. We recommend that this requirement be
removed from the standard or include only Elements that were tripped in the last calendar year.
No
The option under the fourth bullet requires that the Generator Owner and Transmission Owner
obtain agreement from the respective Planning Coordinator, Reliability Coordinator and Transmission
Planner of the Element that either: (a) the existing Protection System design and settings are
acceptable, or (b) a modification of the Protection System design, settings or both are acceptable
and develop a corrective action plan for this modification of the corrective action plan. This requires
specialized knowledge and coordination that is not typical for Planning and Reliability Coordinators.
Yes
No
While the Application Guidelines and Technical Basis provide guidance, we disagree with the current
roles of functional entities to which the standard applies.
No
Given that the currently proposed scope of the standard is very broad, twelve months is not a long
enough timeframe to become compliant with the requirements of this standard, which will create
additional workload for the functional entities subject to the standard. ISO New England suggests 36
months.
Group
ACES Standards Collaborators
Jason Marshall
No
(1) This requirement needs to be further clarified that it is not intended to require additional studies.
Rather, the TP, PC and RC are to identify the information in bullets 1 through 4 based on their
existing knowledge and studies. (2) Part 2 needs further clarification regarding which SOLs should
be applied. Are the SOLs established from the planning horizon per FAC-010-2.1 or the SOLs
established in the operating horizon per FAC-011-2 applicable? We recommend that only SOLs from
the operating horizon should be applied because the SOLs from the planning horizon may include
the impact of proposed or retired facilities which could result in unnecessary relay modifications or
miss necessary relay modifications. (3) Requirement R1 as a whole is problematic because it is
based partly on planning studies. Planning studies include proposed system additions and
retirements which could result in the identification of unnecessary relay modifications or a failure to
identify necessary relay modifications. (4) R1 should be split based on responsibilities. Some of the
bullets should apply to only one entity. For example, an RC is required to monitor the status of
Special Protection Systems per IRO-005-3.1a R1.1. The RC would also have to be aware of
generating plant stability constraints. Thus, the RC could provide all of the information for bullet 1.
Bullets 3 and 4 are based on planning studies and should only apply to the Planning Coordinator. If
only SOLs from the operating horizon are to be evaluated, then bullet 2 should only apply to the RC.
(5) Part 2 should be modified to limit application to IROLs and not all stability related SOLs. By
definition, if an SOL is stability related and is not an IROL, it cannot have a wide area impact on
reliability and is limited to local reliability. If it had a wide area impact, it would cause “instability,
uncontrolled separation or Cascading outages that adversely impact the reliability of the Bulk Electric
System” and would be an IROL. (6) Part 4 is problematic because it now requires relay tripping to be
evaluated in transient studies performed by the Planning Coordinator and Transmission Planner.
These entities may not include all relays in their studies but this part creates a de facto requirement
for them to include all relays. Otherwise, how can a PC or TP determine if relay tripping would occur?
(7) The language of the requirement needs to be clarified that the TP, PC and RC are to only identify
elements in their area. This could be accomplished by adding “in its area” after “each Element.” (8)
The format of the sub-part numbering does not follow the convention that NERC established several
years ago and notified the Commission that it would use for sub-parts. When all sub-parts are
required then they are to be numbered. When only one sub-part is requirement (i.e. one of the list
has to be selected), they are to be bulleted. The draft appears to stray because of the language “one
or more” in the main requirement. In other words, one item could be met or more than one.
However, we argue that bullets should be used because while more than one could apply, if one
applies the Element is to be identified by the PC, TP, or RC. There is no additional need for any tests
once one is met. Thus each Element will only be identified as meeting one of the bullets because
that means it qualifies even though it could meet more than one. (9) Why can’t the islanding
evaluation conducted per PRC-006-1 R1 be used as the basis for identifying Elements rather than
writing a new bullet 3 in the requirement?
No
We do not believe that the Transmission Planner should be an applicable entity. Any studies
completed by the TP will be duplicated in a larger PC study thus making the inclusion of the TP
unnecessary.
No
(1) We do not believe the GO or TO are appropriate entities. In fact, we do not believe any entity is
appropriate to identify the Elements in R2 and that the requirements are not enforceable as written.
NERC cannot compel evidence from dates prior to June 18, 2007, which is when FERC approved the
first set of reliability standards. Furthermore, a new standard cannot compel data and evidence from
before a time period that the standard was in effect. In today’s litigious society, many companies
have data retention programs that result in the destruction of data that is not required to be
retained. Thus, GOs and TOs may not have the data. How would they comply? We simply will never
be able to support a standard requiring data retroactively. (2) The topology of the transmission
system has changed significantly in many areas since the January 1, 2003. That is over 11 years
from the drafting of the standard. It is simply unreasonable to assume that power swings that
occurred in 2003 would occur in the same way and that the data is still applicable. Relying on 11year old data simply does not provide a sound engineering basis. (3) The islanding analysis
conducted for PRC-006-1 R1 would form a better basis for identifying these Elements and could be
used in place of this requirement. The PC could notify the TO and GO of the Elements at the
boundaries of the islands and R2 could then be removed avoiding the issue of retroactive
compliance.
Yes
(1) We agree generally with the approach but note that there are specific issues. (2) First, we
disagree with the sub-bullet requiring the GO or TO to obtain agreement from the PC, TP, and RC to
retain existing Protection System settings to maintain dependable fault detection. Dependable fault
detection is a safety issue. A TO or GO should not have to get agreement to maintain Protection
System settings that are safe. The TO and GO should notify the PC, TP, RC and TOP of such issues
and then the PC and TP can plan the system accordingly (i.e. meet the TPL standards) and the TOP
can operate the system accordingly (i.e. meet the IROL standards). (3) Obtaining the agreement of
the PC, RC, and TP is problematic and repeats similar problems that are associated with PRC-023
R3. PRC-023-2 R3 requires the GO, TO, and DP to obtain the agreement of the PC, RC and TOP to
set the relay loadability using certain criteria. The problem is there is no obligation for the PC, RC or
TOP to agree and they often are reluctant to agree due to legal liability. In other words, no one
really knows what they are agreeing to or the implications except that the standard requires it.
These same problems will be experienced here with this requirement. The need for the PC, TP and
RC to agree should be removed or more specification should be provided for what this means. (4)
For the criterion, we disagree with the need to require the PC, RC, and TP to agree to use a system
separation angle of less than 120 degrees. All that should be required is for the TO or GO to provide
sound engineering justification for using an angle less than 120 degrees.
No
(1) We agree that the VRFs for Requirement R1 through R3 should be no higher than medium. To be
higher than medium, a violation of the requirement would have to lead directly to cascading,
instability or system separation. Power swings were not direct causes to the August 14, 2003
blackout but rather occurred after other events had already happened. (2) We disagree with the VRF
for Requirement R4. Requirement R4 is an administrative requirement to update paperwork (i.e.
update the CAP). It does not and should compel completion of the CAP because it is impossible to
complete construction by a certain date due to the unpredictability (e.g. weather, logistical, legal, or
operational delays) of issues that delays construction. (3) We cannot agree with the VSLs because
we do not agree with the requirements. Furthermore, the VSLs anticipate that the only violation that
could occur is a time violation. VSLs that are not just time-based need to be written.
No
(1) In general the guidelines provide a good explanation; however, we do identify some suggested
improvements below. (2) We suggest modifying the end of the “Applicability” section on page 13 to
clearly state that these load-serving facilities by definition would not be part of the BES. Thus,
standards would not apply. (3) The last sentence of the “Requirement R1” section on page 14 is too
vague. As written, it could be interpreted that the PC and TP must include any Elements identified in
the Planning Assessment for any reason (i.e. including non-power swing issues). This is inaccurate.
Part 4 of the requirement is very specific to only those Elements with relays that trip due to stable
power swings as identified in studies. Please update the guidelines to match the language of the
requirement more closely.
No
(1) We disagree with the implementation plan and believe that a staggered implementation is
necessary. If the standard were approved such that it would become effective on March 1, 2016, the
TO and GO would not have any Elements identified per R1 until approximately 10 months later in
January 2017. How could they comply in 2016 with R3 when they don’t have any Elements identified
per R1?
(1) Requirement R4 is unnecessary and inconsistent with the Reliability Assurance Initiative which is
attempting to move NERC away from paper-driven compliance to reliability-driven compliance. The
only practical violation of R4 will be a failure to update the paperwork. As written, if an
implementation date slips, the TO or GO can update their CAP. We agree they should have the
flexibility to do this since construction schedules nearly always have to be adjusted. Thus, if a
milestone is not completed for any reason, a violation will not occur unless the CAP is not updated.
How does this support reliability? Because it is not practical to require a TO or GO to complete their
CAP by the dates established in the initial version due to unpredictable changes and unforeseen
circumstances always faced in construction, the only real practical solution is to remove Requirement
R4. NERC and the Regional Entities have the authority to request copies of the CAPs and progress
reports and have other methods to encourage completion of CAPs if they are not satisfied with the
progress. (2) We are concerned that the RSAW is not consistent with the principle of the Reliability
Assurance Initiative (RAI). RAI is intended to refocus NERC’s compliance efforts to be forward
looking rather than backwards looking and focus on the matters that impact reliability the most. This
RSAW has reverted to the historical looking compliance review. On every requirement, there are
multiple statements that evidence will be requested for each calendar year since the last audit and
that the compliance assessment approach will evaluate every year since the last compliance audit.
For a TO or GO, this would represent six to seven years of evidence and review that would provide
no reliability benefit. This RSAW needs to be revamped to be consistent with RAI principles. (3)
Thank you for the opportunity to comment.
Group
FirstEnergy Corp.
Richard Hoag
No
FirstEnergy agrees with the focus approach using the criteria but has the following concern. It is
understood that the “… since January 1, 2003” verbiage is intended to capture applicable relay
operations during the Aug. 14, 2003 event. It will be difficult if not nearly impossible for a GO,
especially in a deregulated environment, to piece together details of relay operations prior to recordkeeping requirements for NERC PRC-004. We recommend that these Criteria be reworded to include
only incidents which have occurred since the inception of NERC PRC-004.
Yes
No
It is understood that the “… since January 1, 2003” verbiage is intended to capture applicable relay
operations during the Aug. 14, 2003 event. It will be difficult if not nearly impossible for a GO,
especially in a deregulated environment, to piece together details of relay operations prior to recordkeeping requirements for NERC PRC-004. We recommend that these Criteria be reworded to include
only incidents which have occurred since the inception of NERC PRC-004.
No
It would be most helpful to specify protective functions (e.g., 78, 21, 67, 40?) to be included in this
analysis, similar to what was done with the Criteria Tables in PRC-025. If the reference to “loadresponsive protective relay” in PRC-026-1 R2 means the same as where this terminology is used
(and defined) in PRC-025, the scope of work required for the detailed analysis specified in PRC-0261 R3 is quite significant. Technical resources to perform this analysis on each applicable relay could
be difficult for many GOs to commit or obtain, and it would be difficult to accomplish the analyses in
a short timeframe. One year is unrealistic, especially considering the concern stems from an incident
that occurred nearly eleven years ago. Further, an annual demonstration with associated evidence is
potentially financially burdensome, and seemingly unnecessary if there are no changes to a Unit’s
protection system. Changes to applied protection are already captured via the coordination
requirement in PRC-001, and are available to the PC, RC and TP. Again, in a regulated vs.
competitive environment, it may be difficult to obtain system data needed for such calculations.
However, if the only piece of information needed from the TO is a Thevenin impedance (system
equivalent) at the Point of Interconnection, acquiring this should not be a problem.
Yes
No
It would be most helpful to specify protective functions (e.g., 78, 21, 67, 40?) to be included in this
analysis, similar to what was done with the Criteria Tables in PRC-025. If the reference to “loadresponsive protective relay” in PRC-026-1 R2 means the same as where this terminology is used
(and defined) in PRC-025, the scope of work required for the detailed analysis specified in PRC-0261 R3 is quite significant. Technical resources to perform this analysis on each applicable relay could
be difficult for many GOs to commit or obtain, and it would be difficult to accomplish the analyses in
a short timeframe. One year is unrealistic, especially considering the concern stems from an incident
that occurred nearly eleven years ago. This requirement should also be worded in such a way as to
be sensitive to GOs operating in a competitive environment, where FERC Standard of Conduct issues
make it difficult if not impossible to even know about power swings or other disturbances on the
power system. Please define “stable power swing”. The diagrams (“Figures”) in the Application
Guidelines appear to be typical. Is there enough information contained in the Application Guidelines
that a GO can determine Power Swing Stability Boundaries for each specific application?
No
This current situation has continued for 11 years and an implementation plan of 1 year is
unrealistically short. Two years is more appropriate unless the period is modified to include only
incidents which have occurred since the inception of NERC PRC-004 then 1 year would be
reasonable.
In a competitive/unregulated environment a GO does not have access to the information pertaining
to power swings (stable or otherwise) due to the FERC Standard of Conduct. Therefore the GO would
not know the cause of a relay operation.
None
None
Group
Florida Power & Light
Mike O'Neil
Yes
The language for Criteria 3 & 4 in Requirement 1 should be modified. Criteria 3 should consider
underfrequency planning simulations in addition to angular stability planning simulations. Criteria 4
should consider Planning Assessments in the last year as opposed to “the most recent Planning
Assessment.”
Yes
Yes
Yes
Yes
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
Yes
These comments are submitted on behalf of the following PPL NERC Registered Affiliates: LG&E and
KU Energy, LLC; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; PPL Generation, LLC; PPL
Susquehanna, LLC; and PPL Montana, LLC. The PPL NERC Registered Affiliates are registered in six
regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more of the following NERC functions:
BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TS Comments: We agree with the general
approach, but have some implementation concerns as expressed below.
Yes
No
We agree with R2 in principle, but there are presently some barriers to the specified stand-alone
nature of GO and TO obligations: - R2 should state that, where Elements meet one or more of
criteria 1-4, the TO must provide GOs with the system impedance data necessary to perform their
studies (ref. the comment on p.24 of the Application Guidelines regarding taking into account the
strength of the transmission system). GOs typically do not have automatic access to this data, and
their “firewall” separation from TOs may impede such an information exchange unless it is mandated
by NERC standards. - There has been to-date no obligation for entities to maintain records
pertaining to the criteria specified in R2, so it may not be possible in all cases to perform the lookback to Jan. 1, 2003 mandated in this requirement. The criteria should therefore be changed to
begin, “An Element that is known to have..,” instead of, “An Element that has….” - GOs may not
know whether their Elements formed the boundary of an island (ref. R2.2GOs should not be required
to take any actions under either R2.1 or R2.2 until and unless the PC/RC/TOP gives notification and
provides the relevant necessary information to the GO.
No
We agree with R3 in principle, but there are presently some barriers to the specified stand-alone
nature of GO and TO obligations: - The statement, “Demonstrate that the existing Protection System
is not expected to trip in response to a stable power swing based on the criterion below,” in R3
should be replaced by, “Demonstrate that the existing Protection System is programmed per the
criterion below.” The reason for this change is that, while the criterion on p.6 of PRC-026-1 is the
appropriate “textbook” way of setting-up an out-of-step relay, the genuinely authoritative means of
showing that tripping will not occur for stable power swings is by use of a transient stability program
as discussed in the first paragraph on p.24 of the Application Guidelines. Such programs are far from
simple to set-up and operate however, GOs do not typically have or run them, and the system data
required is known only to the TO and TOP. The requirements and Application Guidelines should make
it clear that GOs have no involvement with transient stability programs. - The statement, “For cases
where infeed affects the apparent impedance (multiple unit connected generators connected to a
transmission switchyard), the Generator Owner will provide the unit and relay data to the
Transmission Planner for analysis,” indicates that compliance responsibility can as a matter of
practicality shift to another entity under certain circumstances, but the requirements do not ensure
that such transactions happen. The, “obtain agreement,” alternatives under the 4th bull-dot of R3 do
not obligate the PC/RC/TOP to perform studies or take other actions to help facilitate compliance
under R3. PRC-026-1 needs revision to explicitly define the circumstances and mechanisms for
multiple-entity collaboration in performing analyses.
No
The VSL for failure to identify an Element in accordance with R2 needs to take into account the
potential impossibility of performing a look-back to Jan. 1, 2003, as stated above.
No
In addition to our comments elsewhere in this document, the term, “load-responsive protective
relays,” needs definition, especially since its meaning appears to change from one standard to
another. We view “out-of-step” devices as not being among the load-responsive protective relays
governed by PRC-025-1, for example, but being included under PRC-026-1. Is the list on p.23 of the
Application Guidelines meant to be exclusive?
No
It is not evident why applicable Elements owned by GOs require a new R3 analysis annually. Their
calculations should remain valid until and unless impedances change significantly. We suggest that
the TO should provide a system impedance update annually (ref. comment #2 above), and a new
study should be required of the GO only if the generator, GSU or system impedance changes by
10% or more.
No.
No.
Individual
Chris Scanlon
Exelon
Yes
Yes
Yes
Yes
Yes
Yes
Yes
The SPCS white paper “Protection System Response to Power Swings” (August 2013), found, “Based
on its review of historical events, consideration of the trade‐offs between dependability and security,
and recognizing the indirect benefits of implementing the transmission relay loadability standard
(PRC‐023), the System Protection and Control Subcommittee (SPCS) concludes that a NERC
Reliability Standard to address relay performance during stable swings is not needed, and could
result in unintended adverse impacts to Bulk‐Power System reliability.” Notwithstanding that
recommendation, the white paper also outlined an approach for developing a power swing reliability
standard in the event a standard is proposed to address the FERC Directive. We agree that the SDT
has adhered to the SPCS’s recommendations in the present draft, but we do not believe that the
technical basis for the SPCS recommendation against creating a standard has been challenged and
that there is sufficient justification for continuing with the effort to write a standard addressing this
issue. To the best of our knowledge, our operating companies, ComEd, BGE and PECO, have never
experienced a relay trip due to a power swing. We recognize and appreciate the Drafting team’s
work in responding to comments to the SAR suggesting that alternative means of meeting the
Directive should be explored. As discussed by numerous stakeholders in the previous response to
comments, we believe further work in this area should continue.
Group
Duke Energy
Michael Lowman
No
(1) Based on the SPCS report stated below (dated August 2013), Duke Energy does not believe that
adequate technical justification has been identified for this project to become a standard. The SDT
and NERC should consider moving this project to a Guideline document until such time as a standard
is warranted. “Based on its review of historical events, consideration of the trade‐offs between
dependability and security, and recognizing the indirect benefits of implementing the transmission
relay loadability standard (PRC‐023), the SPCS concludes that a NERC Reliability Standard to
address relay performance during stable power swings is not needed, and could result in unintended
adverse impacts to Bulk‐Power System reliability.” (2) Duke Energy does not agree with the criteria
specified in R1 because sufficient tools have not been developed at this time for the industry to
conduct the appropriate assessment and identification of the Elements in Criteria 4. However, if this
project moves forward as a standard we suggest the following revision to Criteria 4: “4. An Element
identified in the most recent Planning Assessment where relay tripping occurred as a result of a
power swing during the simulated Disturbance. Generic modeling of relays is acceptable when
conducting this initial Planning Assessment.” This would provide the necessary flexibility until such a
time as tools are developed to conduct a more accurate Planning Assessment and identification of
Elements for Criteria 4.
No
Duke Energy disagrees with the applicability of the Reliability Coordinator (RC) to Requirement R1.
From a NERC Reliability Functional Model standpoint, the RC does not directly interface with a
Generator Owner (GO) or Transmission Owner (TO) as Requirement R1 is proposing. The RC
receives facility and operational data such as maintenance plans from TOs and GOs for reliability
analysis, but this is mostly done through automation i.e. SDX (System Data Exchange). The
Functional Model even states that the RC coordinates with other RCs, Transmission Planners, and
Transmission Service Providers on transmission system limitations, not to TOs or GOs.
Communication from an RC is most always directed to the Balancing Authority (BA) or Transmission
Operator (TOP), and the RC reliability analyses is provided to TOPs, BAs and Generator Operators in
its area as well as other RCs. An RC, per FAC-011, is required to establish a methodology for the
identification of SOLs/IROLs and communicate the methodology to the TOP. RCs assist TOPs in
calculating and coordinating SOLs, but the TOP is the Functional Entity that implements the RC
methodology to identify and communicate the SOLs/IROLs to its RC in the Operations Horizon.
Lastly, we feel that this standard would create a precedent requiring the RC to unnecessarily
communicate and interface with GOs and TOs; an action that is not required by the current
enforceable Reliability Standards. We recommend that the TOP should supplant the RC as the
applicable entity responsible for communicating the criterion list in the proposed PRC-026-1
Requirement R1. Duke Energy proposes the following alternative language for Requirement R1.
“Each Planning Coordinator, Transmission Operator, and Transmission Planner shall, within the first
month of each calendar year, identify and provide notification to its Reliability Coordinator, and to
the respective Generator Owner and Transmission Owner of each Element that meets one or more of
the following criteria, if any:”
Yes
Duke Energy does not agree with the TO and GO combing through 12 years of historical data and
determining the events that were a result of a power swing. In addition, the GO and TO would have
to maintain documentation of power swing events that have occurred since 2003 for every
compliance audit. This would cause an unnecessary administrative burden on the responsible entity
and should be viewed as a P81 candidate. A more appropriate set of criteria would be for the TO and
GO to identify Elements in R2 that have occurred in the previous calendar year or in the previous
audit cycle.
Yes
Yes
No
On page 16 of the Application Guideline and Technical Basis document, paragraph 3 states, “…the
Element passes the evaluation (Figures 6 and 7).” However, Figure 7 on page 23 states, “This
Element does not pass the Requirement R3 evaluation.” It appears that Figure 7 is incorrect with the
statement on page 16.
Yes
Duke Energy would like to reiterate that we do not believe adequate technical justification has been
identified for this project to become a standard. Based on the SPCS recommendation, the SDT and
NERC should consider moving this project to a Guideline document until such time as a standard is
warranted.
Individual
Shivaz Chopra
New York Power Authority
No
The PSRPS technical document does not recommend this Standard. This is stated in pages 5, 20,
and 24: “Based on its review of historical events, consideration of the trade‐offs between
dependability and security, and recognizing the indirect benefits of implementing the transmission
relay loadability standard (PRC‐023), the SPCS concludes that a NERC reliability Standard to address
relay performance during stable power swings is not needed, and could result in unintended adverse
impacts to Bulk‐Power System reliability.” We only agree with R1. R1 calls upon the Planning
Coordinator, Reliability Coordinator, & Transmission Planner, (all single ISO in our region) to provide
notification to GOs and TOs of what the specific “Elements” are. R2 seems to again call for Elements
by the GOs and TOs. R2 can easily be combined into R1 for a simpler answer. In addition, by
practice all registered entities report to the ISO/RC any disturbances, being they are the System
Operator and keep records of events in the region.
Yes
The Planning Coordinator, Reliability Coordinator, and Transmission Planner would have the
necessary data and capabilities to perform such functions for internal control areas and interregional
ties.
No
The Planning and Reliability Coordinator (ISO in our region) would have records of such disturbances
for their control areas. TOs and GOs defer to the ISO to render all final decisions and designations in
these types of matters.
No
The more relevant approach, as is recommended by the PSRPS technical document, is that you do
take corrective actions for unstable power swings. This was determined to be a far greater concern
than not taking actions for stable swings. A more accurate description of “load responsive”
protective relays is also necessary. This Standard seems to just repeat what is in the PSRPS
technical document, without the necessary elaborations needed for proper understanding.
No
We do NOT agree with the need for this standard.
No
This proposed Standard would be better suited as a TPL, or OP Standard, not a PRC one. This is
because the functions and study capabilities required for the Standard are done by Transmission
Planning/Operations Organizations, and are not in the realm of Protective Relay Departments of a
GO/TO.
No
Implementation periods should be consistent with the more relevant approach described in the
PSRPS technical document.
As previously answered, the referenced 61-page PSRPS technical document, from which much of
this Standard’s wording is copied from, specifically recommends against this standard. Again, as
stated in Pages 5, 20, and 24: “Based on its review of historical events, consideration of the trade‐
offs between dependability and security, and recognizing the indirect benefits of implementing the
transmission relay loadability standard (PRC‐023), the SPCS concludes that a NERC reliability
Standard to address relay performance during stable power swings is not needed, and could result in
unintended adverse impacts to Bulk‐Power System reliability.”
Group
BC Hydro
Patricia Robertson
No
Any approach should be based on experience with improper operation during stable power swings. If
there has been no experience of undesired operation during stable power swings then checking
against the criteria just results in fruitless work.
No
BC Hydro does not agree that the criteria of R1 are reasonable. Therefore cannot suggest why an
entity is not appropriate.
No
BC Hydro does not agree that the criteria of R2 are reasonable. Only experience of tripping during
STABLE power swings should be used.
Yes
No
BC Hydro does not agree with R1 and R2, therefore do not agree with violation risk factors or
violation severity levels.
No
The technical basis should be improved to apply only to cases where stable power swings have
historically caused undesirable tripping of transmission lines.
No
BC Hydro does not agree with implementation of the proposed standard at all.
The WECC region should be exempt from this rule. In this region, transmission power along many
lines is subject to stability limits. It is an unnecessary use of resources to check the stability of
protection systems on so many lines, considering there have been a negligible number of
undesirable trips on stable power swings.
Since the SPCS has concluded that no lines were tripped due to stable power swings, in any of the
major disturbances, the FERC directive is flawed, and this regulation should not be implemented.
Individual
Roger Dufresne
Hydro-Quebec Production
Group
JEA
Tom McElhinney
Individual
Gul Khan
Oncor Electric Delivery LLC
No
Oncor does not agree that the approach of this Standard came from recommendations in the PSRPS
technical document, but rather negates the need for the Standard altogether. Specifically, on page 5
paragraph 4 of the document it states “Based on its review of historical events, consideration of the
trade‐offs between dependability and security, and recognizing the indirect benefits of implementing
the transmission relay loadability standard (PRC‐023), the SPCS concludes that a NERC Reliability
Standard to address relay performance during stable power swings is not needed, and could result in
unintended adverse impacts to Bulk‐Power System reliability”. Oncor agrees with this notion and
does not want to add any adverse issues to the power system. This is also repeated on page 20
paragraph 1. In regards to the specific requirements, R1 criteria 1 states “An Element that is located
or terminates at a generating plant, where a generating plant stability constraint exists and is
addressed by an operating limit or a Special Protection System (SPS) (including line-out
conditions).” This requirement duplicates the efforts in TPL-002 (R1.3.10), TPL-003(R1.3.10), TPL004(R1.3.7), and TPL-001-4(R 2.7.1) where the effect of a SPS, which is a protection system, is
already studied. Oncor recommends the SDT aligns the Requirements to eliminate duplication.
Yes
Oncor agrees that the three registered functions defined are those that should identify the elements
in R1; however, if each criterion, except for criteria 4 as it would clearly come from the Transmission
Planner, is assigned to a registered entity it would provide a more clear process. Additionally, R1
calls for “within the first month of each calendar year, identify and provide notification to the
respective Generator Owner and Transmission Owner of each Element that meets one or more of the
following criteria, if any” and then looking at criteria 1 and 2, Oncor recommends the SDT clarify the
time frame, either real time/short term or future/long term, required. The Time Horizon does state
“Long-term Planning” but it also calls for identification of the element within the first month of the
calendar year. This would assist with whether or not planning data, which is done one year out,
would be valid. See “line out condition” statement in Oncor’s response to #6.
Yes
As currently drafted, R2 requires GOs and TOs to evaluate Disturbance records “since January 1,
2003,” a time that will precede the effective date of this standard. A requirement cannot rely upon
records that precede the effective date of a standard. As an example, PRC-005-1, which was
approved in Order 693, became effective on June 11, 2007, does not require a Registered Entity to
have maintenance records available for the period of time that preceded the effective date in order
to calculate the next maintenance interval for a relay. CAN-0008 specifically states “CEAs are not to
require registered entities to produce records of testing and maintenance activities conducted prior
to June 18, 2007, because keeping such records was not mandatory at that time. Therefore, CEAs
are only to require production of actual maintenance and testing records from June 18, 2007
forward.” Oncor would hope the same applies across all Standards and Requirements.
No
See response to question #1.
No
See response to question #1.
No
Oncor agrees with the recommendation of the NERC PC (SCPS) and recommends if this has not been
reviewed by NERC RISC, this may be an opportunity for the NERC Standard Committee (SC) to bring
back to RISC for discussion in conjunction with the PSRPS technical document. If RISC and SC find
the Standard should be developed, a clearer explanation as to what contingency the term “line out
conditions” refers to should be included as this will determine the data source we use to generate
our list of elements.
No
Please see response #1, #6 and #10
R1 criteria 4 states to identify the following element: “An Element identified in the most recent
Planning Assessment where relay tripping occurred for a power swing during a Disturbance.”In the
statement above it is not clear whether the disturbance is actual or simulated. R4 should state Each
Generator Owner and Transmission Owner shall implement each CAP developed pursuant to
Requirement R3 if option 3 or option 4 are chosen, and update each CAP if actions or timetables
change, until all actions are complete. There should be no CAP required if R3 option 2 is chosen and
the application of power swing blocking must be applied to specific relay locations. Oncor agrees
with the recommendation of the NERC PC (SCPS) and recommends if this has not been reviewed by
NERC RISC, this may be an opportunity for the NERC Standard Committee (SC) to bring back to
RISC for discussion in conjunction with the PSRPS technical document.
Individual
Glenn Pressler
CPS Energy
Group
Florida Municipal Power Agency
Frank Gaffney
No
As recognized by the SCPS, the standard is not needed and will result in a reduction of reliability to
the bulk-power system (see report of footnote 1, Chapter 3, section titled “Need for a Standard”).
FMPA strongly agrees with the SCPS that it is better for bulk-power system reliability to bias the “Art
of Protection” to enable the power system to separate for unstable power swings than to bias the art
of protection to prevent operation for stable power swings since it is very difficult, if not impossible,
to distinguish stable from unstable power swings. We ought to enable the power system to
gracefully degrade for unstable events rather than cause entire Interconnections to become
unstable. We cannot with accuracy pre-determine where the separation points are or ought to be
since we cannot know in advance where or what the cause of instability may occur. As such, having
relays throughout the system that can cause separation as needed to prevent the entire
Interconnection from going unstable is recommended. As such, and recognizing that we are directed
to have a standard, the standard should not require PCs, RCs and TPs to identify that for every
Element that meets the criteria of R1, something needs to be done (which is implied in R3). Rather,
the PC, RC and TP ought to have discretion as to whether they want a potential issue resolved or not
within R1. That is, the PC, RC and TP should have discretion as to whether to bias the performance
towards separation for unstable power swings (graceful degradation for instability, but possibly
contribute to cascading for stable power swings – although there is no evidence of the latter from
past events), or bias the performance to prevent operation for stable power swings (which would
have a tendency to cause blackouts to be greater in magnitude, but possibly reduce the risk of
cascading for stable power swings, although there is no evidence of the latter), noting that there is
no dependable way to distinguish between stable and unstable power swings. As such, the PC, RC
and TP ought to be able to identify a subset of Elements that meet the criteria of R1 that would then
be analyzed in R2 and R3. Note also that “Element” is the wrong term and “Facility” should be used.
“Element” applies to both BES and non-BES (including distribution), Facilities is BES. Standards
cannot be written to distribution.
No
Unless there is a requirement somewhere in the standards for Reliability Coordinators to perform
stability analyses (there currently is not, SOLs/IROLs are studied by the TOP in accordance with the
RC’s methodology); then, this requirement would cause all RCs to have to perform stability studies.
Also, “corrective action plans” for protection systems will more likely be a planning horizon activity
(e.g., changing out relays) and hence, the studies should be planning horizon studies, not operating
horizon studies and the RC should not be included.
Yes
There is a significant issue with R2 in that it “requires” entities to have records before 1/1/2003.
Entities had no knowledge of needing to retain such records (i.e., the cause of a relay trip as a
stable power swing). Even if PRC-004 misoperations are the source of such data, there is no
requirement to retain records for longer than 12 months (PRC-004 has a 12 month data retention in
Section D1.4), and certainly not before June 18, 2007. The requirement should only be on a going
forward basis, not going back. Note also that “Element” is the wrong term and “Facility” should be
used. “Element applies to both BES (including distribution) and non-BES, Facilities is BES. Standards
cannot be written to distribution.
No
See response to Question 1, the TO/GO should only respond to those issued identified by the PC/TP
and not all Facilities that meet the criteria of R1.
No
Since a standard is not needed in the first place, then, there should be no VRF above a Low. All
requirements should be Planning Horizon and none in Operating Horizon.
Group
DTE Electric
Kathleen Black
No comment
Yes
No
It would seem that the GO and TO could need input from the PC, RC and TP to determine if the
conditions are still credible, based on system studies.
No
Based on the criterion for R3, it appears that only impedance relays are in scope. What about other
relay types? Specific criteria for all relay types should be provided along with examples on how to
demostrate a no trip response.
No comment
No
Paragraph four on Page 23 of 61 of the PSRPS Report states that current-only based protection is
immune to operating during power swingw, but the Application to Generator Owners paragraph on
page 23 of 25 of the draft standard implies that time overcurrent relays are subject to incorrect
operation caused by stable power swings. Perhaps this could be clarified. Since relay engineers are
typically not familiar with transient stability studies, it would be helpful if more examples were
provided for specific generator relay types that would be prone to operate for power swings.
No comment
No comment
No comment
No comment
Individual
Karin Schweitzer
Texas Reliability Entity
Yes
Yes
A TOP may also provide an analyses in the Operations horizon that could identify other lines
pursuant to the PSRSP technical document. Has the SDT considered the inclusion of TOP in the
applicability? The requirement as written implies that both the identification and notification of
Elements must both be accomplished in January of each year. Identification can happen anytime
each year, but notification must occur annually by January 31 each year. Suggest “Each year, each
Planning Coordinator, Reliability Coordinator, and Transmission Planner shall identify, and by
January 31 of each calendar year, provide notification…”
Yes
The GO and TO are the appropriate responsible entities. The timeframe appears identified in Criteria
1 and 2 back to January 1, 2003 appears onerous. The Northeast Blackout should provide the
impetus to look at power swings but may not need to be the basis for the timeframe. Suggestion is
to leave date out; auditor discretion would tend to indicate “since last audit”. Clarification is
requested for Criteria 1 and 2 regarding the term “credible”; who is responsible for determining
“credible” (is it tied to TPL-001-4)?
Yes
Suggest substituting “R1 and R2” for “R1 or R2” to avoid the possibility of confusion. As written, it
could be construed that GOs and TOs can choose to address either R1 or R2 and not address both
R1 and R2.
Yes
Yes
Section 1.2 – Evidence Retention: Language as written appears to be unnecessarily complicated.
Suggest changing to: “Functional Entities shall retain evidence demonstrating compliance since the
last audit or for three calendar years, whichever is longer.”
Individual
Michael Moltane
ITC
Yes
In general we agree. However, the SDT should clarify what constitutes an island with regard to this
standard as it’s not a defined term. Should this standard pertain to lines which contain both
generation and load, which when tripped form an island? We suggest not. Also, the term “credible”
is unclear. If an event involves scenarios beyond TPL’s “broad spectrum of System conditions” and
“wide range of probably Contingencies”, is it really credible? The example in Application Guideline
involved a single bus outage, which is credible in TPL standards. However, a Disturbance may occur
involving multiple contingencies but well beyond normal planning criteria and now that extreme
event must be studied. If this approach is desired, then it leaves a gap for other extreme events to
occur, just which we’ve had the good fortune not to have experienced yet. We suggest limiting the
definition of “credible” into include those scenarios within the bounds of TPL-001-4.
Yes
We agree the GO and TO are the appropriate entities. However, we suggest removing the inclusion
of events prior to the effective date of this standard.
No
In general we agree with this approach. However, we disagree with requiring compliance of one
entity to be contingent on another entities agreement. We recommend changing to require
notification instead of “agreement” in the fourth bullet and Criterion 1, second bullet.
No
R2 and R3 essentially leave an entity with 11 months to meet compliance. The Violation Severity
Levels should be longer, considering the timeframe allowed to complete the task and the minimal
risk to the BES.
Yes
The App Guide will be sufficient, considering the improvements mentioned in the webinar. In
addition, we request more details regarding islanding scenarios and explanation of “credible” along
the lines of our answer to Question 1.
No.
No
We are voting Negative primarily for two reasons: 1) the issues we raised need to be addressed to
close some gaps and 2) we support the conclusion of SPCS in the PSRPS report that this standard “is
not needed, and could result in unintended adverse impacts to Bulk-Power System reliability.” As
written, the standard only addresses distance and not overcurrent elements. This question was
raised in the webinar and a clear answer was not given. The standard refers to “load-responsive”
relays, which includes overcurrent, but does not provide criteria for evaluation in R3. Also, should
the standard include time-delayed tripping elements, which are commonly ignored for swing tripping
consideration? We also request examples for R3, fourth bullet, of scenarios which do not result in
“dependable fault detection or dependable out-of-step tripping”, perhaps in the App Guide.
Specifically, we are concerned about load/swings with subsequent phase faults which result in timedelayed tripping when power swing blocking is enabled. Even the most modern SEL-400 relays with
zero-setting OOS logic includes additional time delayed tripping for subsequent phase faults. For a
standard around swings and stability, delayed fault clearing seems to counterproductive. Is this the
scenario which could apply to R3, fourth bullet?
Individual
Thomas Standifur
Austin Energy
No
(1) City of Austin dba Austin Energy (AE) notes the following statement from the PSRPS technical
document on page 20: “Based on its review of historical events, consideration of the trade‐offs
between dependability and security, and recognizing the indirect benefits of implementing the
transmission relay loadability standard (PRC‐023), the SPCS concludes that a NERC Reliability
Standard to address relay performance during stable swings is not needed, and could result in
unintended.” AE believes more background work is necessary in justifying the creation of this
standard before proceeding. (2) Further, AE disagrees with the R2 criteria of evaluating Disturbance
records “since January 1, 2003.” The criteria not only predate the enforcement date of this standard,
it goes back to a time before any of the NERC Reliability Standards were enforceable.
Individual
Bill Temple
Northeast Utilities
No
We agree with a focused approach as outlined in the technical document. However, we have the
following serious concerns with criteria in the requirements: 1. The term “credible event” should be
clearly defined. The basis to determine a credible event is missing from the requirement and
application guide. This basis should be provided in the standard requirement. 2. Why is the standard
focused on SOL rather than IROL?The basis for specifying SOL is not supported by the example in
the application guideline since the example did not show inter-area impact. 3. It is not clear in R1,
criteria number 4 whether the assessment should include relay tripping or just stable power swing or
both stable and unstable power swing. 4. In R2, it is unrealistic to require an entity to provide data
on an Element that had tripped since 2003. There is no existing NERC continent-wide disturbance
monitoring or misoperation standard that requires data be retained more than 12 months. We
recommend that this requirement be removed from the standard or include only Elements that were
tripped in the last calendar year.
Yes
Yes
See comment #4 under Question #1. In R2, it is unrealistic to require an entity to provide data on
an Element that had tripped since 2003. There is no existing NERC continent-wide disturbance
monitoring or misoperation standard that requires data be retained more than 12 months. We
recommend that this requirement be removed from the standard or include only Elements that were
tripped in the last calendar year.
No
The purpose of the standard is “to ensure that load responsive relay do not trip in response to stable
power swing during non-fault condition.” The last sentence of Background, Section 5 implies that
protective relay while blocking for a stable power swing also allows for dependable operation for
fault and unstable power swing. Bullet #4 in R3 indicates that the GO and TO must obtain
agreement if dependable protection or dependable out-of-step tripping is not provided by a
protection system that is immune to a stable power swing. Bullet #4 seems to imply that the
purpose of the standard is to ensure blocking for a stable power swing and dependable tripping for
unstable power swing. The drafting team needs to be very clear in the standard what the intention
is. For instance, a line current differential scheme is immune to stable and unstable power swing and
will provide dependable tripping for fault. The criteria as written implies that this type of scheme will
need to be modified or an agreement will need to be obtained from the PC, RC and TP to deploy
since it does not provide dependable out-of-step tripping.
Yes
No
1. In the Application Guidelines, the wording under Requirement 2 for “credible event” is very openended. 2. An example of how line differential protection would be treated with respect to
Requirement 3 would be helpful. See the comment above in Question 4.
Yes
No
No
1. The annual frequency requirements listed in R1 & R2 are not necessary and that a less frequent
(ie: Every 5 years) would be more appropriate. 2. Please provide more examples to help further
illustrate the criteria in listed in R1. 3. Please differentiate between Stable and Unstable power
swings.
Individual
Jonathan Meyer
Idaho Power Co.
No
No. R1 seems to be an acceptable approach for Planners to use. However, R2 is not acceptable.
Having a dated requirement prior to the effective date of a Standard is not appropriate. While it may
be reasonable to look at these earlier disturbances, making a Requirement of that review is not. This
requirement should be removed or rewritten to require only the review of disturbances past the
effective date of the Standard where tripping of Protection Systems during a stable power swing was
a causal factor. In addition, the PSRPS technical document does not use the NERC Glossary term for
Disturbances, yet the Standard does. The Glossary term is not specific which makes these criterion
also non specific. Criterion similar to those in EOP-004 would seem to better identify the
disturbances that are included in this Standard. M2 appears to require the utility to have evidence it
did not know it needed to maintain. The PSRPS technical document suggests that the FERC directive
to develop this standard may have been based on misinformation or a misunderstanding of the 2003
Northeast Blackout investigation report and furthermore suggests such a standard could result in
unintended adverse impacts to the Bulk-Power System. Recommend NERC utilize the findings of the
PSRPS technical document to obtain a stay of development of PRC-026-1 from FERC until FERC can
develop a position based on the conclusions presented in the PSRSP document. If development of
PRC-026-1 continues: I agree with the focused approach. R1.1 and R1.2 need to contain clarity
about what constitutes a "line out condition" - does this mean N-1, N-2, N-X, transformers, etc?
Concerning R1.3, who is the judge of whether an event is "credible"?
Yes
Yes, although I suggest adding the stipulation that the PC, RC, and TP must be in agreement about
whether an Element meets the criteria in R1.
Yes
Yes if the Requirement is better written to address the comments of question 1. In addition, the GOP
and TOP may also need to be included to fully identify disturbances. R2 requires entities to rely on
records prior to the effective date of the standard - records the entities did not know they were
required to keep for this purpose. Either strike R2 or change the wording such that R2 applies to
Disturbances that have happened after the effective date of the standard
No
No. The Requirement as written is onerous to perform annually. Performing these checks during an
initial implementation period for the standard is appropriate to ensure the relays will perform as
designed (for tripping or blocking). After an initial assessment period, a re-check at longer intervals
or triggered by system changes would also be appropriate. Further, as currently written, the R3
language requires one of the 4 bulleted items to be done, but the language on the 4th bullet implies
that the first three be attempted first. If the first three are to be done prior to the 4th, should that
bullet not be its own Requirement, such as an R3.1? The general approach is reasonable but an
annual review is excessive. Bi-annually at the most and then by exception for any relay or system
changes.
Yes
Yes
In the present form of R1-R4
No
The requirements need work before an implementation plan can be defined. It should be adjusted
based on changes proposed in #4.
The PSRPS report and the SPS report no need for this Standard, stating that "operation of
transmission line protection systems during stable power swings was not causal or contributory to
any of these disturbances." This statement conflicts with the need for the Standard and causes
added Compliance burden to entities without reason.
Individual
Patrick Farrell
Southern California Edison Company
Yes
Yes
Yes
No
Although we appreciate the drafting team's efforts, we believe that Requirement R3 is unnecessarily
burdensome from a compliance perspective. We would suggest that the analyses of Elements be
performed on an initial basis, and then when changes occur. An annual analyses of all the Elements
assets is not efficient or warranted.
Yes
Yes
Yes
Individual
Russell Noble
Public Utility District No. 1 of Cowlitz County, WA
No
Cowlitz PUD agrees with the intent of standard PRC-026-1 (Standard) requirements R1 & R2 focused
approach, but finds the current Standard draft creates a compliance difficulty. The Standard should
clearly define the “specific criterion” which will be used to identify Elements, and compare the loadresponsive protective relay characteristics to establish “credible” risk. The Standard lacks specificity
as currently written. --(New Paragraph)-- This draft assumes incorrectly that an entity will have
retained operational historical records since 2003. If such records do not exist, an entity will have no
proof of having established a null or complete list which satisfies requirement R2. Further, there is
no requirement to retain such operational records to facilitate future compliance. The CEA must
either accept attestations, or require applicable entities to develop documentation for each section
4.2 applicable Element which establishes no credible risk of a trip during a [stable] power swing
exists. Cowlitz PUD proposes the SDT identify specific documentation and establish an official listing,
such as all pertinent RE and NERC disturbance studies/reports dated 2003 or later be used to
identify past poorly performing Elements during a Disturbance. We are also unclear on how Elements
might be identified purely from system modeling studies when strictly looking at Requirement R1
(ignoring R3 or other standard requirements outside of this Standard). Further, “credible” is a
subjective term which does not establish a clear compliance line. It may be better to state “…actual
system Disturbance where current system modeling continues to identity a repeat of the Disturbance
possible under an n-3 event.” Another possible method would be to tie “credible” to a probability of
one in a thousand; this method would require probability model development. This is not to say that
“credible” should not be used, but it will require extensive guidance in the RSAW of how the
“credible” benchmark is established. In fairness, the benchmark should be established during
Standard development to allow stakeholder review and comment.
No
Cowlitz PUD questions whether the Transmission Planner (TP) is nothing more than an extension of
the Transmission Owner (TO), Generation Owner (GO), or Planning Coordinator (PC) registrations.
Further, we believe the majority of those entities registered as a TP consider their TP footprint equal
to their TO/GO/PC footprint. Therefore, it may be more appropriate for the TP to simply report
Requirement R1 findings to the PC and RC. Finally, we believe it more efficient that a single entity be
responsible to give notice to the TO and GO. Since every TO and GO must be under a Planning
Coordinator and Reliability Coordinator, either the PC or the RC should be designated to send out the
notice after their review is complete.
Yes
Provided the SDT finds a way to clearly establish the documentation from which the GO and TO will
identify the Elements.
No comment at this time.
Yes
No
It is not clear how past events and Disturbance reports that must be considered in the identification
of Elements will be archived and made available.
Yes
We believe this Standard will address a Reliability gap, but also feel that it can overlap into PRC-004.
Load responsive relays that trip on a stable power swing should be addressed by PRC-004 as a
Protection System Misoperation; subsequently after PRC-004 is satisfied, the affected element
should be subject to PRC-026-1 until a repeat is demonstrated to be remote or nonexistent.
However, a violation of PRC-004 should not automatically bleed into a violation of PRC-026-1.
Individual
Melissa Kurtz
US Army Corps of Engineers
Group
Colorado Springs Utilities
Kaleb Brimhall
Group
Puget Sound Energy
Eleanor Ewry
No
For systems that have not experienced a power swing that caused a trip or islanding condition, there
is the burden of proving the negative to demonstrate compliance with the standard. It is
recommended that Requirement R2 be rewritten in such a way that entities will not have to prove
the negative. It is also recommended that the standard be revised to address the situation where
historical data is not avaialable as far back as 2003. We also request that a NERC definition be
provided for what constitutes a stable power swing and what criteria can be applied to historical data
to determine if a stable power swing has occurred.
Yes
Yes
Yes
While this approach seems reasonable, there is currently a lack of ability to model the loadresponsive protective relays to determine whether a protection system is expected to trip in
response to a stable power swing. While this capability is currently being implemented, it will not be
completed by the proposed implementation date of this standard.
Yes
Yes
No
As noted in question 4, the modeling of protective relays needed to evaluate the system will not be
implemented by by the proposed implementation date for the standard.
As stated in the document entitled "Protection System Response to Power Swings" by PSRPS, a
review of historical system disturbances determined that operation of transmission line protection
systems during stable power swings was not causal or contributory to any of the disturbances
reviewed. The final conclusion of PSRPS was that a NERC Reliability Standard is not needed to
address relay performance due to stable power swings and could result in unintended adverse
impacts to Bulk Power System reliability. In light of this conclusion, as well as the comments
contained in this form, we have voted 'no' on this standard.
Individual
Anthony Jablonski
ReliabiltiyFirst
ReliabilityFirst offers the following comments for consideration. 1. Requirement R1 – To be
consistent with other NERC Reliability Standards, ReliabilityFirst suggests reclassifying the “criteria”
as “sub-parts” of the requirement. 2. Requirement R2 - R2 requires GOs and TOs to evaluate
Disturbances “since January 1, 2003”. It appears that the intent of this requirement is to include
Elements where actual system events caused a trip due to a known power swing and, by including
the 2003 date, ensured that events associated with the 2003 Blackout were included. However, this
may imply that events prior to 2003 need not be considered, especially in areas other than the
Northeast where the blackout occurred. If an Element had a known trip for power swings associated
with a Disturbance, they should be included. Therefore, ReliabilityFirst recommends the flowing for
consideration for the two criteria: “1. An Element that has tripped since January 1, 2003 [(or known
historical Element that tripped prior to January 1, 2003)], due to a power swing during an actual
system Disturbance where the Disturbance(s) that caused the trip due to a power swing continues to
be credible. 2. An Element that has formed the boundary of an island since January 1, 2003 [(or
known historical Element that formed the boundary of an island prior to January 1, 2003)], during
an actual system Disturbance where the Disturbance(s) that caused the islanding condition
continues to be credible.” 3. Requirement R3 – ReliabilityFirst requests clarification on how the
Criterion in Requirement R3 fits into the requirement. Is this criterion part of the requirement or is it
additional information? If it is the later, ReliabilityFirst believes this guidance is already covered in
the “Guidelines and Technical Basis” section and should be removed from the requirements. NERC
Reliability Requirements should address “what” is required and not “how” an entity will comply.
Group
Bonneville Power Administration
Andrea Jessup
No
BPA agrees with the approach, with two exceptions. First, BPA feels more clarity is needed regarding
which Elements are associated with System Operating Limits (SOLs), relevant to the Standard.
Stability constraints can depend on the overall topology of the system, in which case nearly every
Element in the power system would meet the criteria of item 2. For example, BPA may determine a
stability constraint on WECC Path 66 due to poorly damped oscillations. Taking almost any 500 kV or
345 kV line out of service on the western side of WECC could change the value of this limit, in which
case all of these Elements meet the criteria of item 2. BPA suggests the language be changed to: 2.
An Element that has been shown to have a substantial effect on a System Operating Limit (SOL)
that has been established based on stability constraints identified in system planning or operating
studies (including line-out conditions.) Secondly, BPA feels the Glossary definition of Disturbance
lacks sufficient clarity as it relates to this and other existing Standards.
No
BPA feels the Standard needs to delineate which entity performs which role, and under which
conditions. For example, the Reliability Coordinator (RC) only identifies the Elements tripped during
islanding and disturbance, while the Planning Coordinator (PC) and Transmission Planner (TP) do so
for long term planning.
Yes
Yes
BPA believes R3 should be modified for greater clarity and to allow for intentional power swing relays
designed to be tripped in a controlled manner to protect the BES. Additionally, the wording in the
fourth bullet appears to be inconsistent with the Rationale for R3.
Yes
No
BPA feels 12 months is insufficient time for the initial implementation.
Western Interconnection has many long lines and remote generation.
BPA feels the Glossary definition of Disturbance lacks sufficient clarity as it relates to this and other
existing Standards. BPA also requests a descriptive title be used for the Criterion (e.g. Criterion for
Swing Protection Analysis).
Individual
Joshua Andersen
Salt River Project
Yes
Yes
Yes
Yes
Yes
Yes
Yes
None
None
Salt River Project is concerned that system protection should not be "de-tuned" at the expense of
the protection provided the Bulk Electric System for the sake of reliability.
Group
Arizona Public Service Co.
Janet Smith
Yes
While AZPS agrees with the focused approach, AZPS would like to ask the drafting team to consider
revising R1 and R2. APS recommends that the drafting team require an initial identification and
notification of each Element that meets the criteria described in R1. A review of the assessment
should not be required annually if there are no additions to the entity system meeting the criteria. It
would be more practical to require a comprehensive review every five years. In addition, the
standard should require that if Elements are added to the entity system that meet the criteria in R1,
the applicable entity should provide updates within 90 days of the commissioning of a new Element.
APS believes that the current draft requirement is administrative in nature and represents a
reporting burden.
Yes
No
AZPS believes that the GO and TO are not the appropriate entities to identify the Elements that
meet the criteria in R2. The criteria of R2 would be determined based on event analysis and the GO’s
and TO’s have limited access to this information. Also, there are often joint participation projects
which then include multiple owners. This would create confusion regarding who is supposed to
complete the analysis. AZPS recommends that the RC be required to provide this information since
they are necessarily involved in all significant system event analyses.
No
AZPS would recommend changing Protection System to load-responsive protective relays and define
what type of relays qualifies as load-responsive protective relays. If the drafting team does not
agree with defining load-responsive relays, they should specifically state the relay type (i.e. zone
protection) rather than using the broader term Protection System.
No
APS suggests the timelines associated with the proposed VSL for Requirement 1 be adjusted to a
longer time period if drafting team addresses the APS issue associated with the timing requirements
on R1.
Yes
No
AZPS suggests the timeline for the implementation plan be increased to allow for two years for
requirements one and two and requirements three and four be adjusted accordingly. APS believes
significant effort will be required to identify relays that may qualify for inclusion.
APS recommends that the drafting team require an initial identification and notification of each
Element that meets the criteria described R1. A review of the assessment should not be required
yearly if there are no additions to the entity system meeting the criteria. It would be more practical
to require a comprehensive review every five years. In addition, the standard should require that if
Elements are added to the entity system that meet the criteria in R1, the applicable entity should
provide updates within 90 days of the commissioning of a new Element. APS believes that the
current draft requirement is administrative in nature and represents a reporting burden.
Individual
Kenneth A Goldsmith
Alliant Energy
No
In the Application Guide there is guidance provided for the determination of apparent impedance for
Impedance Type Relays on page 23 of 25, under the “Application to Generator Owners” portion of
the document. As noted in this section the process is complex. As such, we recommend adding a
detailed example of how the Transmission Planner should conduct this analysis on the behalf of the
Generation Owner.
Group
Bureau of Reclamation
Erika Doot
Yes
Yes
No
The Bureau of Reclamation (Reclamation) believes that the Transmission Planner or Planning
Coordinator would be in the best position to determine whether Disturbances continue to be
credible. Therefore, Reclamation suggests that the Transmission Planner or Planning Coordinator
would be in the best position to identify the Elements in R2. The Transmission Planner or Planning
Coordinator should be required to notify the Transmission Owner or Generator Owner of which
Elements meet the criteria so that the Transmission Owner or Generator Owner can perform the R3
analysis. Reclamation also suggests that the criteria be rephrased to require analysis of data from
the previous year only. As written, R2 would require Transmission Owners and Generator Owners to
re-analyze data going back to 2003 each year. Reclamation believes that the costs of re-analyzing
this data would outweigh the benefits. Reclamation believes that NERC should develop a data
request to develop a robust initial data set covering January 2003 to present.
Yes
Yes
Yes
Yes
Reclamation suggests that R2 be rephrased to only require analysis of data from the previous year.
As written, R2 would require Transmission Owners and Generator Owners to re-analyze data going
back to 2003 each year. Reclamation believes that the costs of re-analyzing this data would
outweigh the benefits. Reclamation believes that NERC should develop a data request to develop a
robust initial data set covering January 2003 to present.
Consideration of Comments
Project 2010-13.3 – Phase 3 of Relay Loadability: Stable Power Swings
The Stable Power Swings Drafting Team thanks all commenters who submitted comments on the
standard. This standard was posted for a 45-day public comment period from April 25, 2014 through
June 9, 2014. Stakeholders were asked to provide feedback on the standard and associated documents
through a special electronic comment form. There were 70 sets of comments, including comments
from approximately 181 different people from approximately 117 companies representing all 10
Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please 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,
you can contact the Director of Standards, Valerie Agnew, at 404-446-2566 or at
[email protected] . In addition, there is a NERC Reliability Standards Appeals Process.1
NERC Discussion on Proceeding(s) and Directives Regarding: Stable Power Swings
In the NOPR that led to Order No. 733, the Commission stated that the cascade during the August 2003
blackout was accelerated by zone 3/zone 2 relays that operated because they could not distinguish
between a dynamic, but stable power swing and an actual fault. The Commission observed that PRC023-1 does not address stable power swings, and pointed out that currently available protection
applications and relays, such as pilot wire differential, phase comparison and blinder-blocking
applications and relays, and impedance relays with non-circular operating characteristics, are
demonstrably less susceptible to operating unnecessarily because of stable power swings. Given the
availability of alternatives, the Commission stated that the use of protective relay systems that cannot
differentiate between faults and stable power swings constitutes mis-coordination of the protection
system and is inconsistent with entities’ obligations under existing Reliability Standards. The
Commission explained that a protective relay system that cannot refrain from operating under nonfault conditions because of a technological impediment is unable to achieve the performance required
for Reliable Operation. Consequently, the Commission requested comments on whether it should
direct the ERO to develop a new Reliability Standard or a modification to PRC-023-1 that requires the
use of protective relay systems that can differentiate between faults and stable power swings and
phases out protective relay systems that cannot meet this requirement.
NERC and other commenters urged the Commission to not direct modification of PRC-023-1 and
instead allow NERC to determine the proper solution following technical analysis of the issue. Other
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf
commenters challenged the Commission’s reasoning and assumptions for its proposed directive
including challenging the validity of the assertion that stable power swings contributed to the cascade
in the August 2003 blackout. Others argued that PRC-023-1 adequately covers the issue raised by the
Commission. Despite the multiple avenues used to challenge the directive proposed by the
Commission, the Commission ultimately directed NERC to create a new Reliability Standard that
requires the use of protective relay systems that can differentiate between faults and stable power
swings and, when necessary, phases out protective relay systems that cannot meet this requirement.
The Commission stated that it found arguments that stable power swings did not contribute to the
cascade in the August 2003 blackout to be unpersuasive.
Various organizations including NERC, APPA, EEI, NRECA, and TAPS sought rehearing of the
Commission’s directive. EEI made arguments that the Commission’s directive was arbitrary and
capricious and unsupported by the record. APPA asked the Commission to instead require NERC to
examine whether and how operation of protective relays during stable power swings should be
addressed through standards, or at minimum, clarify that it is leaving to NERC to determine the
applicability of a requirement for relays to differentiate between faults and stable power swings and
which relays must be phased out to achieve bulk power system reliability. NERC seeks clarification that
it can use its industry technical experts to address the issue appropriately and asks for clarity as to
whether the directive was intended to create an absolute requirement to highlight a concern that
other approaches might satisfy.
The Commission maintained its position that not addressing stable power swings constitutes a gap in
the current Reliability Standards and must be addressed. It did clarify in Order No. 733-A that NERC is
able to use the standard development process to develop technical analysis and an approach to the
Reliability Standard to meet the Commission’s concern. The Commission also clarified that it did not
direct the development of a Reliability Standard containing an absolute obligation to prevent
protection relays from operating unnecessarily during stable power swings.
The EEI and NRECA jointly filed a timely motion and APPA/TAPS together filed a motion, in both
instances, requesting clarification, or reconsideration of Order No. 733-A. In general, both motions
assert the Commission based its directives on a faulty understanding of the Blackout Report2 or an
incorrect characterization of relay engineering. Both motions also reprise issues addressed in Order No.
733-A relating to the Commission exceeding its statutory authority by failing to give “due weight” to
the technical expertise of the ERO and by giving overly prescriptive directives. Finally, EEI/NRECA seek
clarification or reconsideration of language that they characterize as suggesting that the Commission
expects 100 percent relay security and of the Commission’s directive regarding generator relays. APPA
and TAPS sought rehearing of Order No. 733-A. In summary, the Commission ruled, in Order No. 733-B,
that the issues had been addressed in both Order Nos. 733 and 733-A and that further clarification is
not necessary.
2
http://www.nerc.com/pa/rrm/ea/Pages/Blackout-August-2003.aspx
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In addition to the rehearing requests, NERC filed an informational filing to introduce and clarify certain
aspects of the August 14, 2003 blackout investigation relative to operation of protective relays in
response to stable power swings. NERC explained that the fourteen lines discussed in Order No. 733 did
not trip due to stable power swings. NERC stated that ten of these lines tripped in response to the
steady-state loadability issue addressed by Reliability Standard PRC-023, while the last four lines
tripped in response to dynamic instability of the power system. Although the fourteen line trips by zone
2 and zone 3 relays discussed in the Blackout Report3 did not occur as a result of stable power swings,
the blackout investigation team did identify two transmission lines that tripped due to protective relay
operation in response to stable power swings.
In August of 2013, the NERC System Protection and Control Subcommittee (SPCS) issued its report
Protection System Response to Power Swings, August 20134 (“PSRPS Report”). In response to the FERC
directive, NERC initiated this Project 2010‐13.3 – Phase 3 of Relay Loadability: Stable Power Swings to
address the issue of protection system performance during power swings. To support this effort, and in
response to a request for research from the NERC Standards Committee, the SPCS, with support from
the System Analysis and Modeling Subcommittee (SAMS), developed the PSRPS Report to promote
understanding of the overall concepts related to the nature of power swings; the effects of power
swings on protection system operation; techniques for detecting power swings and the limitations of
those techniques; and methods for assessing the impact of power swings on protection system
operation.
Based on its review of historical events, consideration of the trade‐offs between dependability and
security, and recognizing the indirect benefits of implementing the transmission relay loadability
standard (PRC‐023), the SPCS concluded that a NERC Reliability Standard to address relay performance
during stable power swings is not needed, and could result in unintended adverse impacts to Bulk‐
Power System reliability. While the SPCS recommended that a Reliability Standard is not needed, the
SPCS recognized the directive in Order No. 733 and the Standards Committee request for research to
support Project 2010‐13.3. Therefore, the SPCS provided recommendations for applicability and
requirements that can be used if NERC chooses to develop a standard. The SPCS recommended that if a
standard is developed, the most effective and efficient use of industry resources would be to limit
applicability to protection systems on circuits where the potential for observing power swings has been
demonstrated through system operating studies, transmission planning assessments, event analyses,
and other studies, such as UFLS assessments, that have identified locations at which a system
separation may occur.
Following the issuance of the PSRPS Report and prior to initiating standard development, NERC staff
met with FERC staff to discuss the findings in the PSRPS Report in relation to its directive on creation of
3
Ibid.
4
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Po
wer%20Swing%20Report_Final_20131015.pdf)
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a stable power swings Reliability Standard. FERC staff acknowledged the work of the SPCS and agreed
that it could be persuasive as technical support for the approach to the Reliability Standard to be
developed. It was clear from this meeting that FERC staff was open to an approach designed by NERC
and industry and that the expectation remained that the directive must be met. NERC staff proceeded
with Project 2010-13.3 to design a Reliability Standard to meet the directive.
Summary of Changes to the Standard
Purpose Statement
The standard’s purpose was revised from ensuring “relays do not trip” to “relays are expected to not
trip” … in response to stable power swings during non-Fault conditions.
Applicability
The Reliability Coordinator and Transmission Planner were removed from the standard to address
concerns about overlap and potential gaps when identifying Elements.
Applicability for the Generator Owner and Transmission Owner was augmented to refer to an
appended “Attachment A” which describes load-responsive protective relays that are included in the
standard and associated exclusions.
Requirements
Requirement R1 was revised substantively to remove the Reliability Coordinator and Transmission
Planner functions. The drafting team concurred that having the Planning Coordinator as the single
source for identifying Elements prevents potential duplication of work and a possible gap should an
entity believe another is making the identification and notification. The Requirement now allows a full
calendar year to notify the respective Generator Owner and Transmission Owner of an identified
Element. This was done to eliminate the burden of providing notification each January. The following
describes the changes made to each of the original four criteria including the addition of a fifth
criterion.
1. Added “angular” to clarify that this is not referring to other constraints such as voltage. Also
replaced “Special Protection System (SPS)” with “Remedial Action Scheme (RAS)” to comport
with expected changes to these NERC defined terms.
2. Clarified that criterion 2 applies only to “monitored” Elements of a System Operating Limit
(SOL). Also, added “angular” to clarify that this is not referring to other constraints such as
voltage.
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3. Revised the “islanding” criterion to remove ambiguity about islands that formed during planning
assessments. Islanding is now associated with an Element that forms the boundary of an island
due to angular instability within an underfrequency load shedding (UFLS) assessment. Also,
added “angular” to clarify that this is not referring to other constraints such as voltage.
4. Replaced the term “Disturbance” with the phrase “simulated disturbance.” because it generally
refers to an actual and not simulated event. The lowercase term “disturbance” was considered
to be consistent with the NERC TPL-001-4 Reliability Standard, but it was determined that its
usage would continue to create questions so “simulated” was added. The phrase “stable or
unstable” was inserted to clarify that both are applicable to power swings because the goal of
the standard is to identify Elements susceptible to either.
5. This criterion was added as a mechanism to require the Planning Coordinator to continue
identifying any Element that has been reported by a Generator Owner due to a stable or
unstable power swing during an actual system Disturbance or by the Transmission Owner due
to a stable or unstable power swing during an actual system Disturbance or islanding event.
Reported Elements will continue to be identified by the Planning Coordinator until the Planning
Coordinator determines the Element is no longer susceptible to power swings.
Requirement R2 was revised to remove the Generator Owner performance because the Generator
Owner does not “island.” Also, the January 1, 2003 date was removed due to industry confusion and
concern about compliance with such a date and how enforcement would be handled should an entity
not have good records. In order to maintain continuity of actual Disturbances and to raise awareness of
power swing and islanding events, the Transmission Owner is required to report the affected Element
to its Planning Coordinator. The only timeframe assigned to the Requirement is the notice to the
Planning Coordinator of an Element that tripped due to a stable or unstable power swing. There is no
requirement to review the Protection System operation as such activities are addressed by other NERC
Reliability Standards.
Requirement R3 is a new requirement created from the previous Requirement R2 specifically for the
Generator Owner. In order to maintain continuity of actual Disturbances and to raise awareness of
power swing events, the Generator Owner is required to report the affected Element to its Planning
Coordinator. The only timeframe assigned to the Requirement is the notice to the Planning Coordinator
of an Element that tripped due to a stable or unstable power swing. There is no requirement to review
the Protection System operation as such activities are addressed by other NERC Reliability Standards.
Requirement R4 (previously R3) has been substantially rewritten to eliminate multiple and varying
activities such as, demonstrate, develop, and obtain agreement. The Requirement was further
simplified to reference PRC-026-1 – Attachment B which contains the criteria for evaluating loadresponsive protective relays by the Generator Owner and Transmission Owner. The timing for
evaluating load-responsive protective relays, initially, is 12 full calendar month. As identified Elements
are reported year after year, the Generator Owner and Transmission Owner are only required to reevaluate its load-responsive protective relays applied on the terminals of the identified Element where
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the previous evaluation had not been performed in the last three calendar years. This reduced the
burden to the entities over Draft 1. Note that the Implementation Plan period for Requirement R4 is
336 calendar months.
Requirement R5 was added to address the requirement for developing a Corrective Action Plan (CAP)
that was contained in the previous Draft 1, Requirement R3.
Requirement R6 was previously R4 and only received comporting updates due to numbering changes.
PRC-026-1 – Attachment A
The PRC-026-1 – Attachment A was added to the standard due to reduce stakeholder confusion about
what load-responsive protective relays are in scope and to provide specific exclusions. The attachment
is referenced in the Applicability section of the standard.
PRC-026-1 – Attachment B
The PRC-026-1 – Attachment B was added to the standard to remove the “Criteria” for evaluating loadresponsive protective relays from within the Requirement itself and provide it in an attachment for
referencing by Requirement R4. Among other things, the criteria found in the attachment received
these modifications:
1. The sending and receiving voltages were changed to 0.7 to 1.0 from 0 to 1.0 per unit. This
increases the lens characteristic that the impedance characteristic (e.g., zone 2) must be
completely contained within (Attachment B). It was determined that using the 0.7 per unit is
not in conflict with other NERC Reliability Standards or accepted industry practice for setting
protective relays.
2. In developing the lens characteristic formed in the impedance (R-X) plane that connects the
endpoints of the total system impedance, the criteria now requires the “parallel transfer
impedance” to be removed.
3. Although previously addressed within the standards’ Application Guidelines, criteria as to
whether the transient or sub-transient may be used are now specified. The criteria are further
defined as the “saturated (transient or sub-transient) reactance. The option to use either
transient or sub-transient is provided to entities because either will provide a lens characteristic
that is sufficiently conservative to determine the relay’s susceptibility to tripping in response to
a stable power swing. Also, providing this option reduces the burden on entities from changing
which value it uses when it is already using one or the other preset in software applications.
Saturated reactances are specified since they result in lower system impedances. Most notable,
this criterion now requires the “parallel transfer impedance” to be removed when using the
criteria to determine the relay’s susceptibility to tripping in response to a stable power swing.
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4. The PRC-026-1 – Attachment B now includes an additional Criteria B which provides criteria for
overcurrent-based protective relays. Like the original Criteria A for impedance-based relays, it
uses the 120 degree system separation angle, all Elements in service, and saturated (transient
or sub-transient) reactance. This criterion also requires the “parallel transfer impedance” to be
removed.
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1.
Do you agree with the focused approach using the criteria (see R1 &
R2) which came from recommendations in the PSRPS technical
document (pg. 21 of 61)? If not, please explain why or why not
(e.g., the approach should be more narrow or more broad, and if so,
the basis for a different approach). ............................................................... 21
2. Do you agree that the Planning Coordinator, Reliability Coordinator,
and Transmission Planner are the appropriate entities to identify the
Elements that meet the criteria in Requirement R1? If not, please
explain why an entity is not appropriate and/or suggest an
alternative that should identify the Elements according to the
criteria ........................................................................................................... 62
3. Do you agree that the Generator Owner and Transmission Owner are
the appropriate entities to identify the Elements that meet the
criteria in Requirement R2? If not, please explain why an entity is
not appropriate and/or suggest an alternative that should identify
the Elements according to the criteria ........................................................... 75
4. Do you agree with the approach in Requirement R3 to ensure that
load-responsive protective relays do not trip in response to stable
power swings during non-Fault conditions for an identified Element?
If not, please explain ..................................................................................... 91
5. Do you agree with the proposed Violation Risk Factors (VRF) and
Violation Severity Levels (VSL) for the proposed requirements? If
not, please provide a basis for revising a VRF and/or what would
improve the clarity of the VSLs .................................................................... 116
6. Does PRC-026-1, Application Guidelines and Technical Basis provide
sufficient guidance, basis for approach, and examples to support
performance of the requirements? If not, please provide specific
detail that would improve the Guidelines and Technical Basis ..................... 124
7. Do you agree with implementation period of the proposed standard
based on the considerations listed in the Implementation Plan? If
not, please provide a justification for changing the proposed
implementation period ................................................................................. 137
8. If you are aware of any conflicts between the proposed standard and
any regulatory function, rule, order, tariff, rate schedule, legislative
requirement, or agreement please identify the conflict here ....................... 150
9. If you are aware of the need for a regional variance or business
practice that should be considered with this phase of the project,
please identify it here: ................................................................................. 154
10. If you have any other comments on this Standard that you haven’t
already mentioned above, please provide them here ................................... 157
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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
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
2
3
4
5
6
7
8
9
10
X
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC NPCC
10
2.
David Burke
Orange and Rockland Utilities Inc.
NPCC
3
3.
Greg Campoli
New York Independent System Operator NPCC
2
4.
Sylvain Clermont
Hydro-Québec TransÉnergie
NPCC
1
5.
Wayne Sipperly
New York Power Authority
NPCC
5
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC
5
8.
Matt Goldberg
ISO - New England
NPCC
2
9.
Michael Jones
National Grid
NPCC
1
10. Mark Kenny
Northeast Utilities
NPCC
1
11. Christina Koncz
PSEG Power LLC
NPCC
5
Consideration of Comments: Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: June XX, 2014
9 of 198
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
12. Helen Lainis
Independent Electricity System Operator NPCC
2
3
4
5
6
7
8
9
10
2
13. Alan MacNaughton New Brunswick Power Corporation
NPCC
9
14. Bruce Metruck
New York Power Authority
NPCC
6
15. Ben Wu
Orange and Rockland Utilities Inc.
NPCC
1
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
17. Robert Pellegrini
The United Illuminating Company
NPCC
1
18. Si Truc Phan
Hydro-Québec TransÉnergie
NPCC
1
19. David Ramkalawan Ontario Power Generation, Inc.
NPCC
5
20. Brian Robinson
Utility Services
NPCC
8
21. Ayesha Sabouba
Hydro One Networks Inc.
NPCC
1
22. Brian Shanahan
National Grid
NPCC
1
2.
Group
Sandra Shaffer
PacifiCorp
Group
Joe DePoorter
MRO NERC Standards Review Forum
X
N/A
3.
Additional Member
Additional Organization
X
X
X
X
X
X
Region Segment Selection
1.
Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
2.
Chuck Wicklund
Otter Tail Power
3.
Dan Inman
Minnkota Power Cooperative
MRO
1, 3, 5, 6
4.
Dave Rudolph
Basin Electric Power Cooperative MRO
1, 3, 5, 6
5.
Kayleigh Wilkerson Lincoln Electric System
MRO
1, 3, 5, 6
6.
Jodi Jensen
WAPA
MRO
1, 6
7.
Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
8.
Ken Goldsmith
Alliant Energy
MRO
4
9.
Mahmood Safi
Omaha Public Power District
MRO
1, 3, 5, 6
10. Marie Knox
MISO
MRO
2
11. Mike Brytrowski
Great River Energy
MRO
1, 3, 5, 6
12. Randi Nyholm
Minnesota Power
MRO
1, 6
13. Scott Nickels
Rochester Public Utilities
MRO
4
14. Terry Harbour
MidAmerican
MRO
1, 3, 5, 6
1, 3, 5
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Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
15. Tom Breene
Wisconsin Public Service
MRO
3, 4, 5, 6
16. Tony Eddleman
Nebraska Public Power District
MRO
1, 3, 5
4.
Paul Haase
Group
Seattle City Light
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Pawel Krupa
Seattle City Light
WECC 1
2. Dana Wheelock
Seattle City light
WECC 3
3. Hao Li
Seattle City Light
WECC 4
4. Mike Haynes
Seattle City Light
WECC 5
5. Dennis Sismaet
Seattle City Light
WECC 6
5.
Group
Joe Tarantino
SMUD/BANC
Additional Member Additional Organization Region Segment Selection
1. Kevin Smith
6.
BANC
Group
WECC 1
Dennis Chastain
Tennessee Valley Authority
Additional Member Additional Organization Region Segment Selection
1. DeWayne Scott
SERC
1
2. Ian Grant
SERC
3
3. David Thompson
SERC
5
4. Marjorie Parsons
SERC
6
7.
Group
Additional Member
Robert Rhodes
Additional Organization
SPP Standards Review Group
X
Region Segment Selection
1.
Bud Averill
Grand River Dam Authority
SPP
1
2.
Mo Awad
Westar Energy
SPP
1, 3, 5, 6
3.
Derek Brown
Westar Energy
SPP
1, 3, 5, 6
4.
Karl Diekevers
Nebraska Public Power District MRO
1, 3, 5
5.
Don Hargrove
Oklahoma Gas & Electric
SPP
1, 3, 5
6.
Jonathan Hayes
Southwest Power Pool
SPP
2
7.
Brian Holmes
Nebraska Public Power District MRO
8.
Stephanie Johnson Westar Energy
SPP
1, 3, 5
1, 3, 5, 6
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Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9.
Westar Energy
SPP
1, 3, 5, 6
10. Mike Kidwell
Bo Jones
Empire District Electric
SPP
1, 3, 5
11. Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
12. James Nail
City of Independence, MO
SPP
3
Wayne Johnson
Southern Company: Southern Company
Services, Inc.; Alabama Power Company;
Georgia Power Company; Gulf Power
Company; Mississippi Power Company;
Southern Company Generation; Southern
Company Generation and Energy Marketing
Greg Campoli
ISO RTO Council Standards Review
Committee
8.
Group
2
X
3
4
5
6
X
X
X
X
X
X
7
8
9
10
N/A
9.
Group
X
Additional Member Additional Organization Region Segment Selection
1. Stephanie Monzon
PJM
RFC
2
2. Charles Yeung
SPP
SPP
2
3. Lori Spence
MISO
MRO
2
4. Cheryl Moseley
ERCOT
ERCOT 2
5. Matt Goldberg
ISONE
NPCC
2
6. Ben Li
IESO
NPCC
2
7. Ali Miremadi
CAISO
WECC 2
10.
Group
Mike Garton
Dominion
X
Additional Member Additional Organization Region Segment Selection
1. Louis Slade
Dominion
RFC
2. Randi Heise
Dominion
NPCC 6
5, 6
3. Connie Lowe
Dominion
SERC
5, 6
4. Larry Nash
Dominion
SERC
1, 3
5. Chip Humphrey
Dominion
SERC
5
6. Jeffrey Bailey
Dominion
NPCC 5
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
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Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11.
Group
Jason Marshall
Additional Member
4
5
ERCOT 1, 5
2. Mark Ringhausen
Old Dominion Electric Cooperative
RFC
3. Scott Brame
North Carolina Electric Membership Corporation SERC
1, 3, 4, 5
4. Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
5. Brian Hobbs
Western Farmers Electric Cooperative
SPP
1, 5
6. Bill Hutchison
Southern Illinois Power Cooperative
SERC
1
7. Bernard Johnson
Oglethorpe Power Cooperative
SERC
5
Richard Hoag
6
7
8
9
10
X
Region Segment Selection
Brazos Electric Power Cooperative
Group
3
ACES Standards Collaborators
Additional Organization
1. Shari Heino
12.
2
3, 4
FirstEnergy Corp.
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. William Smith
FirstEnergy Corp
RFC
1
2. Cindy Stewart
FirstEnergy Corp
RFC
3
3. Doug Hohlbaugh
Ohio Edison
RFC
4
4. Ken Dresner
FirstEnergy Solutions
RFC
5
5. Kevin Querry
FirstEnergy Solutions
RFC
6
6. Richard Hoag
FirstEnergy Corp
RFC
NA
7. Brian Orians
FirstEnergy Solutions
RFC
NA
8. Rusty Loy
FirstEnergy Solutions
RFC
NA
9. Dave Barber
FirstEnergy Corp
RFC
NA
13.
Group
Mike O'Neil
Florida Power & Light
X
Group
Brent Ingebrigtson
PPL NERC Registered Affiliates
X
N/A
14.
Additional Member
Additional Organization
1.
Charlie Freibert
LG&E and KU Energy, LLC
2.
Brenda Truhe
PPL Electric Utilities Corporation RFC
1
3.
Annette Bannon
PPL Generation, LLC
RFC
5
PPL Susquehanna, LLC
RFC
5
4.
X
Region Segment Selection
SERC
3
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
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Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5.
PPL Montana, LLC
WECC 5
PPL EnergyPlus, LLC
MRO
6
7.
NPCC
6
8.
RFC
6
9.
SERC
6
10.
SPP
6
11.
WECC 6
6.
Elizabeth Davis
15.
Group
Michael Lowman
Duke Energy
X
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
RFC
1
2. Lee Schuster
FRCC
3
3. Dale Goodwine
SERC
5
4. Greg Cecil
RFC
6
16.
Group
Patricia Robertson
Additional Member
BC Hydro
Additional Organization Region Segment Selection
1. Venkataramakrishnan Vinnakota BC Hydro
WECC 2
2. Pat G. Harrington
BC Hydro
WECC 3
3. Clement Ma
BC Hydro
WECC 5
17.
Group
X
Tom McElhinney
JEA
Additional Member Additional Organization Region Segment Selection
1. Ted Hobson
FRCC
1
2. Garry Baker
FRCC
3
3. John Babik
FRCC
5
18.
Group
Frank Gaffney
Florida Municipal Power Agency
X
Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimee Utility Authority
FRCC
3
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
14 of 198
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Lynne Mila
City of Clewiston
FRCC
3
5. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
6. Randy Hahn
Ocala Utility Services
FRCC
3
7. Stanley Rzad
Keys Energy Services
FRCC
1
8. Don Cuevas
Beaches Energy Services
FRCC
1
9. Mark Schultz
City of Green Cove Springs FRCC
3
19.
Group
Additional Member
Kathleen Black
4
X
5
6
7
8
9
10
X
Region Segment Selection
1. Kent Kujala
NERC Compliance
RFC
3
2. Daniel Herring
NERC Training & Standards Development RFC
4
3. Mark Stefaniac
Regulated Marketing
5
4. David Szulczewski
DO SEE Relay Engineering
20.
3
X
DTE Electric
Additional Organization
2
RFC
Group
Kaleb Brimhall
Colorado Springs Utilities
X
Group
Eleanor Ewry
Puget Sound Energy
X
X
X
X
N/A
21.
X
Additional Member Additional Organization Region Segment Selection
1. Denise Lietz
Puget Sound Energy
WECC 1
2. Lynda Kupfer
Puget Sound Energy
WECC 5
3. Mariah Kennedy
Puget Sound Energy
WECC 3
22.
Group
Andrea Jessup
Bonneville Power Administration
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Jim Burns
Technical Operations
WECC 1
2. Jim Gronquist
Transmission Planning
WECC 1
23.
Group
Janet Smith
Arizona Public Service Co.
X
Group
Erika Doot
Bureau of Reclamation
X
N/A
24.
X
Additional Member Additional Organization Region Segment Selection
1. Rick Jackson
WECC 1
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
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Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
5
Steve Wickel
CHPD - Public Utility District No. 1 of Chelan
County
26.
Individual
Rick Terrill
Luminant Generation Company LLC
X
27.
Individual
Michelle R. D'Antuono
Ingleside Cogeneration LP
X
28.
Individual
Venona Greaff
Occidental Chemical Corporation
29.
Individual
John Seelke
Public Service Enterprise Group
X
30.
Individual
Jared Shakespeare
Peak Reliability
X
31.
Individual
Daniel Duff
Individual
Mauricio Guardado
Liberty Electric Power
Los Angeles Department of Water and
Power
33.
Individual
Brenda Hampton
Luminant Energy Company, LLC
34.
Individual
Ayesha Sabouba
Hydro One
Individual
36. Individual
Frederikc R Plett
Rob Robertson
Masschusetts Attorney General
First Wind
37.
Individual
Ronnie C. Hoeinghaus
City of Garland
38.
Individual
Terry Harbour
39.
Individual
40.
32.
35.
X
4
Individual
25.
X
3
6
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
MidAmerican Energy Company
X
X
Kayleigh Wilkerson
Lincoln Electric System
X
X
X
X
Individual
Thomas Foltz
American Electric Power
X
X
X
X
41.
Individual
Chris de Graffenried
Consolidated Edison, Inc.
X
X
X
X
42.
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
43.
Individual
Amy Casuscelli
Xcel Energy
X
X
X
X
44.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
X
45.
Individual
Jo-Anne Ross
Manitoba Hydro
X
X
X
X
46.
Individual
Mark Wilson
Independent Electricity System Operator
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
7
X
X
16 of 198
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
Individual
David Kiguel
David Kiguel
48.
Individual
Richard Vine
California ISO
49.
Individual
Chris Mattson
Tacoma Power
X
X
50.
Individual
David Jendras
Ameren
X
X
51.
Individual
Scott Langston
City of Tallahassee
X
52.
Individual
Bob Thomas
Illinois Municipal Electric Agency
53.
Individual
Bill Fowler
City of Tallahassee
54.
Individual
John Pearson
ISO New England
55.
Individual
Chris Scanlon
Exelon
X
X
56.
Individual
Shivaz Chopra
New York Power Authority
X
X
Individual
58. Individual
Roger Dufresne
Gul Khan
Hydro-Québec Production
Oncor Electric Delivery LLC
X
59.
Individual
Glenn Pressler
CPS Energy
X
60.
Individual
Karin Schweitzer
Texas Reliability Entity
61.
Individual
Michael Moltane
ITC
X
62.
Individual
Thomas Standifur
Austin Energy
X
63.
Individual
Bill Temple
Northeast Utilities
X
64.
Individual
Jonathan Meyer
Idaho Power Co.
X
65.
Individual
Patrick Farrell
X
Individual
Russell Noble
Southern California Edison Company
Public Utility District No. 1 of Cowlitz
County, WA
67.
Individual
Melissa Kurtz
US Army Corps of Engineers
68.
Individual
Anthony Jablonski
ReliabiltiyFirst
69.
Individual
Joshua Andersen
Salt River Project
66.
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
5
6
7
8
9
10
X
47.
57.
4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
17 of 198
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
70.
Individual
Kenneth A Goldsmith
Alliant Energy
71.
Individual
David Dockery
Associated Electric Cooperative, Inc.
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
2
3
4
5
6
7
8
9
10
X
X
X
X
18 of 198
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select "agree"
below and enter the entity's name in the comment section (please provide the name of the organization, trade association, group, or
committee, rather than the name of the individual submitter).
Summary Consideration: The drafting team appreciates the entities below supporting the comments of others. Having single sets of comments
with documented support greatly improves the efficiency of the standard drafting team (SDT). This format also ensures the drafting team has a
clearer picture of the number of stakeholders supporting the same concerns or suggestions as the case may be.
Organization
Agree
Supporting Comments of “Entity Name”
Ameren
Agree
Public Service Enterprise Group (PSEG)
City of Garland
Agree
Public Service Enterprise Group - comments submitted by John Seelke
City of Tallahassee
Agree
FMPA
City of Tallahassee
Agree
FMPA
Colorado Springs Utilities
Agree
Public Service Enterprise Group and Florida Municipal Power Agency
CPS Energy
Agree
FMPA and PSEG
First Wind
Agree
PSEG Fossil, T.J. Kucey
Hydro One
Agree
NPCC-RSC
Hydro-Québec Production
Agree
NPCC and Hydro-Québec TransÉnergie
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
19 of 198
Organization
Agree
Illinois Municipal Electric Agency
Agree
Florida Municipal Power Agency, and Public Service Enterprise Group
JEA
Agree
FMPA
Luminant Energy Company, LLC
Agree
Luminant Generation Company, LLC (Rick Terrill)
New York Power Authority
Occidental Chemical Corporation
Supporting Comments of “Entity Name”
NPCC RSC Committee
Agree
Ingleside Cogeneration, LP
Seattle City Light
Sacramento Municipal Utility District (SMUD)
Tacoma Power
PSEG
US Army Corps of Engineers
Agree
MRO NSRF
Xcel Energy
Agree
Public Service Enterprise Group (PSEG)
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
20 of 198
1. Do you agree with the focused approach using the criteria (see R1 & R2) which came from recommendations in the PSRPS technical
document (pg. 21 of 61)? If not, please explain why or why not (e.g., the approach should be more narrow or more broad, and if so, the basis
for a different approach).
Summary Consideration: More than half of the 177 commenter disagreed with various aspects of the approach to the standard. The following lists
the chief concerns that resulted in changes to the standard and those that did not.
Comments that resulted in a change to the standard:
There were 17 comments from 58 individuals that were concerned about the initial burden of evaluating load-responsive protective relays. To
address this, the drafting team increased the Implementation Plan to 36 calendar months for Requirement R4 to provide for the initial influx of
identified Elements under Requirement R1. The evaluation of relays under Requirement R4 (previously R3) is to be performed “within 12 full
calendar months of receiving notification of an Element … where the evaluation has not been performed in the last three calendar years.” The
Implementation Plan provides an initial 36 calendar months from approval. Ten comments from 39 stakeholders were concerned about how the
term “credible” would be interpreted. The term “credible” was removed from the standard. Requirement R1, Criterion 3 was clarified by framing
the criterion in the present tense to refer to current assessment(s). The term “credible” was also removed from the previous Requirement R2 (and
new R3) because the required performance should only refer to only current actual events.
Four significant issues were raised in Requirement R1 and its Criterion. First, there were five comments from 36 individuals that requested clarity as
to what “stability constraint” meant. To clarify this issue the term “angular” was added to “stability constraint” to clarify the intent in Requirement
R1, both Criterion 1 and 2. Second, there were five comments from 38 stakeholders questioning if “power swings” meant both “stable” and
“unstable” power swings. Requirement R1 – Criterion 4, Requirement R2 – Criterion 1, and the new Requirement R3 – Criterion 1, were clarified by
adding both “stable and unstable” to the power swings language. Both stable and unstable power swings determine whether an Element will be
identified as being affected by a power swing. Four comments supported by 13 individuals believed the term “associated” was not clear; therefore,
the term “associated” was removed and the criteria was clarified that the Element is the “monitored” Element. Last, there were three comments
from 11 stakeholders that were concerned about how to apply Requirement R1, Criterion 3. Because of this, Requirement R1, Criterion 3 was
revised include island boundaries due to angular instability within an underfrequency load shedding (UFLS) assessment. Additionally, the Generator
Owner function was moved from Requirement R2 to the new Requirement R3 in order to remove the “islanding” criteria for Generator Owners.
Comments that did not result in a change to the standard:
There were 21 comments from 58 stakeholders for varying reasons that a standard was not necessary with the primary reason being based on the
conclusions of the technical report by the NERC System Protection and Control Subcommittee called Protection System Response to Power Swings,
August 2013 (PSRPS Report). To address this concern and the need for a standard, the drafting team prepared information found at the beginning
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
21 of 198
of this document called, “NERC Discussion on Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The
drafting team understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that the Commission still
desired NERC to pursue its work to meet the directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally
received positive feedback on the narrow approach to address the regulatory directive. The directive itself was challenged by commenters prior to
the issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No. 733-B proceedings.
Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were advanced in these FERC proceedings.
Five comments by 34 individuals questioned the use of a System Operating Limit (SOL) in Requirement R1, Criterion 2 to determine Elements that
needed evaluation because they were not necessarily associated with wide-area problems. The drafting team contends that not only SOLs that
have been shown to expose a widespread area to instability, uncontrolled separation(s) or cascading outages should be considered. Identified
localized instability issues also point to Elements that should reduce the likelihood of tripping for stable power swings. There were four comments
by 18 individual that believe the standard required the inclusion of protective relay models. The standard does not require the inclusion of relay
models. Requirement R1 – Criterion 4 is not requiring a study, but the identification of any Element that was observed as tripping in the most
recent Planning Assessment.
Organization
Northeast Power
Coordinating Council
Yes or No
Question 1 Comment
No
We agree with a focused approach as outlined in the technical document. However, we have the following
serious concerns with criteria in the requirements:
1. The term “credible event” should be clearly defined. The basis to determine a credible event is missing
from the requirement and application guide. This basis should be provided in the standard requirement.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to current
assessment(s). The term “credible” was removed from the previous Requirement R2 (and new R3)
because the required performance refers to only current actual events. Change made.
2. Why is the standard focused on SOL rather than IROL? The basis for specifying SOL is not supported by
the example in the application guideline since the example did not show inter-area impact.
Response: Several commenters questioned the use of a System Operating Limit (SOL) to determine
Elements that needed evaluation because they were not necessarily associated with wide-area problems.
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
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Organization
Yes or No
Question 1 Comment
The drafting team contends that not only SOLs that have been shown to expose a widespread area to
instability, uncontrolled separation(s) or cascading outages should be considered. Identified localized
instability issues also point to Elements that should reduce the likelihood of tripping for stable power
swings. No change made.
3. It is not clear in R1, criteria number 4 whether the assessment should include relay tripping or just
stable power swing or both stable and unstable power swing.
Response: Requirement R1 – Criterion 4, Requirement R2 – Criterion 1, and the new Requirement R3 –
Criterion 1, were clarified by adding both “stable and unstable” power swings. Both stable and unstable
power swings determine whether an Element will be identified as experiencing a power swing. Change
made.
4. In R2, it is unrealistic to require an entity to provide data on an Element that had tripped since 2003.
There is no existing NERC continent-wide disturbance monitoring or misoperation standard that requires
data be retained more than 12 months. We recommend that this requirement be removed from the
standard or include only Elements that were tripped in the last calendar year.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
It must be noted that the standard is unsupported by the Protection System Response to Power Swings,
System Protection and Control Subcommittee, August, 2013 document. Referring to p. 20, the “Need for a
Standard” section, states “Based on its review of historical events, consideration of the trade-offs
between dependability and security, and recognizing the indirect benefits of implementing the
transmission relay loadability standard (PRC-023), the SPCS concludes that a NERC Reliability Standard to
address relay performance during stable swings is not needed, and could result in unintended adverse
impacts to Bulk-Power System reliability.” (Emphasis added).
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
23 of 198
Organization
Yes or No
Question 1 Comment
The following report references support the PSRPS document’s conclusion that this standard is not
needed:
1) Page 8 of 61, 1965 Northeast Blackout Conclusion, first sentence “Relays tripping due ...”
2) Page 8 of 61, 1977 New York Blackout Conclusions, first sentence, “Relays tripping due...”
3) Page 9 of 61, July 2-3, 1996: West Coast Blackout Conclusions, first sentence “Relays tripping
due...”
4) Page 10 of 61, August 10, 1996 Conclusions, first sentence, “Relays tripping due...”
5) Page 16 of 61, 2003 Northeast Blackout Conclusion, “Relays tripping due...”
6) Page 17 of 61, Overall Observations from Review of Historical Events, first and second sentences,
“Relays tripping...”
7) Page 19 of 61, final paragraph, “Given the ....”NERC’s informational filing in Docket No. RM08-13000 dated July 21, 2011 concluded that there is a need for a standard on stable power swings. The
subsequently developed PSRPS document, which was developed by industry experts and approved
by the NERC Planning Committee, clearly refutes the FERC directive in Order No. 773 (Docket No.
RM08-13-000), that was subsequently affirmed in Order Nos. 773-A and 773-B, that a standard is
needed to ensure that load-responsive protective relays do not trip in response to stable power
swings during non-Fault conditions.
We recommend that the NERC Standards Committee explore means to utilize the more recent PSRPS
document to obtain relief from the aforementioned FERC directive that is driving this project.
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
24 of 198
Organization
Yes or No
Question 1 Comment
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
SMUD/BANC
No
(1) Collected data and subsequent analysis has not identified tripping during stable power swings. This
phenomenon is rare if at all. Any tripping during stable power swings would more appropriately included
as a mis-operation and addressed as such.
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
(2) The requirement R2 is particularly unacceptable as it requires data for pre June 18, 2007; effective
date of Order 693 standards.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
ISO RTO Council
Standards Review
Committee
No
Conditions (2) and (3) are unclear.
Condition (2) stipulates that the responsible entity notify the facility owner of an Element that is
associated with a System Operating Limit (SOL) that has been established based on stability constraints.
It’s not clear whether the Element is the contingent Element or the monitored Element or both. This
needs to be clarified/specified in the standard/requirement.
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
25 of 198
Organization
Yes or No
Question 1 Comment
Response: For Requirement R1, Criterion 2, the drafting team removed the term “associated” and revised
the criteria to clarify that the Element is the “monitored” Element. Change made.
Condition (3) stipulates that the responsible entity notify the facility owner of an Element that has formed
the boundary of an island within an angular stability planning simulation where the system Disturbance(s)
that caused the islanding condition continues to be a credible event. The term “credible event” is hard to
determine since the Disturbance could be caused by one of those events listed in the TPL standards, or
could be one that is beyond those listed, such as natural phenomena. We realize that the Application
Guideline provides some general guidance on assessing the credibility of a Disturbance, but we do not
agree that a Disturbance is no longer credible when it is deemed no longer capable of occurring in the
future due to actual changes to the BES. Changes to the BES may reduce the possibility of the same
Disturbance, but such Disturbances (e.g. loss of right of way or an entire station) may still occur due to
other means. If the SDT should continue to hold the position that the criteria for excluding a Disturbance
is that BES changes are made to mitigate (but not totally eliminate) the recurrence, then it should be
clearly stated in the requirement itself.
In short, the basis with which to deem a Disturbance “credible” is missing from the requirements, which
needs to be provided/clarified in the standard/requirement.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to current
assessment(s). The term “credible” was removed from the previous Requirement R2 (and new R3)
because the required performance refers to only current actual events. Change made.
ACES Standards
Collaborators
No
(1) This requirement needs to be further clarified that it is not intended to require additional studies.
Rather, the TP, PC and RC are to identify the information in bullets 1 through 4 based on their existing
knowledge and studies.
Response: Requirement R1 sufficiently conveys that no new or additional studies are required. Additional
clarification has been added to the Guidelines and Technical Basis. Change made.
Consideration of Comments (To Draft 1: PRC-026-1)
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
26 of 198
Organization
Yes or No
Question 1 Comment
(2) Part 2 needs further clarification regarding which SOLs should be applied. Are the SOLs established
from the planning horizon per FAC-010-2.1 or the SOLs established in the operating horizon per FAC-011-2
applicable? We recommend that only SOLs from the operating horizon should be applied because the
SOLs from the planning horizon may include the impact of proposed or retired facilities which could result
in unnecessary relay modifications or miss necessary relay modifications.
Response: Requirement R1, Criterion 1 and 2 address operating limits associated with angular stability
limits; therefore, System Operating Limits (SOL) specified in Requirement R1, Criterion 2 includes both
operations and planning horizons. In the event that a Corrective Action Plan (CAP) is necessary based on
future system conditions, the CAP can specify a timeframe that does not enact changes until those system
conditions require modification. An example has been added to clarify this scenario in the Guidelines and
Technical Basis. Change made.
(3) Requirement R1 as a whole is problematic because it is based partly on planning studies. Planning
studies include proposed system additions and retirements which could result in the identification of
unnecessary relay modifications or a failure to identify necessary relay modifications.
Response: In the event that a Corrective Action Plan (CAP) is necessary based on future system conditions,
the CAP can specify a timeframe that does not enact changes until the actual system modifications have
occurred. No change made.
(4) R1 should be split based on responsibilities. Some of the bullets should apply to only one entity. For
example, an RC is required to monitor the status of Special Protection Systems per IRO-005-3.1a R1.1. The
RC would also have to be aware of generating plant stability constraints. Thus, the RC could provide all of
the information for bullet 1. Bullets 3 and 4 are based on planning studies and should only apply to the
Planning Coordinator. If only SOLs from the operating horizon are to be evaluated, then bullet 2 should
only apply to the RC.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
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access to the knowledge including the wide-area view. Change made to the Requirement.
(5) Part 2 should be modified to limit application to IROLs and not all stability related SOLs. By definition, if
an SOL is stability related and is not an IROL, it cannot have a wide area impact on reliability and is limited
to local reliability. If it had a wide area impact, it would cause “instability, uncontrolled separation or
Cascading outages that adversely impact the reliability of the Bulk Electric System” and would be an IROL.
Response: Several commenters questioned the use of a System Operating Limit (SOL) to determine
Elements that needed evaluation because they were not necessarily associated with wide-area problems.
The drafting team contends that not only SOLs that have been shown to expose a widespread area to
instability, uncontrolled separation(s) or cascading outages should be considered. Identified localized
instability issues also point to Elements that should reduce the likelihood of tripping for stable power
swings. No change made.
(6) Part 4 is problematic because it now requires relay tripping to be evaluated in transient studies
performed by the Planning Coordinator and Transmission Planner. These entities may not include all
relays in their studies but this part creates a de facto requirement for them to include all relays.
Otherwise, how can a PC or TP determine if relay tripping would occur?
Response: The drafting team asserts that the standard does not require the inclusion of relay models.
Requirement R1 – Criterion 4 is not requiring a study, but the identification of any Element that was
observed as tripping in the most recent Planning Assessment. No change made.
(7) The language of the requirement needs to be clarified that the TP, PC and RC are to only identify
elements in their area. This could be accomplished by adding “in its area” after “each Element.”
Response: The drafting team clarified that the responsible entity is to identify Elements in its area. Change
made.
(8) The format of the sub-part numbering does not follow the convention that NERC established several
years ago and notified the Commission that it would use for sub-parts. When all sub-parts are required
then they are to be numbered. When only one sub-part is requirement (i.e. one of the list has to be
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selected), they are to be bulleted. The draft appears to stray because of the language “one or more” in the
main requirement. In other words, one item could be met or more than one. However, we argue that
bullets should be used because while more than one could apply, if one applies the Element is to be
identified by the PC, TP, or RC. There is no additional need for any tests once one is met. Thus each
Element will only be identified as meeting one of the bullets because that means it qualifies even though
it could meet more than one.
Response: The NERC convention for use of bullets and numbering is for identifying which items are
“options” and which items are “all-inclusive:” however, in the use of criteria a numbered list (i.e., not
using sub-part conventions) is acceptable. No change was made based on the comment.
(9) Why can’t the islanding evaluation conducted per PRC-006-1 R1 be used as the basis for identifying
Elements rather than writing a new bullet 3 in the requirement?
Response: The drafting team modified Requirement R1, Criterion 3 to include island boundaries due to
angular instability within an underfrequency load shedding (UFLS) assessment. Also, the Generator Owner
was moved from Requirement R2 to the new Requirement R3 in order to remove the “islanding” criteria
for Generator Owners. Change made.
FirstEnergy Corp.
No
FirstEnergy agrees with the focus approach using the criteria but has the following concern. It is
understood that the “... since January 1, 2003” verbiage is intended to capture applicable relay operations
during the Aug. 14, 2003 event. It will be difficult if not nearly impossible for a GO, especially in a
deregulated environment, to piece together details of relay operations prior to record-keeping
requirements for NERC PRC-004. We recommend that these Criteria be reworded to include only incidents
which have occurred since the inception of NERC PRC-004.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Duke Energy
No
(1) Based on the SPCS report stated below (dated August 2013), Duke Energy does not believe that
adequate technical justification has been identified for this project to become a standard. The SDT and
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NERC should consider moving this project to a Guideline document until such time as a standard is
warranted.
“Based on its review of historical events, consideration of the trade-offs between dependability and
security, and recognizing the indirect benefits of implementing the transmission relay loadability
standard (PRC-023), the SPCS concludes that a NERC Reliability Standard to address relay
performance during stable power swings is not needed, and could result in unintended adverse
impacts to Bulk-Power System reliability.”
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
(2) Duke Energy does not agree with the criteria specified in R1 because sufficient tools have not been
developed at this time for the industry to conduct the appropriate assessment and identification of the
Elements in Criteria 4. However, if this project moves forward as a standard we suggest the following
revision to Criteria 4:
“4. An Element identified in the most recent Planning Assessment where relay tripping occurred as a
result of a power swing during the simulated Disturbance. Generic modeling of relays is acceptable
when conducting this initial Planning Assessment.”
This would provide the necessary flexibility until such a time as tools are developed to conduct a more
accurate Planning Assessment and identification of Elements for Criteria 4.
Response: The drafting team asserts that the standard does not require the inclusion of relay models.
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Requirement R1 – Criterion 4 is not requiring a study, but the identification of any Element that was
observed as tripping in the most recent Planning Assessment. No change made.
BC Hydro
No
Any approach should be based on experience with improper operation during stable power swings. If
there has been no experience of undesired operation during stable power swings then checking against
the criteria just results in fruitless work.
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
The drafting team asserts that the standard is proactively addressing the risk of load-responsive protective
relays applied on Elements that are expected to have the greatest risk of exposure to power swings. The
standard is based on guidance from the PSRPS Report and includes Elements that trip during future
events. No change made.
Florida Municipal
Power Agency
No
As recognized by the SCPS, the standard is not needed and will result in a reduction of reliability to the
bulk-power system (see report of footnote 1, Chapter 3, section titled “Need for a Standard”). FMPA
strongly agrees with the SCPS that it is better for bulk-power system reliability to bias the “Art of
Protection” to enable the power system to separate for unstable power swings than to bias the art of
protection to prevent operation for stable power swings since it is very difficult, if not impossible, to
distinguish stable from unstable power swings. We ought to enable the power system to gracefully
degrade for unstable events rather than cause entire Interconnections to become unstable. We cannot
with accuracy pre-determine where the separation points are or ought to be since we cannot know in
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advance where or what the cause of instability may occur. As such, having relays throughout the system
that can cause separation as needed to prevent the entire Interconnection from going unstable is
recommended.
As such, and recognizing that we are directed to have a standard, the standard should not require PCs, RCs
and TPs to identify that for every Element that meets the criteria of R1, something needs to be done
(which is implied in R3). Rather, the PC, RC and TP ought to have discretion as to whether they want a
potential issue resolved or not within R1. That is, the PC, RC and TP should have discretion as to whether
to bias the performance towards separation for unstable power swings (graceful degradation for
instability, but possibly contribute to cascading for stable power swings - although there is no evidence of
the latter from past events), or bias the performance to prevent operation for stable power swings (which
would have a tendency to cause blackouts to be greater in magnitude, but possibly reduce the risk of
cascading for stable power swings, although there is no evidence of the latter), noting that there is no
dependable way to distinguish between stable and unstable power swings. As such, the PC, RC and TP
ought to be able to identify a subset of Elements that meet the criteria of R1 that would then be analyzed
in R2 and R3.
Response: The drafting team asserts that it has implemented an approach consistent with the
recommendations of the NERC System Protection and Control Subcommittee (SPCS) technical report,
Protection System Response to Power Swings, August 20135 (PSRPS Report). The standard does not
preclude the Planning Coordinator providing information to the Generator Owner or Transmission Owner
about the Element and any known stability issues, power swings, or apparent impedance characteristics;
however, the Elements need to be reported as a part of ensuring the Generator Owner and Transmission
Owner are aware of Elements that are susceptible. Modifications were made to have only the Planning
Coordinator identify Elements and in Requirement R5 to have the Generator Owner and Transmission
Owner develop a Corrective Action Plan to meet the criteria PRC-026-1 – Attachment B while maintaining
5
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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dependable fault detection and dependable out-of-step tripping. The drafting team asserts protective
relays that meet the PRC-026-1 – Attachment B criteria are expected to not trip during stable power
swings. Change made.
Note also that “Element” is the wrong term and “Facility” should be used. “Element” applies to both BES
and non-BES (including distribution), Facilities is BES. Standards cannot be written to distribution.
Response: Section 4.2, Facilities provides sufficient language that the standard is applicable to only “BES
Elements.” No change made to the standard based upon the comment.
Puget Sound Energy
No
For systems that have not experienced a power swing that caused a trip or islanding condition, there is
the burden of proving the negative to demonstrate compliance with the standard. It is recommended that
Requirement R2 be rewritten in such a way that entities will not have to prove the negative.
Response: The drafting team contends it is up to the entity to certify that no trips occurred due to stable
or unstable power swings during audit period. The intent is not for an entity to prove the negative, but for
an entity to certify that no Elements met the criteria in Requirement R2.No Change made.
It is also recommended that the standard be revised to address the situation where historical data is not
avaialable as far back as 2003. We also request that a NERC definition be provided for what constitutes a
stable power swing and what criteria can be applied to historical data to determine if a stable power
swing has occurred.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Bonneville Power
Administration
No
BPA agrees with the approach, with two exceptions.
First, BPA feels more clarity is needed regarding which Elements are associated with System Operating
Limits (SOLs), relevant to the Standard. Stability constraints can depend on the overall topology of the
system, in which case nearly every Element in the power system would meet the criteria of item 2. For
example, BPA may determine a stability constraint on WECC Path 66 due to poorly damped oscillations.
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Taking almost any 500 kV or 345 kV line out of service on the western side of WECC could change the
value of this limit, in which case all of these Elements meet the criteria of item 2. BPA suggests the
language be changed to:
2. An Element that has been shown to have a substantial effect on a System Operating Limit (SOL)
that has been established based on stability constraints identified in system planning or operating
studies (including line-out conditions.)
Response: For Requirement R1, Criterion 2, the drafting team removed the term “associated” and revised
the criteria to clarify that the Element is the “monitored” Element. Change made.
Secondly, BPA feels the Glossary definition of Disturbance lacks sufficient clarity as it relates to this and
other existing Standards.
Response: The drafting team revised Requirement R1, Criterion 4 by changing “Disturbance” to
“simulated disturbance” to comport with the approved Reliability Standard TPL-001-4. The use of
“Disturbance” in Requirements R2 (TO) and R3 (GO) relates to an actual system disturbance. Change
made.
Luminant
Generation
Company LLC
No
The focused approach is too narrow for Generation Owners in that it restricts to the Transmission Planner
and Generation Owner to events that have occurred and not a Planning Assessment transient stability
study results that indicate load responsive relay operation is challenged. Item #4 in Requirement R1 may
not capture all power system swings since it is focused on previous events. Luminant recommends that
the Transmission Planner be responsible for transient stability studies and reporting the information to
the Generation Owner for locations where load responsive relays are challenged.
Response: The drafting team revised Requirement R1, Criterion 4 by changing “Disturbance” to
“simulated disturbance” to comport with the approved Reliability Standard TPL-001-4. The use of
“Disturbance” in Requirements R2 (TO) and R3 (GO) relates to an actual system disturbance. The
Reliability Coordinator and Transmission Planner have been removed from the standard’s Applicability;
therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single entity source of
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identifying Elements. The drafting team asserts that the Planning Coordinator has or has access to the
knowledge including the wide-area view. Change made to the Requirement.
The date of 2003 needs to be removed from the standard as it prefaces compliance on data that predates
the approval of the standard.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Also, the Generation Owner and Transmission Owner (in cases where the Transmission Planner and
Transmission Owner are not the same entity) do not have the tools to determine if the BES is configured
such that a Disturbance event is still credible.
Luminant believes that R2 criteria 1 and 2 need to be modified as follows:
“1. An Element that load responsive relaying has tripped during the past calendar year due to a
power swing during an actual system Disturbance. “
“2. An Element that has formed the boundary of an island during the past calendar year during an
actual system Disturbance.”
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to current
assessment(s). The term “credible” was removed from the previous Requirement R2 (and new R3)
because the required performance refers to only current actual events. Change made.
Ingleside
Cogeneration LP
No
Ingleside Cogeneration LP (“ICLP”) believes that the drafting team has generally captured the intent of
FERC Order 733 by specifying the planning and operations criteria used to identify susceptible Elements.
Clearly those load responsive relays that protect Elements that have a stability constraint or are tripped in
response to a stable power swing should be in scope.
However, we do not agree that those Elements that form the boundary of an island during planning
assessments or as a result of an actual Disturbance should be subject to PRC-026-1.
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Response: The drafting team removed the islanding requirement from the responsibility of the Generator
Owner (now Requirement R3). The islanding criteria remains in Requirement R1 (Planning Coordinator)
and the new Requirement R2 (Transmission Owner); therefore, keeping the standard approach consistent
with the PSRPS Report recommendation. Change made.
Our assertion is based upon a reading of the FERC directive in Order 733, which responds to a stakeholder
suggestion that islanding strategies are a reasonable approach to limit the effect of a relay that improperly
reacts to a stable power swing. Instead, the project team has interpreted the ruling as a means to identify
susceptible Elements - adding an unnecessary burden to every relay owner and planner in the annual
assessment process. In our view, the item should be re-positioned as a bullet point in R3, which allows the
TO or GO to show that an islanding scheme sufficiently protects the greater BES against instability. This
would be similar to the acknowledgement that power swing blocking limits the effect of a load relay trip essentially another mitigation strategy that may be used address a situation where the relay settings
themselves cannot be changed for some reason.
Response: The drafting team contends that it followed the FERC directive to consider islanding strategies
and simply includes the Elements that form the boundaries of islands to be evaluated with regard to
tripping during stable power swings. The team contends that islanding strategies are developed to isolate
the system from unstable power swings, which is still allowed under the proposed PRC-026-1. No change
made.
Public Service
Enterprise Group
No
The entire standard is unsupported by the PSRPS document. See p. 20 in the “Need for a Standard”
section, which states “Based on its review of historical events, consideration of the trade-offs between
dependability and security, and recognizing the indirect benefits of implementing the transmission relay
loadability standard (PRC-023), THE SPCS CONCLUDES THAT A NERC RELIABILITY STANDARD TO ADDRESS
RELAY PERFORMANCE DURING STABLE POWER SWINGS IS NOT NEEDED, AND COULD RESULT IN
UNINTENDED ADVERSE IMPACTS TO BULK-POWER SYSTEM RELIABILITY." (Emphasis added by
CAPITALIZATION.) See the specific report references below that support the PSRPS document’s conclusion
that this standard is not needed:
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1) Page 8 of 61, 1965 Northeast Blackout Conclusion, first sentence “Relays tripping due ...”
2) Page 8 of 61, 1977 New York Blackout Conclusions, first sentence, “Relays tripping due...”
3) Page 9 of 61, July 2-3, 1996: West Coast Blackout Conclusions, first sentence “Relays tripping due...”
4) Page 10 of 61, August 10, 1996 Conclusions, first sentence, “Relays tripping due...”
5) Page 16 of 61, 2003 Northeast Blackout Conclusion, “Relays tripping due...”
6) Page 17 of 61, Overall Observations from Review of Historical Events, first and second sentences,
“Relays tripping...”
7) Page 19 of 61, final paragraph, “Given the ....”The PSRPS document, developed by industry experts and
approved by the NERC Planning Committee, clearly disputes the FERC directive in Order No. 773 (Docket
No. RM08-13-000), that was subsequently affirmed in Order Nos. 773-A and 773-B, that a standard is
needed to ensure that load-responsive protective relays do not trip in response to stable power swings
during non-Fault conditions. NERC’s informational filing in Docket No. RM08-13-000 dated July 21, 2011
concluded that there is a need for a standard on stable power swings. This conclusion is the opposite of
what the PSRPS document concluded.
We recommend that the NERC Standards Committee explore means to utilize the more recent PSRPS
document to obtain relief from the aforementioned FERC directive that is driving this project.
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
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Los Angeles
Department of
Water and Power
No
Masschusetts
Attorney General
No
Question 1 Comment
LADWP opposes the criteria from Requirement 2 that proposed looking back on Elements since 2003.
Requirements cannot be applied retroactively.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
R2 requires GOs and TOs to evaluate Disturbance records “since January 1, 2003,” a time that will precede
the effective date of this standard. A requirement cannot rely upon records that precede the effective
date of a standard.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
MidAmerican
Energy Company
No
The approach for R2 is incorrect. NERC standards cannot require compliance prior to the effective date of
the standard itself. All references to 2003 should be deleted from the requirements and any guidance.
Deleting the references to 2003 would make the requirement effective upon the effective date of the
standard.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Consolidated
Edison, Inc.
No
We agree with a focused approach as outlined in the technical document. However, we have the
following serious concerns with criteria in the requirements:
1. The term “credible event” should be clearly defined. The basis to determine a credible event is missing
from the requirement and application guide. This basis should be provided in the standard requirement.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to current
assessment(s). The term “credible” was removed from the previous Requirement R2 (and new R3)
because the required performance refers to only current actual events. Change made.
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2. Why is the standard focused on SOL rather than IROL? The basis for specifying SOL is not supported by
the example in the application guideline since the example did not show inter-area impact.
Response: Several commenters questioned the use of a System Operating Limit (SOL) to determine
Elements that needed evaluation because they were not necessarily associated with wide-area problems.
The drafting team contends that not only SOLs that have been shown to expose a widespread area to
instability, uncontrolled separation(s) or cascading outages should be considered. Identified localized
instability issues also point to Elements that should reduce the likelihood of tripping for stable power
swings. No change made.
3. It is not clear in R1, criteria number 4 whether the assessment should include relay tripping or just
stable power swing or both stable and unstable power swing.
Response: Requirement R1 – Criterion 4, Requirement R2 – Criterion 1, and the new Requirement R3 –
Criterion 1, were clarified by adding both “stable and unstable” power swings. Both stable and unstable
power swings determine whether an Element will be identified as experiencing a power swing. Change
made.
4. In R2, it is unrealistic to require an entity to provide data on an Element that had tripped since 2003.
There is no existing NERC continent-wide disturbance monitoring or misoperation standard that requires
data be retained more than 12 months. We recommend that this requirement be removed from the
standard or include only Elements that were tripped in the last calendar year.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Electric Reliability
Council of Texas,
Inc.
No
The time periods in the requirements are unnecessarily restrictive, particularly R1, which essentially
requires the work to be done in January of each year. There does not appear to be a reliability reason to
have the work completed in January as long as the GO and TO perform the necessary actions in R3 in a
timely manner. We suggest taking an approach similar to PRC-023 R6. In this case R1 would begin:
“Each Planning Coordinator, Reliability Coordinator, and Transmission Planner shall conduct an
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assessment at least once each calendar year, with no more than 15 months between
assessments...”
R2 through R4 could use a similar approach.
Response: The Requirement R1 language about “January of each calendar” has been removed and
replaced with “each calendar year.” Based on time period changes in other Requirements, the drafting
team determined that an annual periodicity in Requirement R1 is more appropriate. Change made.
The identification of Elements in R1 seems to be unnecessarily redundant between the applicable entities
for some criteria and inappropriate for other criteria. ERCOT suggests splitting R1 into two separate
requirements based on the responsible entity: one requirement for the Planning Coordinator to identify
elements per criteria 2, 3, and 4; and one requirement for the Reliability Coordinator to identify elements
per criterion 1.
The Transmission Planner should be removed from the Applicability of the standard, including removal
from R3.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
Independent
Electricity System
Operator
No
The criteria used to limit the applicability of the transmission lines are unclear. Specifically,
•
Regarding Criteria 1 in Requirement 1, entities’ may employ SPS to avoid tripping of any Element
for stable power swings under all normal recognized contingencies included in the TPL standards.
Given that the SPS is used as a mitigation measure, should this proposed standard be applicable to
those elements that are susceptible to trip for stable power swings, when a failure of the SPS is
considered?
Response: The drafting team contends that the Special Protection System (SPS) as stated in Requirement
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R1 is in place to prevent angular instability. The standard does not address a failing SPS, but is addressing
the Elements associated with an SPS that would be susceptible to a power swing. (Note: The use of SPS
has been replaced with Remedial Action Scheme (RAS) for consistency with a current project to revise the
definition of “Special Protection System”). No change made.
•
Similar to the above, for Criteria 2 in Requirement 1, entities’ may establish an SOL to avoid
tripping of any Element for stable power swings under all normal recognized contingencies
included in TPL standards. Given that SOL is used as a mitigation measure, should those elements
susceptible to trip for stable power swings, when the SOL is exceeded (and which is not allowed in
normal operation conditions) be applicable to this proposed standard?
Response: The drafting team contends that a System Operating Limit (SOL) as stated in Requirement R1 is
in place to prevent angular instability. The standard addresses Elements associated with an SOL as an
Element that would be susceptible to a power swing. No change made.
•
Requirement 1 stipulates that the responsible entity notify the facility owner of an Element that
meets Criteria 2 (i.e., an Element associated with a System Operating Limit (SOL) that has been
established based on stability constraints). It is not clear whether the Element is the contingent
Element or the monitored Element or both. This needs to be clarified/specified in the
standard/requirement.
Response: For Requirement R1, Criterion 2, the drafting team removed the term “associated” and revised
the criteria to clarify that the Element is the “monitored” Element. Change made.
•
•
Requirement 1 stipulates that the responsible entity notify the facility owner of an Element that
meets Criteria 3 (i.e., has formed the boundary of an island within an angular stability planning
simulation where the system Disturbance(s) that caused the islanding condition continues to be a
credible event. The term “credible event” is hard to determine since the Disturbance could be
caused by one of those events listed in the TPL standards, or could be one that is beyond those
listed, such as natural phenomena.
We realize that the Application Guideline provides some general guidance on assessing the
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•
creditability of a Disturbance, but we do not agree that a Disturbance is no longer credible when it
is deemed no longer capable of occurring in the future due to actual changes to the BES. Changes
to the BES may reduce the possibility of the same Disturbance, but such Disturbances (e.g. loss of
right of way or an entire station) may still occur due to other means. If the SDT should continue to
hold the position that the criteria for excluding a Disturbance is that BES changes are made to
mitigate (but not totally eliminate) the recurrence, then it should be clearly stated in the
requirement itself.
In short, the basis with which to deem a Disturbance “credible” is missing from the requirements,
which needs to be provided/clarified in the standard/requiremen
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2. Change made.
David Kiguel
No
1. The second criterion in R1 refers to "An Element that is associated with a System Operating Limit
(SOL)." Clarification is necessary to specify the meaning of "associated." Does it refer to an Element in the
SOL itself or monitored and protected but outside the SOL (or both)?
Response: For Requirement R1, Criterion 2, the drafting team removed the term “associated” and revised
the criteria to clarify that the Element is the “monitored” Element. Change made.
2. The draft repeatedly uses the term “credible event.” In some instances, e.g. past disturbance(s) it might
be subject to interpretation. In general, without a probabilistically quantified criterion, the term "credible"
is subjective and subject to interpretation, thus should be avoided in this context.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to current
assessment(s). The term “credible” was removed from the previous Requirement R2 (and new R3)
because the required performance refers to only current actual events. Change made.
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3. Clarification is required in regards to load-responsive relays in a Protection System. It is unclear as to
what relays/components should not trip during power swing.
Response: The term “load-responsive protective relays” is widely understood and is any protective
functions which could trip with or without time delay, on load current. A clarification has been provided in
PRC-026-1 – Attachment A. Change made.
4. R2 requires GOs and TOs to evaluate Disturbance records “since January 1, 2003,” a time that will
precede the effective date of this standard. A requirement cannot rely upon records that precede the
effective date of a standard.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
California ISO
No
As “line-out conditions” used in Requirement R1 Criteria 1 and 2 is not a defined term, please clarify the
intent of “line-out conditions”, particularly addressing if “line-out conditions” are expected to go beyond
the TPL Standard(s) of what the Planning Coordinator and Transmission Planner already study.
Response: The phrase “line-out conditions” has been removed. Elements should be identified based on
the Requirement R1 criterion regardless of the outage conditions that may be necessary to trigger
enforcement of the System Operating Limit (SOL) or arming of the Special Protection System (SPS). The
Guidelines and Technical Basis have been supplemented to provide additional information. (Note: The use
of SPS has been replaced with Remedial Action Scheme (RAS) for consistency with a current project to
revise the definition of “Special Protection System”). Change made.
Tacoma Power
No
Tacoma Power supports PSEG’s response to Question 1.
Setting aside the previous comment (that is, assuming FERC does not provide reflief from its directive to
develop this standard), Tacoma Power supports a narrower approach. That is, the screening criteria
should be refined and made simpler. For example, PRC-023 applies relatively straightforward screening
criteria, yet PRC-023 addresses a greater reliability risk than the proposed PRC-026-1.
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Presently, PRC-026-1 Requirement R1 (and R2) could pose a greater burden on entities than PRC-023 for
screening to identify applicable Facilities. Alternatives might be to conduct a data request to collect better
information so that Requirements R1 and R2 could be consolidated and then provide more refined and
simpler criteria.
Response: The drafting team contends that the standard approach is consistent with the PSRPS Report
recommendation. Also, PRC-023 includes all BES Elements above 200 kV and select Elements below 200
kV and the proposed PRC-026-1 is a narrow focus on BES Elements at greater risk of power swings.
Requirement R1 is not requiring additional or new studies; it is relying on existing studies. The burden of
Requirement R2 (and new R3) has been reduced by eliminating the need to evaluate Disturbances prior to
the Effective Date of the standard. Changes made.
Setting aside the previous comment, Criterion 4 needs more clarification.
Response: Requirement R1 – Criterion 4, Requirement R2 – Criterion 1, and the new Requirement R3 –
Criterion 1, were clarified by adding both “stable and unstable” power swings. Both stable and unstable
power swings determine whether an Element will be identified as experiencing a power swing. Change
made.
Response: The drafting team asserts that the standard does not require the inclusion of relay models.
Requirement R1 – Criterion 4 is not requiring a study, but the identification of any Element that was
observed as tripping in the most recent Planning Assessment. No change made.
What is the technical basis in Requirement R1 for identification and notification to occur in January of
each year?
Response: The Requirement R1 language about “January of each calendar” has been removed and
replaced with “each calendar year.” Based on time period changes in other Requirements, the drafting
team determined that an annual periodicity in Requirement R1 is more appropriate. Change made.
Ameren
No
(1) Along with our comments we agree with and adopt the Public Service Enterprise Group (PSEG)
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Comments by reference.
Response: Thank you for your comment.
(2) If this standard does proceed, we generally can accept the focused approach, but believe it should be
narrower. We believe that R2 reaching all the way back to 1/1/2003 creates an ex post facto compliance
obligation.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
(3) In our opinion R1 needs to limit the Criteria 3 and 4 time horizon to Operations Planning to be
consistent with R3 which deals with the existing Protection System. We believe that resetting an existing
relay for a future, but not present, stability issue could harm present reliability. Although, we do
understand the benefits of identifying a future stability concern, and a future need to possibly alter
relaying schemes or reset relays in an orderly fashion is important; we believe that such activity is part of
the planning process and need not be governed by this standard. However, if the SDT intended that the
R3 CAP (3rd bullet) apply to future scenarios, then please add the timing of such an example in the
Application Guidelines.
Response: Requirement R1 has been revised to only include the Planning Coordinator and due to this
revision, the Criterion that identifies Elements is now specifically assigned the Time Horizon: Long-term
Planning. In the event that a Corrective Action Plan (CAP) is necessary based on future system conditions,
the CAP can specify a timeframe that does not enact changes until those system conditions require
modification. An example has been added to clarify this scenario in the Guidelines and Technical Basis.
Change made.
(4) We ask the drafting team to include a broader explanation of changed conditions that would
discontinue credibility in R2, item 2 (“...during an actual system Disturbance where the Disturbance(s) that
caused the islanding condition continues to be credible.”).
Include items such as completed PRC-004 CAPs that have fixed a contributing cause, and procedures to
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avoid a unique maintenance switching topology that was causal.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to current
assessment(s). The term “credible” was removed from the previous Requirement R2 (and new R3)
because the required performance refers to only current actual events. Change made.
Following the notification of a Disturbance to the Planning Coordinator in Requirements R2 by the
Transmission Owner or by Requirement R3 by the Generator Owner, the Planning Coordinator in
Requirement R1 will continue notifying the respective Generator Owner and Transmission Owner of the
Element, unless the Planning Coordinator determines the Element is no longer susceptible to power
swings.
ISO New England
No
ISO New England recommends that requirements R1, R2, and R3 be changed from an annual requirement
to once every 60 months. We also think that the approach should be narrower.
Response: The Requirement R1 language about “January of each calendar” has been removed and
replaced with “each calendar year.” Based on time period changes in other Requirements, the drafting
team determined that an annual periodicity in Requirement R1 is more appropriate.
The drafting team revised Requirement R4 (previous R3) from “each calendar year” to “within 12 full
calendar months of receiving notification of an Element pursuant to Requirement R1 or within 12 full
calendar months of identifying an Element pursuant to Requirement R2 and R3,” and “where the
evaluation has not been performed in the last three calendar years.” Three calendar years was selected
over five calendar years because the implementation plan provides a greater length of time to implement
the standard and future occurrences would be incremental. Change made.
Criteria 1 should be limited to IROL’s and read as follows:
1. An Element that is located or terminates at a generating plant, where a generating plant stability
constraint exists and is addressed by an IROL.
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Criteria 2 should be deleted. This criteria appears to be redundant to Criteria 1.
Response: Criterion 1 is for identifying Bulk Electric System (BES) Elements associated with a Special
Protection System (SPS) or operating limit associated generating plant. Criterion 2 is associated with
identifying BES Elements with a System Operating Limit SOL that has been established based on angular
stability constraints. (Note: The use of SPS has been replaced with Remedial Action Scheme (RAS) for
consistency with a current project to revise the definition of “Special Protection System”). The drafting
team contends that the standard approach is consistent with the PSRPS Report recommendation. No
change made. Several commenters questioned the use of a System Operating Limit (SOL) to determine
Elements that needed evaluation because they were not necessarily associated with wide-area problems.
The drafting team contends that not only SOLs that have been shown to expose a widespread area to
instability, uncontrolled separation(s) or cascading outages should be considered. Identified localized
instability issues also point to Elements that should reduce the likelihood of tripping for stable power
swings. No change made.
In Criteria 3, Disturbance is too broad. It should be limited to single or multiple contingencies but not
extreme contingencies. Criteria 3 should read as follows:
3. An Element that has formed the boundary of an island within an angular stability planning
simulation where the system Disturbance(s) that caused the islanding is a single or multiple
contingency but not an extreme contingency.
Response: The drafting team modified Requirement R1, Criterion 3 to include island boundaries due to
angular instability within an underfrequency load shedding (UFLS) assessment. Also, the Generator Owner
was moved from Requirement R2 to the new Requirement R3 in order to remove the “islanding” criteria
for Generator Owners. Change made.
Criteria 4 should be narrower in scope and read as follows:
4. An Element identified in the most recent Planning Assessment where relay tripping occurred for a
power swing during a Disturbance caused by a single or multiple contingency but not an extreme
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contingency.
Response: The drafting team asserts that the most recent Planning Assessment provides a concrete
reference to the information used in identifying BES Elements. Since the Planning Assessments (i.e., TPL001-4) are performed annually, any other description would create confusion as to whether an entity
should use past information or information revealed during preparation of a Planning Assessment. No
change made.
Again, Disturbance is too broad. It should be limited to single or multiple contingencies but not extreme
contingencies.
Response: The drafting team revised Requirement R1, Criterion 4 by changing “Disturbance” to
“simulated disturbance” to comport with the approved Reliability Standard TPL-001-4. The use of
“Disturbance” in Requirements R2 (TO) and R3 (GO) relates to an actual system disturbance. Change
made.
New York Power
Authority
No
The PSRPS technical document does not recommend this Standard. This is stated in pages 5, 20, and
24:”Based on its review of historical events, consideration of the trade-offs between dependability and
security, and recognizing the indirect benefits of implementing the transmission relay loadability standard
(PRC-023), the SPCS concludes that a NERC reliability Standard to address relay performance during stable
power swings is not needed, and could result in unintended adverse impacts to Bulk-Power System
reliability.”
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
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Protection and Control Subcommittee were advanced in these FERC proceedings.
We only agree with R1. R1 calls upon the Planning Coordinator, Reliability Coordinator, & Transmission
Planner, (all single ISO in our region) to provide notification to GOs and TOs of what the specific
“Elements” are. R2 seems to again call for Elements by the GOs and TOs. R2 can easily be combined into
R1 for a simpler answer. In addition, by practice all registered entities report to the ISO/RC any
disturbances, being they are the System Operator and keep records of events in the region.
Response: The Generator Owner (GO) in Requirement R3 and Transmission Owner (GO) in Requirement
R2 are required to report the Element that tripped during a Disturbance in response to a power swing.
These Requirements allow the Planning Coordinator to be the sole source of funneling the “identified
Elements” to the GO and TO. A fifth Criterion was added to Requirement R1 that requires the Planning
Coordinator (PC) to continue identifying an Element “unless the PC determines the Element is no longer
susceptible to power swings.” This ensures visibility of the Elements reported by the GO or TO on an
ongoing basis since the Element tripped in response to a power swing. Change made.
Oncor Electric
Delivery LLC
No
Oncor does not agree that the approach of this Standard came from recommendations in the PSRPS
technical document, but rather negates the need for the Standard altogether. Specifically, on page 5
paragraph 4 of the document it states “Based on its review of historical events, consideration of the tradeoffs between dependability and security, and recognizing the indirect benefits of implementing the
transmission relay loadability standard (PRC-023), the SPCS concludes that a NERC Reliability Standard to
address relay performance during stable power swings is not needed, and could result in unintended
adverse impacts to Bulk-Power System reliability”.
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
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issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
Oncor agrees with this notion and does not want to add any adverse issues to the power system. This is
also repeated on page 20 paragraph 1. In regards to the specific requirements, R1 criteria 1 states “An
Element that is located or terminates at a generating plant, where a generating plant stability constraint
exists and is addressed by an operating limit or a Special Protection System (SPS) (including line-out
conditions).” This requirement duplicates the efforts in TPL-002 (R1.3.10), TPL-003(R1.3.10), TPL004(R1.3.7), and TPL-001-4(R 2.7.1) where the effect of a SPS, which is a protection system, is already
studied. Oncor recommends the SDT aligns the Requirements to eliminate duplication.
Response: The drafting team contends that the Requirements do not duplicate the transmission (i.e., TPL
standards) Requirements. The TPL standards address the effects of the planned actions of the Special
Protection System (SPS), which is installed to address a stability constraint. The Elements are included
because other relays protecting the Element may operate for a stable power swing across the Element.
(Note: The use of SPS has been replaced with Remedial Action Scheme (RAS) for consistency with a
current project to revise the definition of “Special Protection System”). No change made.
Austin Energy
No
(1) City of Austin dba Austin Energy (AE) notes the following statement from the PSRPS technical
document on page 20: “Based on its review of historical events, consideration of the trade-offs between
dependability and security, and recognizing the indirect benefits of implementing the transmission relay
loadability standard (PRC-023), the SPCS concludes that a NERC Reliability Standard to address relay
performance during stable swings is not needed, and could result in unintended.”
AE believes more background work is necessary in justifying the creation of this standard before
proceeding.
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
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the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
(2) Further, AE disagrees with the R2 criteria of evaluating Disturbance records “since January 1, 2003.”
The criteria not only predate the enforcement date of this standard, it goes back to a time before any of
the NERC Reliability Standards were enforceable.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Northeast Utilities
No
We agree with a focused approach as outlined in the technical document. However, we have the following
serious concerns with criteria in the requirements:
1. The term “credible event” should be clearly defined. The basis to determine a credible event is missing
from the requirement and application guide. This basis should be provided in the standard requirement.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to current
assessment(s). The term “credible” was removed from the previous Requirement R2 (and new R3)
because the required performance refers to only current actual events. Change made.
2. Why is the standard focused on SOL rather than IROL? The basis for specifying SOL is not supported by
the example in the application guideline since the example did not show inter-area impact.
Response: Several commenters questioned the use of a System Operating Limit (SOL) to determine
Elements that needed evaluation because they were not necessarily associated with wide-area problems.
The drafting team contends that not only SOLs that have been shown to expose a widespread area to
instability, uncontrolled separation(s) or cascading outages should be considered. Identified localized
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instability issues also point to Elements that should reduce the likelihood of tripping for stable power
swings. No change made.
3. It is not clear in R1, criteria number 4 whether the assessment should include relay tripping or just
stable power swing or both stable and unstable power swing.
Response: Requirement R1 – Criterion 4, Requirement R2 – Criterion 1, and the new Requirement R3 –
Criterion 1, were clarified by adding both “stable and unstable” power swings. Both stable and unstable
power swings determine whether an Element will be identified as experiencing a power swing. Change
made.
4. In R2, it is unrealistic to require an entity to provide data on an Element that had tripped since 2003.
There is no existing NERC continent-wide disturbance monitoring or misoperation standard that requires
data be retained more than 12 months. We recommend that this requirement be removed from the
standard or include only Elements that were tripped in the last calendar year.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Idaho Power Co.
No
No. R1 seems to be an acceptable approach for Planners to use. However, R2 is not acceptable. Having a
dated requirement prior to the effective date of a Standard is not appropriate. While it may be reasonable
to look at these earlier disturbances, making a Requirement of that review is not. This requirement should
be removed or rewritten to require only the review of disturbances past the effective date of the Standard
where tripping of Protection Systems during a stable power swing was a causal factor.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
In addition, the PSRPS technical document does not use the NERC Glossary term for Disturbances, yet the
Standard does. The Glossary term is not specific which makes these criterion also non specific. Criterion
similar to those in EOP-004 would seem to better identify the disturbances that are included in this
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Standard.
Response: The drafting team revised Requirement R1, Criterion 4 by changing “Disturbance” to
“simulated disturbance” to comport with the approved Reliability Standard TPL-001-4. The use of
“Disturbance” in Requirements R2 (TO) and new R3 (GO) relates to an actual system Disturbance. Change
made.
M2 appears to require the utility to have evidence it did not know it needed to maintain.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard; therefore, the
Measure now only requires the entity to have evidence from the Effective Date forward. Change made.
The PSRPS technical document suggests that the FERC directive to develop this standard may have been
based on misinformation or a misunderstanding of the 2003 Northeast Blackout investigation report and
furthermore suggests such a standard could result in unintended adverse impacts to the Bulk-Power
System. Recommend NERC utilize the findings of the PSRPS technical document to obtain a stay of
development of PRC-026-1 from FERC until FERC can develop a position based on the conclusions
presented in the PSRSP document.
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
The NERC System Protection and Control Subcommittee (SPCS) concern is that an overly prescriptive
standard as contemplated in Order No. 733 could lead to unintended adverse impacts. The focused
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approach recommended by the SPCS, and implemented by the drafting team, addresses the concern by
requiring entities implement Corrective Action Plans to improve security for stable power swings by
meeting the criteria in PRC-026-1 – Attachment B while maintaining dependable fault detection and
dependable out-of-step tripping. No change made.
If development of PRC-026-1 continues: I agree with the focused approach.
R1.1 and R1.2 need to contain clarity about what constitutes a "line out condition" - does this mean N-1,
N-2, N-X, transformers, etc?
Response: The phrase “line-out conditions” has been removed. Elements should be identified based on
the Requirement R1 criterion regardless of the outage conditions that may be necessary to trigger
enforcement of the System Operating Limit (SOL) or arming of the Special Protection System (SPS). The
Guidelines and Technical Basis have been supplemented to provide additional information. (Note: The use
of SPS has been replaced with Remedial Action Scheme (RAS) for consistency with a current project to
revise the definition of “Special Protection System”). Change made.
Concerning R1.3, who is the judge of whether an event is "credible"?
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2. Change made.
Public Utility District
No. 1 of Cowlitz
County, WA
No
Cowlitz PUD agrees with the intent of standard PRC-026-1 (Standard) requirements R1 & R2 focused
approach, but finds the current Standard draft creates a compliance difficulty. The Standard should clearly
define the “specific criterion” which will be used to identify Elements, and compare the load-responsive
protective relay characteristics to establish “credible” risk. The Standard lacks specificity as currently
written.
Response: The drafting team modified Requirement R1 to add clarity. For example, Criterion 1 – added
“angular” to “stability constraint, Criterion 2 – “monitored” to identify which Element, Criterion 3 – to
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Organization
Yes or No
Question 1 Comment
include island boundaries due to angular instability within an underfrequency load shedding (UFLS)
assessment, and Criterion 4 – that a “power swing” refers to both “stable” and “unstable.” Also, the
Generator Owner was moved from Requirement R2 to the new Requirement R3 in order to remove the
“islanding” criteria for Generator Owners.
The term “credible” has been removed from the standard. The drafting team clarified Requirement R1,
Criterion 3 by framing the criterion in the present tense to refer to current assessment(s). The term
“credible” was removed from the previous Requirement R2 (and new R3) because the required
performance refers to only current actual events. Change made.
--(New Paragraph)—
This draft assumes incorrectly that an entity will have retained operational historical records since 2003. If
such records do not exist, an entity will have no proof of having established a null or complete list which
satisfies requirement R2.
Further, there is no requirement to retain such operational records to facilitate future compliance. The
CEA must either accept attestations, or require applicable entities to develop documentation for each
section 4.2 applicable Element which establishes no credible risk of a trip during a [stable] power swing
exists. Cowlitz PUD proposes the SDT identify specific documentation and establish an official listing, such
as all pertinent RE and NERC disturbance studies/reports dated 2003 or later be used to identify past
poorly performing Elements during a Disturbance.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
We are also unclear on how Elements might be identified purely from system modeling studies when
strictly looking at Requirement R1 (ignoring R3 or other standard requirements outside of this Standard).
Response: The drafting team has included ways for Elements to be identified other than through system
modeling studies, but it contends that some Elements may be identified and included through that
process. Requirement R1 – Criterion 4 is not requiring additional studies, but the identification of any
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Organization
Yes or No
Question 1 Comment
Element that was observed as tripping in the most recent Planning Assessment (i.e., TPL-001-4) would be
included. No change made.
Further, “credible” is a subjective term which does not establish a clear compliance line. It may be better
to state “...actual system Disturbance where current system modeling continues to identity a repeat of the
Disturbance possible under an n-3 event.” Another possible method would be to tie “credible” to a
probability of one in a thousand; this method would require probability model development. This is not to
say that “credible” should not be used, but it will require extensive guidance in the RSAW of how the
“credible” benchmark is established. In fairness, the benchmark should be established during Standard
development to allow stakeholder review and comment.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2. Change made.
PacifiCorp
Yes
R1, which states “Any Element that is located or terminates at a generating plant, where a generating
plant stability constraints exists and is addressed by an operating limit or a Special Protection System (SPS)
(including line-out condition)”.... raises concerns. In WECC region, a SPS or RAS has to be redundant.
Language needs to be added to make a redundant system an exemption from this requirement.
Response: The drafting team contends that the Special Protection System (SPS) as stated in Requirement
R1 is in place to prevent angular instability. The standard does not address a failing SPS, but is addressing
the Elements associated with an SPS that would be susceptible to a power swing. (Note: The use of SPS
has been replaced with Remedial Action Scheme (RAS) for consistency with a current project to revise the
definition of “Special Protection System”). No change made.
MRO NERC
Standards Review
Forum
Yes
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Organization
Yes or No
Tennessee Valley
Authority
Yes
SPP Standards
Review Group
Yes
Question 1 Comment
Establishing criteria that determine which Elements must be assessed according to Requirements R1 and
R2 reduce the compliance burden on Generator Owners and Transmission Owners. This is the right
approach. That said, we concur with AEP in that the SDT should limit the use of the term ‘stability’ in the
standard to oscillatory and transient stability in order to avoid confusion with voltage and steady state
stability.
Response: The drafting team added “angular” to “stability constraint” to clarify the intent in Requirement
R1, both Criterion 1 and 2. Change made.
Southern Company:
Southern Company
Services, Inc.;
Alabama Power
Company; Georgia
Power Company;
Gulf Power
Company;
Mississippi Power
Company; Southern
Company
Generation;
Southern Company
Generation and
Energy Marketing
Yes
Yes, in part. Addressing situations and occurrences of undesired relay operations is an appropriate
method to minimize future undesired operations.
The review period should be a rolling time period (previous 5 years) rather than > 10 years ago, as many
entities will not have historical records to validate potential mis-operations. Entities were not required to
keep such records to the date specified in R1 and R2.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard.
A fifth Criterion was added to Requirement R1 that requires the Planning Coordinator to continue
identifying an Element “unless the Planning Coordinator determines the Element is no longer susceptible
to power swings.” This ensures visibility of the Elements reported by the Generator Owner or
Transmission Owner on an ongoing basis since the Element tripped in response to a power swing. Change
made.
R1 #4 and R2 #1 should specify the inclusion of Elements that trip due to "stable power swings" instead of
all power swings.
Response: Requirement R1 – Criterion 4, Requirement R2 – Criterion 1, and the new Requirement R3 –
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Organization
Yes or No
Question 1 Comment
Criterion 1, were clarified by adding both “stable and unstable” power swings. Both stable and unstable
power swings are included because both are indicators that load-responsive protective relays may be
challenged by power swing conditions. Clarification made.
Dominion
Yes
Florida Power &
Light
Yes
The language for Criteria 3 & 4 in Requirement 1 should be modified.
Criteria 3 should consider underfrequency planning simulations in addition to angular stability planning
simulations.
Response: The drafting team modified Requirement R1, Criterion 3 to include island boundaries due to
angular instability within an underfrequency load shedding (UFLS) assessment. Also, the Generator Owner
was moved from Requirement R2 to the new Requirement R3 in order to remove the “islanding” criteria
for Generator Owners. Change made.
Criteria 4 should consider Planning Assessments in the last year as opposed to “the most recent Planning
Assessment.”
Response: The drafting team asserts that the most recent Planning Assessment provides a concrete
reference to the information used in identifying BES Elements. Since the Planning Assessments (i.e., TPL001-4) are performed annually, any other description would create confusion as to whether an entity
should use past information or information revealed during preparation of a Planning Assessment. No
change made.
PPL NERC Registered
Affiliates
Yes
These comments are submitted on behalf of the following PPL NERC Registered Affiliates: LG&E and KU
Energy, LLC; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; PPL Generation, LLC; PPL Susquehanna,
LLC; and PPL Montana, LLC. The PPL NERC Registered Affiliates are registered in six regions (MRO, NPCC,
RFC, SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA,
PSE, RP, TO, TOP, TP, and TS Comments:
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Yes or No
Question 1 Comment
We agree with the general approach, but have some implementation concerns as expressed below.
Response: Thank you for your comment.
Arizona Public
Service Co.
Yes
While AZPS agrees with the focused approach, AZPS would like to ask the drafting team to consider
revising R1 and R2. APS recommends that the drafting team require an initial identification and
notification of each Element that meets the criteria described in R1. A review of the assessment should
not be required annually if there are no additions to the entity system meeting the criteria. It would be
more practical to require a comprehensive review every five years.
In addition, the standard should require that if Elements are added to the entity system that meet the
criteria in R1, the applicable entity should provide updates within 90 days of the commissioning of a new
Element.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
APS believes that the current draft requirement is administrative in nature and represents a reporting
burden.
Response: The drafting asserts that notifying the other entities is not administrative and provides a
reliability necessity to communicate the BES Elements that meet the defined criteria or Elements that
have experienced an actual stable or unstable power swing. No change made.
Bureau of
Reclamation
Yes
Peak Reliability
Yes
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Organization
American Electric
Power
Yes or No
Yes
Question 1 Comment
We agree with the focused approach. We would recommend qualifying the term “stability,” in R1.2 in
particular, as “transient or oscillatory stability” so that voltage or steady-state stability, which would not
cause power swings, are not mistakenly construed by an auditor. TPL-001-4 permits use of generic relay
models in dynamic simulation planning studies, so the reference in R1.4 to relay tripping in planning
assessments may not end up being based on the relays actually installed.
Response: The drafting team added “angular” to “stability constraint” to clarify the intent in Requirement
R1, both Criterion 1 and 2. Change made.
American
Transmission
Company, LLC
Yes
Manitoba Hydro
Yes
Exelon
Yes
Texas Reliability
Entity
Yes
ITC
Yes
In general we agree. However, the SDT should clarify what constitutes an island with regard to this
standard as it’s not a defined term. Should this standard pertain to lines which contain both generation
and load, which when tripped form an island? We suggest not.
Response: The drafting team modified Requirement R1, Criterion 3 to include island boundaries due to
angular instability within an underfrequency load shedding (UFLS) assessment. Also, the Generator Owner
was moved from Requirement R2 to the new Requirement R3 in order to remove the “islanding” criteria
for Generator Owners. Change made.
Also, the term “credible” is unclear. If an event involves scenarios beyond TPL’s “broad spectrum of
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Yes or No
Question 1 Comment
System conditions” and “wide range of probably Contingencies”, is it really credible? The example in
Application Guideline involved a single bus outage, which is credible in TPL standards. However, a
Disturbance may occur involving multiple contingencies but well beyond normal planning criteria and now
that e``xtreme event must be studied. If this approach is desired, then it leaves a gap for other extreme
events to occur, just which we’ve had the good fortune not to have experienced yet. We suggest limiting
the definition of “credible” into include those scenarios within the bounds of TPL-001-4.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2. Change made.
Southern California
Edison Company
Yes
Salt River Project
Yes
DTE Electric
Xcel Energy
No comment
Yes
The frequency of performing the tasks within these requirements is unnecessarily aggressive; power
systems dynamics do not change that fast. We should recommend changing the frequency to every 3 to 4
years.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
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2. Do you agree that the Planning Coordinator, Reliability Coordinator, and Transmission Planner are the appropriate entities to identify the
Elements that meet the criteria in Requirement R1? If not, please explain why an entity is not appropriate and/or suggest an alternative that
should identify the Elements according to the criteria
Summary Consideration: About two-thirds of the commenters for Question 2 agreed with the proposed applicable entities; however, the drafting
team did remove two of the applicable entities as noted here. There were three primary concerns in this area all of which resulted in a revision to
the standard. The chief issue was the use of a historical date (January 1, 2003) in the Requirements. The intent of this language was to provide a
“current day look” back into history concerning Disturbances. The historical information would then be used to assess Elements and/or relays
concerning power swings. This concern was raised in 34 comments supported by 144 stakeholders. To address the concern, this reference was
removed and all of the associated requirements and criteria have been worded in the present tense to make clear that that no historical review is
being required. Seventeen comments from 75 individuals raised varying issues about having the Planning Coordinator, Reliability Coordinator, and
the Transmission Planner all identifying Elements pursuant to Requirement R1. The comments were considered and it was determined that the
Planning Coordinator should be designated as a single entity source of identifying Elements. The reasoning is that the Planning Coordinator has or
has access to the knowledge including the wide-area view and having a single entity will avoid duplication and potential gaps should multiple
entities believe the other is identifying Elements. Last, 8 comments from 24 stakeholders argued that one month at the beginning of each calendar
year for notifying the respective Generator Owner and Transmission Owner is onerous. Although the idea was to keep activities synchronized on an
annual basis, the drafting team understood the concerns; therefore, the Requirement R1 language about “January of each calendar” has been
removed and replaced with “each calendar year.” This revision was based on comment and on time period changes in other Requirements and
determined to be more appropriate.
Organization
Yes or No
SMUD/BANC
No
Question 2 Comment
Collected data and subsequent analysis has not identified tripping during stable power swings. This
phenomenon is rare if at all. Any tripping during stable power swings would more appropriately included
as a mis-operation and addressed as such.
Response: Tripping for stable power swings were observed in the August 14, 2003 Blackout.6
Misoperation standard is a reactive standard and PRC-026-1 is a proactive standard aiming to prevent
load-responsive protective relay operations for stable power swings. This standard is different from the
6
http://www.nerc.com/pa/rrm/ea/Pages/Blackout-August-2003.aspx
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Question 2 Comment
Misoperations standard because it requires notification to the Planning Coordinator of Elements that have
tripped due to stable or unstable power swings.
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
This comment is the same as SMUD/BANC, Question 1, #1. See response in Question 1.
SPP Standards
Review Group
No
The Reliability Coordinator may not be aware of Elements identified in Criteria 3 and 4, since that
knowledge is based upon the Planning Coordinator or the Transmission Planner notifying the Reliability
Coordinator of the situation. Yet the Reliability Coordinator is held accountable for the identification and
notification ‘...of each Element that meets one or more...’ of the criteria. Similarly, there may be situations
where the Planning Coordinator or Transmission Planner may not be aware of Elements identified by the
Reliability Coordinator yet they are also held accountable for identification and notification of each
Element. There should be one, single list of all the Elements that satisfy the criteria but the responsible
entities may not, individually, reach the same conclusions regarding the make-up of that list. Their
individual lists may not contain all the Elements to be identified but a composite of all their lists should
result in the one, true list of all Elements. The requirement needs to be modified to include this
consideration.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
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Organization
Yes or No
Question 2 Comment
access to the knowledge including the wide-area view. Change made to the Requirement.
ISO RTO Council
Standards Review
Committee
No
These three entities are appropriate for the R1 requirement. However, there should be a requirement
that only one of the three is deemed responsible to provide notice to the facility owner. Every facility that
falls under the R1 criteria is under the authority of all three entities. It would be repetitious and redundant
to require all three entities to provide the same information to the same facility owner.
However, if the intent of the requirement is that the Reliability Coordinator will address the Operations
Planning Horizon, while the Planning Coordinator and Transmission Planner will address the Long-Term
Planning Horizon, then it may not be repetitious nor redundant to require these entities to address
Requirement R1. Also, the entity who is registered as the RC may differ from the entity who is registered
as the PC and TP. For example, in the Western Interconnection, Peak Reliability is the RC, the CAISO is the
PC for much of California (but not all), and the Participating Transmission Owners are registered as the TP.
In CAISO’s case, the three registered entities of RC, PC, and TP are represented by different entities.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
ACES Standards
Collaborators
No
We do not believe that the Transmission Planner should be an applicable entity. Any studies completed by
the TP will be duplicated in a larger PC study thus making the inclusion of the TP unnecessary.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
Duke Energy
No
Duke Energy disagrees with the applicability of the Reliability Coordinator (RC) to Requirement R1. From a
NERC Reliability Functional Model standpoint, the RC does not directly interface with a Generator Owner
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Organization
Yes or No
Question 2 Comment
(GO) or Transmission Owner (TO) as Requirement R1 is proposing. The RC receives facility and operational
data such as maintenance plans from TOs and GOs for reliability analysis, but this is mostly done through
automation i.e. SDX (System Data Exchange). The Functional Model even states that the RC coordinates
with other RCs, Transmission Planners, and Transmission Service Providers on transmission system
limitations, not to TOs or GOs. Communication from an RC is most always directed to the Balancing
Authority (BA) or Transmission Operator (TOP), and the RC reliability analyses is provided to TOPs, BAs
and Generator Operators in its area as well as other RCs. An RC, per FAC-011, is required to establish a
methodology for the identification of SOLs/IROLs and communicate the methodology to the TOP. RCs
assist TOPs in calculating and coordinating SOLs, but the TOP is the Functional Entity that implements the
RC methodology to identify and communicate the SOLs/IROLs to its RC in the Operations Horizon.
Lastly, we feel that this standard would create a precedent requiring the RC to unnecessarily communicate
and interface with GOs and TOs; an action that is not required by the current enforceable Reliability
Standards. We recommend that the TOP should supplant the RC as the applicable entity responsible for
communicating the criterion list in the proposed PRC-026-1 Requirement R1. Duke Energy proposes the
following alternative language for Requirement R1.
”Each Planning Coordinator, Transmission Operator, and Transmission Planner shall, within the first
month of each calendar year, identify and provide notification to its Reliability Coordinator, and to
the respective Generator Owner and Transmission Owner of each Element that meets one or more
of the following criteria, if any:”
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
BC Hydro
No
BC Hydro does not agree that the criteria of R1 are reasonable. Therefore cannot suggest why an entity is
not appropriate.
Response: The drafting team asserts that it has implemented the recommended approach provided in the
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Organization
Yes or No
Question 2 Comment
NERC System Protection and Control Subcommittee (SPCS) technical report, Protection System Response
to Power Swings, August 20137 (PSRPS Report). No change made.
Florida Municipal
Power Agency
No
Unless there is a requirement somewhere in the standards for Reliability Coordinators to perform stability
analyses (there currently is not, SOLs/IROLs are studied by the TOP in accordance with the RC’s
methodology); then, this requirement would cause all RCs to have to perform stability studies.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
Also, “corrective action plans” for protection systems will more likely be a planning horizon activity (e.g.,
changing out relays) and hence, the studies should be planning horizon studies, not operating horizon
studies and the RC should not be included.
Response: The time period for Requirement R4 (previously R3) has been changed to be within twelve full
calendar months of notification of the Elements pursuant to Requirement R1. Requirement R4 (previous
R3) and new R5 are applicable to the Generator Owner and Transmission Owner. The Reliability
Coordinator has been removed from the applicability of the standard.. Change made.
Response: The “Operations Planning” time horizon for Requirement R6 (previously R4) regarding the
implementation of the Corrective Action Plan (CAP) was eliminated, leaving the “Long-term Planning”
time horizon. Change made.
Bonneville Power
Administration
No
BPA feels the Standard needs to delineate which entity performs which role, and under which conditions.
For example, the Reliability Coordinator (RC) only identifies the Elements tripped during islanding and
disturbance, while the Planning Coordinator (PC) and Transmission Planner (TP) do so for long term
7
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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Organization
Yes or No
Question 2 Comment
planning.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
Public Service
Enterprise Group
No
Peak Reliability
No
We disagree with the need for this standard.
Response: Thank you for your comment. Please see response in Question 1 above.
The TP’s relationship to the PC is synonymous with the TOP’s relationship with the RC, so leaving the TOP
out as an applicable entity creates a reliability gap. The TOP is responsible for establishing SOLs.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
The drafting team contends that a System Operating Limit (SOL) as stated in Requirement R1 is in place to
prevent angular instability. The standard addresses Elements associated with an SOL as an Element that
would be susceptible to a power swing. No change made.
Electric Reliability
Council of Texas,
Inc.
No
Tacoma Power
No
See our comments to Q1.
Response: Thank you for your comment. Please see response in Question 1 above.
See Tacoma Power’s response to Question 9. At least in WECC, not all of these entities may be
appropriate to lead the identification effort.
Response: Thank you for your comment. Please see response in Question 9 below.
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Organization
Ameren
Yes or No
Question 2 Comment
No
We believe that even if these are the right entities, it is unclear who is driving the identification process or
if they even agree. Please change to ‘Each Transmission Planner with the Planning Coordinator’s and
Reliability Coordinator’s concurrence shall, within the first month of each calendar year, identify and
provide notification to the respective Generator Owner and Transmission Owner of each Element that
meets one or more of the following criteria...’ In most cases, we believe the TP would identify these with
their studies and therefore should take the lead.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
The Requirement R1 language about “January of each calendar” has been removed and replaced with
“each calendar year.” Based on time period changes in other Requirements, the drafting team determined
that an annual periodicity in Requirement R1 is more appropriate. Change made.
Public Utility District
No. 1 of Cowlitz
County, WA
No
Cowlitz PUD questions whether the Transmission Planner (TP) is nothing more than an extension of the
Transmission Owner (TO), Generation Owner (GO), or Planning Coordinator (PC) registrations. Further, we
believe the majority of those entities registered as a TP consider their TP footprint equal to their
TO/GO/PC footprint. Therefore, it may be more appropriate for the TP to simply report Requirement R1
findings to the PC and RC.
Finally, we believe it more efficient that a single entity be responsible to give notice to the TO and GO.
Since every TO and GO must be under a Planning Coordinator and Reliability Coordinator, either the PC or
the RC should be designated to send out the notice after their review is complete.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
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Organization
Yes or No
PacifiCorp
Yes
MRO NERC
Standards Review
Forum
Yes
Tennessee Valley
Authority
Yes
Southern Company:
Southern Company
Services, Inc.;
Alabama Power
Company; Georgia
Power Company;
Gulf Power
Company;
Mississippi Power
Company; Southern
Company
Generation;
Southern Company
Generation and
Energy Marketing
Yes
Dominion
Yes
FirstEnergy Corp.
Yes
Question 2 Comment
The PC, RC and TP, or some combination is the appropriate entity to identify elements that meet the
criteria in Requirement R1. R1 should allow collaboration between the PC, RC and TP to produce a single
list of Elements that will satisfy compliance for all three entities.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
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Organization
Yes or No
Florida Power &
Light
Yes
PPL NERC Registered
Affiliates
Yes
DTE Electric
Yes
Puget Sound Energy
Yes
Arizona Public
Service Co.
Yes
Bureau of
Reclamation
Yes
Luminant
Generation
Company LLC
Yes
Ingleside
Cogeneration LP
Yes
Los Angeles
Department of
Water and Power
Yes
Masschusetts
Yes
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Question 2 Comment
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Organization
Yes or No
Question 2 Comment
Attorney General
MidAmerican
Energy Company
Yes
Consolidated
Edison, Inc.
Yes
American
Transmission
Company, LLC
Yes
Manitoba Hydro
Yes
Independent
Electricity System
Operator
Yes
David Kiguel
Yes
ISO New England
Yes
Exelon
Yes
New York Power
Authority
Yes
The Planning Coordinator, Reliability Coordinator, and Transmission Planner would have the necessary
data and capabilities to perform such functions for internal control areas and interregional ties.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
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Organization
Yes or No
Question 2 Comment
access to the knowledge including the wide-area view. Change made to the Requirement.
Oncor Electric
Delivery LLC
Yes
Oncor agrees that the three registered functions defined are those that should identify the elements in
R1; however, if each criterion, except for criteria 4 as it would clearly come from the Transmission
Planner, is assigned to a registered entity it would provide a more clear process.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
Additionally, R1 calls for “within the first month of each calendar year, identify and provide notification to
the respective Generator Owner and Transmission Owner of each Element that meets one or more of the
following criteria, if any” and then looking at criteria 1 and 2, Oncor recommends the SDT clarify the time
frame, either real time/short term or future/long term, required. The Time Horizon does state “Long-term
Planning” but it also calls for identification of the element within the first month of the calendar year. This
would assist with whether or not planning data, which is done one year out, would be valid. See “line out
condition” statement in Oncor’s response to #6.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
The Requirement R1 language about “January of each calendar” has been removed and replaced with
“each calendar year.” Based on time period changes in other Requirements, the drafting team determined
that an annual periodicity in Requirement R1 is more appropriate. Change made.
Texas Reliability
Entity
Yes
A TOP may also provide an analyses in the Operations horizon that could identify other lines pursuant to
the PSRSP technical document. Has the SDT considered the inclusion of TOP in the applicability?
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Organization
Yes or No
Question 2 Comment
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. The Planning Coordinator is believed to be the best
single-source of information and not the Transmission Operator. Change made.
The requirement as written implies that both the identification and notification of Elements must both be
accomplished in January of each year. Identification can happen anytime each year, but notification must
occur annually by January 31 each year. Suggest “Each year, each Planning Coordinator, Reliability
Coordinator, and Transmission Planner shall identify, and by January 31 of each calendar year, provide
notification...”
Response: The Requirement R1 language about “January of each calendar” has been removed and
replaced with “each calendar year.” Based on time period changes in other Requirements, the drafting
team determined that an annual periodicity in Requirement R1 is more appropriate. Change made.
Northeast Utilities
Yes
Idaho Power Co.
Yes
Yes, although I suggest adding the stipulation that the PC, RC, and TP must be in agreement about
whether an Element meets the criteria in R1.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
Southern California
Edison Company
Yes
Salt River Project
Yes
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Organization
Xcel Energy
Yes or No
Yes
Question 2 Comment
We should recommend changing the frequency to every 3 to 4 years and changing the window to 3 to 6
months. It is troubling that the criteria (#4 in special) suggest that software used by planners should
include detailed relay model. If approved, this will be huge work load for system protection engineering
(SPE) and the planning department.
Response: The Requirement R1 language about “January of each calendar” has been removed and
replaced with “each calendar year.” Based on time period changes in other Requirements, the drafting
team determined that an annual periodicity in Requirement R1 is more appropriate. Change made.
The drafting team asserts that the standard does not require the inclusion of relay models. Requirement
R1 – Criterion 4 is not requiring a study, but the identification of any Element that was observed as
tripping in the most recent Planning Assessment pursuant to TPL-001-4, Requirement R4, Part 4.3.1.3 –
“Tripping of Transmission lines and transformers where transient swings cause Protection System
operation based on generic or actual relay models” which will become effective January 1, 2015 (U.S.).
Other clarifying changes were made to Requirement R1 – Criterion 4.
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3. Do you agree that the Generator Owner and Transmission Owner are the appropriate entities to identify the Elements that meet the criteria
in Requirement R2? If not, please explain why an entity is not appropriate and/or suggest an alternative that should identify the Elements
according to the criteria.
Summary Consideration: This section was evenly split between comments as to whether or not the Generator Owner and Transmission Owner are
the appropriate entities to identify the Elements that meet the criteria in Requirement R2. Of the comments, there were two primary concerns not
addressed in previous sections, one which resulted in a revision to the standard and the other no revision.
There were five comments by 18 stakeholders that were concerned about how the Generator Owner (GO) and Transmission Owner (GO) in
Requirement R2 (now split between R2-TO and R3-GO) are to manage the record keeping for identified Elements as a result of a trip due to an
actual power swing related Disturbance. In order to address this main concern, Requirement R2 (and the new R3) was modified to require the GO
and TO to report any identified Elements to the Planning Coordinator. These Requirements allow the Planning Coordinator to be the sole source of
channeling the “identified Elements” back to the GO and TO each year; therefore, a fifth Criterion was added to Requirement R1 that requires the
Planning Coordinator (PC) to continue identifying a reported Element unless it determines the Element is no longer susceptible to power swings.
This ensures visibility of the Elements reported by the GO or TO on an ongoing basis because the Element tripped in response to a power swing.
No change was made based on three comments by 34 individuals that the Generator Owner and Transmission Owners are not the most
appropriate entities to evaluate load-responsive protective relay operations due to power swings. The drafting team contends that the Protection
System owner (i.e., Generator Owner and Transmission Owner) is the appropriate entity for reviewing operations.
Organization
Northeast Power
Coordinating Council
Yes or No
Question 3 Comment
No
Requirement R2 requires GOs and TOs to evaluate Disturbance records “since January 1, 2003,” a time
that will precede the effective date of this standard. A requirement CANNOT RELY UPON RECORDS THAT
PRECEDE THE EFFECTIVE DATE OF A STANDARD. As an example, PRC-005-1, which was approved in Order
693, became effective on June 11, 2007, does not require a Registered Entity to have maintenance records
available for the period of time that preceded the effective date in order to calculate the next
maintenance interval for a relay. We recommend that this requirement be removed from the standard or
include only Elements that were tripped in the last calendar year.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
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Organization
Yes or No
Question 3 Comment
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
PacifiCorp
No
These functions would be more appropriate assigned to the GOP and TOP.
Response: The drafting team contends that the Protection System owner (i.e., Generator Owner and
Transmission Owner) is the appropriate entity for reviewing operations. No change made.
SMUD/BANC
No
The requirement R2 is particularly unacceptable as it requires data for pre June 18, 2007; effective date of
Order 693 standards.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Southern Company:
Southern Company
Services, Inc.;
Alabama Power
Company; Georgia
Power Company;
Gulf Power
Company;
Mississippi Power
Company; Southern
Company
Generation;
Southern Company
Generation and
Energy Marketing
No
The TOs and GOs are the owners of the protection systems whose operation is being addressed, but the
GO does not have a system view of stable power swings.
Response: The Generator Owner (GO) in Requirement R3 and Transmission Owner (GO) in Requirement
R2 are required to report the Element that tripped during a Disturbance in response to a power swing.
These Requirements allow the Planning Coordinator to be the sole source of funneling the “identified
Elements” to the GO and TO. A fifth Criterion was added to Requirement R1 that requires the Planning
Coordinator (PC) to continue identifying an Element “unless the PC determines the Element is no longer
susceptible to power swings.” This ensures visibility of the Elements reported by the GO or TO on an
ongoing basis since the Element tripped in response to a power swing.
Based on this comment and other comments, the Generator Owner was moved from Requirement R2 to
the new Requirement R3 in order to remove the “islanding” criteria for Generator Owners. Change made.
Requiring the GO and TO to look back to 2003 every year as specified by R2 is unreasonable. Looking
backwards to consider problems known to have occurred is understandable, but requiring this every year
is not reasonable. These trip investigations have been occurring in the industry long before the mandated
PRC-004 operation reviews. Most responsible utilities have addressed undesirable protection system
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Organization
Yes or No
Question 3 Comment
misoperations to maximize availability - the market forces have long driven utilities to correct undesirable
relay operations so they can be available to the market.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
ISO RTO Council
Standards Review
Committee
No
We ask whether the TO or GO, especially a GO, will have access to studies and fault analysis reports that
will determine if the Disturbance remains credible. There seems to be an assumption in R2 that a fault
analysis study was performed that documents the Disturbance and system conditions at the time. There
must be a requirement in some NERC standard that obligates appropriate entities are notified of these
results.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2. Change made.
We are unclear on the relevance or need to trace back to 2003 for Disturbances that caused an Element to
trip due to a power swing or which formed the boundary of an island. Further, the term credible
Disturbance needs clarification. Please see our comment under Q1, above.
Response: The Generator Owner (GO) in Requirement R3 and Transmission Owner (GO) in Requirement
R2 are required to report the Element that tripped during a Disturbance in response to a power swing.
These Requirements allow the Planning Coordinator to be the sole source of funneling the “identified
Elements” to the GO and TO. A fifth Criterion was added to Requirement R1 that requires the Planning
Coordinator (PC) to continue identifying an Element “unless the PC determines the Element is no longer
susceptible to power swings.” This ensures visibility of the Elements reported by the GO or TO on an
ongoing basis since the Element tripped in response to a power swing. Change made.
This requirement should not be written with a date specific start point. Over time, this date would be
meaningless and inappropriate for applying the standard. Instead this requirement could be written in a
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Organization
Yes or No
Question 3 Comment
rolling calendar basis, e.g. - “prior twelve months”.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
ACES Standards
Collaborators
No
(1) We do not believe the GO or TO are appropriate entities. In fact, we do not believe any entity is
appropriate to identify the Elements in R2 and that the requirements are not enforceable as written.
NERC cannot compel evidence from dates prior to June 18, 2007, which is when FERC approved the first
set of reliability standards. Furthermore, a new standard cannot compel data and evidence from before a
time period that the standard was in effect. In today’s litigious society, many companies have data
retention programs that result in the destruction of data that is not required to be retained. Thus, GOs
and TOs may not have the data. How would they comply? We simply will never be able to support a
standard requiring data retroactively.
(2) The topology of the transmission system has changed significantly in many areas since the January 1,
2003. That is over 11 years from the drafting of the standard. It is simply unreasonable to assume that
power swings that occurred in 2003 would occur in the same way and that the data is still applicable.
Relying on 11-year old data simply does not provide a sound engineering basis.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
(3) The islanding analysis conducted for PRC-006-1 R1 would form a better basis for identifying these
Elements and could be used in place of this requirement. The PC could notify the TO and GO of the
Elements at the boundaries of the islands and R2 could then be removed avoiding the issue of retroactive
compliance.
Response: The drafting team modified Requirement R1, Criterion 3 – to include island boundaries due to
angular instability within an underfrequency load shedding (UFLS) assessment (i.e., PRC-006), and moved
the Generator Owner to the new Requirement R3 in order to remove the “islanding” criteria for
Generator Owners. Change made.
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Organization
FirstEnergy Corp.
Yes or No
Question 3 Comment
No
It is understood that the “... since January 1, 2003” verbiage is intended to capture applicable relay
operations during the Aug. 14, 2003 event. It will be difficult if not nearly impossible for a GO, especially in
a deregulated environment, to piece together details of relay operations prior to record-keeping
requirements for NERC PRC-004. We recommend that these Criteria be reworded to include only incidents
which have occurred since the inception of NERC PRC-004.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
PPL NERC Registered
Affiliates
No
We agree with R2 in principle, but there are presently some barriers to the specified stand-alone nature of
GO and TO obligations:
- R2 should state that, where Elements meet one or more of criteria 1-4, the TO must provide GOs with
the system impedance data necessary to perform their studies (ref. the comment on p.24 of the
Application Guidelines regarding taking into account the strength of the transmission system). GOs
typically do not have automatic access to this data, and their “firewall” separation from TOs may impede
such an information exchange unless it is mandated by NERC standards.
Response: The standard is based on planning impedance models used in Protection System coordination
that is commonly shared among entities. This information is not related to system status that would
reveal that certain Elements that are not in-service; therefore, the drafting team does not see a conflict
with the exchange of information or standards of conduct. The criteria requires all generation is in service
and all transmission Elements are in their normal operating state when calculating the system impedance.
- There has been to-date no obligation for entities to maintain records pertaining to the criteria specified
in R2, so it may not be possible in all cases to perform the look-back to Jan. 1, 2003 mandated in this
requirement. The criteria should therefore be changed to begin, “An Element that is known to have..,”
instead of, “An Element that has....”
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
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Organization
Yes or No
Question 3 Comment
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
- GOs may not know whether their Elements formed the boundary of an island (ref. R2.2 GOs should not
be required to take any actions under either R2.1 or R2.2 until and unless the PC/RC/TOP gives notification
and provides the relevant necessary information to the GO.
Response: The Generator Owner was moved from Requirement R2 to the new Requirement R3 in order to
remove the “islanding” criteria for Generator Owners. Change made.
BC Hydro
No
BC Hydro does not agree that the criteria of R2 are reasonable. Only experience of tripping during STABLE
power swings should be used.
Response: Requirement R1 – Criterion 4, Requirement R2 – Criterion 1, and the new Requirement R3 –
Criterion 1, were clarified by adding both “stable and unstable” power swings. Both stable and unstable
power swings determine whether an Element will be identified as experiencing a power swing. Change
made.
DTE Electric
No
It would seem that the GO and TO could need input from the PC, RC and TP to determine if the conditions
are still credible, based on system studies.
Response: Requirements R2 (TO) and the new R3 (GO) require the GO and TO to report the Element that
tripped in response to a power swing. These requirements allow the Planning Coordinator to be the sole
source of funneling the “identified Elements” to the GO and TO. A fifth Criterion was added to
Requirement R1 that requires the PC to continue identifying an Element “unless the Planning Coordinator
determines the Element is no longer susceptible to power swings.” This ensures visibility of the Elements
reported by the GO or TO on an ongoing basis since the Element tripped in response to a power swing.
Change made.
Arizona Public
Service Co.
No
AZPS believes that the GO and TO are not the appropriate entities to identify the Elements that meet the
criteria in R2. The criteria of R2 would be determined based on event analysis and the GO’s and TO’s have
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Organization
Yes or No
Question 3 Comment
limited access to this information.
Response: The drafting team contends that the Protection System owner (i.e., Generator Owner and
Transmission Owner) is the appropriate entity for reviewing operations. No change made.
Also, there are often joint participation projects which then include multiple owners. This would create
confusion regarding who is supposed to complete the analysis. AZPS recommends that the RC be required
to provide this information since they are necessarily involved in all significant system event analyses.
Response: While a BES interrupting device may be contractually owned by multiple entities that are not
jointly registered, all of the entities would ultimately be responsible for the requisite documentation and
results. Contractually organized entities may share or designate compliance responsibilities as well as
associated documentation. No change made.
Bureau of
Reclamation
No
The Bureau of Reclamation (Reclamation) believes that the Transmission Planner or Planning Coordinator
would be in the best position to determine whether Disturbances continue to be credible. Therefore,
Reclamation suggests that the Transmission Planner or Planning Coordinator would be in the best position
to identify the Elements in R2. The Transmission Planner or Planning Coordinator should be required to
notify the Transmission Owner or Generator Owner of which Elements meet the criteria so that the
Transmission Owner or Generator Owner can perform the R3 analysis.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
Reclamation also suggests that the criteria be rephrased to require analysis of data from the previous year
only. As written, R2 would require Transmission Owners and Generator Owners to re-analyze data going
back to 2003 each year.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
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Organization
Yes or No
Question 3 Comment
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Reclamation believes that the costs of re-analyzing this data would outweigh the benefits. Reclamation
believes that NERC should develop a data request to develop a robust initial data set covering January
2003 to present.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
Luminant
Generation
Company LLC
No
Public Service
Enterprise Group
No
See the response to Question 1. If R2 were modified as proposed in Question 1, then Luminant would
agree that these are the appropriate entities.
Response: Thank you for your comment. Please see response to Question 1.
We disagree with the need for this standard. However, this requirement is so egregious with regard to
one item that we offer these comments so that similar language may never appear in any future
standards.R2 requires GOs and TOs to evaluate Disturbance records “since January 1, 2003,” a time that
will precede the effective date of this standard. A requirement cannot rely upon records that precede the
effective date of a standard. As an example, PRC-005-1, which was approved in Order 693, became
effective on June 11, 2007, does not require a Registered Entity to have maintenance records available for
the period of time that preceded the effective date in order to calculate the next maintenance interval for
a relay.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
American Electric
Power
No
Generator Owners may not have the information or expertise needed to determine if their Element
formed the boundary of an island (R2 Criteria 2) or if the Disturbance that caused a trip or islanding
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Organization
Yes or No
Question 3 Comment
condition remains to be credible.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2.
The drafting team modified Requirement R1, Criterion 3 – to include island boundaries due to angular
instability within an underfrequency load shedding (UFLS) assessment (i.e., PRC-006), and moved the
Generator Owner to the new Requirement R3 in order to remove the “islanding” criteria for Generator
Owners. Change made.
It is unclear how the operation of Automatic Load Rejection (ALR) on a power generation unit during a
system event affects applicability to R2 of the standard. The proper operation of a unit’s ALR controls
should not result in its automatic inclusion. Clarity is needed in this standard so that only those relays that
operated for the observed or simulated power swings in R1 or R2 are applicable to R3.
Response: Automatic Load Rejection controls are not load-responsive and therefore are not applicable to
this standard. PRC-026-1 – Attachment A has been added to clarify the protective relay elements that are
subject to the standard. Change made.
Tacoma Power
No
Tacoma Power disagrees with the need for this standard.
Response: Thank you for your comment.
ISO New England
No
In R2, it is unrealistic to require an entity to provide data on an Element that had tripped since 2003.
There is no existing NERC continent-wide disturbance monitoring or misoperation standard that requires
data be retained more than 12 months. We recommend that this requirement be removed from the
standard or include only Elements that were tripped in the last calendar year.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
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Organization
New York Power
Authority
Yes or No
No
Question 3 Comment
The Planning and Reliability Coordinator (ISO in our region) would have records of such disturbances for
their control areas. TOs and GOs defer to the ISO to render all final decisions and designations in these
types of matters.
Response: Thank you for your comment.
MRO NERC
Standards Review
Forum
Yes
Tennessee Valley
Authority
Yes
SPP Standards
Review Group
Yes
Dominion
Yes
Florida Power &
Light
Yes
Duke Energy
Yes
Duke Energy does not agree with the TO and GO combing through 12 years of historical data and
determining the events that were a result of a power swing. In addition, the GO and TO would have to
maintain documentation of power swing events that have occurred since 2003 for every compliance audit.
This would cause an unnecessary administrative burden on the responsible entity and should be viewed as
a P81 candidate. A more appropriate set of criteria would be for the TO and GO to identify Elements in R2
that have occurred in the previous calendar year or in the previous audit cycle.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
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Organization
Yes or No
Question 3 Comment
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Florida Municipal
Power Agency
Yes
There is a significant issue with R2 in that it “requires” entities to have records before 1/1/2003. Entities
had no knowledge of needing to retain such records (i.e., the cause of a relay trip as a stable power
swing). Even if PRC-004 misoperations are the source of such data, there is no requirement to retain
records for longer than 12 months (PRC-004 has a 12 month data retention in Section D1.4), and certainly
not before June 18, 2007. The requirement should only be on a going forward basis, not going back.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Note also that “Element” is the wrong term and “Facility” should be used. “Element applies to both BES
(including distribution) and non-BES, Facilities is BES. Standards cannot be written to distribution.
Response: Section 4.2, Facilities provides sufficient language that the standard is applicable to only “BES
Elements.” No change made to the standard based upon the comment.
Puget Sound Energy
Yes
Bonneville Power
Administration
Yes
Ingleside
Cogeneration LP
Yes
Los Angeles
Department of
Water and Power
Yes
Masschusetts
Yes
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Organization
Yes or No
Question 3 Comment
Attorney General
MidAmerican
Energy Company
Yes
Consolidated
Edison, Inc.
Yes
See comment #4 under Question #1. In R2, it is unrealistic to require an entity to provide data on an
Element that had tripped since 2003. There is no existing NERC continent-wide disturbance monitoring or
misoperation standard that requires data be retained more than 12 months. We recommend that this
requirement be removed from the standard or include only Elements that were tripped in the last
calendar year.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Electric Reliability
Council of Texas,
Inc.
Yes
American
Transmission
Company, LLC
Yes
Manitoba Hydro
Yes
Independent
Electricity System
Operator
Yes
We agree that the Generator Owner and Transmission Owner are the appropriate entities to identify the
Elements that meet the criteria in Requirement R2. However, we question the relevance or need to trace
back to 2003 for Disturbances that caused an Element to trip due to a power swing or which formed the
boundary of an island.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
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Organization
Yes or No
Question 3 Comment
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Further, the term credible Disturbance needs clarification. Please see our comment under Q1, above.
Response: Thank you for your comment. Please see the response in Question 1 above.
David Kiguel
Yes
Ameren
Yes
Exelon
Yes
Oncor Electric
Delivery LLC
Yes
As currently drafted, R2 requires GOs and TOs to evaluate Disturbance records “since January 1, 2003,” a
time that will precede the effective date of this standard. A requirement cannot rely upon records that
precede the effective date of a standard. As an example, PRC-005-1, which was approved in Order 693,
became effective on June 11, 2007, does not require a Registered Entity to have maintenance records
available for the period of time that preceded the effective date in order to calculate the next
maintenance interval for a relay. CAN-0008 specifically states “CEAs are not to require registered entities
to produce records of testing and maintenance activities conducted prior to June 18, 2007, because
keeping such records was not mandatory at that time. Therefore, CEAs are only to require production of
actual maintenance and testing records from June 18, 2007 forward.” Oncor would hope the same applies
across all Standards and Requirements.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Texas Reliability
Entity
Yes
The GO and TO are the appropriate responsible entities. The timeframe appears identified in Criteria 1
and 2 back to January 1, 2003 appears onerous. The Northeast Blackout should provide the impetus to
look at power swings but may not need to be the basis for the timeframe. Suggestion is to leave date out;
auditor discretion would tend to indicate “since last audit”.
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Organization
Yes or No
Question 3 Comment
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Clarification is requested for Criteria 1 and 2 regarding the term “credible”; who is responsible for
determining “credible” (is it tied to TPL-001-4)?
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2. Change made.
ITC
Yes
We agree the GO and TO are the appropriate entities. However, we suggest removing the inclusion of
events prior to the effective date of this standard.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Northeast Utilities
Yes
See comment #4 under Question #1. In R2, it is unrealistic to require an entity to provide data on an
Element that had tripped since 2003. There is no existing NERC continent-wide disturbance monitoring or
misoperation standard that requires data be retained more than 12 months. We recommend that this
requirement be removed from the standard or include only Elements that were tripped in the last
calendar year.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Idaho Power Co.
Yes
Yes if the Requirement is better written to address the comments of question 1. In addition, the GOP and
TOP may also need to be included to fully identify disturbances.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
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Question 3 Comment
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
R2 requires entities to rely on records prior to the effective date of the standard - records the entities did
not know they were required to keep for this purpose. Either strike R2 or change the wording such that R2
applies to Disturbances that have happened after the effective date of the standard
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
Southern California
Edison Company
Yes
Public Utility District
No. 1 of Cowlitz
County, WA
Yes
Salt River Project
Yes
Xcel Energy
Yes
Provided the SDT finds a way to clearly establish the documentation from which the GO and TO will
identify the Elements.
Response: The drafting team modified Requirement R1, Criterion 3 – to include island boundaries due to
angular instability within an underfrequency load shedding (UFLS) assessment (i.e., PRC-006), and moved
the Generator Owner to the new Requirement R3 in order to remove the “islanding” criteria for
Generator Owners. Change made.
This requirement is a labor intensive, and it is meaningless to perform annually as the system dynamics do
not change as fast. It should be recommended to change the frequency to every 4 years.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
Further, it is unreasonable to set up the criteria to date back to 2003; this should be 4 years from the date
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Question 3 Comment
of approval at maximum.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
There is no mechanism specified to permit Generation and Transmission Owners to challenge the results
of R2. In the event of a dispute, who arbitrates?
Response: The Generator Owner (GO) in Requirement R3 and Transmission Owner (GO) in Requirements
R2 are required to report the Element that tripped in response to a power swing. These requirements
allow the Planning Coordinator to be the sole source of funneling the “identified Elements” to the GO and
TO. A fifth Criterion was added to Requirement R1 that requires the Planning Coordinator (PC) to continue
identifying an Element “unless the PC determines the Element is no longer susceptible to power swings.”
This ensures visibility of the Elements reported by the GO or TO on an ongoing basis since the Element
tripped in response to a power swing. The term “credible” has been removed from the standard. Change
made.
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4. Do you agree with the approach in Requirement R3 to ensure that load-responsive protective relays do not trip in response to stable power
swings during non-Fault conditions for an identified Element? If not, please explain.
Summary Consideration: Overwhelmingly 68% of commenter disagreed with the approach in Requirement R3 to ensure that load-responsive
protective relays do not trip in response to stable power swings during non-Fault conditions for an identified Element. There were two significant
revisions based on comments. The first revision came as a result of 14 comments supported by 88 stakeholders that, in summary, were confused
about the performance of Requirement R3 (now R4 in draft 2). To address all of the concerns, the previous Requirement R3 was split into a new
Requirement R4 (evaluation) and a new R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new Requirement R4 requires an evaluation of the
existing load-responsive protective relays against the criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective
relays do not meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action Plan (CAP) to modify the
Protection System to meet the PRC-026-1 – Attachment B Criteria while maintaining dependable fault detection and dependable out-of-step
tripping (if out-of-step tripping is applied at the terminal of the Element).
Second, 8 comments by 39 individuals questioned what is a “load-responsive protective relay.” The term and type of relay is widely understood and
is any protective functions which could trip with or without time delay on load current. To address the concerns, a clarification has been provided
in PRC-026-1 – Attachment A to not only list what is included, but also certain exclusions.
Organization
Northeast Power
Coordinating Council
Yes or No
Question 4 Comment
No
The Purpose of the standard is “To ensure that load-responsive protective relays do not trip in response to
stable power swings during non-Fault conditions.” The last sentence of Background, Section 5 implies that
a protective relay, while blocking for a stable power swing also allows for dependable operation for fault
and unstable power swing. Requirement R3 Bullet #4 is contrary to the Purpose of the standard. The subParts of R3 Bullet 4 are “or”, which means that if there isn’t dependable fault detection or dependable
out-of-step tripping, agreement would just have to be obtained from the respective Planning Coordinator,
Reliability Coordinator, and Transmission Planner of the Element that the existing Protection System
design and settings are acceptable. The sub-Parts of R3 Bullet should be an “and”. Item b under the fourth
bullet in Requirement R3 is not stated using clear and unambiguous language whereby responsible
entities, using reasonable judgment, are able to arrive at a consistent interpretation of the required
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Question 4 Comment
performance. The R3 Rationale and the Protection System Response to Power Swings technical document
provide some clarity; however, the fourth bullet is not clear and troublesome from a compliance
perspective. Suggest to consider revising the fourth bullet to ensure the responsible entity understands
the balance between security and dependability and how that is to be achieved by either sub-parts “a” or
“b”. The standard does not specify any time parameters for developing and correcting the conditions
addressed by a CAP. We suggest that time parameters for developing and correcting the conditions
addressed by the CAP be addressed within the requirements of the standard.
Response: The Purpose statement was modified to note that the purpose is to ensure that relays “are
expected to not trip.” The previous Requirement R3 has been split into a new Requirement R4
(evaluation) and a new R5 (corrective action). The new Requirement R4 requires an evaluation of the
existing load-responsive protective relays against the criteria now defined in PRC-026-1 – Attachment B. If
the existing load-responsive protective relays do not meet the criteria, the new Requirement R5 requires
the applicable entity to develop a Corrective Action Plan (CAP) to modify the Protection System to meet
the PRC-026-1 – Attachment B Criteria while maintaining dependable fault detection and dependable outof-step tripping (if out-of-step tripping is applied at the terminal of the Element). Change made.
Response: The Corrective Action Plan (CAP) has its own timetable and set of actions that are determined
by the entity. The work necessary under the CAP may vary greatly depending on the work being
performed; therefore, the drafting team has not specified any timeframes. No change made.
MRO NERC
Standards Review
Forum
No
Tennessee Valley
Authority
No
The NSRF requests that the SDT provide additional details on how the Lens characteristic is derived and
examples of its use with the system parameters that were calculated from the example.
Response: Additional clarifications and examples have been added to the Guidelines and Technical Basis.
Change made.
1) Every year is too often for this requirement. We recommend changing this to every 5 years.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
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Question 4 Comment
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
2) We believe that the criterion is too specific for a regulatory document. It should allow entities to use
their preferred methods for determining if a line is likely to trip during a stable power swing. Recommend
changing the first bullet to: "...in response to a stable power swing based on either the criterion below or
by another industry accepted method.”
Response: The criteria included in the standard are consistent with the NERC System Protection and
Control (SPCS), Protection System Response to Power Swings, August 20138 (PSRPS Report). The basis for
the criteria is documented in the Guidelines and Technical Basis. The drafting team has concluded that a
single method for evaluating load-responsive protective relays is the most effective and efficient approach
to achieve the reliability objective of the FERC order. No change made.
3) At the end of the fourth bullet it states “dependable out-of-step tripping”. We recommend changing
this to “dependable unstable power swing tripping”.
Response: The drafting team asserts that out-of-step tripping is understood as occurring during unstable
power swings. No change made.
SPP Standards
Review Group
No
We question the need for the annual assessment required in Requirement R3. PRC-005-2 satisfactorily
covers the routine maintenance and testing of protective relays and this requirement would be redundant
with those requirements. Additionally, only system changes (topology changes, load/generation changes,
etc.) would impact the application of the relays applicable to this requirement. Thus they should only
need to be reviewed or re-assessed if those types of changes occurred on the system.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
8
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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Question 4 Comment
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
We suggest that the 4th bullet under Requirement R3 be made a notification rather than the existing
agreement. As stated, the requirement for agreement places unintended risk on the Planning
Coordinator, Reliability Coordinator and Transmission Planner. While we agree that if there is no
dependable fault detection or out of step tripping the Planning Coordinator, Reliability Coordinator and
Transmission Planner would need to be notified, we are unclear how these registered functional entities
would have the knowledge of each applicable entity’s protection systems to be able to agree to a correct
relay setting. Would the fact that the Planning Coordinator, Reliability Coordinator and Transmission
Planner accepted the settings place the responsibility of a cascading event due to the undependable fault
detection or out of step tripping on the shoulders of these entities? This risk should be solely placed with
the experts that design and maintain protection systems.
Both a. and b. under the last bullet of Requirement R3 require the Generator Owner and Transmission
Owner to obtain agreement with the Planning Coordinator, Reliability Coordinator and Transmission
Planner yet nothing in the standard requires the Planning Coordinator, Reliability Coordinator or
Transmission Planner to provide that agreement. Generator Owner and Transmission Owner compliance
may hinge on that agreement but there is no incentive for the Planning Coordinator, Reliability
Coordinator or Transmission Planner to reach that agreement. We concur with AEP in that rather than
requiring agreement, the requirement should only require notification of the Planning Coordinator,
Reliability Coordinator and Transmission Planner by the Generator Owner and Transmission Owner.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
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Question 4 Comment
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). Change made.
Southern Company:
Southern Company
Services, Inc.;
Alabama Power
Company; Georgia
Power Company;
Gulf Power
Company;
Mississippi Power
Company; Southern
Company
Generation;
Southern Company
Generation and
Energy Marketing
No
The method defined in R3 should be an option for determining susceptibility of a given relay, but the
requirement should be for the responsible entity to develop criteria to determine susceptibility of a given
relay to tripping for stable power swings and then other requirements to demonstrate the adherence to
and compliance with those criteria.
Response: The criteria included in the standard are consistent with the NERC System Protection and
Control (SPCS), Protection System Response to Power Swings, August 20139 (PSRPS Report). The basis for
the criteria is documented in the Guidelines and Technical Basis. The drafting team has concluded that a
single method for evaluating load-responsive protective relays is the most effective and efficient approach
to achieve the reliability objective of the FERC order. No change made.
If the prescriptive method of R3 remains in the standard, R3, bullet #4 (b), should explicitly state that it is
acceptable for the modifications specified in the CAP not to result in meeting the criteria of R3.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element).
The drafting team contends that meeting the criteria in Requirement R4 (previously R3) while maintaining
9
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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Yes or No
Question 4 Comment
dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is applied at the
terminal of the Element) is achievable. Therefore, the items ‘a’ and ‘b’ under previous Requirement R3,
bullet #4 were removed from the standard. The criteria in the PRC-026-1 – Attachment B referenced in
Requirement R4 (previously R3) allows some flexibility in the separation angle if supported by a
documented stability analysis. Change made.
ISO RTO Council
Standards Review
Committee
No
R3 and its bulleted items need to be clarified that they apply to the load-responsive relays only, to be
consistent with the purpose and scope of the standard, not the Protection System which could include
other protective relays or components. However, if the standard is to ensure that Elements do not trip in
response to stable power swings during non-Fault conditions, then all references to Protection Systems
should be replaced with load-responsive relays.
Response: The term “load-responsive protective relays” is widely understood and is any protective
functions which could trip with or without time delay, on load current. A clarification has been provided in
PRC-026-1 – Attachment A.
The drafting team split the previous Requirement R3 into a new Requirement R4 (evaluation) and R5
(corrective action) and included the phrase “load-responsive protective relays” where it uniquely applies
to a Protection System. Change made.
We are concerned that holding relay engineers to limit load-responsive protection schemes to meet these
settings in order to be compliant may not always be in the best interest of bulk power system reliability.
Although it is good practice to see that facilities can withstand transients that are expected to dissipate
and not pose a recurring threat to the grid, requiring these settings to always be adhered to takes away
the ability for the relay engineer to apply engineering judgment if there are conflicting needs to allow for
tripping the load-responsive relays in order to protect from another more imposing system threat. These
relays are primarily to protect from a specific condition identified by studied and credible faults. This
setting may be inside the trip circle identified by the stable power swing. In these cases, the relay engineer
makes a best judgment to ensure a balance between which threat is more relevant or immediate to make
the appropriate setting. The standard should allow for entities to provide technical evidence that a load-
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Question 4 Comment
responsive relay may have to be set within a trip circle of a stable power swing, if there is no other
protection scheme available to mitigate the primary threat.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). Change made.
Dominion
No
Item b under the 4th bullet in Requirement R3 is not stated using clear and unambiguous language
whereby responsible entities, using reasonable judgment, are able to arrive at a consistent interpretation
of the required performance. The R3 rationale and the Protection System Response to Power Swings
technical document provide some clarity; however, the simple fact is the 4th bullet is not clear and
troublesome from a compliance perspective. Dominion suggest revising the 4th bullet to ensure the
responsible entity understands the balance between security and dependability and how that is to be
achieved by either sub-parts a or b.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
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Question 4 Comment
applied at the terminal of the Element).
The drafting team contends that meeting the criteria in Requirement R4 (previously R3) while maintaining
dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is applied at the
terminal of the Element) is achievable. Therefore, the items ‘a’ and ‘b’ under previous Requirement R3,
bullet #4 were removed from the standard. The criteria in the PRC-026-1 – Attachment B referenced in
Requirement R4 (previously R3) allows some flexibility in the separation angle if supported by a
documented stability analysis. Change made.
FirstEnergy Corp.
No
It would be most helpful to specify protective functions (e.g., 78, 21, 67, 40?) to be included in this
analysis, similar to what was done with the Criteria Tables in PRC-025.
If the reference to “load-responsive protective relay” in PRC-026-1 R2 means the same as where this
terminology is used (and defined) in PRC-025, the scope of work required for the detailed analysis
specified in PRC-026-1 R3 is quite significant.
Response: The term “load-responsive protective relays” is widely understood and is any protective
functions which could trip with or without time delay, on load current. A clarification has been provided in
PRC-026-1 – Attachment A. Change made.
Technical resources to perform this analysis on each applicable relay could be difficult for many GOs to
commit or obtain, and it would be difficult to accomplish the analyses in a short timeframe. One year is
unrealistic, especially considering the concern stems from an incident that occurred nearly eleven years
ago.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard.
The drafting team revised Requirement R4 (previously R3) from “each calendar year” to “within 12 full
calendar months of receiving notification of an Element pursuant to Requirement R1 or within 12 full
calendar months of identifying an Element pursuant to Requirement R2 or R3,” “where the evaluation has
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Question 4 Comment
not been performed in the last three calendar years.” Change made.
Further, an annual demonstration with associated evidence is potentially financially burdensome, and
seemingly unnecessary if there are no changes to a Unit’s protection system. Changes to applied
protection are already captured via the coordination requirement in PRC-001, and are available to the PC,
RC and TP.
Response: The drafting team modified the Implementation Plan (to 36 months) and several Requirements
to provide additional time to reduce the burden. Also, the standard is consistent with the PSRPS Report
which recommends a focused approach to identifying Elements that are most susceptible to power swings
and therefore reduces the financial burden by not requiring all relays to be in scope. Changes made.
Again, in a regulated vs. competitive environment, it may be difficult to obtain system data needed for
such calculations. However, if the only piece of information needed from the TO is a Thévenin impedance
(system equivalent) at the Point of Interconnection, acquiring this should not be a problem.
Response: The Application Guidelines have been clarified that the only requirement for the GO is to have
the Thévenin impedance (system equivalent). Change made.
PPL NERC Registered
Affiliates
No
We agree with R3 in principle, but there are presently some barriers to the specified stand-alone nature of
GO and TO obligations:
- The statement, “Demonstrate that the existing Protection System is not expected to trip in response to a
stable power swing based on the criterion below,” in R3 should be replaced by, “Demonstrate that the
existing Protection System is programmed per the criterion below.” The reason for this change is that,
while the criterion on p.6 of PRC-026-1 is the appropriate “textbook” way of setting-up an out-of-step
relay, the genuinely authoritative means of showing that tripping will not occur for stable power swings is
by use of a transient stability program as discussed in the first paragraph on p.24 of the Application
Guidelines. Such programs are far from simple to set-up and operate however, GOs do not typically have
or run them, and the system data required is known only to the TO and TOP. The requirements and
Application Guidelines should make it clear that GOs have no involvement with transient stability
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programs.
Response: The drafting team modified the criteria now contained in PRC-026-1 – Attachment B from “an
angle less than 120 degrees as agreed upon” to “an angle less than 120 degrees where a documented
stability analysis demonstrates the expected maximum stable separation angle is less than 120 degrees.”
Change made.
The Guidelines and Technical Basis have been supplemented to address the concern of how to perform
the evaluation of the relays. Examples demonstrate a means other than the use of stability analysis
programs. The same techniques or concepts used in transmission applications are also used for generator
applications. Change made.
- The statement, “For cases where infeed affects the apparent impedance (multiple unit connected
generators connected to a transmission switchyard), the Generator Owner will provide the unit and relay
data to the Transmission Planner for analysis,” indicates that compliance responsibility can as a matter of
practicality shift to another entity under certain circumstances, but the requirements do not ensure that
such transactions happen. The, “obtain agreement,” alternatives under the 4th bull-dot of R3 do not
obligate the PC/RC/TOP to perform studies or take other actions to help facilitate compliance under R3.
PRC-026-1 needs revision to explicitly define the circumstances and mechanisms for multiple-entity
collaboration in performing analyses.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). Change made.
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Florida Municipal
Power Agency
Yes or No
No
Question 4 Comment
See response to Question 1, the TO/GO should only respond to those issued identified by the PC/TP and
not all Facilities that meet the criteria of R1.
Response: The drafting team asserts that it has implemented an approach consistent with the
recommendations of the NERC System Protection and Control Subcommittee (SPCS) technical report,
Protection System Response to Power Swings, August 201310 (PSRPS Report). The standard does not
preclude the Planning Coordinator providing information to the Generator Owner or Transmission Owner
about the Element and any known stability issues, power swings, or apparent impedance characteristics;
however, the Elements need to be reported as a part of ensuring the Generator Owner and Transmission
Owner are aware of Elements that are susceptible. Change made.
DTE Electric
No
Based on the criterion for R3, it appears that only impedance relays are in scope. What about other relay
types? Specific criteria for all relay types should be provided along with examples on how to demostrate a
no trip response.
Response: The term “load-responsive protective relays” is widely understood and is any protective
functions which could trip with or without time delay, on load current. A clarification has been provided in
PRC-026-1 – Attachment A. Change made.
Arizona Public
Service Co.
No
AZPS would recommend changing Protection System to load-responsive protective relays and define what
type of relays qualifies as load-responsive protective relays. If the drafting team does not agree with
defining load-responsive relays, they should specifically state the relay type (i.e. zone protection) rather
than using the broader term Protection System.
Response: The term “load-responsive protective relays” is widely understood and is any protective
functions which could trip with or without time delay, on load current. A clarification has been provided in
10
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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Question 4 Comment
PRC-026-1 – Attachment A. Change made.
Luminant
Generation
Company LLC
No
Requirement R3 focuses on a method commonly used for transmission application. Generator Owners will
not be able to use this method for elements that satisfy the criteria in Requirement R1 and R2 for
impedance relays used at the generator terminals or at the high voltage side of the Generator Step-up
Transformer. Transmission Planners have the tools and data to perform these studies. A requirement
should be added for Transmission Planners to provide the data to the Generation Owners for elements
that have stable power swings that challenge the relay. Luminant recommends the following additional
requirement. “Each Planning Coordinator, Reliability Coordinator, and Transmission Planner shall, within
the first quarter month of each calendar year provide to the identified Generator Owner or Transmission
Owner pursuant to R1, the stable power swing characteristics (i.e. R-X vs time, current vs time plots,
voltage and current vs time) and identified event information.” In addition, the criterion in Requirement
R3 considers distance relays which is a subset of load responsive relays used in Generating Facilities.
Protective relays such as loss of field, time overcurrent, and voltage controlled overcurrent relays should
be excluded and listed in an Attachment similar to PRC-023.
Response: The standard does not preclude the Planning Coordinator from providing information to the
Generator Owner (GO) or Transmission Owner (TO) about the Element and any known stability issues,
power swings, or apparent impedance characteristics; however, the Elements need to be reported as a
part of ensuring the GO and TO are aware of Elements that are susceptible.
The Guidelines and Technical Basis have been supplemented to address the concern of how to perform
the evaluation of the relays. Examples demonstrate a means other than the use of stability analysis
programs. The same techniques or concepts used in transmission applications are also used for generator
applications.
The term “load-responsive protective relays” is widely understood and is any protective functions which
could trip with or without time delay, on load current. A clarification has been provided in PRC-026-1 –
Attachment A. Change made.
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Ingleside
Cogeneration LP
Yes or No
Question 4 Comment
No
ICLP agrees that the Transmission Owner and Generator Owner is in the best position to provide the
equipment models and relay settings necessary to perform an adequate assessment. However, the
application guidelines contain several statements that infer that the Transmission Planner must be
involved in the process (e.g.; the TP must be consulted to validate the slip rates of power swing blocking
schemes or if infeed affects the apparent impedance). In our view, there must be a mandatory means to
engage the TP when such coordination is required. Otherwise, a TP could refuse to support the analysis
for any reason, leaving the TO or GO to look for other less sufficient alternatives. Even if the Transmission
Planner’s reasons are justified, the Element owner may be found in violation of R3 due to circumstances
out of their control. ICLP suggests that the same situation was addressed in the generator validation
standards - which also requires GO/TP coordination to evaluate local system performance - and could be
applied in PRC-026-1.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). The drafting team removed the Application Guidelines text
regarding “slip rates” to avoid confusion. Change made.
Public Service
Enterprise Group
No
MidAmerican
Energy Company
No
We disagree with the need for this standard.
Response: Thank you for your comment. Please see response in Question 1 above.
While the reliability concept of preventing unnecessary overtripping is understood, the NERC white paper
supporting the PRC-026 standard indicated that tripping due to stable power swings neither contributed
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to blackouts or increased the severity of blackouts since 1965.
The NERC standards drafting team should consider limiting the scope in R1 and R3 to out-of-step
transmission related protection systems specifically designed and installed to monitor weak ties between
areas or islands. These systems would open tie-lines in predetermined locations between areas in an
attempt to balance load and generation between groups of generators that swing together during the
identified power swings.
Response: The proposed standard is consistent with the PSRPS Report which recommends a focused
approach to identifying Elements that are most susceptible to power swings. No change made.
American Electric
Power
No
In reference to R3, bullet point four, sub items a and b, we do not believe it is necessary to obtain further
agreement with the PC, RC and TP, as there is no benefit to reliability (since it was not possible to achieve
dependability) and represents an unnecessary administrative burden. Rather, the TO should be required
only to *notify* the PC, RC, and TP. The bullet points of R3 should be revised to replace “Demonstrate
that the existing protection system is not expected to trip...” with “Demonstrate that the existing
Protection System satisfies the criteria...”. This would prevent the GO or TO from being found noncompliant if they were to set the relaying in accordance with the criterion, but unforeseen events caused
a relay to operate.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). Change made.
We agree with the approach, but do not believe that R3 would need to be executed annually. It should
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only need to be done once per relay until something about the relay in question or the transmission
system in the immediate vicinity changes.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
Consolidated
Edison, Inc.
No
The purpose of the standard is “to ensure that load responsive relay do not trip in response to stable
power swing during non-fault condition.” The last sentence of Background, Section 5 implies that
protective relay while blocking for a stable power swing also allows for dependable operation for fault and
unstable power swing. Bullet #4 in R3 indicates that the GO and TO must obtain agreement if dependable
protection or dependable out-of-step tripping is not provided by a protection system that is immune to a
stable power swing. Bullet #4 seems to imply that the purpose of the standard is to ensure blocking for a
stable power swing and dependable tripping for unstable power swing. The drafting team needs to be
very clear in the standard what the intention is. For instance, a line current differential scheme is immune
to stable and unstable power swing and will provide dependable tripping for fault. The criteria as written
implies that this type of scheme will need to be modified or an agreement will need to be obtained from
the PC, RC and TP to deploy since it does not provide dependable out-of-step tripping.
Response: The Purpose statement was modified to note that the purpose is to ensure that relays “are
expected to not trip.” The previous Requirement R3 has been split into a new Requirement R4
(evaluation) and a new R5 (corrective action). The new Requirement R4 requires an evaluation of the
existing load-responsive protective relays against the criteria now defined in PRC-026-1 – Attachment B. If
the existing load-responsive protective relays do not meet the criteria, the new Requirement R5 requires
the applicable entity to develop a Corrective Action Plan (CAP) to modify the Protection System to meet
the PRC-026-1 – Attachment B Criteria while maintaining dependable fault detection and dependable outof-step tripping (if out-of-step tripping is applied at the terminal of the Element). Change made.
An exclusion for current differential relay, pilot wire relay, and phase comparison relay was added to
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Question 4 Comment
Attachment A.
American
Transmission
Company, LLC
No
Independent
Electricity System
Operator
No
ATC requests that the SDT provide additional details on how the Lens characteristic is derived and
examples of its use with the system parameters that were calculated from the example.
Response: The Guidelines and Technical Basis have been supplemented to address the concern of how to
perform the evaluation of the relays. Change made.
R3 and its bulleted items need to be clarified that they apply to the load-responsive relays only, to be
consistent with the purpose and scope of the standard, not the Protection System which could include
other protective relays or components. However, if the standard is to ensure that Elements do not trip in
response to stable power swings during non-Fault conditions, then all references to Protection Systems
should be replaced with load-responsive relays.
Response: The drafting team split the previous Requirement R3 into a new Requirement R4 (evaluation)
and R5 (corrective action) and included the phrase “load-responsive protective relays” where it uniquely
applies to a Protection System. Change made.
Bullet number four requires to prove dependable out-of-step tripping. However the entity may decide to
use selective tripping when out- of-step conditions are detected. Studies show that in case of severe
disturbance selective tripping when out-of step conditions are detected can increase the chance of
creating successfully islands. We suggest changing the wording from “dependable out-of-step tripping” to
“dependable out-of-step detection”.
Response: Requirement R4 (previously R3) and the new Requirement R5 were modified to provide clarity
that dependable out-of-step tripping only applies if out-of-step tripping is applied at the terminal of an
Element. Change made.
Tacoma Power
No
Tacoma Power disagrees with the need for this standard. However, assuming FERC does not provide
reflief from its directive to develop this standard, the transient, rather than sub-transient, impedance may
represent a better model. Granted, as noted in the Application Guidelines, the sub-transient impedance
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would yield a more conservative assessment.
Response: The drafting team made a modification to allow entities the option of using transient or subtransient reactance. Change made.
Ameren
No
Even though we may be able to accept and appreciate the SDT’s approach; our recommended changes to
this approach are as follows:
(1) Change 1st sentence of Criterion to “Only load sensitive, high speed distance relays are within scope
(e.g. zone 1 phase distance, pilot zone phase distance). For such a distance relay impedance characteristic,
used for tripping, that is completely....” which adds the first sentence for clarity. We believe that this
comment is consistent with the SDT’s answers in NERC’s 5/12/2014 webinar.
Response: A clarification has been provided in PRC-026-1 – Attachment A. For example, relay elements
that are intended to trip after time delays of 15 cycles or greater are excluded. Change made.
(2) Change Criterion #3 to transient reactance, because it aligns better with power swing time constants
(see Reimert text pages 40, 289, 291, and particularly bottom of page 302).
Response: The drafting team made a modification to allow entities the option of using transient or subtransient reactance. Change made.
(3) Change ‘once each calendar year’ to ‘within 2 calendar years of initial identification, and once every 5
calendar years thereafter’ because once each calendar year is too frequent.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
ISO New England
No
The option under the fourth bullet requires that the Generator Owner and Transmission Owner obtain
agreement from the respective Planning Coordinator, Reliability Coordinator and Transmission Planner of
the Element that either: (a) the existing Protection System design and settings are acceptable, or (b) a
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Question 4 Comment
modification of the Protection System design, settings or both are acceptable and develop a corrective
action plan for this modification of the corrective action plan. This requires specialized knowledge and
coordination that is not typical for Planning and Reliability Coordinators.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). Change made.
New York Power
Authority
No
The more relevant approach, as is recommended by the PSRPS technical document, is that you do take
corrective actions for unstable power swings. This was determined to be a far greater concern than not
taking actions for stable swings.
Response: The previous Requirement R3 has been split into a new Requirement R4 and a new R5. The
new Requirement R4 requires an evaluation of the existing relays against the criteria now defined in PRC026-1 – Attachment B. If the existing relays do not meet the criteria, the new Requirement R5 requires an
entity to develop a Corrective Action Plan (CAP) to modify the Protection System to meet the PRC-026-1 –
Attachment B Criteria A and B while maintaining dependable fault detection and dependable out-of-step
tripping (if out-of-step tripping is applied at the terminal of the Element). These changes remove the
ambiguity around the previous Requirement R3 language. Change made.
A more accurate description of “load responsive” protective relays is also necessary.
Response: The term “load-responsive protective relays” is widely understood and is any protective
functions which could trip with or without time delay, on load current. A clarification has been provided in
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Question 4 Comment
PRC-026-1 – Attachment A. Change made.
This Standard seems to just repeat what is in the PSRPS technical document, without the necessary
elaborations needed for proper understanding.
Response: The Guidelines and Technical Basis have been supplemented to address the concern of how to
perform the evaluation of the relays. Change made.
Oncor Electric
Delivery LLC
No
ITC
No
See response to question #1.
Response: See response in Question 1.
In general we agree with this approach. However, we disagree with requiring compliance of one entity to
be contingent on another entities agreement. We recommend changing to require notification instead of
“agreement” in the fourth bullet and Criterion 1, second bullet.
Response: The Purpose statement was modified to note that the purpose is to ensure that relays “are
expected to not trip.” The previous Requirement R3 has been split into a new Requirement R4
(evaluation) and a new R5 (corrective action). The new Requirement R4 requires an evaluation of the
existing load-responsive protective relays against the criteria now defined in PRC-026-1 – Attachment B. If
the existing load-responsive protective relays do not meet the criteria, the new Requirement R5 requires
the applicable entity to develop a Corrective Action Plan (CAP) to modify the Protection System to meet
the PRC-026-1 – Attachment B Criteria while maintaining dependable fault detection and dependable outof-step tripping (if out-of-step tripping is applied at the terminal of the Element).
The agreement has been removed from Bullet #2 of the criterion (now PRC-026-1 – Attachment B). The
criterion now allows an angle less than 120 degrees to be used where a documented stability analysis
demonstrates the expected maximum stable separation angle is less than 120 degrees. Change made.
Northeast Utilities
No
The purpose of the standard is “to ensure that load responsive relay do not trip in response to stable
power swing during non-fault condition.” The last sentence of Background, Section 5 implies that
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protective relay while blocking for a stable power swing also allows for dependable operation for fault and
unstable power swing. Bullet #4 in R3 indicates that the GO and TO must obtain agreement if dependable
protection or dependable out-of-step tripping is not provided by a protection system that is immune to a
stable power swing. Bullet #4 seems to imply that the purpose of the standard is to ensure blocking for a
stable power swing and dependable tripping for unstable power swing. The drafting team needs to be
very clear in the standard what the intention is. For instance, a line current differential scheme is immune
to stable and unstable power swing and will provide dependable tripping for fault. The criteria as written
implies that this type of scheme will need to be modified or an agreement will need to be obtained from
the PC, RC and TP to deploy since it does not provide dependable out-of-step tripping.
Response: The Purpose statement was modified to note that the purpose is to ensure that relays “are
expected to not trip.” The previous Requirement R3 has been split into a new Requirement R4 and a new
R5. The new Requirement R4 requires an evaluation of the existing relays against the criteria now defined
in PRC-026-1 – Attachment B. If the existing relays do not meet the criteria, the new Requirement R5
requires an entity to develop a Corrective Action Plan (CAP) to modify the Protection System to meet the
PRC-026-1 – Attachment B Criteria A and B while maintaining dependable fault detection and dependable
out-of-step tripping (if out-of-step tripping is applied at the terminal of the Element). An exclusion for
current differential relay, pilot wire relay, and phase comparison relay was added to PRC-026-1 –
Attachment A. Change made.
Idaho Power Co.
No
No. The Requirement as written is onerous to perform annually. Performing these checks during an initial
implementation period for the standard is appropriate to ensure the relays will perform as designed (for
tripping or blocking). After an initial assessment period, a re-check at longer intervals or triggered by
system changes would also be appropriate.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
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Question 4 Comment
Further, as currently written, the R3 language requires one of the 4 bulleted items to be done, but the
language on the 4th bullet implies that the first three be attempted first. If the first three are to be done
prior to the 4th, should that bullet not be its own Requirement, such as an R3.1?
Response: The previous Requirement R3 has been split into a new Requirement R4 and a new R5. The
new Requirement R4 requires an evaluation of the existing relays against the criteria now defined in PRC026-1 – Attachment B. If the existing relays do not meet the criteria, the new Requirement R5 requires an
entity to develop a Corrective Action Plan (CAP) to modify the Protection System to meet the PRC-026-1 –
Attachment B Criteria A and B while maintaining dependable fault detection and dependable out-of-step
tripping (if out-of-step tripping is applied at the terminal of the Element). These changes remove the
ambiguity around the previous Requirement R3 language. Change made.
The general approach is reasonable but an annual review is excessive. Bi-annually at the most and then by
exception for any relay or system changes.
Response: See response to first comment.
Southern California
Edison Company
No
Although we appreciate the drafting team's efforts, we believe that Requirement R3 is unnecessarily
burdensome from a compliance perspective. We would suggest that the analyses of Elements be
performed on an initial basis, and then when changes occur. An annual analyses of all the Elements assets
is not efficient or warranted.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
PacifiCorp
Yes
ACES Standards
Yes
(1) We agree generally with the approach but note that there are specific issues.
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Question 4 Comment
(2) First, we disagree with the sub-bullet requiring the GO or TO to obtain agreement from the PC, TP, and
RC to retain existing Protection System settings to maintain dependable fault detection. Dependable fault
detection is a safety issue. A TO or GO should not have to get agreement to maintain Protection System
settings that are safe. The TO and GO should notify the PC, TP, RC and TOP of such issues and then the PC
and TP can plan the system accordingly (i.e. meet the TPL standards) and the TOP can operate the system
accordingly (i.e. meet the IROL standards).
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). Change made.
(3) Obtaining the agreement of the PC, RC, and TP is problematic and repeats similar problems that are
associated with PRC-023 R3. PRC-023-2 R3 requires the GO, TO, and DP to obtain the agreement of the PC,
RC and TOP to set the relay loadability using certain criteria. The problem is there is no obligation for the
PC, RC or TOP to agree and they often are reluctant to agree due to legal liability. In other words, no one
really knows what they are agreeing to or the implications except that the standard requires it. These
same problems will be experienced here with this requirement. The need for the PC, TP and RC to agree
should be removed or more specification should be provided for what this means.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
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Organization
Yes or No
Question 4 Comment
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). Change made.
(4) For the criterion, we disagree with the need to require the PC, RC, and TP to agree to use a system
separation angle of less than 120 degrees. All that should be required is for the TO or GO to provide sound
engineering justification for using an angle less than 120 degrees.
Response: The drafting team modified the criteria now contained in PRC-026-1 – Attachment B from “an
angle less than 120 degrees as agreed upon” to “an angle less than 120 degrees where a documented
stability analysis demonstrates the expected maximum stable separation angle is less than 120 degrees.”
Change made.
Duke Energy
Yes
BC Hydro
Yes
Puget Sound Energy
Yes
While this approach seems reasonable, there is currently a lack of ability to model the load-responsive
protective relays to determine whether a protection system is expected to trip in response to a stable
power swing. While this capability is currently being implemented, it will not be completed by the
proposed implementation date of this standard.
Response: The drafting team asserts that the standard does not require the inclusion of relay models.
Requirement R1, Criterion 4 is not requiring a study, but the identification of any Element that was
observed as tripping in the most recent Planning Assessment pursuant to TPL-001-4, R4, Part 4.3.1.3 –
“Tripping of Transmission lines and transformers where transient swings cause Protection System
operation based on generic or actual relay models” which becomes effective January 1, 2015 (U.S.). Other
clarifying changes were made to Requirement R1, Criterion 4.
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Organization
Bonneville Power
Administration
Yes or No
Yes
Question 4 Comment
BPA believes R3 should be modified for greater clarity and to allow for intentional power swing relays
designed to be tripped in a controlled manner to protect the BES. Additionally, the wording in the fourth
bullet appears to be inconsistent with the Rationale for R3.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). Change made.
Bureau of
Reclamation
Yes
Masschusetts
Attorney General
Yes
Manitoba Hydro
Yes
David Kiguel
Yes
Exelon
Yes
Texas Reliability
Entity
Yes
Suggest substituting “R1 and R2” for “R1 or R2” to avoid the possibility of confusion. As written, it could
be construed that GOs and TOs can choose to address either R1 or R2 and not address both R1 and R2.
Response: The drafting team contends that the “or” in Requirement R3 (now R4) is correct. The Generator
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Organization
Yes or No
Question 4 Comment
Owner and Transmission Owner must evaluate its relays for each Element identified by the Planning
Coordinator in Requirement R1, the Transmission Owner in Requirement R2, or Generator Owner in
Requirement R3.
Salt River Project
Yes
Xcel Energy
Yes
This requirement is a labor intensive, and it is meaningless to perform annually as the system dynamics do
not change as fast. It should be recommended to change the frequency to every 4 years.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
When seeking agreement from the Planning or Reliability Coordinator that existing settings or specific
modifications are adequate, a specified response time is required to permit alternate actions to be
undertaken, should agreement not be obtained.
Response: The previous Requirement R3 has been split into a new Requirement R4 (evaluation) and a new
R5 (corrective action). The requirement for reaching agreements with the Planning Coordinator, Reliability
Coordinator, and Transmission Planner has been eliminated from Requirements R4 and R5. The new
Requirement R4 requires an evaluation of the existing load-responsive protective relays against the
criteria now defined in PRC-026-1 – Attachment B. If the existing load-responsive protective relays do not
meet the criteria, the new Requirement R5 requires the applicable entity to develop a Corrective Action
Plan (CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria while
maintaining dependable fault detection and dependable out-of-step tripping (if out-of-step tripping is
applied at the terminal of the Element). Change made.
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5. Do you agree with the proposed Violation Risk Factors (VRF) and Violation Severity Levels (VSL) for the proposed requirements? If not,
please provide a basis for revising a VRF and/or what would improve the clarity of the VSLs
Summary Consideration: Sixty percent of commenters favor the proposed Violation Risk Factors (VRF) and Violation Severity Levels (VSL) for the
proposed requirements. There were no specific common comments and due to the significant changes to the Requirements in Draft 2, a summary
is not being provided.
Organization
Yes or No
Question 5 Comment
SPP Standards
Review Group
No
The VSLs for Requirement R1 should be changed in consideration to the point we made in our response to
Question 2.
Insert an ‘an’ between ‘identified’ and ‘Element’ in the VSLs for Requirement R2.
Response: Correction made.
References to 30-, 60-, and 90-calendar days should be hyphenated in the VSLs for Requirements R1, R2
and R3.
Response: The use of a hyphen as suggested is not consistent with the NERC style guide.
ACES Standards
Collaborators
No
(1) We agree that the VRFs for Requirement R1 through R3 should be no higher than medium. To be
higher than medium, a violation of the requirement would have to lead directly to cascading, instability or
system separation. Power swings were not direct causes to the August 14, 2003 blackout but rather
occurred after other events had already happened.
Response: Thank you for your comment.
(2) We disagree with the VRF for Requirement R4. Requirement R4 is an administrative requirement to
update paperwork (i.e. update the CAP). It does not and should compel completion of the CAP because it
is impossible to complete construction by a certain date due to the unpredictability (e.g. weather,
logistical, legal, or operational delays) of issues that delays construction.
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Organization
Yes or No
Question 5 Comment
Response: Requirement R6 (previously R4) requires the Corrective Action Plan to be updated in order to
show progress and for measurability of implementation. No change made.
(3) We cannot agree with the VSLs because we do not agree with the requirements. Furthermore, the
VSLs anticipate that the only violation that could occur is a time violation. VSLs that are not just timebased need to be written.
Response: The Violation Severity Levels are both performance of the activity and time-based. Generally,
the first VSLs (i.e., Low, Med, High) are for performance that was done, but late. The VSL of Severe is
generally for failure to perform the reliability activity. No change made.
PPL NERC Registered
Affiliates
No
The VSL for failure to identify an Element in accordance with R2 needs to take into account the potential
impossibility of performing a look-back to Jan. 1, 2003, as stated above.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
BC Hydro
No
BC Hydro does not agree with R1 and R2, therefore do not agree with violation risk factors or violation
severity levels.
Response: Thank you for your comment.
Florida Municipal
Power Agency
No
Since a standard is not needed in the first place, then, there should be no VRF above a Low. All
requirements should be Planning Horizon and none in Operating Horizon.
Response: Thank you for your comment.
Arizona Public
Service Co.
No
APS suggests the timelines associated with the proposed VSL for Requirement 1 be adjusted to a longer
time period if drafting team addresses the APS issue associated with the timing requirements on R1.
Response: The drafting team made revisions to the timing of Requirement R1 and did not make changes
to the incremental timing of violations for tardiness in the Violation Severity Level (VSL) for Requirement
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Organization
Yes or No
Question 5 Comment
R1 based on the NERC Guidelines for VSLs.
Public Service
Enterprise Group
No
Peak Reliability
No
We disagree with the need for this standard.
Response: Thank you for your comment. Please see response in Question 1 above.
Peak Reliability disagrees with the assignment of the multiple VSL’s for Requirements R1, R2 and R3
because the proposed VSLs simply increase the penalty for tardiness. Any delay in identifying and element
is a reliability concern. Recommend changing the VSL as follows:
R1 Lower VSL: The responsible entity identified an Element and provided notification in accordance with
Requirement R1, but was late by less than or equal to 7 calendar days.
R1 Severe VSL: The responsible entity failed to identify an Element or to provide notification in accordance
with Requirement R1 or was late by more than 7 calendar days.
Response: The drafting team contends that based on the revision to allow the Planning Coordinator a
complete calendar year to identify Elements that meet the criteria, an incremental Violation Severity Level
(VSL) meets the NERC Guidelines with the failure to identify an Element having a VSL of Severe (i.e.,
binary). No change made.
R2 Lower VSL: The responsible entity identified Element in accordance with Requirement R2, but was late
by less than or equal to 7 calendar days.
R2 Severe VSL: The responsible entity failed to identify an Element in accordance with Requirement R2 or
was late by more than 7 calendar days.
Response: The drafting team contends that based on the revisions made to Requirement R2 and the new
R3, an incremental Violation Severity Level (VSL) meets the NERC Guidelines with the failure to notify the
Planning Coordinator of an Element having a VSL of Severe (i.e., binary). No change made.
R3 Lower VSL: The responsible entity performed one of the options in accordance with Requirement R3,
but was less than or equal to 7 calendar days late.
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Organization
Yes or No
Question 5 Comment
R# Severe VSL: The responsible entity performed one of the options in accordance with Requirement R3,
but was more than 7 calendar days late or the responsible entity failed to perform one of the options in
accordance with Requirement R3.
Response: The drafting team contends that based on the revisions made to Requirement R4 (previously
R3), an incremental Violation Severity Level (VSL) meets the NERC Guidelines with the failure to evaluate
its load-responsive protective relays having a VSL of Severe (i.e., binary). No change made.
American Electric
Power
No
The severe VSL for R1 and R2 could be interpreted that a lack of applicable elements would be a violation.
It should be revised so that it is clear that the entity owns an element that should have been identified,
but did not identify that element.
Response: The drafting team modified the Violation Severity Levels (VSL) for Requirements R1, R2, and
the new R3 to address the concern.
Tacoma Power
No
Tacoma Power disagrees with the need for this standard. In particular, Tacoma Power has significant
concerns with Requirements R1 and R2. It is therefore difficult to provide additional feedback on the VRFs
and VSLs at this time.
Response: Thank you for your comment.
New York Power
Authority
No
Oncor Electric
Delivery LLC
No
ITC
No
We do NOT agree with the need for this standard.
Response: Thank you for your comment.
See response to question #1.
Response: Thank you for your comment. Please see the response in Question 1.
R2 and R3 essentially leave an entity with 11 months to meet compliance. The Violation Severity Levels
should be longer, considering the timeframe allowed to complete the task and the minimal risk to the BES.
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Organization
Yes or No
Question 5 Comment
Response: The drafting team asserts that the incremental value for tardiness is consistent with the time
periods provided in the revisions to the Requirement. The Violation Severity Levels have been updated to
align with the Requirement changes.
Xcel Energy
No
As recommended above, it is recommended that the frequency to complete the tasks related to this
standard to be changed to every 4 years. It is also recommended that the window for completing the tasks
change to 3 to 6 months. The proposed VSL should change accordingly.
Response: The drafting team asserts that the incremental value for tardiness is consistent with the time
periods provided in the revisions to the Requirement. The Violation Severity Levels have been updated to
align with the Requirement changes.
MRO NERC
Standards Review
Forum
Yes
Tennessee Valley
Authority
Yes
Southern Company:
Southern Company
Services, Inc.;
Alabama Power
Company; Georgia
Power Company;
Gulf Power
Company;
Mississippi Power
Company; Southern
Yes
The requirement language should be finalized before establishing VRFs, VSLs. and measures.
Response: Thank you for your comments.
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Organization
Yes or No
Question 5 Comment
Company
Generation;
Southern Company
Generation and
Energy Marketing
Dominion
Yes
FirstEnergy Corp.
Yes
Florida Power &
Light
Yes
Duke Energy
Yes
Puget Sound Energy
Yes
Bureau of
Reclamation
Yes
Luminant
Generation
Company LLC
Yes
Ingleside
Cogeneration LP
Yes
Masschusetts
Attorney General
Yes
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Organization
Yes or No
MidAmerican
Energy Company
Yes
Consolidated
Edison, Inc.
Yes
American
Transmission
Company, LLC
Yes
Manitoba Hydro
Yes
Independent
Electricity System
Operator
Yes
David Kiguel
Yes
ISO New England
Yes
Exelon
Yes
Texas Reliability
Entity
Yes
Northeast Utilities
Yes
Idaho Power Co.
Yes
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Question 5 Comment
122 of 198
Organization
Yes or No
Southern California
Edison Company
Yes
Public Utility District
No. 1 of Cowlitz
County, WA
Yes
Salt River Project
Yes
Question 5 Comment
PacifiCorp
No comment
DTE Electric
No comment
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6. Does PRC-026-1, Application Guidelines and Technical Basis provide sufficient guidance, basis for approach, and examples to support
performance of the requirements? If not, please provide specific detail that would improve the Guidelines and Technical Basis
Summary Consideration: Over 75% of commenters disagreed that the PRC-026-1, Application Guidelines and Technical Basis provide sufficient
guidance, basis for approach, and examples to support performance of the Requirements. Many of the comments here were also raised in previous
questions. A summary of those are provided in other questions summaries. Among other things, the drafting team greatly enhanced the Guidelines
and Technical Basis to include numerous examples, calculations, and figures.
Organization
Northeast Power
Coordinating Council
Yes or No
Question 6 Comment
No
In the Application Guidelines, the wording under Requirement 2 for credible event is very ambiguous and
needs specificity.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2. Change made.
MRO NERC
Standards Review
Forum
No
SPP Standards
Review Group
No
The NSRF believes there is some significant discussion in the guidelines and technical basis. However, we
recommend that the SDT provide more clear explanation of all of the important parameters.
Response: Thank you for your comments.
Requirement R2 calls for the responsible entities to identify Elements based on performance since January
1, 2003 which is before the effective date of the standard. During the webinar, the SDT indicated that
although this requirement was included in the standard, it was not the intent of the SDT to hold the
responsible entities accountable for this data. This exception should be included in the Application
Guideline and especially in the RSAW.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
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Organization
Yes or No
Question 6 Comment
One-line diagrams for the examples in the explanations for Requirements R1 and R2 would be helpful.
Response: The drafting team added clarifications and examples in the Guidelines and Technical Basis for
Generator Owners. Change made.
In the 3rd paragraph on Page 15, the SDT attempts to clarify the 2nd option under Requirement R3. The
1st sentence in the paragraph does just that. However, the next two sentences seem to go beyond the
requirement by expanding the scope of the requirement. We propose to delete these last two sentences.
Response: This problem has been addressed due to other changes to the Requirements.
ACES Standards
Collaborators
No
(1) In general the guidelines provide a good explanation; however, we do identify some suggested
improvements below.
(2) We suggest modifying the end of the “Applicability” section on page 13 to clearly state that these loadserving facilities by definition would not be part of the BES. Thus, standards would not apply.
Response: Section 4.2, Facilities provides sufficient language that the standard is applicable to only “BES
Elements.” No change made to the standard based upon the comment.
(3) The last sentence of the “Requirement R1” section on page 14 is too vague. As written, it could be
interpreted that the PC and TP must include any Elements identified in the Planning Assessment for any
reason (i.e. including non-power swing issues). This is inaccurate. Part 4 of the requirement is very specific
to only those Elements with relays that trip due to stable power swings as identified in studies. Please
update the guidelines to match the language of the requirement more closely.
Response: The drafting team contends the requirement only applies to inclusions that are based on
Elements tripping on stable or unstable power swings. The Guidelines and Technical Basis has changed
significantly and provide additional guidance for Criterion 4. The sentence noted above has been
removed. Change made.
FirstEnergy Corp.
No
It would be most helpful to specify protective functions (e.g., 78, 21, 67, 40?) to be included in this
analysis, similar to what was done with the Criteria Tables in PRC-025. If the reference to “load-responsive
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Organization
Yes or No
Question 6 Comment
protective relay” in PRC-026-1 R2 means the same as where this terminology is used (and defined) in PRC025, the scope of work required for the detailed analysis specified in PRC-026-1 R3 is quite significant.
Response: The term “load-responsive protective relays” is widely understood and is any protective
functions which could trip with or without time delay, on load current. A clarification has been provided in
PRC-026-1 – Attachment A. Change made.
Technical resources to perform this analysis on each applicable relay could be difficult for many GOs to
commit or obtain, and it would be difficult to accomplish the analyses in a short timeframe. One year is
unrealistic, especially considering the concern stems from an incident that occurred nearly eleven years
ago.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Events that occur
will be reported to the Planning Coordinator in order to maintain the Element as an “identified Element.”
Change made.
This requirement should also be worded in such a way as to be sensitive to GOs operating in a competitive
environment, where FERC Standard of Conduct issues make it difficult if not impossible to even know
about power swings or other disturbances on the power system.
Response: The drafting team contends that the Protection System owner (i.e., Generator Owner and
Transmission Owner) is the appropriate entity for reviewing operations. No change made.
Please define “stable power swing”. The diagrams (“Figures”) in the Application Guidelines appear to be
typical.
Response: The drafting team provided the general definitions in the Guidelines and Technical Basis.
Change made.
Is there enough information contained in the Application Guidelines that a GO can determine Power
Swing Stability Boundaries for each specific application?
Response: The Generator Owner was moved from Requirement R2 to the new Requirement R3 in order to
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Organization
Yes or No
Question 6 Comment
remove the “islanding” criteria for Generator Owners. Change made.
PPL NERC Registered
Affiliates
No
In addition to our comments elsewhere in this document, the term, “load-responsive protective relays,”
needs definition, especially since its meaning appears to change from one standard to another. We view
“out-of-step” devices as not being among the load-responsive protective relays governed by PRC-025-1,
for example, but being included under PRC-026-1. Is the list on p.23 of the Application Guidelines meant
to be exclusive?
Response: The term “load-responsive protective relays” is widely understood and is any protective
functions which could trip with or without time delay, on load current. A clarification has been provided in
PRC-026-1 – Attachment A. Change made.
The drafting team provided both inclusions (“including, but not limited to”) and specific exclusions.
Duke Energy
No
On page 16 of the Application Guideline and Technical Basis document, paragraph 3 states, “...the
Element passes the evaluation (Figures 6 and 7).” However, Figure 7 on page 23 states, “This Element
does not pass the Requirement R3 evaluation.” It appears that Figure 7 is incorrect with the statement on
page 16.
Response: The drafting team has rewritten of the Guidelines and Technical Basis to address
inconsistencies, errors, and lack of detail. Change made.
BC Hydro
No
The technical basis should be improved to apply only to cases where stable power swings have historically
caused undesirable tripping of transmission lines.
Response: The drafting team asserts that the standard is proactively addressing the risk of loadresponsive protective relays applied on Elements that are expected to have the greatest risk of exposure
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Organization
Yes or No
Question 6 Comment
to power swings. The standard is based on guidance from the NERC System Protection and Control
Subcommittee (SPCS) Protection System Response to Power Swings, August 201311 (PSRPS Report) and
includes Elements that trip during future events. No change made.
DTE Electric
No
Paragraph four on Page 23 of 61 of the PSRPS Report states that current-only based protection is immune
to operating during power swingw, but the Application to Generator Owners paragraph on page 23 of 25
of the draft standard implies that time overcurrent relays are subject to incorrect operation caused by
stable power swings. Perhaps this could be clarified.
Response: The PSRPS Report pg. 23 states:
“Although current‐only‐based protection is immune to operating during power swings, exclusive use
of current‐only‐based protection is not practical and would reduce dependability of tripping for
system faults and unstable power swings. A power system with no remote backup protection is
susceptible to uncleared faults and the inability to separate during unstable power swings during
extreme system events. Although current‐only‐based protection is secure for stable power swings
and can be used on lines which require tripping on out‐of‐step conditions, additional separate out‐of‐
step protection is required. Application of impedance‐based backup protection and, where
necessary, out‐of‐step protection, reintroduces the need to discriminate between stable and unstable
power swings.”
The drafting team understands the section above to refer to line current differential schemes which are
immune to power swings and not phase overcurrent schemes that are applicable to the standard. No
change made.
Since relay engineers are typically not familiar with transient stability studies, it would be helpful if more
examples were provided for specific generator relay types that would be prone to operate for power
11
NERC System Protection and Control Subcommittee. Protection System Response to Power Swings. August 2013: http://www.nerc.com/comm/PC/System%20Protection%20and%20Control
%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf.
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Organization
Yes or No
Question 6 Comment
swings.
Response: The drafting team added clarifications and examples in the Guidelines and Technical Basis for
Generator Owners. Change made.
Luminant
Generation
Company LLC
No
The Application Guide should include examples for Generator Owners using distance relays. The example
should provide illustrations of transient stability R-X plots in the time domain provided by the
Transmission Planner in a format that allows the Transmission Owner and Generation Owner to plot
distance relay settings.
Response: The drafting team added clarifications and examples in the Guidelines and Technical Basis for
Generator Owners. Change made.
Public Service
Enterprise Group
No
American Electric
Power
No
We disagree with the need for this standard.
Response: Thank you for your comment. Please see response in Question 1 above.
The Application Guidelines and Technical Basis section makes a number of assumptions and expectations,
which would be difficult to prove. For example, “If PSB is applied, it is expected that the relays were set in
consultation with the Transmission Planner to verify maximum slip rates.” Does such a quote imply an
obligation to prove such consultation took place? This section should not imply or specify any obligations
not contained elsewhere in the requirements.
Response: The drafting team removed this text and notes the Guidelines and Technical Basis do not
obligate the entity under the standard. Change made.
Consolidated
Edison, Inc.
No
1. In the Application Guidelines, the wording under Requirement 2 for “credible event” is very openended.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
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Organization
Yes or No
Question 6 Comment
R2. Change made.
2. An example of how line differential protection would be treated with respect to Requirement 3 would
be helpful. See the comment above in Question 4.
Response: The drafting team added an exclusion for “current differential” elements to PRC-026-1 –
Attachment A. Change made.
American
Transmission
Company, LLC
No
Tacoma Power
No
ATC believes there is some significant discussion in the guidelines and technical basis, however,
recommends that the SDT provide more clear explanation of all of the important parameters.
Response: The drafting team has provided additional information in the Guidelines and Technical Basis
about the PRC-026-1 - Attachment B Criteria. Change made.
: Tacoma Power disagrees with the need for this standard. In particular, Tacoma Power has significant
concerns with Requirements R1 and R2. The Application Guidelines and Technical Basis do not provide
sufficient clarification related to these two requirements.
Response: The drafting team has rewritten of the Guidelines and Technical Basis to address
inconsistencies, errors, and lack of detail. Change made.
Ameren
No
These are generally well written considering this complex situation that we feel is very rare, but we do
have the following recommendations for the drafting team:
(1) The variables in Figure 2 need to be defined;
Response: The figures have been cleaned up and clarified. Change made.
(2) The issue of aligning the planning assessment time horizon with present Protection System settings
(see our 2nd comment Q1) needs to be clarified;
Response: Requirement R1 has been revised to only include the Planning Coordinator and due to this
revision, the Criterion that identify Elements is now specifically assigned the Time Horizon: Long-term
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Organization
Yes or No
Question 6 Comment
Planning. In the event that a Corrective Action Plan (CAP) is necessary based on future system conditions,
the CAP can specify a timeframe that does not enact changes until those system conditions require
modification. An example has been added to clarify this scenario in the Guidelines and Technical Basis.
Change made.
(3) On page 24 change “the generator unsaturated generator X"d,” to “the generator saturated generator
transient reactance X’d,” because transient time constant aligns better with power swing timeframe, and
faults most often are the triggering event in such power swing scenarios (also see Reimert text pages 40,
289, 291, and particularly bottom of page 302).
Response: The drafting team made a modification to allow entities the option of using transient or subtransient reactance. The drafting team clarified that the “saturated” (transient or sub-transient) reactance
is used. Change made.
(4) On page 23 add “Overcurrent relays usually have long enough time delays that they can be excluded
from consideration.” at the end of the ‘Application to Generator Owners’ section.
Response: The drafting team did not add the proposed suggestion, but did add a clarification that
standard is applicable to load-responsive protective relays (including overcurrent) which could trip
instantaneously or with a time delay of less than 15 cycles. Change made.
(5) To clarify when the simplified method instead of transient stability simulations can be used on page 24
in the last paragraph of the ‘Impedance Type Relays’ section change ‘is’ to ‘can’ and add “only” in the third
line so it reads
“The simplified method used in the Application to Transmission Owners section can also be used
here to provide a helpful understanding of a stable power swing on load-responsive protective
relays for only those cases where the generator is connected to the transmission system and there
are no infeed effects to be considered.”
Response: The drafting team provided additional detail in the Guidelines and Technical Basis. Change
made.
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Organization
ISO New England
Yes or No
Question 6 Comment
No
While the Application Guidelines and Technical Basis provide guidance, we disagree with the current roles
of functional entities to which the standard applies.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. Change made to the Requirement.
New York Power
Authority
No
This proposed Standard would be better suited as a TPL, or OP Standard, not a PRC one. This is because
the functions and study capabilities required for the Standard are done by Transmission
Planning/Operations Organizations, and are not in the realm of Protective Relay Departments of a GO/TO.
Response: The drafting team contends that there is not a practical way to specify the exact planning
studies under the TPL standards that would result in the worst case stable power swing; similarly, under
the TOP standards, operators would not be capable of taking action during the timeframe of a power
swing. Therefore, the drafting team has established the graphical approach under the PRC body of NERC
Reliability Standards by providing the standard’s proposed PRC-026-1 - Attachment B Criteria that loadresponsive protective relays must meet on an identified Element. No change made.
Oncor Electric
Delivery LLC
No
Oncor agrees with the recommendation of the NERC PC (SCPS) and recommends if this has not been
reviewed by NERC RISC, this may be an opportunity for the NERC Standard Committee (SC) to bring back
to RISC for discussion in conjunction with the PSRPS technical document.
Response: The NERC RISC evaluates emerging issues and this project is the result of FERC directives. The
NERC RISC does not evaluate directives. No change made.
If RISC and SC find the Standard should be developed, a clearer explanation as to what contingency the
term “line out conditions” refers to should be included as this will determine the data source we use to
generate our list of elements.
Response: The phrase “line-out conditions” has been removed. Elements should be identified for
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Organization
Yes or No
Question 6 Comment
Requirement R1 criterion regardless of the outage conditions that may be necessary to trigger
enforcement of the System Operating Limits (SOL) or arming of the Special Protection System (SPS).
Change made
Northeast Utilities
No
1. In the Application Guidelines, the wording under Requirement 2 for “credible event” is very openended.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2. Change made.
2. An example of how line differential protection would be treated with respect to Requirement 3 would
be helpful. See the comment above in Question 4.
Response: The drafting team added an exclusion for “current differential” elements to PRC-026-1 –
Attachment A. Change made.
Public Utility District
No. 1 of Cowlitz
County, WA
No
Alliant Energy
No
It is not clear how past events and Disturbance reports that must be considered in the identification of
Elements will be archived and made available.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Events that occur
will be reported to the Planning Coordinator in order to maintain the Element as an “identified Element.”
Change made.
In the Application Guide there is guidance provided for the determination of apparent impedance for
Impedance Type Relays on page 23 of 25, under the “Application to Generator Owners” portion of the
document. As noted in this section the process is complex. As such, we recommend adding a detailed
example of how the Transmission Planner should conduct this analysis on the behalf of the Generation
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Organization
Yes or No
Question 6 Comment
Owner.
Response: The drafting team has rewritten this section of the Technical Basis and Guidelines.
PacifiCorp
Yes
Tennessee Valley
Authority
Yes
Dominion
Yes
Florida Power &
Light
Yes
Puget Sound Energy
Yes
Bonneville Power
Administration
Yes
Arizona Public
Service Co.
Yes
Bureau of
Reclamation
Yes
Ingleside
Cogeneration LP
Yes
Masschusetts
Yes
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Organization
Yes or No
Question 6 Comment
Attorney General
MidAmerican
Energy Company
Yes
Manitoba Hydro
Yes
Independent
Electricity System
Operator
Yes
Exelon
Yes
ITC
Yes
The App Guide will be sufficient, considering the improvements mentioned in the webinar. In addition, we
request more details regarding islanding scenarios and explanation of “credible” along the lines of our
answer to Question 1.
Response: The term “credible” has been removed from the standard. The drafting team clarified
Requirement R1, Criterion 3 by framing the criterion in the present tense to refer to the current
assessment(s). Islands caused by natural phenomena (i.e., Disturbances) are covered under Requirement
R2. Change made.
Idaho Power Co.
Yes
In the present form of R1-R4
Response: Thank you for your comment.
Southern California
Edison Company
Yes
Salt River Project
Yes
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Organization
Xcel Energy
Yes or No
Question 6 Comment
Yes
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7. Do you agree with implementation period of the proposed standard based on the considerations listed in the Implementation Plan? If not,
please provide a justification for changing the proposed implementation period
Summary Consideration: About two-thirds (64%) disagreed with the implementation period of the proposed standard based on the considerations
listed in the Implementation Plan. The chief concern, from 12 comments by 56 stakeholders, related to the initial influx of Elements and performing
the evaluations. To address this concern the implementation plan was modified. Requirements R1-R3, R5, and R6 all become effective 12 months
following approval. An implementation of 36 months is provided in Requirement R4 to evaluate identified Elements pursuant to Requirement R1.
The Planning Coordinator is to become compliant with the initial identification of Elements in Requirement R1 during the calendar year 12 calendar
months after approval and perform Requirement R1 each calendar year thereafter.
Again, Requirement R4 (previously R3) will become effective 36 calendar months after approval of the standard. During the implementation of the
standard, notifications (i.e., from R1-R3) are likely to occur prior to Requirement R4 becoming effective. Where notification under R1 or
identification under Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in Requirement R4 will
begin from the Effective Date of Requirement R4. Thereafter, entities will follow the 12 month time period in R4. The intention of the additional
time for Requirement R4 to become effective is to handle the initial influx of notifications and identifications.
Organization
MRO NERC
Standards Review
Forum
Yes or No
No
Question 7 Comment
The NSRF believes there may be many elements, questions or unexpected problems in preparing for the
first compliance deadline. Therefore, 24 months may be more reasonable than 12 months.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
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Organization
Yes or No
Question 7 Comment
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made.
SPP Standards
Review Group
No
We would prefer to see the twelve months increased to twenty-four months to allow adequate time to
complete all the studies and analyses that will be needed to comply with the standard.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made. Change made.
ACES Standards
Collaborators
No
(1) We disagree with the implementation plan and believe that a staggered implementation is necessary.
If the standard were approved such that it would become effective on March 1, 2016, the TO and GO
would not have any Elements identified per R1 until approximately 10 months later in January 2017. How
could they comply in 2016 with R3 when they don’t have any Elements identified per R1?
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
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Organization
Yes or No
Question 7 Comment
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made. Change made.
FirstEnergy Corp.
No
This current situation has continued for 11 years and an implementation plan of 1 year is unrealistically
short. Two years is more appropriate unless the period is modified to include only incidents which have
occurred since the inception of NERC PRC-004 then 1 year would be reasonable.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made. Change made.
PPL NERC Registered
Affiliates
No
It is not evident why applicable Elements owned by GOs require a new R3 analysis annually. Their
calculations should remain valid until and unless impedances change significantly. We suggest that the TO
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Organization
Yes or No
Question 7 Comment
should provide a system impedance update annually (ref. comment #2 above), and a new study should be
required of the GO only if the generator, GSU or system impedance changes by 10% or more.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial
influx of identified Elements under Requirement R1. The evaluation of relays under Requirement R4
(previously R3) is to be performed “within 12 full calendar months of receiving notification of an Element
… where the evaluation has not been performed in the last three calendar years.” Change made.
BC Hydro
No
BC Hydro does not agree with implementation of the proposed standard at all.
Response: Thank you for your comment.
Puget Sound Energy
No
As noted in question 4, the modeling of protective relays needed to evaluate the system will not be
implemented by by the proposed implementation date for the standard.
Response: The drafting team asserts that the standard does not require the inclusion of relay models.
Requirement R1 – Criterion 4 is not requiring a study, but the identification of any Element that was
observed as tripping in the most recent Planning Assessment Response: The drafting team asserts that the
standard does not require the inclusion of relay models. Requirement R1 – Criterion 4 is not requiring a
study, but the identification of any Element that was observed as tripping in the most recent Planning
Assessment. No change made.
Bonneville Power
Administration
No
BPA feels 12 months is insufficient time for the initial implementation.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
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Organization
Yes or No
Question 7 Comment
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made. Change made.
Arizona Public
Service Co.
No
AZPS suggests the timeline for the implementation plan be increased to allow for two years for
requirements one and two and requirements three and four be adjusted accordingly. APS believes
significant effort will be required to identify relays that may qualify for inclusion.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made. Change made.
Public Service
Enterprise Group
No
Peak Reliability
No
We disagree with the need for this standard.
Response: Thank you for your comment. Please see response in Question 1 above.
The expectations of the RC need to be clarified, and until they are clarified, it is unclear whether the
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Organization
Yes or No
Question 7 Comment
implementation period is reasonable. It is unclear whether the annual list of Elements provided by the RC
is intended to be a result of a new and different one-time analysis performed by the RC or TOP, or if the
list of Elements is intended to be compiled over time as a result of ongoing operations planning analyses
and real-time assessments already being performed. The RC performs many assessments throughout the
Operations Planning horizon, Same-Day horizon, and Real-time horizons for expected and actual operating
conditions. As related to the RC specifically, is the intent of R1 for the RC to continuously add to this list of
Elements based on the results from all of these RC studies performed throughout the year, and to report
this compiled list to the GOs and TOs once per calendar year? This approach would seem to add the most
reliability benefit.
Response: The Reliability Coordinator and Transmission Planner have been removed from the standard’s
Applicability; therefore, Requirement R1 is now only applicable to the Planning Coordinator as a single
entity source of identifying Elements. The drafting team asserts that the Planning Coordinator has or has
access to the knowledge including the wide-area view. The Planning Coordinator is believed to be the best
single-source of information and not the Transmission Operator.
Requirement R1 has been modified to state that at least once per calendar year the Elements in its area
meeting the Requirement R1 criteria are to be identified. Requirement R1 is not intended to require new
studies, but to identify Elements based on existing information. Change made.
American Electric
Power
No
The implementation plan only allows the GO/TO 11 months to complete their initial R3 study of all
Elements identified in R1. We believe the time allowed is too short for the initial implementation of the
standard, as the GO/TO will need to research all Elements, not just those incrementally added from the
previous year’s planning analysis. The implementation plan should be revised to guarantee the GO/TO a
minimum of at least 36 months to complete their initial R2 and R3 studies.
The timing of the sequence as proposed in the standard is acceptable after the initial implementation.
However, as currently written, the initial implementation plan does not guarantee adequate time for the
applicable Entities to become compliant.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
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Organization
Yes or No
Question 7 Comment
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made. Change made.
American
Transmission
Company, LLC
No
ATC believes there may be many elements, questions or unexpected problems in preparing for the first
compliance deadline. Therefore, 24 months may be more reasonable than 12 months.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made. Change made.
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Organization
Yes or No
Independent
Electricity System
Operator
No
Tacoma Power
No
Question 7 Comment
Tacoma Power disagrees with the need for this standard. In particular, Tacoma Power has significant
concerns with Requirements R1 and R2.
Response: Please see the section at the beginning of this document called, “NERC Discussion on
Proceeding(s) and Directives Regarding: Stable Power Swings” for a complete background. The SDT
understands that NERC staff re-engaged FERC staff following the completion of the PSRPS Report and that
the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open
to an approach designed by NERC. NERC staff has informally received positive feedback on the approach
to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No.
733-A and Order No. 733-B proceedings. Similar arguments to the conclusions of the NERC System
Protection and Control Subcommittee were advanced in these FERC proceedings.
See responses to Question 1 comments on R1 and R2.
Ameren
No
(1) We request that the SDT provide a 1 year implementation period for R1 and R2 combined, followed by
a 2 year implementation period for R3.
(2) We believe that this standard poses a considerable burden on the TO and GO and the first pass may be
a significant amount of work.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
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Organization
Yes or No
Question 7 Comment
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made. Change made.
ISO New England
No
Given that the currently proposed scope of the standard is very broad, twelve months is not a long
enough timeframe to become compliant with the requirements of this standard, which will create
additional workload for the functional entities subject to the standard. ISO New England suggests 36
months.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications. Change made. Change made.
New York Power
Authority
No
Implementation periods should be consistent with the more relevant approach described in the PSRPS
technical document.
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Organization
Yes or No
Question 7 Comment
Response: The drafting team modified the Implementation Plan (to 36 months) and several Requirements
to provide additional time to reduce the burden. Also, the standard is consistent with the PSRPS Report
which recommends a focused approach to identifying Elements that are most susceptible to power swings
and therefore reduces the financial burden by not requiring all relays to be in scope. Changes made.
Oncor Electric
Delivery LLC
No
Idaho Power Co.
No
Please see response #1, #6 and #10
Response: Thank you for your comment. Please see responses to your comments in Questions 1, 6, and
10.
The requirements need work before an implementation plan can be defined. It should be adjusted based
on changes proposed in #4.
Response: Thank you for your comment. Please see the response in Question #4.
Xcel Energy
No
The implementation window and the implementation frequency is unnecessarily aggressive as powers
system dynamics do not changes as fast. Four year frequency and 3 to 6 months implementation window
are reasonable.
R1 and R2 should be released earlier for the initial completion of R3. Additional time may be required to
ensure appropriate relays are installed in the field.
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require
evaluation under the time period allotted in Requirement R4 (previously R3) for any identified Elements.
The Planning Coordinator is to become compliant with the initial identification of Elements in
Requirement R1 during the calendar year after 12 calendar months of approval and perform Requirement
R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the
standard. During the implementation of the standard, notifications (i.e., from R1-R3) are likely to occur
prior to Requirement R4 becoming effective. Where notification under R1 or identification under
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Yes or No
Question 7 Comment
Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12 month time period in
Requirement R4 will begin from the Effective Date of Requirement R4. Thereafter, entities will follow the
12 month time period in R4. The intention of the additional time for R4 to become effective is to handle
the initial influx of notifications and identifications.
The standard is requiring that a CAP be created to modify the relaying to increase its security for stable
power swings. It also requires the CAP to be implemented, but it does not state specific time frames for
relay replacements to be done. Change made.
PacifiCorp
Yes
Tennessee Valley
Authority
Yes
Southern Company:
Southern Company
Services, Inc.;
Alabama Power
Company; Georgia
Power Company;
Gulf Power
Company;
Mississippi Power
Company; Southern
Company
Generation;
Southern Company
Generation and
Energy Marketing
Yes
Yes, provided the R2 review period begins with the enforcement date of the stantard looking forward.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new
R3) are based on actual Disturbances that occur after the Effective Date of the standard. Change made.
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Organization
Yes or No
Dominion
Yes
Duke Energy
Yes
Bureau of
Reclamation
Yes
Luminant
Generation
Company LLC
Yes
Ingleside
Cogeneration LP
Yes
Masschusetts
Attorney General
Yes
MidAmerican
Energy Company
Yes
Consolidated
Edison, Inc.
Yes
Manitoba Hydro
Yes
David Kiguel
Yes
Exelon
Yes
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Question 7 Comment
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Organization
Yes or No
Texas Reliability
Entity
Yes
Northeast Utilities
Yes
Southern California
Edison Company
Yes
Public Utility District
No. 1 of Cowlitz
County, WA
Yes
Salt River Project
Yes
DTE Electric
Question 7 Comment
No comment
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8. If you are aware of any conflicts between the proposed standard and any regulatory function, rule, order, tariff, rate schedule, legislative
requirement, or agreement please identify the conflict here.
Summary Consideration: No conflicts between the proposed standard and any regulatory function, rule, order, tariff, rate schedule, legislative
requirement, or agreement were identified.
Organization
FirstEnergy Corp.
Question 8 Comment
In a competitive/unregulated environment a GO does not have access to the information
pertaining to power swings (stable or otherwise) due to the FERC Standard of Conduct. Therefore
the GO would not know the cause of a relay operation.
Response: Thank you for your comment.
Luminant Generation Company LLC
NERC standards requirements should not reference data that predates the approval of the
standard; therefore, rendering the Requirement R2 January 2003 date unenforceable.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2
(and new R3) are based on actual Disturbances that occur after the Effective Date of the standard.
Change made.
Dominion
No
Consolidated Edison, Inc.
No
Northeast Utilities
No
DTE Electric
No comment
Northeast Power Coordinating Council
No.
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Question 8 Comment
PPL NERC Registered Affiliates
No
ITC
No
Salt River Project
None
CHPD - Public Utility District No. 1 of
Chelan County
R1.2 - Is this an SOL for the planning (FAC-010) or operating (FAC-011) horizon? This requirement
seems to be duplicating, at least in part, FAC-014 R6 (The Planning Authority shall identify the
subset of multiple contingencies (if any), from Reliability Standard TPL-003 which result in stability
limits.). SOLs are generally established to facilitate performance under a NERC TPL Category B
performance. Select NERC TPL category C and limited D criteria are added by the WECC regional
criteria.
Response: Requirement R1, Criterion 1 and 2 address operating limits associated with angular
stability limits; therefore, System Operating Limits (SOL) specified in Requirement R1, Criterion 2
includes both operations and planning horizons. In the event that a Corrective Action Plan (CAP) is
necessary based on future system conditions, the CAP can specify a timeframe that does not
enact changes until those system conditions require modification. An example has been added to
clarify this scenario in the Guidelines and Technical Basis. Change made.
R1.3 - TPL studies require transient stability simulations, not angular stability simulations. There is
no standard that requires angular stability simulations. There is no mention of angular stability
simulations in FAC-010, FAC-011, or the new TPL-001-4 either.
Response: The drafting team contends that a System Operating Limit (SOL) as stated in
Requirement R1 is in place to prevent angular instability. The standard addresses Elements
associated with an SOL as an Element that would be susceptible to a power swing. No change
made.
R1.4 - WECC is slowly coming on board with this as a result of the San Diego outage and is adding
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Question 8 Comment
overcurrent relays to system models at this time. However, the relay tripping addressed in this
proposed standard may also occur by distance or other elements, which are not required to be
modeled in WECC at this time in its base case process. There is also a lack of a performance
category for these reporting requirements (such as for Category B and C events). Performance
issues may show up for extreme Category D events in the assessment, but in the language as it
stands, these must also be identified and the GO and TO notified even for category D extreme
events. This is a significant departure from traditional practice, which emphasizes category B and
C issue communication. In the existing TPL standards, severe power swings are considered a
Category D.14 event.
Response: The drafting team asserts that the standard does not require the inclusion of relay
models. Requirement R1, Criterion 4 is not requiring a study, but the identification of any Element
that was observed as tripping in the most recent Planning Assessment pursuant to TPL-001-4, R4,
Part 4.3.1.3 – “Tripping of Transmission lines and transformers where transient swings cause
Protection System operation based on generic or actual relay models” which becomes effective
January 1, 2015 (U.S.). Other clarifying changes were made to Requirement R1, Criterion 4.
SPP Standards Review Group
We are not aware of any conflicts between the proposed standard and any regulatory function,
rule, order, tariff, rate schedule, legislative requirement, or agreement.
Response: Thank you for your comment.
Southern Company: Southern Company
Services, Inc.; Alabama Power Company;
Georgia Power Company; Gulf Power
Company; Mississippi Power Company;
Southern Company Generation; Southern
Company Generation and Energy
Marketing
We are not aware of any conflicts.
Response: Thank you for your comment.
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Organization
SMUD/BANC
Question 8 Comment
YES! The requirement R2 is particularly unacceptable as it requires data for pre June 18, 2007;
effective date of Order 693 standards.
Response: Thank you for your comment.
Xcel Energy
No
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9. If you are aware of the need for a regional variance or business practice that should be considered with this phase of the project, please
identify it here:
Summary Consideration: No need for a regional variance or business practice that should be considered with this phase of the project was
identified.
Organization
Question 9 Comment
Dominion
No
Consolidated Edison, Inc.
No
ITC
No
Northeast Utilities
No
DTE Electric
No comment
Northeast Power Coordinating Council
No
PPL NERC Registered Affiliates
No
FirstEnergy Corp.
None
Salt River Project
None
Tacoma Power
Tacoma Power disagrees with the need for this standard. However, assuming FERC does not
provide reflief from its directive to develop this standard, a regional variance should be
considered, at least for WECC. The footprint of a typical Planning Coordinator or Transmission
Planner in WECC may not be large enough to adequately perform the desired assessments in the
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Question 9 Comment
planning horizon. Instead, it may be more effective to perform this analysis more regionally. The
Reliability Coordinator may have a large enough vantage, but most of their focus is in the
operating horizon.
Response: Thank you for your comment.
BC Hydro
The WECC region should be exempt from this rule. In this region, transmission power along many
lines is subject to stability limits. It is an unnecessary use of resources to check the stability of
protection systems on so many lines, considering there have been a negligible number of
undesirable trips on stable power swings.
Response: The drafting team asserts that it has provided the criteria for identifying Elements
susceptible to power swings that are consistent with the PSRPS Report. The proposed standard
does not require entities to check the stability of any Protection Systems. Notification of the
identified Elements is required to be provided to the respective Generator Owner and
Transmission Owner for evaluation. No change made.
SPP Standards Review Group
No. We are not aware of any need for a regional variance or business practice.
Response: Thank you for your comment.
Southern Company: Southern Company
Services, Inc.; Alabama Power Company;
Georgia Power Company; Gulf Power
Company; Mississippi Power Company;
Southern Company Generation; Southern
Company Generation and Energy
Marketing
No. We are not aware of any needs for exceptions.
Bonneville Power Administration
Western Interconnection has many long lines and remote generation.
Response: Thank you for your comment.
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Question 9 Comment
Response: The drafting team asserts that it has provided the criteria for identifying Elements
susceptible to power swings that are consistent with the PSRPS Report. The proposed standard
does not require entities to check the stability of any Protection Systems. Notification of the
identified Elements is required to be provided to the respective Generator Owner and
Transmission Owner for evaluation. No change made.
Xcel Energy
No
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10. If you have any other comments on this Standard that you haven’t already mentioned above, please provide them here
Summary Consideration: This question mainly generated comments that were submitted in the previous questions and are too varying and
numerous to summarize coherently. There were two remarkable comments that generated a revision to the standard. The first concerns the
assignment of Time Horizons. For Requirement R1, the drafting team eliminated the “Time-Horizon: Operation Planning” because it occurs on an
annual basis and violating the Requirement beyond a year without mitigation would have little impact. Under the definition, “Time Horizon: Longterm Planning” is a planning horizon of one year or longer.
Furthermore, Requirement R2 (and the new R3) eliminated the “Time Horizon: Operation Planning” and kept “Time Horizon: Long-term Planning”
because the information would be used by the PC in its annual assessments and violating the Requirement beyond a year and would have little
impact to the Planning Coordinator’s assessments. The drafting team eliminated “Time Horizon: Long-term Planning” and kept “Time Horizons:
Operations Planning” for Requirement R4 (previously R3) and the new Requirement R5 because the associated timeframes comport with a “Time
Horizon: Operations Planning.” For Requirement R6 (previously R4), the drafting team eliminated the “Time Horizon: Operation Planning” because
the failure to implement the CAP beyond a year without mitigation would have little impact when the length of CAPs that are generally
implemented over several years.
The second remarkable comment relates to cost. The drafting team recognizes that cost is a consideration; however, this standard’s approach
narrowly focuses the reliability objectives to a select set of BES Elements (i.e., Requirement R1) to address the power swing concern where it is
expected to be of greatest risk. This minimizes the cost to entities and compliance burden by not developing the standard to be applicable to the
entire BES.
Organization
David Kiguel
Question 10 Comment
The PSRPS document, developed by industry experts and approved by the NERC Planning Committee, clearly disputes the
FERC directive in Order No. 773 (Docket No. RM08-13-000), that was subsequently affirmed in Order Nos. 773-A and 773-B,
that a standard is needed to ensure that load-responsive protective relays do not trip in response to stable power swings
during non-Fault conditions. NERC’s informational filing in Docket No. RM08-13-000 dated July 21, 2011 concluded that there
is a need for a standard on stable power swings. This conclusion is the opposite of what the PSRPS document concluded. The
SPCS concludes that a NERC Reliability Standard to address relay performance during stable swings is not needed, and could
result in unintended adverse impacts to Bulk-Power System reliability. I support the recommendation that the NERC
Standards Committee explore means to utilize the more recent PSRPS document to obtain relief from the aforementioned
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Question 10 Comment
FERC directive that is driving this project.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
Southern
Company:
Southern
Company
Services, Inc.;
Alabama
Power
Company;
Georgia Power
Company; Gulf
Power
Company;
Mississippi
Power
Company;
Southern
Company
Generation;
a) The phrase "continues to be credible" in R2 needs explanation. Is the intended meaning either 1) the trip was believed to
be caused by the Disturbance, 2) a repeat trips susceptibility continues to be possible or likely, or 3) something else?
Response: The term “credible” has been removed from the standard. The drafting team clarified Requirement R1, Criterion 3
by framing the criterion in the present tense to refer to the current assessment(s). Islands caused by natural phenomena (i.e.,
Disturbances) are covered under Requirement R2. Change made.
b) Is the consequence of R2/M2 having to analyze and document every relay operation (trip) which occurs for determination
of if it was caused by a system Disturbance? Also, do all system Disturbances have to be reviewed for possible relay (trip)
operations, for subsequent validation of desired operation? The NERC glossary definition of a Disturbance is very much openended and not specifically defined in part 2:
"2. Any perturbation to the electric system."
Response: The Requirement was structured to determine if the tripping was caused by a power swing, not a Disturbance. The
drafting team revised Requirement R2 (and the new R3) to reference both stable and unstable power swing. This standard
does not address the review of Protection System operations, only the actions required as a result of determining that
tripping occurred due to a stable or unstable power swing. No change made.
Is this requirement duplicative of PRC-004 relay mis-operation determination? Does PRC-026 subject entities to possible
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Southern
Company
Generation
and Energy
Marketing
Question 10 Comment
violation of two standards for a single possible (lack of) action?
Response: This standard does not address the review of Protection System operations, only the actions required as a result of
determining that tripping occurred due to a stable or unstable power swing. The drafting team does not see this as duplicative
of another standard. No change made.
c) An annual requirement for R1, R2, and R3 seems excessive. Extended periodicity intervals or triggers from system
topographic changes should be considered rather than annual reviews. For example, PRC-006 and PRC-010 prescribe
evaluation intervals of 5 years for UVLS and UFLS. Five years seems to be a reasonable interval for this analysis.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial influx of identified
Elements under Requirement R1. The evaluation of relays under Requirement R4 (previously R3) is to be performed “within
12 full calendar months of receiving notification of an Element … where the evaluation has not been performed in the last
three calendar years.” Change made.
D) Does any specific item on the Identified Element list ever get removed from the list? The resolution of a review in a
previous year should eliminate it from future reviews.
Response: The drafting team notes that Elements do need to be identified when the Element no longer meets the Criteria in
Requirement R1. No change made.
ACES
Standards
Collaborators
(1) Requirement R4 is unnecessary and inconsistent with the Reliability Assurance Initiative which is attempting to move NERC
away from paper-driven compliance to reliability-driven compliance. The only practical violation of R4 will be a failure to
update the paperwork. As written, if an implementation date slips, the TO or GO can update their CAP. We agree they should
have the flexibility to do this since construction schedules nearly always have to be adjusted. Thus, if a milestone is not
completed for any reason, a violation will not occur unless the CAP is not updated. How does this support reliability? Because
it is not practical to require a TO or GO to complete their CAP by the dates established in the initial version due to
unpredictable changes and unforeseen circumstances always faced in construction, the only real practical solution is to
remove Requirement R4. NERC and the Regional Entities have the authority to request copies of the CAPs and progress
reports and have other methods to encourage completion of CAPs if they are not satisfied with the progress.
Response: The drafting team contends that updating actions and timeframes provides measurable evidence of
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Question 10 Comment
implementation of the CAP. In addition, implementation may require months or years to schedule and complete due to
outages and other factors. No change made.
(2) We are concerned that the RSAW is not consistent with the principle of the Reliability Assurance Initiative (RAI). RAI is
intended to refocus NERC’s compliance efforts to be forward looking rather than backwards looking and focus on the matters
that impact reliability the most. This RSAW has reverted to the historical looking compliance review. On every requirement,
there are multiple statements that evidence will be requested for each calendar year since the last audit and that the
compliance assessment approach will evaluate every year since the last compliance audit. For a TO or GO, this would
represent six to seven years of evidence and review that would provide no reliability benefit. This RSAW needs to be
revamped to be consistent with RAI principles.
Response: The drafting team has provided your comments to NERC Compliance who develops the RSAW.
(3) Thank you for the opportunity to comment.
Manitoba
Hydro
1) In R1, please clarify what you mean by “Stability constrained”, does it mean the constraint for angular stability only or does
it include other stability concerns such as transient voltage violations?
Response: The drafting team added “angular” to “stability constraint” to clarify the intent in Requirement R1, both Criterion 1
and 2. Change made.
2) Also in R1, does “Line-out conditions” mean “N-1” condition?
Response: The phrase “line-out conditions” has been removed. Elements should be identified based on the Requirement R1
criterion regardless of the outage conditions that may be necessary to trigger enforcement of the System Operating Limit
(SOL) or arming of the Special Protection System (SPS). The Guidelines and Technical Basis have been supplemented to
provide additional information. (Note: The use of SPS has been replaced with Remedial Action Scheme (RAS) for consistency
with a current project to revise the definition of “Special Protection System”). Change made.
3) What definition of an island is used in the standard?
Response: The drafting team modified Requirement R1, Criterion 3 to include island boundaries due to angular instability
within an underfrequency load shedding (UFLS) assessment. Also, the Generator Owner was moved from Requirement R2 to
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the new Requirement R3 in order to remove the “islanding” criteria for Generator Owners. Change made.
4) In R1 through R4, why is long-term planning included in the time horizon? The standard is not clear that an assessment of
the 10-year planning horizon is expected. It seems the assessment is more based on the current system or at most plans
proposed to be implemented in the next year, which makes this applicable to Operations Planning only. The Table of
compliance elements discussing notification deadlines of 30-90 days is more applicable to an Operations Planning time
horizon. If we see an issue in 2020, due to a new proposed Facility, why do we have to notify anyone within 30 days today in
order to be compliant with the standard? We have time to investigate alternatives, new settings etc. If the problem still exists
in the operations horizon, this standard is applicable.
Response: For Requirement R1, the drafting team eliminated the “Time-Horizon: Operation Planning” because it occurs on an
annual basis and violating the Requirement beyond a year without mitigation would have little impact. Under the definition,
“Time Horizon: Long-term Planning” is a planning horizon of one year or longer.12
Requirement R2 (and the new R3) eliminated the “Time Horizon: Operation Planning” and kept “Time Horizon: Long-term
Planning” because the information would be used by the PC in its annual assessments and violating the Requirement beyond
a year and would have little impact to the Planning Coordinator’s assessments. The drafting team eliminated “Time Horizon:
Long-term Planning” and kept “Time Horizons: Operations Planning” for Requirement R4 (previously R3) and the new
Requirement R5 because the associated timeframes comport with a “Time Horizon: Operations Planning.” For Requirement
R6 (previously R4), the drafting team eliminated the “Time Horizon: Operation Planning” because the failure to implement the
CAP beyond a year without mitigation would have little impact when the length of CAPs that are generally implemented over
several years. Change made.
Northeast
Utilities (Bill
Temple)
12
1. The annual frequency requirements listed in R1 & R2 are not necessary and that a less frequent (ie: Every 5 years) would be
more appropriate.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial influx of identified
Elements under Requirement R1. The evaluation of relays under Requirement R4 (previously R3) is to be performed “within
12 full calendar months of receiving notification of an Element … where the evaluation has not been performed in the last
http://www.nerc.com/pa/Stand/Resources/Documents/Time_Horizons.pdf
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Question 10 Comment
three calendar years.” Change made.
2. Please provide more examples to help further illustrate the criteria in listed in R1.
Response: The drafting team provided additional detail in the Guidelines and Technical Basis. Change made.
3. Please differentiate between Stable and Unstable power swings.
Response: The drafting team provided the general definitions in the Guidelines and Technical Basis. Change made.
Northeast
Utilities,
supplemental
comment
(Mark Kenny)
Northeast Utilities is voting Negative based on the following concerns:
•
Potential Costs associated with relay upgrades
Response: The drafting team recognizes that cost is a consideration; however, this standard’s approach narrowly focuses the
reliability objectives to a select set of BES Elements (i.e., Requirement R1) to address the power swing concern where it is
expected to be of greatest risk. This minimizes the cost to entities and compliance burden by not requiring the standard to be
applicable to the entire BES. No change made.
•
Lack of clarity in some of the criteria in requirements
o What is considered a credible event?
Response: The term “credible” has been removed from the standard. The drafting team clarified Requirement R1, Criterion 3
by framing the criterion in the present tense to refer to current assessment(s). The term “credible” was removed from the
previous Requirement R2 (and new R3) because the required performance refers to only current actual events. Change made.
o Should Planning assessment be used to capture relay tripping or just stable power swing or both stable and unstable
power swing?
Response: Requirement R1, Criterion 4 requires identification of any Element that was observed as tripping in the most recent
Planning Assessment pursuant to TPL-001-4, R4, Part 4.3.1.3 – “Tripping of Transmission lines and transformers where
transient swings cause Protection System operation based on generic or actual relay models” which becomes effective January
1, 2015 (U.S.). Other clarifying changes were made to Requirement R1, Criterion 4.
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Question 10 Comment
o Is the purpose of the standard is to ensure blocking for a stable power swing and dependable tripping for unstable
power swing?
Response: The Purpose statement was modified to note that the purpose is to ensure that relays “are expected to not trip.”
This may include the use of power swing blocking.
•
Annual analysis is to frequent
Response: Requirements R1-R3, R5, and R6 all become effective following approval and require evaluation under the time
period allotted in Requirement R4 (previously R3) for any identified Elements. The Planning Coordinator is to become
compliant with the initial identification of Elements in Requirement R1 during the calendar year after 12 calendar months of
approval and perform Requirement R1 each calendar year thereafter.
Requirement R4 (previously R3) will become effective 36 calendar months following approval of the standard. During the
implementation of the standard, notifications (i.e., from R1-R3) are likely to occur prior to Requirement R4 becoming
effective. Where notification under R1 or identification under Requirement R2 or R3 occurs prior to the Effective Date of
Requirement R4, the 12 month time period in Requirement R4 will begin from the Effective Date of Requirement R4.
Thereafter, entities will follow the 12 month time period in R4. The intention of the additional time for R4 to become effective
is to handle the initial influx of notifications and identifications. Change made.
•
Requiring an entity to provide data on an Element that had tripped since 2003 is inconsistent with other NERC Standards
related to disturbance monitoring or misoperations, where data does not need to be retained for more than 12 months.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Events that occur will be reported to the Planning
Coordinator in order to maintain the Element as an “identified Element.” Change made.
American
Electric Power
AEP supports the proposed standard’s scope and overall direction, but has chosen to vote negative based on the various
concerns expressed in our response. AEP envisions voting in the affirmative once sufficient concerns have been addressed in
future drafts.
R2 should be revised to be forward-looking only. Generator Owners and Transmission Owners were not required in the past
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to keep comprehensive records of these events and cannot be expected to know all applicable Elements as implied by the
standard. If after the initial standard implementation period, an Entity identifies an applicable Element based on a
Disturbance occurring between 1/1/2003 and the standard effective date, the Entity could be found non-compliant with R2
and R3. If the drafting team feels it is absolutely necessary to go back to 2003, the standard should be revised to allow an
Entity to remain fully compliant with R2 and R3 at any time an Element is identified based on a Disturbance occurring
between 1/1/2003 and the effective date of the standard. This could be accomplished by adding wording to bring newly
identified Elements into scope of R2 and R3 during the first full calendar year after they are identified. The R2 criterion
assumes that registered entities have had a process in place to flag events due to power swings and retain information related
to them. We do not believe that industry should be required to identify and provide information on events that have occurred
in the past. There has been no established standard requirement to capture this information, so there is no way to reliably
conclude that all events caused by power swings have been identified. In the event such historical information *is* required,
the standard should explicitly state that such information is needed only once rather than once every calendar year.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Events that occur will be reported to the Planning
Coordinator in order to maintain the Element as an “identified Element.” Change made.
The standard should require the Transmission Owner to make the system impedance available to the Generator Owner
annually or within 30 days of a written request. The Generator Owner would not normally have this information, but will need
it in order to meet their obligations under R3.
Response: The standard does not preclude the Planning Coordinator from providing information to the Generator Owner or
Transmission Owner about a particular Element (e.g., known stability issues, power swings, or apparent impedance
characteristics). The drafting team has not included a Requirement for the exchange of information; that is being managed by
entities outside of Reliability Standard requirements.
It is not clear why R3 will require the TO/GO’s Elements to be studied annually. A study’s result should remain valid until
either the relay setting changes or the impedance changes significantly. The standard should be revised to only require a
study be repeated if the relay setting is changed or if the generator, GSU or system impedances change by 10% or more.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial influx of identified
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Elements under Requirement R1. The evaluation of relays under Requirement R4 (previously R3) is to be performed “within
12 full calendar months of receiving notification of an Element … where the evaluation has not been performed in the last
three calendar years.” Change made.
The standard should not require the study of voltage controlled/restrained overcurrent relays or loss of field relays. In stable
power swings, the voltage should remain above the threshold that allows these voltage controlled/restrained overcurrent
relays to operate. Failure to set the relay appropriately should be reported and corrected under the requirements of PRC-004.
Loss of field relays are installed as part of the generator protection and should be permitted to trip when necessary to protect
the generator, regardless of whether the power swing is stable or unstable.
Response: The drafting team provided an exclusion for voltage controlled/restrained overcurrent relays in PRC-026-1 –
Attachment A; however, the standard remains applicable to loss of field relays. This draft of the proposed standard is now
consistent with the approach generally employed by industry for ensuring loss of field relays do not trip in response to a
stable power swing. Change made.
Lincoln
Electric
System
Although appreciative of the drafting team’s efforts in developing PRC-026-1, LES questions whether the development of a
Reliability Standard is necessary for addressing relay performance during stable power swings. Further consideration should
instead be given to the recommendations of the System Protection and Control Subcommittee which noted that “a NERC
Reliability Standard to address relay performance during stable power swings is not needed, and could result in unintended
adverse impacts to Bulk Power System reliability”. In lieu of the standards development process, LES suggests communicating
to FERC an alternative to a Reliability Standard such as an industry guidance or reference document.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
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Arizona Public
Service Co.
Question 10 Comment
APS recommends that the drafting team require an initial identification and notification of each Element that meets the
criteria described R1. A review of the assessment should not be required yearly if there are no additions to the entity system
meeting the criteria. It would be more practical to require a comprehensive review every five years.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial influx of identified
Elements under Requirement R1. The evaluation of relays under Requirement R4 (previously R3) is to be performed “within
12 full calendar months of receiving notification of an Element … where the evaluation has not been performed in the last
three calendar years.” Change made.
In addition, the standard should require that if Elements are added to the entity system that meet the criteria in R1, the
applicable entity should provide updates within 90 days of the commissioning of a new Element.
Response: The drafting team contends that Requirement R1 does not preclude the Planning Coordinator from providing
notice of an identified Element more frequently. No change made.
APS believes that the current draft requirement is administrative in nature and represents a reporting burden.
Response: The proposed standard is consistent with the PSRPS Report which recommends a focused approach to identifying
Elements that are most susceptible to power swings. No change made.
New York
Power
Authority
As previously answered, the referenced 61-page PSRPS technical document, from which much of this Standard’s wording is
copied from, specifically recommends against this standard.
Again, as stated in Pages 5, 20, and 24: “Based on its review of historical events, consideration of the trade-offs between
dependability and security, and recognizing the indirect benefits of implementing the transmission relay loadability standard
(PRC-023), the SPCS concludes that a NERC reliability Standard to address relay performance during stable power swings is not
needed, and could result in unintended adverse impacts to Bulk-Power System reliability.”
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
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feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
Puget Sound
Energy
As stated in the document entitled "Protection System Response to Power Swings" by PSRPS, a review of historical system
disturbances determined that operation of transmission line protection systems during stable power swings was not causal or
contributory to any of the disturbances reviewed. The final conclusion of PSRPS was that a NERC Reliability Standard is not
needed to address relay performance due to stable power swings and could result in unintended adverse impacts to Bulk
Power System reliability. In light of this conclusion, as well as the comments contained in this form, we have voted 'no' on this
standard.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
Response: Minor clarification to the above comment. The NERC System Protection and Control Subcommittee (SPCS)
authored the Protection System Response to Power Swings, August 201313 (PSRPR Report) technical document. This drafting
team took on the Protection System Response to Power Swings Standard Drafting Team (PSRPS SDT) designation. The drafting
team has drafted the standard consistent with the approach provided by the PSRPS Report.
13
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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American
Transmission
Company, LLC
Question 10 Comment
ATC recommends the SDT consider the following changes to add clarity to the Standard:
a. Applicability (Section 4.1.1 & 4.1.4), Requirement R2 - Replace “load responsive” protective relays with “impedance based”
protective relays.
Response: The drafting team did not add the proposed suggestion, but did add a clarification that standard is applicable to
load-responsive protective relays (including overcurrent) which could trip instantaneously or with a time delay of less than 15
cycles. Change made.
b. Requirement R1 - ATC questions the necessity of performing the identification and notification in any particular month.
Why does the requirement stipulate “within the first month of each calendar year”? ATC believes that it should be sufficient
to use wording like, “at least once each calendar year”.
Response: The drafting team adjusted the time periods in the proposed Requirements and Implementation Plan to account
for varying activities. Change made.
c. Requirements R.1.1, R1.2 - What is meant by “stability constraints” (e.g. steady state voltage, transient voltage, steady state
angle, transient angle)? ATC recommends that the SDT use descriptive adjectives before “stability constraint” to clarify which
one, or ones, are intended.
Response: The drafting team added “angular” to “stability constraint” to clarify the intent in Requirement R1, both Criterion 1
and 2. Change made.
d. Requirements R1.3, R1.4 - What is meant by “Disturbances” (e.g. Category B, Category C, P1-P7)? ATC recommends that the
SDT use descriptive adjectives before “Disturbances” to clarify which one, or ones, are intended.
Response: The drafting team revised Requirement R1, Criterion 4 by changing “Disturbance” to “simulated disturbance” to
comport with the approved Reliability Standard TPL-001-4. The use of “Disturbance” in Requirements R2 (TO) and new R3
(GO) relates to an actual system Disturbance. Change made.
e. Requirements R1.3, R2.1, R2.2 - What is meant by the term “credible” when discussing Disturbances (e.g. Disturbances
associated with islands that were selected through R2 of PRC-006-1)? ATC suggests developing proposed alternate language
like, “relevant”, which is easier to demonstrate simply with power flow analysis, rather than valid statistical analysis.
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Response: The term “credible” has been removed from the standard. The drafting team clarified Requirement R1, Criterion 3
by framing the criterion in the present tense to refer to the current assessment(s). Islands caused by natural phenomena (i.e.,
Disturbances) are covered under Requirement R2. Change made.
f. Requirement R1.4 - What is meant by “most recent Planning Assessment”? (e.g. TPL-002/TPL-003 annual assessment, FAC002-1 interconnection assessment) ? ATC recommends to specify which type, or types, are intended.
Response: The drafting team asserts that the most recent Planning Assessment provides a concrete reference to the
information used in identifying BES Elements. Since the Planning Assessments (i.e., TPL-001-4) are performed annually, any
other description would create confusion as to whether an entity should use past information or information revealed during
preparation of a Planning Assessment. No change made.
g. Requirement R2, Criteria 1 and 2 - ATC has concerns about requiring entities to refer to data on power swings and forming
an island back to 1 Jan 2003. ATC recommends additional text in the Criteria such as “if available prior to the effective date”
immediately after “since January 1, 2003”. Retaining this data prior 1 Jan 2003 was not required as implied by the proposed
Standard. Another approach for SDT consideration would be to require retention of data from the effective date of the
Standard.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Change made.
h. Requirements R2.1, R2.2 - ATC questions the inclusion of the statement “since January 1, 2003”. ATC believes that a specific
historical time frame would be more appropriate, such as “in the past 10 years”. Referring to “since January 1, 2003” makes
an ever expanding historical time frame, which at some point, should no longer be relevant.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Change made.
i. R3 - The “Criterion” text only applies to bullet 1 and 3 only, but due to the indentation appears to be a sub element of bullet
4. Therefore, ATC suggests that the “Criterion” be moved more to the left move to avoid the appearance of only applying to
bullet 4.
Response: The drafting team has revised Requirement R4 (previously R3) and moved the criteria to PRC-026-1 – Attachment B
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to increase the understandability of the Requirement. Change made.
Bonneville
Power
Administration
BPA feels the Glossary definition of Disturbance lacks sufficient clarity as it relates to this and other existing Standards. BPA
also requests a descriptive title be used for the Criterion (e.g. Criterion for Swing Protection Analysis).
Response: The drafting team revised Requirement R1, Criterion 4 by changing “Disturbance” to “simulated disturbance” to
comport with the approved Reliability Standard TPL-001-4. The use of “Disturbance” in Requirements R2 (TO) and new R3
(GO) relates to an actual system Disturbance. Change made.
Response: The drafting team has revised Requirement R4 (previously R3) and moved the criteria to PRC-026-1 – Attachment B
to increase the understandability of the Requirement. Change made.
Dominion
Dominion suggests that Associated Documents (at least those where there are no copyright concerns) be included in the
standard as attachments or appendices as we are concerned that cited URLs will change over time.
Response: Thank you for your comment.
Requirement R2 Criteria 1 and 2 require review of Disturbances since January 1, 2003. While Dominion recognizes the desire
to consider Disturbances since January 1, 2003 in order to capture the August 14, 2003 Blackout, it is important to note that
NERC Reliability Standards were not mandatory at that point and data may or may not be available. Dominion recommends
changing the criteria dates to June 18, 2007 to be consistent with the establishment of mandatory and enforceable Reliability
Standards.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Change made.
Duke Energy
Duke Energy would like to reiterate that we do not believe adequate technical justification has been identified for this project
to become a standard. Based on the SPCS recommendation, the SDT and NERC should consider moving this project to a
Guideline document until such time as a standard is warranted.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
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following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
Electric
Reliability
Council of
Texas, Inc.
ERCOT agrees with the NERC System Protection and Control Subcommittee August 2013 report titled Protection System
Response to Power Swings which states: “Based on its review of historical events, consideration of the trade-offs between
dependability and security, and recognizing the indirect benefits of implementing the transmission relay loadability standard
(PRC-023), the SPCS concludes that a NERC Reliability Standard to address relay performance during stable power swings is
not needed, and could result in unintended adverse impacts to Bulk-Power System reliability.” Accordingly, ERCOT
recommends that the standard not move forward.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
If the standard does move forward ERCOT recommends that requirements R1, R2, and R3 be changed from an annual
requirement to once every 60 months in order to minimize unintended adverse impacts to Bulk-Power System reliability.
Response: The drafting team increased the Implementation Plan to three years to provide for the initial influx of identified
Elements under Requirement R1. The evaluation of relays under Requirement R4 (previously R3) is to be performed “within
12 full calendar months of receiving notification of an Element … where the evaluation has not been performed in the last
three calendar years.” Change made.
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Ingleside
Cogeneration
LP
ICLP believes that the findings by NERC’s System Protection and Control Subcommittee (SPCS) compellingly demonstrate that
the initial findings from the 2003 Northeastern blackout were flawed. There is no doubt some load responsive relays did trip
during the event when unusual, but non-threating transients manifested themselves as a result of a downstream Fault.
However, the SPCS found that in every case, a subsequent unstable power swing followed within seconds - and the relay
would have tripped anyways. Furthermore, planning simulations confirmed that had the stable power swing in question had
taken place under N-1 and N-2 contingencies - the norm to which the electric system is designed - those relays would not have
reacted.
Even more concerning, the report goes on to say that “over-emphasizing secure operation for stable powers swings could be
detrimental to Bulk-Power System reliability” (see page 19). This means that FERC Order 733, which relies heavily on the 2003
investigative task force recommendations, may actually increase the threat of wide-area instability or Cascading.
ICLP does not question FERC’s authority to order the development of a Reliability Standard - and we agree the subject matter
is ultra-complex. Nevertheless, FERC should be operating to the best information available, which may have changed over
time. There are far too many other pressing priorities for Registered Entities, CEAs, and even the Commission to expend this
much effort on one that has little or even negative benefit.
At the very least, we would like NERC or the SPCS to request a Technical Conference on the subject. Other such conferences in
the past seem to have resulted in effective, yet reasonable, approaches to similarly complex issues.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
Los Angeles
LADWP is voting “Negative” on PRC-026-1 for the reason that the reference document entitled “Protection System Response
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Department of
Water and
Power
to Power Swings” (the PSRPS document) used to justify the standard does not support the need for a reliability standard.
MidAmerican
Energy
Company
MidAmerican has concerns about the actual reliability benefit the proposed PRC-026 standards would provide versus the
incremental compliance analysis work. There is also the potential for scope creep and the industry needs to focus on
appropriate risks. The criteria specified under R1 could be broad. Criterion 4 seems susceptible to significant scope creep
stating, “An Element identified in the more recent Planning Assessment where relay tripping occurred for a power swing
during a disturbance." Planning Assessments are performed regularly in the TPL standards.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
Response: The drafting team asserts that if the Planning Assessment (i.e., TPL-001-4) shows tripping for a power swing, the
Element would be identified under the Requirement. Additional discussion is provided in the Guidelines and Technical Basis
regarding Criterion 4 under the heading “Requirement R1.” No change made.
The new TPL-001-4 planning standard and R3.1.1 requires the simulated “removal of all elements that the Protection System
and other automatic controls are expected to disconnect for each Contingency without operator intervention”. At a minimum,
this will require generic protection models for each BES line, generator, and transformer. If the Planning assessment shows a
protection model trip, will that element require a PRC-026 analysis?
Response: The drafting team would not expect an entity to model tripping under TPL-001-4, R3 (R3.3.1 as referenced by the
quote). Tripping of an Element observed in the stability section under Requirement R4, 4.3.1.3 would be an Element identified
under PRC-026-1, Requirement R1, Criteria 4 and analyzed by the Generator Owner or Transmission Owner under the
proposed Requirement R4 (previously R3). No change made.
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Many entities are performing stability studies for existing TOP standards on a short-term to nearly daily basis to verify that
entities are not entering and “unknown state”. While such studies aren’t a traditional “Planning Assessments”, could shortterm TOP related dynamic analyses that show potential trippling (such as exceeding a protection setting limit) be forced to
prove tripping wasn't due to stable power swings in PRC-026?
Response: The drafting team asserts “operations assessments” are not considered within the scope of the proposed standard.
The standard addresses the risk for specific Elements and conditions revealed in operations assessments and could be
communicated to the Planning Coordinator for evaluation and possible identification under PRC-026-1, Requirement R1,
Criterion 4. No change made.
Will the criteria in R1 inappropriately identify suggested islands required by PRC-006? The NERC PRC-006 UFLS standards
require entities to identify and simulate islands. Will PRC-026 inappropriately identify PRC-006 islands (which may not have a
real UFLS event as a basis) because PRC-006 required an island be developed and a simulation be performed by a powerflow
stability simulation which considers angular stability? Criterion 3 mentions both island boundaries and angular stability. There
is a qualifier of a credible event. But entities will construct reasonable events for PRC-006. Are reasonable and credible the
same?
Response: The term “credible” has been removed from the standard. The drafting team clarified Requirement R1, Criterion 3
by framing the criterion in the present tense to refer to the current assessment(s). Islands caused by natural phenomena (i.e.,
Disturbances) are covered under Requirement R2. Change made.
DTE Electric
No comment
FirstEnergy
Corp.
None
Oncor Electric
Delivery LLC
R1 criteria 4 states to identify the following element: “An Element identified in the most recent Planning Assessment where
relay tripping occurred for a power swing during a Disturbance.” In the statement above it is not clear whether the
disturbance is actual or simulated.
Response: The drafting team revised Requirement R1, Criterion 4 by changing “Disturbance” to “simulated disturbance” to
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comport with the approved Reliability Standard TPL-001-4. The use of “Disturbance” in Requirements R2 (TO) and new R3
(GO) relates to an actual system Disturbance. Change made.
R4 should state Each Generator Owner and Transmission Owner shall implement each CAP developed pursuant to
Requirement R3 if option 3 or option 4 are chosen, and update each CAP if actions or timetables change, until all actions are
complete. There should be no CAP required if R3 option 2 is chosen and the application of power swing blocking must be
applied to specific relay locations.
Response: The drafting team has modified the Requirements to be clearer that a CAP is required when the entity must
develop a Corrective Action Plan (CAP) to modify a Protection System to meet the PRC-026-1 – Attachment B. Change made.
Oncor agrees with the recommendation of the NERC PC (SCPS) and recommends if this has not been reviewed by NERC RISC,
this may be an opportunity for the NERC Standard Committee (SC) to bring back to RISC for discussion in conjunction with the
PSRPS technical document.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
CHPD - Public
Utility District
No. 1 of
Chelan County
R1.1 - There should be a clarification or definition of a line-out condition. The meaning and intent of this note is not clear.
Response: The phrase “line-out conditions” has been removed. Elements should be identified based on the Requirement R1
criterion regardless of the outage conditions that may be necessary to trigger enforcement of the System Operating Limit
(SOL) or arming of the Special Protection System (SPS). The Guidelines and Technical Basis have been supplemented to
provide additional information. (Note: The use of SPS has been replaced with Remedial Action Scheme (RAS) for consistency
with a current project to revise the definition of “Special Protection System”). Change made.
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Liberty Electric
Power
Question 10 Comment
R2 requires Generator Operators to possess evidence prior to the enforcement date of the Standards, and prior to the
passage of the Energy Act of 2005. No standard should be written which requires an entity to possess, analyze, or have
knowledge of an event prior to the effective date of the standard. The beginning date of analysis should be the first full
calander year after the FERC approval date of the standard.
Response: The term “credible” has been removed from the standard. The drafting team clarified Requirement R1, Criterion 3
by framing the criterion in the present tense to refer to the current assessment(s). Islands caused by natural phenomena (i.e.,
Disturbances) are covered under Requirement R2. Change made.
Bureau of
Reclamation
Reclamation suggests that R2 be rephrased to only require analysis of data from the previous year. As written, R2 would
require Transmission Owners and Generator Owners to re-analyze data going back to 2003 each year. Reclamation believes
that the costs of re-analyzing this data would outweigh the benefits. Reclamation believes that NERC should develop a data
request to develop a robust initial data set covering January 2003 to present.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Events that occur will be reported to the Planning
Coordinator in order to maintain the Element as an “identified Element.” Change made.
ReliabiltiyFirst
ReliabilityFirst offers the following comments for consideration.
1. Requirement R1 - To be consistent with other NERC Reliability Standards, ReliabilityFirst suggests reclassifying the “criteria”
as “sub-parts” of the requirement.
Response: The drafting team has revised Requirement R4 (previously R3) and moved the criteria to PRC-026-1 – Attachment B
to increase the understandability of the Requirement. Change made.
2. Requirement R2 - R2 requires GOs and TOs to evaluate Disturbances “since January 1, 2003”. It appears that the intent of
this requirement is to include Elements where actual system events caused a trip due to a known power swing and, by
including the 2003 date, ensured that events associated with the 2003 Blackout were included. However, this may imply that
events prior to 2003 need not be considered, especially in areas other than the Northeast where the blackout occurred. If an
Element had a known trip for power swings associated with a Disturbance, they should be included. Therefore, ReliabilityFirst
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recommends the flowing for consideration for the two criteria:”
1. An Element that has tripped since January 1, 2003 [(or known historical Element that tripped prior to January 1,
2003)], due to a power swing during an actual system Disturbance where the Disturbance(s) that caused the trip due to
a power swing continues to be credible.
2. An Element that has formed the boundary of an island since January 1, 2003 [(or known historical Element that
formed the boundary of an island prior to January 1, 2003)], during an actual system Disturbance where the
Disturbance(s) that caused the islanding condition continues to be credible.”
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Events that occur will be reported to the Planning
Coordinator in order to maintain the Element as an “identified Element.” Change made.
3. Requirement R3 - ReliabilityFirst requests clarification on how the Criterion in Requirement R3 fits into the requirement. Is
this criterion part of the requirement or is it additional information? If it is the later, ReliabilityFirst believes this guidance is
already covered in the “Guidelines and Technical Basis” section and should be removed from the requirements. NERC
Reliability Requirements should address “what” is required and not “how” an entity will comply.
Response: The drafting team has revised Requirement R4 (previously R3) and moved the criteria to PRC-026-1 – Attachment B
to increase the understandability of the Requirement. Change made.
Salt River
Project
Salt River Project is concerned that system protection should not be "de-tuned" at the expense of the protection provided the
Bulk Electric System for the sake of reliability.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
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advanced in these FERC proceedings.
Texas
Reliability
Entity
Section 1.2 - Evidence Retention: Language as written appears to be unnecessarily complicated. Suggest changing to:
“Functional Entities shall retain evidence demonstrating compliance since the last audit or for three calendar years, whichever
is longer.”
Response: NERC staff has informed the drafting team that the language in the evidence retention section is pro-forma
language used in each Reliability Standard. After reviewing the language and consulting with NERC staff, no change has been
made. The drafting team encourages TRE to contact NERC standards staff to determine whether a change is necessary to its
pro-forma language.
BC Hydro
Since the SPCS has concluded that no lines were tripped due to stable power swings, in any of the major disturbances, the
FERC directive is flawed, and this regulation should not be implemented.
Response: The drafting team acknowledges BC Hydro’s position on the FERC directive. However, the validity of the directive
was challenged at multiple stages of the FERC proceeding and despite the arguments made, FERC issued its directive and has
since maintained its position that a standard is needed to meet the directive. The drafting team is charged with designing a
standard to meet the Commission directive. The drafting team understands that NERC staff re-engaged FERC staff following
the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the directive, but
they were open to an approach designed by NERC. The drafting team thanks you for your comment.
Northeast
Power
Coordinating
Council
Suggest that Associated Documents (at least those where there are no copyright concerns) be included in the standard as
attachments or appendices as we are concerned that cited URLs will change over time. The information in the Criteria and
Criterion in the standard should not be in the requirements, but in the Rationale Boxes.
Tacoma Power
Tacoma Power supports the spirit of PSEG’s response to Question 3. Furthermore, Tacoma Power has the following, additional
comments related to the January 1, 2003, date.
Response: It is more appropriate to cite a specific work where applicable. The drafting team has provided sufficient citations
of the work and URL links, if available.
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1) Not all Generator Owners and Transmission Owners may be required to retain records going back to January 1, 2003.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Change made.
2) Apart from including the 2003 Northeast Blackout, no other technical justification has been provided for why the January 1,
2003, date was selected. Alternatives might be to indicate specific disturbances for which documentation likely exists or to
conduct a data request to collect better information so that Requirements R1 and R2 could be consolidated and then provide
more refined and simpler criteria.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Change made.
Setting aside the previous comment, does Requirement R2 Criterion 2 add any value beyond that provided by Criterion 1? If
so, the term ‘island’ may need to be better defined.
Response: The drafting team has provided additional discussion and example why Criterion 2 is providing additional value.
Change made.
What is the technical basis in Requirement R2 for identification to occur in January of each year?
Response: The Requirement R1 language about “January of each calendar” has been removed and replaced with “each
calendar year.” Based on time period changes in other Requirements, the drafting team determined that an annual periodicity
in Requirement R1 is more appropriate. Change made.
Luminant
Generation
Company LLC
The Attachments to the standard should include a listing of the specific load responsive relays that are included in the scope
of the standard.
MRO NERC
Standards
The NSRF recommends the SDT consider the following changes to add clarity to the Standard:
Response: The drafting team has provided PRC-026-1 – Attachment A to address which relays are included and excluded.
Change made.
a. Applicability (Section 4.1.1 and 4.1.4), Requirement R2 - Replace “load responsive” protective relays with “impedance
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based” protective relays.
Response: The drafting team did not add the proposed suggestion, but did add a clarification that standard is applicable to
load-responsive protective relays (including overcurrent) which could trip instantaneously or with a time delay of less than 15
cycles. Change made.
b. Requirement R1 - The NSRF questions the necessity of performing the identification and notification in any particular
month. Why does the requirement stipulate “within the first month of each calendar year”? THE NSRF believes that it should
be sufficient to use wording like, “at least once each calendar year”.
Response: The Requirement R1 language about “January of each calendar” has been removed and replaced with “each
calendar year.” Based on time period changes in other Requirements, the drafting team determined that an annual periodicity
in Requirement R1 is more appropriate. Change made.
c. Requirements R.1.1, R1.2 - What is meant by “stability constraints” (e.g. steady state voltage, transient voltage, steady state
angle, transient angle)? The NSRF recommends that the SDT use descriptive adjectives before “stability constraint” to clarify
which one, or ones, are intended.
Response: The drafting team added “angular” to “stability constraint” to clarify the intent in Requirement R1, both Criterion 1
and 2. Change made.
d. Requirements R1.3, R1.4 - What is meant by “Disturbances” (e.g. Category B, Category C, P1-P7)? THE NSRF recommends
that the SDT use descriptive adjectives before “Disturbances” to clarify which one, or ones, are intended.
Response: The drafting team revised Requirement R1, Criterion 4 by changing “Disturbance” to “simulated disturbance” to
comport with the approved Reliability Standard TPL-001-4. The use of “Disturbance” in Requirements R2 (TO) and new R3
(GO) relates to an actual system Disturbance. Change made.
e. Requirements R1.3, R2.1, R2.2 - What is meant by the term “credible” when discussing Disturbances (e.g. Disturbances
associated with islands that were selected through R2 of PRC-006-1)? THE NSRF suggests developing proposed alternate
language like, “relevant”, which is easier to demonstrate simply with power flow analysis, rather than valid statistical analysis.
Response: The term “credible” has been removed from the standard. The drafting team clarified Requirement R1, Criterion 3
by framing the criterion in the present tense to refer to the current assessment(s). Islands caused by natural phenomena (i.e.,
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Disturbances) are covered under Requirement R2. Change made.
f. Requirement R1.4 - What is meant by “most recent Planning Assessment”? (e.g. TPL-002/TPL-003 annual assessment, FAC002-1 interconnection assessment) ? THE NSRF recommends to specify which type, or types, are intended.
Response: The drafting team asserts that the most recent Planning Assessment provides a concrete reference to the
information used in identifying BES Elements. Since the Planning Assessments (i.e., TPL-001-4) are performed annually, any
other description would create confusion as to whether an entity should use past information or information revealed during
preparation of a Planning Assessment. No change made.
g. Requirements R2.1, R2.2 - The NSRF questions the inclusion of the statement “since January 1, 2003”. THE NSRF believes
that a specific historical time frame would be more appropriate, such as “in the past 10 years”. Referring to “since January 1,
2003” makes an ever expanding historical time frame, which at some point, should no longer be relevant.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Change made.
h. R3 - The “Criterion” text only applies to bullet 1 and 3 only, but due to the indentation appears to be a sub element of bullet
4. Therefore, THE NSRF suggests that the “Criterion” be moved more to the left move to avoid the appearance of only
applying to bullet 4.
Response: The drafting team has revised Requirement R4 (previously R3) and moved the criteria to PRC-026-1 – Attachment B
to increase the understandability of the Requirement. Change made.
NSRF has concerns about not having data back to 1 Jan 2003. R2 needs to have “if available prior to the effective date “. The
SDT is looking for data before the effective date of the proposed Standard. We believe the intention of having the data but we
did not know that the required data was needed to be saved from 1 Jan 2003. From the effective date of this Standard is
another approach in retaining the required data.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Change made.
Idaho Power
The PSRPS report and the SPS report no need for this Standard, stating that "operation of transmission line protection systems
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Question 10 Comment
during stable power swings was not causal or contributory to any of these disturbances." This statement conflicts with the
need for the Standard and causes added Compliance burden to entities without reason.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
Exelon
The SPCS white paper “Protection System Response to Power Swings” (August 2013), found, “Based on its review of historical
events, consideration of the trade-offs between dependability and security, and recognizing the indirect benefits of
implementing the transmission relay loadability standard (PRC-023), the System Protection and Control Subcommittee (SPCS)
concludes that a NERC Reliability Standard to address relay performance during stable swings is not needed, and could result
in unintended adverse impacts to Bulk-Power System reliability.”
Notwithstanding that recommendation, the white paper also outlined an approach for developing a power swing reliability
standard in the event a standard is proposed to address the FERC Directive. We agree that the SDT has adhered to the SPCS’s
recommendations in the present draft, but we do not believe that the technical basis for the SPCS recommendation against
creating a standard has been challenged and that there is sufficient justification for continuing with the effort to write a
standard addressing this issue. To the best of our knowledge, our operating companies, ComEd, BGE and PECO, have never
experienced a relay trip due to a power swing. We recognize and appreciate the Drafting team’s work in responding to
comments to the SAR suggesting that alternative means of meeting the Directive should be explored. As discussed by
numerous stakeholders in the previous response to comments, we believe further work in this area should continue.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
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directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
Seattle City
Light
The Standard is very complicated and confusing. It appears to be a lot like FERC Order 754 effort that we recently went
through, which required two or three rounds of submissions before industry was providing the information envisioned by the
framers of the process.
Proposed PRC-026 involves considerable new interaction between the Planning and Protection groups. The Application
Guidelines, while somewhat helpful, need to include much more explicit examples. A flow chart, or something similar, is
necessary to fully delineate the steps in the process. Much more guidance is definitely needed before the Standard can be
implemented.
Response: The drafting team has substantively revised the standard and Guidelines and Technical Basis to improve the
understandability. Change made.
This draft of the Standard represents a work in progress, at best. Before any such untried process be mandated as a Standard
(if it is ultimately deemed necessary that a Standard is required) Seattle City Light recommends a non-mandatory trial period
of at least two years, long enough to work the bugs out of the system and ensure that entities understand and are able to
perform the activities as envisioned and required. Perhaps such a trail could be conducted as a NERC request for data under
Section 1600 Rules of Procedure.
Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background.
ITC
We are voting Negative primarily for two reasons: 1) the issues we raised need to be addressed to close some gaps and 2) we
support the conclusion of SPCS in the PSRPS report that this standard “is not needed, and could result in unintended adverse
impacts to Bulk-Power System reliability.”
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Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
As written, the standard only addresses distance and not overcurrent elements. This question was raised in the webinar and a
clear answer was not given. The standard refers to “load-responsive” relays, which includes overcurrent, but does not provide
criteria for evaluation in R3. Also, should the standard include time-delayed tripping elements, which are commonly ignored
for swing tripping consideration?
Response: The drafting team added a clarification that standard is applicable to load-responsive protective relays (including
overcurrent) which could trip instantaneously or with a time delay of less than 15 cycles. Change made.
We also request examples for R3, fourth bullet, of scenarios which do not result in “dependable fault detection or dependable
out-of-step tripping”, perhaps in the App Guide. Specifically, we are concerned about load/swings with subsequent phase
faults which result in time-delayed tripping when power swing blocking is enabled. Even the most modern SEL-400 relays with
zero-setting OOS logic includes additional time delayed tripping for subsequent phase faults. For a standard around swings
and stability, delayed fault clearing seems to counterproductive. Is this the scenario which could apply to R3, fourth bullet?
Response: The drafting team has concluded that it is possible to comply with the PRC-026-1 – Attachment B, Criteria while
providing dependable fault detection or dependable out-of-step tripping and has removed this bullet from Requirement R4
(previously R3).
Public Utility
District No. 1
of Cowlitz
We believe this Standard will address a Reliability gap, but also feel that it can overlap into PRC-004. Load responsive relays
that trip on a stable power swing should be addressed by PRC-004 as a Protection System Misoperation; subsequently after
PRC-004 is satisfied, the affected element should be subject to PRC-026-1 until a repeat is demonstrated to be remote or
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Question 10 Comment
nonexistent. However, a violation of PRC-004 should not automatically bleed into a violation of PRC-026-1.
Response: There should be no conflict here. If an entity determines a protective relay operation was a Misoperation, it would
address the cause of the miss operation under PRC-004. A Misoperation in and of itself is not a violation according to the
effective version PRC-004-2.1a. If the operation was due to a stable power swing, then the Element for which the loadresponsive relay is applied at the terminals, would then become an identified Element under PRC-026-1.
SPP Standards
Review Group
We note that the SPCS concluded that this standard was not needed based on their review and analysis of past disturbances.
They went on to say that such a standard ‘...could result in unintended adverse impacts to Bulk-Power System reliability.’
Given their conclusion, has NERC and/or the SDT given any consideration to requesting FERC reconsider their directive to
develop this standard?
Response: Yes. The drafting team understands that NERC staff re-engaged FERC staff following the completion of the PSRPS
Report and that the Commission still desired NERC to pursue its work to meet the directive. However, FERC staff was open to
an approach designed by NERC. NERC staff has informally received positive feedback on the approach to address the
regulatory directive. The directive itself was challenged by commenters prior to the issuance of Order No. 733 and was
already the subject of multiple rehearing requests in the Order No. 733-A and Order No. 733-B proceedings. Similar
arguments to the conclusions of the NERC System Protection and Control Subcommittee (SPCS) were advanced in these FERC
proceedings.
The following are comments on the draft RSAW.
We recommend that a specific reference be made to the question of providing evidence based on experience prior to the
effective date of the standard. Please see our response to Question 6 above. The industry needs assurances from NERC
Compliance that auditors will not be holding responsible entities accountable for providing data on events that occurred prior
to the effective date of the standard.
The 1st and 2nd cells of the Evidence Requested and Compliance Assessment Approach tables for both Requirements R1 and
R2 insert additional requirements that are not contained in the requirements in the standard. These items request
evidence/documentation on the methodology and the utilization of that methodology by the responsible entity in the
identification of the Elements called for in the two requirements. Neither Requirement R1 nor Requirement R2 mention
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anything about requiring the responsible entity to 1) have a methodology for performing that identification and 2) use the
methodology in the identification process. These items need to be deleted from the RSAW along with the Note to Auditor
under the Registered Entity Response for both Requirements R1 and R2. These notes refer to these two items.
In the Note to Auditor under the Compliance Assessment Approach Specific to PRC-026-1, R2 replace the ‘all’ at the end of the
3rd line with ‘a’. Still within this section, does the SDT concur with the interpretation of the example at the top of Page 9? If
not, we ask that the SDT inform the RSAW developers.
Response: Thank you for your comments. The Reliability Standard Audit Worksheet (RSAW) comments have been provided to
NERC Compliance as they are responsible for the content of the RSAW.
Xcel Energy
R2 states that elements involved in a power swing since 2003 are targeted for evaluation, with the caveat that the “power
swing continues to be credible.” It seems that what constitutes a credible threat is widely open for debate. If it’s not credible
once, is it eliminated from consideration going forward?
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard.
The term “credible” has been removed from the standard. The drafting team clarified Requirement R1, Criterion 3 by framing
the criterion in the present tense to refer to current assessment(s). The term “credible” was removed from the previous
Requirement R2 (and new R3) because the required performance refers to only current actual events. Change made.
Associated
Electric
Cooperative,
Inc.
1. This standard is the result of a FERC directive. Yet the reference document entitled “Protection System Response to Power
Swings” (the PSRPS document) used to justify the standard does not support the need for the standard. The reference
document was prepared by the NERC System Protection and Control Subcommittee and was approved by the NERC Planning
Committee. It is posted at
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Powe
r%20Swing%20Report_Final_20131015.pdf.
Our comments explains this concern and recommends that “the NERC Standards Committee explore means to utilize the
more recent PSRPS document to obtain relief from the aforementioned FERC directive that is driving this project.”
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Response: Please see the section at the beginning of this document called, “NERC Discussion on Proceeding(s) and Directives
Regarding: Stable Power Swings” for a complete background. The SDT understands that NERC staff re-engaged FERC staff
following the completion of the PSRPS Report and that the Commission still desired NERC to pursue its work to meet the
directive. However, FERC staff was open to an approach designed by NERC. NERC staff has informally received positive
feedback on the approach to address the regulatory directive. The directive itself was challenged by commenters prior to the
issuance of Order No. 733 and was already the subject of multiple rehearing requests in the Order No. 733-A and Order No.
733-B proceedings. Similar arguments to the conclusions of the NERC System Protection and Control Subcommittee were
advanced in these FERC proceedings.
2. Although we object to the standard in its entirety, R2 is particularly egregious and we are objecting to it so that similar
language will never appear in a NERC standard. R2 requires GOs and TOs to evaluate Disturbance records “since January 1,
2003,” a time that will precede the effective date of this standard. A requirement cannot rely upon records that precede the
effective date of a standard. As an example, PRC-005-1, which was approved in Order 693, became effective on June 11, 2007,
does not require a Registered Entity to have maintenance records available for the period of time that preceded the effective
date in order to calculate the next maintenance interval for a relay.
Response: The “January 1, 2003” date has been removed from the standard. Requirement R2 (and new R3) are based on
actual Disturbances that occur after the Effective Date of the standard. Events that occur will be reported to the Planning
Coordinator in order to maintain the Element as an “identified Element.” Change made.
Additional Comments (Response follows)
Si Truc PHAN
Hydro-QuébecTransÉnergie
Author: .Eric Loiselle, eng. Automatismes, Hydro-Québec TransÉnergie
Date 2014-05-19
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Requirement R3 Application Guidelines, Application to Transmission Owners, page 16 to 19
The 120° lens shape criterion with system impedance including all parallel paths defines a boundary limit corresponding to ZbusA_ allowable =
Application Guidelines should explain that distance relay R, at the line L of bus A, measures I L , and not Itotal. I L = I total ×
VA
. The
I total
ZTR
.
Z L + ZTR
R
L
ITotal
Bus A
Bus B
Figure 114 : Two- Machine Equivalent of a Power System with Parallel System Transfer Impedance.
14
Figure 29, SPCS Power Swings Report, 20131015
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The distance reach allowable before the relay R trip is:
Z relayR_ allowable =
VA
IL
=
(ZL + ZTR )
ZTR
VA
Itotal
ZrelayR_ allowable= = Z busA _ allowable
(Z L + ZTR )
ZTR
The distance element of a relay R, measuring I L , can be set greater that the distance element of a relay measuring Itotal. Therefore, the lens
characteristic of the total system impedance cannot directly be compared with the distance characteristic of a line. To juxtapose the two
characteristics in the same R-X plane, either the lens or the distance element need to be scale by a factor
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Z TR
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Example: Hydro-Quebec 735 kV network
Typical Hydro-Quebec network configuration is 3 parallel 735 kV lines connecting into 2 substations. See figure below.
Figure 2: Two- Machine Equivalent of a typical Hydro-Quebec network.
R
X
Notes
Zg
0,9
23,9 Subtransient impedance, nominal generator and load
ZL1
3,2
55,8 Include -32 j ohms of series compensation CXC
ZL2
2,9
50,6 Include -32 j ohms of series compensation CXC
ZL3
2,9
50,6 Include -32 j ohms of series compensation CXC
Zthe
14,6
325,9 Thevenin equivalent of other links between Bus A and B
2,1
55,5 Subtransient impedance, nominal generator and load
Zh
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The 120° lens characteristic and the total system impedance at bus A are drawn at the figure below.
System
Impedance
80
60
40
20
0
-40
-30
-20
-10
0
10
20
30
40
-20
-40
Figure 3: Stability boundary at 120° and total system impedance at bus A.
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Typical 735 kV lines are protected by main A and main B current differential protections. Back up distance protection is also used. This distance
protection is subject to PRC-026 and need to be evaluated. The larger tripping element of this protection is typically a zone 3 MHO set at 130% of
the line impedance without CXC compensation. See next figure.
130
Line impedance
110
Zone 3 tripping
characteristic
90
Z relayR _ allowable =
VA
IL
70
50
30
10
-70
-60
-50
-40
-30
-20
-10
0
-10
10
20
30
40
50
60
70
Figure 4: Relay R zone 3 MHO set at 130% of the line impedance without CXC compensation.
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This distance relay R measures IL1, not Itotal. The distance element of figure 4 cannot be juxtaposed with figure 3 lens shape.
Figure 5: Calculation of the ratio between IL1 and Itotal.
(Z L1 + Z TR ) = 4.6
Z TR
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Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings | August 22, 2014
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The distance relay measures 1/4.6 of the total system current. Therefore, the zone element of the line 1 is divided by 4.6 before being juxtaposed
with the total system boundary stability.
80
Total System Impedance 3
lines in service
Stability boundary at 120°
Zone 3 element of line 1
scaled down
60
40
20
0
-40
-30
-20
-10
0
10
20
30
40
-20
-40
Figure 6: Juxtaposition of zone 3 line element and 120° lens shape, in the total system R-X plane, at bus A
Consideration of Comments (To Draft 1: PRC-026-1)
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The MHO 130% elements is clearly inside the 120° lens characteristic. With three735 kV lines interconnecting bus A and B, power swings are
unlikely to occur. As mentioned by the SPCS power swing report, considering all the parallel transfer impedance is more accurate and allows a
greater relay reach.
The 735 kV Hydro-Quebec is more likely to swing when two of the three 735 kV lines are out of service. PRC-026 R3 doesn’t impose to evaluate this
case. However, it’s an interesting topology to study.
Bus A
R
Bus B
IL1
ZL1
EG
EH
ZL2
ZG
735 kV
Itot
ZL3
ZH
735 kV
Zthe
275 km
Figure 7: Two- Machine Equivalent of a typical Hydro-Quebec network with two 735 kV lines out of service.
Here, the transfer impedance is increased approximately by three. The line current IL1 measures by the relay R is almost equal to the total system
current Itotal.
The scale factor is reduced:
(Z L1 + Z TR ) = 1.2
Z TR
Consideration of Comments (To Draft 1: PRC-026-1)
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With this special topology, the MHO Zone 3 element is no more contain within the 120° stability boundary, as shown at the next figure.
120
Total System Impedance 2 Lines
Out of Service
Stability boundary at 120°
100
L1 Zone 3 tripping element scaled
down
Stability boundary at 100°
80
60
40
20
0
-60
-50
-40
-30
-20
-10
0
10
20
30
40
50
60
-20
-40
Figure 7: Juxtaposition of zone 3 line element and total system 120° lens shape, in the same R-X plane.
Consideration of Comments (To Draft 1: PRC-026-1)
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With only one 735 kV in service, nominal generation and load are not allowed. In case of a sudden loss of two 735 kV lines, specials protection
systems will reject generation and load within 20 cycles. Zg and Zh will be increased, so as the lens shape representing the stability boundary.
The total system impedance of figure 7 can only exist for a maximum of 20 cycles. Zone 3 is a delayed tripping element of 30 cycles. It can be
assumed that it won’t trip in this condition. As allowed by PRC-026-R3, maybe a reduced stability angle could be used to evaluate this particular
topology. The last figure shows that the zone 3 tripping element is within a 100° lens shape.
Response: On May 9, 2014, Eric Loiselle of Hydro-Québec presented a technical document showing that the impedance seen by a relay on a line
being evaluated for PRC-026-1 compliance is affected by the parallel transfer impedance in the reduced system network. Inclusion of the transfer
impedance in the lens evaluation results in an “apparent lens” impedance as observed by the relay in question that is larger than the observed
impedance without the parallel transfer impedance. It was the opinion of Hydro-Quebec that this transfer impedance should be considered when
performing the lens evaluation.
The drafting team agrees with the analysis in the technical document presented by Hydro-Quebec, but disagrees with their assessment that the
parallel transfer impedance should be included in the lens evaluation.
The drafting team asserts that the parallel transfer impedance should be removed when calculating the total system impedance so that the most
conservative portion of a lens characteristic is formed. When the parallel transfer impedance is included, the split in current through the parallel
transfer impedance path results in actual measured relay impedances that are larger than those measured when the parallel transfer impedance is
removed, which would make it more likely for an impedance relay element to be completely contained within the portion of the lens characteristic.
If the transfer impedance is included in the lens evaluation, a distance relay element could be deemed passing, but could subsequently trip for a
stable power swing during an actual event if the system was weakened to the point where the lines that make up the parallel transfer impedance
were removed.
Other changes have been made to alleviate some of the concerns shown in Hydro-Quebec’s example. In their example, they show a zone 3 relay
with a trip time delay of 30 cycles. This relay would be exempted from evaluation per the revised Standard since it trips in a time delay of 15 cycles
or greater. Also, the lens evaluation in the criteria has been modified to a portion of a lens. The first posted draft 1 of the proposed standard used a
complete lens characteristic by varying the system voltages from 0 to 1.0 per unit. Draft 2 of the proposed standard changed this voltage range
from 0.7 to 1.0 so that only a portion of a lens is formed. These voltage ranges are more realistic and sufficiently conservative, and will make it
more likely for an impedance relay element to meet the criteria.
It was additionally noted in Hydro-Quebec’s zone 3 example that it would pass with a system angle of 100 degrees. This reduced system angle is
still allowed in the Criteria if a documented stability analysis shows the reduced angle is acceptable.
Consideration of Comments (To Draft 1: PRC-026-1)
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END OF REPORT
Consideration of Comments (To Draft 1: PRC-026-1)
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PRC-026-1 — Relay Performance During Stable Power Swings
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SAR posted for comment from August 19, 2010 through September 19, 2010.
2. SC authorized moving the SAR forward to standard development on August 12, 2010.
3. SC authorized initial posting of draft 1 on April 24, 2014.
4. Draft 1 of PRC-026-1 was posted for a 45-day formal comment period from April 25 –
June 9, 2014 and an initial ballot in the last ten days of the comment period from May 30
– June 9, 2014.
Description of Current Draft
The Protection System Response to Power Swings Standard Drafting Team (PSRPS SDT) is
posting Draft 2 of PRC-026-1 – Relay Performance During Stable Power Swings for a 45-day
additional comment period and concurrent/parallel additonal ballot in the last ten days of the
comment period.
Anticipated Actions
Anticipated Date
45-day Formal Comment Period with Concurrent/Parallel Initial Ballot
April 2014
45-day Formal Comment Period with Concurrent/Parallel Additional
Ballot
August 2014
Final Ballot
October 2014
NERC Board of Trustees Adoption
November 2014
Version History
Version
Date
1.0
TBD
Action
Effective Date
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
Change
Tracking
New
Page 1 of 73
PRC-026-1 — Relay Performance During Stable Power Swings
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Glossary of Terms Used in Reliability Standards are not repeated here.
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.
Term: None.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
When this standard has received ballot approval, the rationale boxes will be moved to the
Application Guidelines Section of the Standard.
A. Introduction
1.
Title:
Relay Performance During Stable Power Swings
2.
Number:
PRC-026-1
3.
Purpose: To ensure that load-responsive protective relays are expected to not trip in
response to stable power swings during non-Fault conditions.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Generator Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
4.1.2
Planning Coordinator.
4.1.3
Transmission Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
4.2. Facilities: The following Bulk Electric System (BES) Elements:
5.
4.2.1
Generators.
4.2.2
Transformers.
4.2.3
Transmission lines.
Background:
This is the third phase of a three-phased standard development project that focused on
developing this new Reliability Standard to address protective relay operations due to
stable power swings. The March 18, 2010, FERC Order No. 733, approved Reliability
Standard PRC-023-1 – Transmission Relay Loadability. In this Order, FERC directed
NERC to address three areas of relay loadability that include modifications to the
approved PRC-023-1, development of a new Reliability Standard to address generator
protective relay loadability, and a new Reliability Standard to address the operation of
protective relays due to stable power swings. This project’s SAR addresses these
directives with a three-phased approach to standard development.
Phase 1 focused on making the specific modifications to PRC-023-1 and was
completed in the approved Reliability Standard PRC-023-2, which became mandatory
on July 1, 2012.
Phase 2 focused on developing a new Reliability Standard, PRC-025-1 – Generator
Relay Loadability, to address generator protective relay loadability; PRC-025-1 was
approved by FERC on July 17, 2014.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
This Phase 3 of the project establishes requirements aimed at preventing protective
relays from tripping unnecessarily due to stable power swings by requiring the
identification of Elements on which a power swing may affect Protection System
operation, and to develop requirements to assess the security of load-responsive
protective relays to tripping in response to a stable power swing. Last, to require
entities to implement Corrective Action Plans, where necessary, to improve security of
security of load-responsive protective relays for stable power swings so they are
expected to not trip in response to stable power swings during non-Fault conditions
while maintaining dependable fault detection and dependable out-of-step tripping.
6.
Effective Date:
Requirements R1-R3, R5, and R6
First day of the first full calendar year that is 12 months after the date that the standard
is approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is
not required, the standard shall become effective on the first day of the first full
calendar year that is 12 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Requirement R4
First day of the first full calendar year that is 36 months after the date that the standard
is approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is
not required, the standard shall become effective on the first day of the first full
calendar year that is 36 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
B. Requirements and Measures
R1. Each Planning Coordinator shall, at least once each calendar year, identify each Element in
its area that meets one or more of the following criteria and provide notification to the
respective Generator Owner and Transmission Owner, if any: [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning]
Criteria:
1. Generator(s) where an angular stability constraint exists that is addressed by an
operating limit or a Remedial Action Scheme (RAS) and those Elements
terminating at the transmission switching station associated with the generator(s).
2. An Element that is monitored as part of a System Operating Limit (SOL) that has
been established based on angular stability constraints identified in system
planning or operating studies.
3. An Element that forms the boundary of an island due to angular instability within
the most recent underfrequency load shedding (UFLS) assessment.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
4. An Element identified in the most recent Planning Assessment where relay
tripping occurs due to a stable or unstable power swing during a simulated
disturbance.
5. An Element reported by the Generator Owner or Transmission Owner pursuant to
Requirement R2 or Requirement R3, unless the Planning Coordinator determines
the Element is no longer susceptible to power swings.
M1. Each Planning Coordinator shall have dated evidence that demonstrates identification and
the respective notification of the Element(s), if any, which meet one or more of the criteria
in Requirement R1. Evidence may include, but is not limited to, the following
documentation: emails, facsimiles, records, reports, transmittals, lists, or spreadsheets.
Rationale for R1: The Planning Coordinator has a wide-area view and is in the position to
identify Elements which meet the criteria, if any. The criterion-based approach is consistent
with the NERC System Protection and Control Subcommittee (SPCS) technical document
Protection System Response to Power Swings, August 2013 (“PSRPS Report”),1 which
recommends a focused approach to determine an at-risk Element.
R2. Each Transmission Owner shall, within 30 calendar days of identifying an Element that
meets either of the following criteria, provide notification of the Element to its Planning
Coordinator: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
Criteria:
1. An Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load-responsive protective relays.
2. An Element that forms the boundary of an island during an actual system
Disturbance due to the operation of its load-responsive protective relays.
M2. Each Transmission Owner shall have dated evidence that demonstrates identification of the
Element(s), if any, which meet either of the criteria in Requirement R2. Evidence may
include, but is not limited to, the following documentation: emails, facsimiles, records,
reports, transmittals, lists, or spreadsheets.
1
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
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PRC-026-1 — Relay Performance During Stable Power Swings
Rationale for R2: The Transmission Owner is in the position to identify the load-responsive
protective relays that have tripped due to power swings, if any. The criteria is consistent with
the PSRPS Report. A time to complete a review of the relay tripping is not addressed here as
other NERC Reliability Standards address the review of Protection System operations.
R3. Each Generator Owner shall, within 30 calendar days of identifying an Element that meets
the following criterion, provide notification of the Element to its Planning Coordinator:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
Criterion:
1. An Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load-responsive protective relays.
M3. Each Generator Owner shall have dated evidence that demonstrates identification of the
Element(s), if any, which the criterion in Requirement R3. Evidence may include, but is
not limited to, the following documentation: emails, facsimiles, records, reports,
transmittals, lists, or spreadsheets.
Rationale for R3: The Generator Owner is in the position to identify the load-responsive
protective relays that have tripped due to power swings, if any. The criterion is consistent with
the PSRPS Report. A requirement or time to complete a review of the relay tripping is not
addressed here as other NERC Reliability Standards address the review of Protection System
operations.
R4. Each Generator Owner and Transmission Owner shall, within 12 full calendar months of
receiving notification of an Element pursuant to Requirement R1 or within 12 full calendar
months of identifying an Element pursuant to Requirement R2 or R3, evaluate each
identified Element’s load-responsive protective relay(s) based on the PRC-026-1 –
Attachment B Criteria where the evaluation has not been performed in the last three
calendar years. [Violation Risk Factor: High] [Time Horizon: Operations Planning]
M4. Each Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the evaluation was performed according to Requirement R4. Evidence may
include, but is not limited to, the following documentation: apparent impedance
characteristic plots, email, design drawings, facsimiles, R-X plots, software output,
records, reports, transmittals, lists, settings sheets, or spreadsheets.
Rationale for R4: Performing the evaluation in Requirement R4 is the first step in ensuring
that the reliability goal of this standard will be met. The PRC-026-1 – Attachment B, Criteria
provides a basis for determining if the relays are expected to not trip for a stable power swing.
See the Guidelines and Technical Basis for a detailed explanation of the evaluation.
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PRC-026-1 — Relay Performance During Stable Power Swings
R5. Each Generator Owner and Transmission Owner shall, within 60 calendar days of an
evaluation that identifies load-responsive protective relays that do not meet the PRC-026-1
– Attachment B Criteria pursuant to Requirement R4, develop a Corrective Action Plan
(CAP) to modify the Protection System to meet the PRC-026-1 – Attachment B Criteria
while maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the Element). [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]
M5. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the development of a CAP in accordance with Requirement R5. Evidence
may include, but is not limited to, the following documentation: corrective action plans,
maintenance records, settings sheets, project or work management program records, or
work orders.
Rationale for R5: To meet the reliability purpose of the standard, a CAP is necessary to
modify the entity’s Protection System to meet PRC-026-1 – Attachment B so that protective
relays are expected to not trip in response to stable power swings. The phrase, “while
maintaining dependable fault detection and dependable out-of-step tripping” in Requirement
R5 describes that the entity is to comply with this standard while achieving their desired
protection goals. Refer to the Guidelines and Technical Basis, Introduction, for more
information.
R6. Each Generator Owner and Transmission Owner shall implement each CAP developed
pursuant to Requirement R5, and update each CAP if actions or timetables change until all
actions are complete. [Violation Risk Factor: Medium][Time Horizon: Long-Term
Planning]
M6. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates implementation of each CAP according to Requirement R6, including
updates to actions or timetables. Evidence may include, but is not limited to, the following
documentation: corrective action plans, maintenance records, settings sheets, project or
work management program records, or work orders.
Rationale for R6: Implementation of the CAP must accomplish all identified actions to be
complete to achieve the desired reliability goal. During the course of implementing a CAP,
updates may be necessary for a variety of reasons such as new information, scheduling
conflicts, or resource issues. Documenting changes and completion of activities provides
measurable progress and confirmation of completion.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods 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 CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The Generator Owner, Planning Coordinator, and Transmission Owner shall keep
data or evidence to show compliance as identified below unless directed by its
CEA to retain specific evidence for a longer period of time as part of an
investigation.
•
The Planning Coordinator shall retain evidence of Requirement R1 for a
minimum of three calendar years following the completion of each
Requirement.
•
The Transmission Owner shall retain evidence of Requirement R2 for a
minimum of three calendar years following the completion of each
Requirement.
•
The Generator Owner shall retain evidence of Requirement R3 for a
minimum of three calendar years following the completion of each
Requirement.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirement R4 for a minimum of 36 calendar months following
completion of each evaluation.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R5 and R6, including any supporting analysis per
Requirements R1, R2, R3, and R4, for a minimum of 12 calendar months
following completion of each CAP.
If a Generator Owner, Planning Coordinator, or Transmission Owner is found
non-compliant, it shall keep information related to the non-compliance until
mitigation is complete and approved, or for the time specified above, whichever is
longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None.
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PRC-026-1 — Relay Performance During Stable Power Swings
Table of Compliance Elements
R#
R1
Time
Horizon
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Planning
Coordinator identified
an Element and
provided notification
in accordance with
Requirement R1, but
was less than or equal
to 30 calendar days
late.
Moderate VSL
High VSL
Severe VSL
The Planning
Coordinator identified
an Element and
provided notification
in accordance with
Requirement R1, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Planning
Coordinator identified
an Element and
provided notification
in accordance with
Requirement R1, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Planning
Coordinator identified
an Element and
provided notification
in accordance with
Requirement R1, but
was more than 90
calendar days late.
OR
The Planning
Coordinator failed to
identify an Element in
accordance with
Requirement R1.
OR
The Planning
Coordinator failed to
provide notification in
accordance with
Requirement R1.
R2
Long-term
Planning
Medium The Transmission
Owner identified an
Element and provided
notification in
accordance with
The Transmission
Owner identified an
Element and provided
notification in
accordance with
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
The Transmission
Owner identified an
Element and provided
notification in
accordance with
The Transmission
Owner identified an
Element and provided
notification in
accordance with
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
Time
Horizon
Violation Severity Levels
VRF
Lower VSL
Moderate VSL
High VSL
Requirement R2, but
was less than or equal
to 10 calendar days
late.
Requirement R2, but
was more than 10
calendar days and less
than or equal to 20
calendar days late.
Requirement R2, but
was more than 20
calendar days and less
than or equal to 30
calendar days late.
Severe VSL
Requirement R2, but
was more than 30
calendar days late.
OR
The Transmission
Owner failed to
identify an Element in
accordance with
Requirement R2.
OR
The Transmission
Owner failed to
provide notification in
accordance with
Requirement R2.
R3
Long-term
Planning
Medium The Generator Owner
identified an Element
and provided
notification in
accordance with
Requirement R3, but
was less than or equal
to 10 calendar days
late.
The Generator Owner
identified an Element
and provided
notification in
accordance with
Requirement R3, but
was more than 10
calendar days and less
than or equal to 20
calendar days late.
The Generator Owner
identified an Element
and provided
notification in
accordance with
Requirement R3, but
was more than 20
calendar days and less
than or equal to 30
calendar days late.
The Generator Owner
identified an Element
and provided
notification in
accordance with
Requirement R3, but
was more than 30
calendar days late.
OR
The Generator Owner
failed to identify an
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
Time
Horizon
Violation Severity Levels
VRF
Lower VSL
Moderate VSL
High VSL
Severe VSL
Element in
accordance with
Requirement R3.
OR
The Generator Owner
failed to provide
notification in
accordance with
Requirement R3.
R4
Operations
Planning
High
The Generator Owner
or Transmission
Owner evaluated each
identified Element’s
load-responsive
protective relay(s) in
accordance with
Requirement R4, but
was less than or equal
to 30 calendar days
late.
The Generator Owner
or Transmission
Owner evaluated each
identified Element’s
load-responsive
protective relay(s) in
accordance with
Requirement R4, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Generator Owner
or Transmission
Owner evaluated each
identified Element’s
load-responsive
protective relay(s) in
accordance with
Requirement R4, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Generator Owner
or Transmission
Owner evaluated each
identified Element’s
load-responsive
protective relay(s) in
accordance with
Requirement R4, but
was more than 90
calendar days late.
OR
The Generator Owner
or Transmission
Owner failed to
evaluate each
identified Element’s
load-responsive
protective relay(s) in
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
Time
Horizon
Violation Severity Levels
VRF
Lower VSL
Moderate VSL
High VSL
Severe VSL
accordance with
Requirement R4.
R5
Long-term
Planning
Medium The Generator Owner
or Transmission
Owner developed a
CAP in accordance
with Requirement R5,
but in more than 60
calendar days and less
than or equal to 70
calendar days.
The Generator Owner
or Transmission
Owner developed a
CAP in accordance
with Requirement R5,
but in more than 70
calendar days and less
than or equal to 80
calendar days.
The Generator Owner
or Transmission
Owner developed a
CAP in accordance
with Requirement R5,
but in more than 80
calendar days and less
than or equal to 90
calendar days.
The Generator Owner
or Transmission
Owner developed a
CAP in accordance
with Requirement R5,
but in more than 90
calendar days.
OR
The Generator Owner
or Transmission
Owner failed to
develop a CAP in
accordance with
Requirement R5.
R6
Long-term
Planning
Medium The Generator Owner
or Transmission
Owner implemented,
but failed to update a
CAP, when actions or
timetables changed, in
accordance with
Requirement R6.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
N/A
N/A
The Generator Owner
or Transmission
Owner failed to
implement a CAP in
accordance with
Requirement R6.
Page 14 of 73
PRC-026-1 — Relay Performance During Stable Power Swings
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
Burdy, John, Loss-of-excitation Protection for Synchronous Generators GER-3183, General
Electric Company.
IEEE Power System Relaying Committee WG D6, Power Swing and Out-of-Step
Considerations on Transmission Lines, July 2005: http://www.pespsrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20Tr
ansmission%20Lines%20F..pdf.
Kimbark Edward Wilson, Power System Stability, Volume II: Power Circuit Breakers and
Protective Relays, Published by John Wiley and Sons, 1950.
Kundar, Prabha, Power System Stability and Control, 1994, Palo Alto: EPRI, McGraw Hill,
Inc.
NERC System Protection and Control Subcommittee, Protection System Response to Power
Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf.
Reimert, Donald, Protective Relaying for Power Generation Systems, 2006, Boca Raton:
CRC Press.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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Application Guidelines
PRC-026-1 – Attachment A
This standard includes any protective functions which could trip instantaneously or with a time
delay of less than 15 cycles, on load current (i.e., “load-responsive”) including, but not limited
to:
•
•
•
•
Phase distance
Phase overcurrent
Out-of-step tripping
Loss-of-field
The following protection functions are excluded from requirements of this standard:
•
•
•
•
•
•
•
•
•
•
•
Relay elements supervised by power swing blocking
Relay elements that are only enabled when other relays or associated systems fail. For
example:
o Overcurrent elements that are only enabled during loss of potential conditions.
o Elements that are only enabled during a loss of communications
Thermal emulation relays which are used in conjunction with dynamic Facility Ratings
Relay elements associated with dc lines
Relay elements associated with dc converter transformers
Phase fault detector relay elements employed to supervise other load-responsive phase
distance elements (e.g., in order to prevent false operation in the event of a loss of
potential) provided the distance element is set in accordance with the criteria outlined in
the standard
Relay elements associated with switch-onto-fault schemes
Reverse power relay on the generator
Generator relay elements that are armed only when the generator is disconnected from
the system, (e.g., non-directional overcurrent elements used in conjunction with
inadvertent energization schemes, and open breaker flashover schemes)
Current differential relay, pilot wire relay, and phase comparison relay
Voltage-restrained or voltage-controlled overcurrent relays
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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Application Guidelines
PRC-026-1 – Attachment B
Criteria A:
An impedance-based relay characteristic, used for tripping, that is completely contained
within the portion of the lens characteristic formed in the impedance (R-X) plane that
connects the endpoints of the total system impedance (with the parallel transfer impedance
removed) bounded by varying the sending- and receiving-end voltages from 0.7 to 1.0 per
unit, while maintaining a constant system separation angle across the total system impedance
where:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
Rationale for Attachment B (Criteria A): The PRC-026-1, Attachment B, Criteria A
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending-end and receiving-end
voltages varying from 0.7 to 1.0 per unit (See Guidelines and Technical Basis).
Criteria B:
The pickup of an overcurrent relay element used for tripping, that is above the calculated
current value (with the parallel transfer impedance removed) for the conditions below:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
4. Both the sending and receiving voltages at 1.05 per unit.
Rationale for Attachment B (Criteria B): The PRC-026-1, Attachment B, Criteria B
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending and receiving voltages
at 1.05 per unit (See Guidelines and Technical Basis).
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Application Guidelines
Guidelines and Technical Basis
Introduction
The NERC System Protection and Control Subcommittee technical document, Protection System
Response to Power Swings, August 20132 (“PSRPS Report” or “report”) was specifically
prepared to support the development of this NERC Reliability Standard. The report provided a
historical perspective on power swings as early as 1965 up through the approval of the report by
the NERC Planning Committee. The report also addresses reliability issues regarding trade-offs
between security and dependability of protection systems, considerations for this NERC
Reliability Standard, and a collection of technical information about power swing characteristics
and varying issues with practical applications and approaches to power swings. Of these topics,
the report suggests an approach for this NERC Reliability Standard (“standard” or “PRC-026-1”)
which is consistent with addressing two of the three regulatory directives in the FERC Order No.
733. The first directive concerns the need for “…protective relay systems that differentiate
between faults and stable power swings and, when necessary, phases out protective relay systems
that cannot meet this requirement.”3 Second, is “…to develop a Reliability Standard addressing
undesirable relay operation due to stable power swings.”4 The third directive “…to consider
“islanding” strategies that achieve the fundamental performance for all islands in developing the
new Reliability Standard addressing stable power swings”5 was considered during development
of the standard.
The development of this standard implements the majority of the approach suggested by the
report. However, it is noted that the Reliability Coordinator and Transmission Planner have not
been included in the standard’s Applicability (as suggested by the PSRPS Report). This is so that
a single entity, the Planning Coordinator, may be the single source for identifying Elements
according to Requirement R1. A single source will insure that multiple entities will not identify
Elements in duplicate, nor will one entity fail to provide an Element because it believes the
Element is being provided by another entity. The Planning Coordinator has, or has access to, the
wide-area model and can correctly identify the Elements that may be susceptible to a stable
power swing.
The phrase, “while maintaining dependable fault detection and dependable out-of-step tripping”
in Requirement R1, describes that the Generator Owner and Transmission Owner is to comply
with this standard while achieving its desired protection goals. Load-responsive protective
relays, as addressed within this standard, may be intended to provide a variety of backup
protection functions, both within the generating unit or generating plant and on the Transmission
2
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
3
Transmission Relay Loadability Reliability Standard, Order No. 733, P.150 FERC ¶ 61,221 (2010).
4
Ibid. P.153.
5
Ibid. P.162.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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Application Guidelines
system, and this standard is not intended to result in the loss of these protection functions.
Instead, it is suggested that the Generator Owner and Transmission Owner consider both the
requirements within this standard and its desired protection goals, and perform modifications to
its protective relays or protection philosophies as necessary to achieve both.
Power Swings
The IEEE Power System Relaying Committee WG D6 developed a technical document called
Power Swing and Out-of-Step Considerations on Transmission Lines (July 2005) that provides
background on power swings. The following are general definitions from that document:6
Power Swing: a variation in three phase power flow which occurs when the generator
rotor angles are advancing or retarding relative to each other in response to changes in
load magnitude and direction, line switching, loss of generation, faults, and other system
disturbances.
Pole Slip: a condition whereby a generator, or group of generators, terminal voltage
angles (or phases) go past 180 degrees with respect to the rest of the connected power
system.
Stable Power Swing: a power swing is considered stable if the generators do not slip
poles and the system reaches a new state of equilibrium, i.e. an acceptable operating
condition.
Unstable Power Swing: a power swing that will result in a generator or group of
generators experiencing pole slipping for which some corrective action must be taken.
Out-of-Step Condition: Same as an unstable power swing.
Electrical System Center or Voltage Zero: it is the point or points in the system where the
voltage becomes zero during an unstable power swing.
Burden to Entities
The PSRPS Report provides a technical basis and approach for focusing on Protection Systems,
which are susceptible to power swings while achieving the reliability objective. The approach
reduces the number of relays that the PRC-026-1 Requirements would apply to by first
identifying the Bulk Electric System (BES) Element(s) that need to be evaluated. The first step
uses criteria to identify a BES Element on which a Protection System is expected to be
challenged by power swings. Of those BES Elements, the second step is to evaluate each loadresponsive protective relay that is applied on each identified Element. Rather than requiring the
Transmission Planner to perform simulations to obtain information for each identified Element,
the Generator Owner and Transmission Owner will reduce the need for simulation by comparing
6
http://www.pes-psrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission
%20Lines%20F..pdf.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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Application Guidelines
the load-responsive protective relay characteristic to specific criteria found in PRC-026-1 –
Attachment B.
Applicability
The standard is applicable to the Generator Owner, Planning Coordinator, and Transmission
Owner entities. More specifically, the Generator Owner and Transmission Owner entities are
applicable when applying load-responsive protective relays at the terminals of the applicable
BES Elements. All the entities have a responsibility to identify the Elements which meet specific
criteria. The standard is applicable to the following BES Elements: generators, transmission
lines, and transformers. The Distribution Provider was considered for inclusion in the standard;
however, it is not subject to the standard because this entity, by functional registration, would not
own generators, transmission lines, or transformers other than load serving.
Load-responsive protective relays include any protective functions which could trip with or
without time delay, on load current.
Requirement R1
The Planning Coordinator has a wide-area view and is in the positon to identify what, if any,
Elements meet the criteria. The criterion-based approach is consistent with the NERC System
Protection and Control Subcommittee (SPCS) technical document Protection System Response to
Power Swings (August 2013),7 which recommends a focused approach to determine an at-risk
Element. Identification of Elements comes from the annual Planning Assessments pursuant to
the transmission planning (i.e., “TPL”) and other NERC Reliability Standards, and the standard
is not requiring any other assessments to be performed by the Planning Coordinator. The
required annual notification to the respective Generator Owner and Transmission Owner is
sufficient because it is expected that the Planning Coordinator will make its notifications
following the completion of its annual Planning Assessments.
Criterion 1
The first criterion involves generator(s) where an angular stability constraint exists which is
addressed by an operating limit or a Remedial Action Scheme (RAS) and those Elements
terminating at the transmission switching station associated with the generator(s). For example, a
scheme to remove generation for specific conditions is implemented for a four-unit generating
plant (1,100 MW). Two of the units are 500 MW each; one is connected to the 345 kV system
and one is connected to the 230 kV system. The Transmission Owner has two 230 kV
transmission lines and one 345 kV transmission line all terminating at the generating facility as
well as a 345/230 kV autotransformer. The remaining 100 MW consists of two 50 MW
7
http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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Application Guidelines
combustion turbine (CT) units connected to four 66 kV transmission lines. The 66 kV
transmission is not electrically joined to the 345 kV and 230 kV transmission lines at the plant
site and is not a part of the operating limit or RAS. A stability constraint limits the output of the
portion of the plant affected by the RAS to 700 MW for an outage of the 345 kV transmission
line. The RAS trips one of the 500 MW units to maintain stability for a loss of the 345 kV
transmission line when the total output from both 500 MW units is above 700 MW. For this
example, both 500 MW generating units and the associated generator step-up (GSU)
transformers would be identified as Elements meeting this criterion. The 345/230 kV
autotransformer, the 345 kV transmission line, and the two 230 kV transmission lines would also
be identified as Elements meeting this criterion. The 50 MW combustion turbines and 66 kV
transmission lines would not be identified pursuant Criterion 1 because these Elements are not
subject to an operating limit or RAS and do not terminate at the transmission switching station
associated with the generators that are subject to the operating limit and RAS.
Criterion 2
The second criterion involves Elements that are monitored due to an established System
Operating Limit (SOL) based on an angular stability limit regardless of the outage conditions
that result in the enforcement of the SOL. For example, if two long parallel 500 kV transmission
lines have a combined SOL of 1,200 MW, and this limit is based on angular instability resulting
from a fault and subsequent loss of one of the two lines, then both lines would be identified as an
Element meeting the criterion.
Criterion 3
The third criterion involves the Element that forms the boundary of an island due to angular
instability within an underfrequency load shedding (UFLS) assessment. While the island may
form due to various transmission lines tripping for a combination of reasons, such as stable and
unstable power swings, faults, and excessive loading, the criterion requires that all lines that
tripped in simulation due to “angular instability” to form the island be identified as meeting the
criterion.
Criterion 4
The fourth criterion involves Elements identified in the most recent Planning Assessment where
relay tripping occurs due to a stable or unstable power swing during a simulated disturbance. The
intent is for the Planning Coordinator to include any Element(s) where relay tripping was
observed during simulations performed for the most recent Planning Assessment associated with
the transmission planning TPL-001-4 Reliability Standard. Note that relay tripping must be
assessed within Planning Assessments per TPL-001-4, R4, Part 4.3.1.3, which indicates that
analysis shall include the “Tripping of Transmission lines and transformers where transient
swings cause Protection System operation based on generic or actual relay models.” Identifying
such Elements according to criterion 4 and notifying the respective Generator Owner and
Transmission Owner will require that the owners of any load-responsive protective relay applied
at the terminals of the identified Element evaluate the relay’s susceptibility to tripping in
response a stable power swing.
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Application Guidelines
Planning Coordinators have discretion to determine whether observed tripping for a power swing
in its Planning Assessments occurs for valid contingencies and system conditions. The Planning
Coordinator will address tripping that is observed in transient analyses on an individual basis;
therefore, the Planning Coordinator is responsible for identifying the Elements based only on
simulation results that are determined to be valid.
Due to the nature of how a Planning Assessment is performed, there may be cases where a
previously identified Element is not identified in the most recent Planning Assessment. If so, this
is acceptable because the Generator Owner and Transmission Owner would have taken action
upon the initial notification of the previously identified Element. When an Element is not
identified in later Planning Assessments, the risk would have already been assessed under
Requirement R4 and mitigated according to Requirements R5 and R6 when appropriate.
According to Requirement R4, the Generator Owner and Transmission Owner are only required
to re-evaluate each load-responsive protective relay for an identified Element where the
evaluation has not been performed in the last three calendar years.
Criterion 5
The fifth criterion involves Elements that have actually tripped due to a stable or unstable power
swing as reported by the Generator Owner and Transmission Owner. The Planning Coordinator
will continue to identify each reported Element until the Planning Coordinator determines that
the Element is expected to not trip in response to power swings due to BES configuration
changes. For example, eight lines interconnecting areas containing both generation and load to
the rest of the BES, and five of the lines terminate on a single straight bus as shown in Figure 1.
A forced outage of the straight bus in the past caused an island to form by tripping open the five
lines connecting to the straight bus, and subsequently causing the other three lines into the area
to trip on power swings. If the BES is reconfigured such that the five lines into the straight bus
are now divided between two different substations, the Planning Coordinator may determine that
the changes eliminated susceptibility to power swings as shown in Figure 2. If so, the Planning
Coordinator is no longer required to identify these Elements previously reported by either the
Transmission Owner pursuant to Requirement R2 or Generator Owner pursuant to Requirement
R3.
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Application Guidelines
Single Tie-line
Single Tie-line
Area
with generation
and load
Straight Bus
Single Tie-line
Single Tie-line
Single Tie-line
Area
with generation
and load
Straight Bus A
Single Tie-line
Straight Bus B
Figure 1. Criterion five example of an area Figure 2. Criterion five example of an area
with generation and load that experienced a with generation and load that was later
power swing.
reconfigured and determined to no longer be
susceptible to power swings.
Although Requirement R1 requires the Planning Coordinator to notify the respective Generator
Owner and Transmission Owner of any Elements meeting the one or more of the five criteria, it
does not preclude the Planning Coordinator from providing additional information, such as
apparent impedance characteristics, in advance or upon request, that may be useful in evaluating
protective relays. Generator Owners and Transmission Owners are able to complete protective
relay evaluations and perform the required actions without additional information. The standard
does not included any requirement for the entities to provide information that is already being
shared or exchanged between entities for operating needs. While a requirement has not been
included for the exchange of information, entities must recognize that relay performance needs to
be measured against the most current information.
Requirement R2
The approach of Requirement R2 requires the Transmission Owner to identify Elements that
meet the focused criteria. Only the Elements that meet the criteria and apply a load-responsive
protective relay at the terminal of the Element are in scope. Using the criteria focuses the
reliability concern on the Element that is at-risk to power swings.
The first criterion involves Elements that have tripped due to a power swing during an actual
system Disturbance, regardless of whether the power swing was stable or unstable. Elements that
have tripped by unstable power swings are included in this requirement because they were not
identified in Requirement R1 and this forms a basis for evaluating the load responsive relay
operation for stable power swings. After this standard becomes effective, if it is determined in an
outage investigation that an Element tripped because of a power swing condition (either stable or
unstable), this standard will become applicable to the Element. An example of an identified
Element is an Element tripped by a distance relay element (i.e., a relay with a time delay of less
than 15 cycles) during a power swing condition. Another example that would identify an
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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Application Guidelines
Element is where out-of-step (OOS) tripping is applied on the Element, and if a legitimate OOS
trip occurred as expected during a power swing event.
The second criterion involves the formation of an island based on an actual system Disturbance.
While the island may form due to several transmission lines tripping for a combination of
reasons, such as power swings (stable or unstable), faults, or excessive loading, the criterion
requires that all Elements that tripped to form the island be identified as meeting this criterion.
For example, the Disturbance may have been initiated by one line faulting with a second line
being out of service. The outage of those two lines then initiated a swing condition between the
“island” and the rest of the system across the remaining ties causing the remaining ties to open.
A second case might be that the island could have formed by a fault on one of the other ties with
a line out of service with the swing going across the first and second lines mentioned above
resulting in those lines opening due to the swing. Therefore, the inclusion of all the Elements that
formed the boundary of the island are included as Elements to be reported to the Planning
Coordinator.
The owner of the load-responsive protective relay that tripped for either criterion is required to
identify the Element and notify its Planning Coordinator. Notifying the Planning Coordinator of
the Element ensures that the planner is aware of an Element that is susceptible to a power swing
or formed an island. The Planning Coordinator will continue to notify the respective entities of
the identified Element under Requirement R1, Criterion 5 unless the Planning Coordinator
determines the Element is no longer susceptible to power swings.
Requirement R3
Requirement R3 is similar to Requirement R2, Criterion 1 and requires the Generator Owner to
identify any Element that trips due to a power swing condition (stable or unstable) in an actual
event. This standard does not focus on the review of Protection Systems because they are
covered by other NERC Reliability Standards. When a review of the Generator Owner’s
Protection System reveals that tripping occurred due to a power swing, it is required to identify
the Element and to notify its Planning Coordinator. Notifying the Planning Coordinator of the
Element ensures that the planner is aware of an Element that was susceptible to a power swing.
The Planning Coordinator will continue to notify entities of the identified Element under
Requirement R1 unless the Planning Coordinator determines the Element is no longer
susceptible to power swings.
Requirement R4
Requirement R4 requires the Generator Owner and Transmission Owner to evaluate its loadresponsive protective relays applied at all of the terminals of an identified Element to ensure that
load-responsive protective relays are expected to not trip in response to stable power swings
during non-Fault conditions. A method is provided within the standard to support consistent
evaluation by Generator Owners and Transmission Owners based on specified conditions. Once
a Generator Owner or Transmission Owner is notified of Elements pursuant to Requirement R1,
or once a Generator Owner or Transmission Owner identifies an Element pursuant to
Requirement R2 or R3, it has 12 full calendar months to evaluate each Element’s load-
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
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responsive protective relays based on the PRC-026-1 – Attachment B, Criteria A and B if the
evaluation hasn’t been performed in the last three calendar years.
Information Common to Both Generation and Transmission Elements
The PRC-026-1 – Attachment A lists the load-responsive protective relays that are subject to this
standard. Generator Owners and Transmission Owners may own load–responsive protective
relays (i.e. distance relays) that directly affect generation or transmission BES Elements and will
require analysis as a result of Elements being identified by Requirements R1, R2 or R3. For
example, distance relays owned by the Transmission Owner may be installed at the high-voltage
side of the generator step-up (GSU) transformer (directional toward the generator) providing
backup to generation protection. Generator Owners may have distance relays applied for back-up
transmission protection or back-up protection for the GSU transformer. The Generator Owner
may have relays installed at the generator terminals or the high-voltage side of the GSU
transformer.
Exclusion of Time Based Load-Responsive Protective Relays
The purpose of the standard is “To ensure that load-responsive protective relays are expected to
not trip in response to stable power swings during non-Fault conditions.” Load-responsive
protective relays with high-speed tripping pose the highest risk of operating during a power
swing. Because of this, high-speed tripping is included in the standard and others (Zone 2 and 3)
with a time a delay of 15 cycles or greater are excluded. The time delay used for exclusion on
some load-responsive protective relays is recommended based on 1) the minimum time delay
these relays are set in practice, and 2) the maximum expected time that load-responsive
protective relays would be exposed to the stable swing based on a swing rate.
In order to establish a time delay that strikes a line between a high-risk load-responsive
protective relay and one that has a time delay for tripping, a sample of swing rates were
calculated based on a stable power swing entering and leaving the impedance characteristic as
shown in Table 1. For a relay impedance characteristic that has the swing entering and leaving
beginning at 90 degrees with a termination at 120 before exiting the zone, calculation of the
timer must be greater than the time the stable swing is inside the relay operate zone.
Eq. (1)
> 2 ×
(120° −
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ℎ
ℎ
)
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Table 1. Swing Rates
Zone Timer
Slip Rate
(Cycles)
(Hz)
10
1.00
15
0.67
20
0.50
30
0.33
With a minimum zone timer of 15 cycles, the corresponding slip of the system is 0.67 Hz. This
represents an approximation of a slow slip rate during a system Disturbance. This value
corresponds to the typical minimum time delay used for zone 2 distance relays in transmission
line protection. Longer time delays allow for slower slip rates.
Application to Transmission Elements
The criteria in PRC-026-1 – Attachment B describe a lens characteristic formed in the impedance
(R-X) plane that connects the endpoints of the total system impedance together by varying the
sending and receiving-end system voltages from 0.7 to 1.0 per unit, while maintaining a constant
system separation angle across the total system impedance (with the parallel transfer impedance
removed—see Figures 3 through 5). The total system impedance is derived from a two-bus
equivalent network and is determined by summing the sending-end source impedance, the line
impedance (excluding the Thévenin equivalent transfer impedance), and the receiving-end
source impedance as shown in Figures 6 and 7. The goal in establishing the total system
impedance is to represent a conservative condition that will maximize the security of the relay
against various system conditions. The smallest total system impedance represents a condition
where the size of the lens characteristic in the R-X plane is smallest and is a conservative
operating point from the standpoint of ensuring a load responsive relay will not trip given a
predetermined angular displacement between the sending- and receiving-end voltages. The
smallest total system impedance results when all generation is in service and all transmission
elements are modeled in their “normal” system configuration (PRC-026-1 – Attachment B,
Criteria A). The parallel transfer impedance is removed to represent a likely condition where
parallel elements may be lost during the disturbance, and the loss of these elements magnifies the
sensitivity of the load-responsive relays on the parallel line by removing the “infeed effect” (i.e.,
the apparent impedance sensed by the relay is decreased as a result of the loss of the transfer
impedance, thus making the relay more likely to trip for a stable power swing).
The sending- and receiving-end source voltages are varied from 0.7 to 1.0 per unit to form a
portion of a lens characteristic instead of varying the voltages from 0 to 1.0 per unit, which
would form a full-lens characteristic. The ratio of these two voltages is used in the calculation of
the portion of the lens, and result in a ratio range from 0.7 to 1.43.
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Eq. (2)
=
0.7
= 0.7
1.0
=
0.85
= 0.739
1.15
Eq. (3):
=
1.0
= 1.43
0.7
=
1.15
= 1.353
0.85
The internal generator voltage during severe power swings or transmission system fault
conditions will be greater than zero, due to voltage regulator support. The voltage ratio of 0.7 to
1.43 is chosen to be more conservative than the PRC-023 and PRC-025 NERC Reliability
Standards, where a lower bound voltage of 0.85 per unit voltage is used. A plus and minus 15%
internal generator voltage range was chosen as a conservative voltage range for calculation of the
voltage ratio that would determine the end points of the portion of the lens. For example, the
voltage ratio using these voltages would result in a ratio range from 0.739 to 1.353.
Eq. (4)
Eq. (5):
The lower ratio is rounded down to 0.7 to be more conservative, allowing a voltage range of 0.7
to 1.0 per unit to be used for the calculation of the lens end points.8
When the parallel transfer impedance is included in the model, the split in current through the
parallel transfer impedance path results in actual measured relay impedances that are larger than
those measured when the parallel transfer impedance is removed (i.e., infeed effect), which
would make it more likely for an impedance relay element to be completely contained within the
applicable portion of the lens characteristic in Figure 11. If the transfer impedance is included in
the lens evaluation, a distance relay element could be deemed as meeting PRC-026-1 –
Attachment B and, in fact would be secure, assuming all elements were in their normal state. In
this case, it could trip for a stable power swing during an actual event if the system was
weakened (i.e., a higher transfer impedance) by the loss of a subset of lines that make up the
parallel transfer impedance. This could happen because those parallel lines tripped on unstable
swings, contained the initiating fault, and/or were lost due to operation of breaker failure or
remote back-up protection schemes in Figure 10.
Either the saturated transient or sub-transient direct axis reactance values may be used for
machines in the evaluation because they are smaller than un-saturated reactance values. Since,
sub-transient saturated generator reactances are smaller than the transient or synchronous
reactance, they result in a smaller source impedance and a smaller lens characteristic in the
graphical analysis as shown in Figures 8 and 9. Since power swings occur in a time frame where
generator transient reactances will be prevalent, it is acceptable to use saturated transient
reactances instead of saturated sub-transient reactance values. Some short-circuit models may not
include transient reactance values, so in this case, the use of sub-transient is acceptable because it
also produces more conservative results than transient reactances. For this reason, either value is
8
Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations,
April 2004, Section 6 (The Cascade Stage of the Blackout), p. 94 under “Why the Generators Tripped Off,” states,
“Some generator undervoltage relays were set to trip at or above 90% voltage. However, a motor stalls out at about
70% voltage and a motor starter contactor drops out around 75%, so if there is a compelling need to protect the
turbine from the system the under-voltage trigger point should be no higher than 80%.”
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acceptable when determining the system source impedances (PRC-026-1 – Attachment B,
Criteria A and B, No. 3).
Saturated reactance values are also the values used in short-circuit programs that produce the
system impedance mentioned above. Planning and stability software generally use the unsaturated reactance values. Generator models used in transient stability analyses recognize that
the extent of the saturation effect depends upon both rotor (field) and stator currents.
Accordingly, they derive the effective saturated parameters of the machine at each instant by
internal calculation from the specified (constant) unsaturated values of machine reactances and
the instantaneous internal flux level. The specific assumptions regarding which inductances are
affected by saturation, and the relative effect of that saturation, are different for the various
generator models used. Thus, unsaturated values of all machine reactances are used in setting up
planning and stability software data, and the appropriate set of open-circuit magnetization curve
data is provided for each machine.
The source or system equivalent impedances can be obtained by a number of different methods
using commercially available short-circuit calculation tools.9 Most short-circuit tools have a
network reduction feature that allows the user to select the local and remote terminal buses to
retain. The first method reduces the system to one that contains two buses, an equivalent
generator at each bus (representing the source impedance at the sending- and receiving-ends),
and two parallel lines; one being the line impedance of the protected line with relays being
analyzed, the other being the transfer impedance representing all other combinations of lines that
connect the two buses together in Figure 6. Another conservative method is to open both ends of
the line in question, and apply a three-phase bolted fault at each bus. The resulting source
impedance at each end will be less than or equal to the actual source impedance calculated by the
network reduction method. Either method can be used to develop the system source impedances
at both ends.
The two bullets of PRC-026-1 – Attachment B, Criteria A, No. 1, identify the system separation
angles to identify the size of the power swing stability boundary to be used to test loadresponsive impedance relay elements. Both bullets test impedance relay elements that are not
supervised by power swing blocking. The first bullet of PRC-026-1 – Attachment B, Criteria A,
No. 1 evaluates a system separation angle of at least 120 degrees that is held constant while
varying the sending- and receiving-end source voltages from 0.7 to 1.0 per unit, thus creating a
power swing stability boundary shaped like a portion of a lens about the total system impedance
in Figure 3. This portion of a lens characteristic is compared to the tripping portion of the
distance relay characteristic, that is, the portion that is not supervised by load encroachment,
blinders, or some other form of supervision as shown in Figure 12 that restricts the distance
element from tripping for heavy, balanced load conditions. If the tripping portion of the
impedance characteristics are completely contained within the portion of a lens characteristic, the
Element meets Criteria A in PRC-026-1 – Attachment B. A system separation angle of 120
9
Demetrios A. Tziouvaras and Daqing Hou, Appendix in Out-Of-Step Protection Fundamentals and Advancements,
April 17, 2014: https://www.selinc.com.
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degrees was chosen for the evaluation where PSB is not applied because it is generally accepted
in the industry that recovery for a swing beyond this angle is unlikely to occur.10
The second bullet of PRC-026-1 – Attachment B, Criteria A, No. 1 evaluates impedance relay
elements at a system separation angle of less than 120 degrees, similar to the first bullet
described above. An angle less than 120 degrees may be used if a documented stability analysis
demonstrates that the power swing becomes unstable at a system separation angle of less than
120 degrees.
10
“The critical angle for maintaining stability will vary depending on the contingency and the system condition at
the time the contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is
marginal and 120 degrees is generally accepted as an appropriate basis for setting out‐of‐step protection. Given the
importance of separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a
proper balance between dependable tripping for unstable power swings and secure operation for stable power
swings.” NERC System Protection and Control Subcommittee, Protection System Response to Power Swings,
August 2013: http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20
SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf), p. 28.
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Figure 3. The portion of the lens characteristic that is formed in the impedance (R-X) plane.
The pilot zone 2 relay is completely contained within the portion of the lens (e.g., it does not
intersect any portion of the partial lens), therefore it complies with PRC-026-1 – Attachment
B, Criteria A, No. 1.
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Figure 4. System impedance as seen by relay R.
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Figure 5. Lens characteristic with the transfer impedance included and contains specific points
identified for the calculations.
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Table 2. Example Calculation (Lens Point 1)
This example is for calculating the impedance the first point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending voltage (ES) leading the
receiving voltage (ER) by 120 degrees. See Figures 4 and 5.
Eq. (6)
∠120°
=
√3
230,000∠120°
=
Eq. (7)
√3
= 132,791∠120°
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
= 2 + 10 Ω
Given:
Given:
=
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
Eq. (8)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
Total system impedance.
Eq. (9)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
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Table 2. Example Calculation (Lens Point 1)
Total system current from sending source.
Eq. (10)
=
=
−
132,791∠120° − 132,791∠0°
(10 + 50 )Ω
= 4,511∠71.3°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (11)
=
×
+
= 4,511∠71.3°
= 4,511∠71.3°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (12)
=
−
×
= 132,791∠120°
= 95,757∠106.1°
− [(2 + 10) Ω × 4,511∠71.3° ]
The impedance seen by the relay on ZL.
Eq. (13)
=
=
95,757∠106.1°
4,511∠71.3°
= 17.434 + 12.113 Ω
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Table 3. Example Calculation (Lens Point 2)
This example is for calculating the impedance second point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending voltage (ES) at 70% of the
receiving voltage (ER) and leading the receiving voltage by 120 degrees. See Figures 4 and 5.
Eq. (14)
∠120°
=
√3
230,000∠120°
=
Eq. (15)
× 70%
√3
= 92,953.7∠120°
=
=
× 0.70
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
= 2 + 10 Ω
Given:
Given:
=
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
Eq. (16)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
Total system impedance.
Eq. (17)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
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Table 3. Example Calculation (Lens Point 2)
Total system current from sending source.
Eq. (18)
=
=
−
92,953.7∠120° − 132,791∠0°
(10 + 50) Ω
= 3,854∠77°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (19)
=
×
+
= 3,854∠77°
= 3,854∠77°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (20)
=
−
×
= 92,953∠120°
= 65,271∠99°
− [(2 + 10 )Ω × 3,854∠77° ]
The impedance seen by the relay on ZL.
Eq. (21)
=
=
65,271∠99°
3,854∠77°
= 15.676 + 6.41 Ω
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Table 4. Example Calculation (Lens Point 3)
This example is for calculating the impedance third point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving voltage (ER) at 70% of
the sending voltage (ES) and the sending voltage leading the receiving voltage by 120 degrees.
See Figures 4 and 5.
Eq. (22)
∠120°
=
√3
230,000∠120°
=
Eq. (23)
√3
= 132,791∠120°
=
=
∠0°
√3
× 70%
230,000∠0°
× 0.70
√3
= 92,953.7∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
= 2 + 10 Ω
Given:
Given:
=
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
Eq. (24)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
Total system impedance.
Eq. (25)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
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Table 4. Example Calculation (Lens Point 3)
Total system current from sending source.
Eq. (26)
=
=
−
132,791∠120° − 92,953.7∠0°
(10 + 50) Ω
= 3,854∠65.5°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (27)
=
×
+
= 3,854∠65.5°
= 3,854∠65.5°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (28)
=
−(
× )
= 132,791∠120°
= 98,265∠110.6°
− [(2 + 10) Ω × 3,854∠65.5° ]
The impedance seen by the relay on ZL.
Eq. (29)
=
=
98,265∠110.6°
3,854∠65.5°
= 18.005 + 18.054 Ω
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Table 5. Example Calculation (Lens Point 4)
This example is for calculating the impedance fourth point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending voltage (ES) leading the
receiving voltage (ER) by 240 degrees. See Figures 4 and 5.
Eq. (30)
∠240°
=
√3
230,000∠240°
=
Eq. (31)
√3
= 132,791∠240°
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
= 2 + 10 Ω
Given:
Given:
=
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
Eq. (32)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
Total system impedance.
Eq. (33)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
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Table 5. Example Calculation (Lens Point 4)
Total system current from sending source.
Eq. (34)
=
=
−
132,791∠240° − 132,791∠0°
(10 + 50 )Ω
= 4,510∠131.3°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (35)
=
×
+
= 4,510∠131.1°
= 4,510∠131.1°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (36)
=
−(
× )
= 132,791∠240°
− [(2 + 10 ) Ω × 4,510∠131.1° ]
= 95,756∠ − 106.1°
The impedance seen by the relay on ZL.
Eq. (37)
=
=
95,756∠ − 106.1°
4,510∠131.1°
= −11.434 + 17.887 Ω
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Table 6. Example Calculation (Lens Point 5)
This example is for calculating the impedance fifth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending voltage (ES) at 70% of the
receiving voltage (ER) and leading the receiving voltage by 240 degrees. See Figures 4 and 5.
Eq. (38)
∠240°
=
√3
230,000∠240°
=
Eq. (39)
× 70%
√3
= 92,953.7∠240°
=
=
× 0.70
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
= 2 + 10 Ω
Given:
Given:
=
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
Eq. (40)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
Total system impedance.
Eq. (41)
=
+
+
= (2 + 10 Ω) + (4 + 20 Ω) + (4 + 20 Ω)
= 10 + 50 Ω
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Table 6. Example Calculation (Lens Point 5)
Total system current from sending source.
Eq. (42)
=
=
−
92,953.7∠240° − 132,791∠0°
10 + 50 Ω
= 3,854∠125.5°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (43)
=
×
+
= 3,854∠125.5°
= 3,854∠125.5°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (44)
=
−(
× )
= 92,953.7∠240°
− [(2 + 10 ) Ω × 3,854∠125.5° ]
= 65,270.5∠ − 99.4°
The impedance seen by the relay on ZL.
Eq. (45)
=
=
65,270.5∠ − 99.4°
3,854∠125.5°
= −12.005 + 11.946 Ω
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Table 7. Example Calculation (Lens Point 6)
This example is for calculating the impedance sixth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving voltage (ER) at 70% of
the sending voltage (ES) and the sending voltage leading the receiving voltage by 240 degrees.
See Figures 4 and 5.
Eq. (46)
∠240°
=
√3
230,000∠240°
=
Eq. (47)
√3
= 132,791∠240°
=
=
∠0°
√3
× 70%
230,000∠0°
× 0.70
√3
= 92,953.7∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
= 2 + 10 Ω
Given:
Given:
=
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
Eq. (48)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
Total system impedance.
Eq. (49)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
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Table 7. Example Calculation (Lens Point 6)
Total system current from sending source.
Eq. (50)
=
=
−
132,791∠240° − 92,953.7∠0°
10 + 50 Ω
= 3,854∠137.1°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (51)
=
×
+
= 3,854∠137.1°
= 3,854∠137.1°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (52)
=
−(
× )
= 132,791∠240°
− [(2 + 10 )Ω × 3,854∠137.1° ]
= 98,265∠ − 110.6°
The impedance seen by the relay on ZL.
Eq. (53)
=
=
98,265∠ − 110.6°
3,854∠137.1°
= −9.676 + 23.59 Ω
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Figure 6. Reduced two bus system with sending-end source impedance ZS, receiving-end source
impedance ZR, line impedance ZL, and transfer impedance ZTR.
Figure 7. Reduced two bus system with sending-end source impedance ZS, receiving-end source
impedance ZR, line impedance ZL, and transfer impedance ZTR removed.
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Figure 8. A strong-source system with a line impedance of ZL = 20.4 ohms (i.e., the thicker
red line). This relay element (i.e., the blue circle) does not meet the PRC-026-1 – Attachment
B, Criteria A because it is not completely contained within the power swing stability boundary
(i.e., the orange lens characteristic).
The figure above represents a heavily loaded system using a maximum generation profile. The
zone 2 mho circle (set at 137% of ZL) extends into the power swing stability boundary (i.e., the
orange partial lens characteristic). Using the strongest source system is more conservative
because it shrinks the power swing stability boundary, bringing it closer to the mho circle. This
figure also graphically represents the effect of a system strengthening over time and this is the
reason for re-evaluation if the relay has not been evaluated in the last three calendar years. Figure
9 below depicts a relay that meets the, PRC-026-1 – Attachment B, Criteria A. Figure 8 depicts
the same relay with the same setting three years later, where each source has strengthened by
about 10% and now the same zone 2 element does not meet Criteria A.
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Figure 9. A weak-source system with a line impedance of ZL = 20.4 ohms (i.e., the thicker red
line). This zone 2 element (i.e., the blue circle) meets the PRC-026-1 – Attachment B, Criteria A
because it is completely contained within the power swing stability boundary (i.e., the orange
lens characteristic).
The figure above represents a lightly loaded system, using a minimum generation profile. The
zone 2 mho circle (set at 137% of ZL) does not extend into the power swing stability boundary
(i.e., the orange lens characteristic). Using a weaker source system expands the power swing
stability boundary away from the mho circle.
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Figure 10. This is an example of a power swing stability boundary (i.e., the orange lens
characteristic) with the transfer impedance removed. This relay zone 2 element (i.e., the blue
circle) does not meet PRC-026-1 – Attachment B, Criteria A because it is not completely
contained within the power swing stability boundary.
Table 8. Example Calculation (Transfer Impedance Removed)
Calculations for the point at 120 degrees with equal source impedances. The total system
current equals the line current. See Figure 10.
Eq. (54)
=
=
∠120°
√3
230,000∠120°
√3
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Table 8. Example Calculation (Transfer Impedance Removed)
Eq. (55)
= 132,791∠120°
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given impedance data.
= 2 + 10 Ω
Given:
Given:
=
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
=
Eq. (56)
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
Total system impedance.
Eq. (57)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Total system current from sending source.
Eq. (58)
=
=
−
132,791∠120° − 132,791∠0°
10 + 50 Ω
= 4,511∠71.3°
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Table 8. Example Calculation (Transfer Impedance Removed)
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (59)
=
×
+
= 4,511∠71.3°
= 4,511∠71.3°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (60)
=
−
×
= 132,791∠120°
= 95,757∠106.1°
− [(2 + 10 Ω) × 4,511∠71.3° ]
The impedance seen by the relay on ZL.
Eq. (61)
=
=
95,757∠106.1°
4,511∠71.3°
= 17.434 + 12.113 Ω
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Figure 11. This is an example of a power swing stability boundary (i.e., the orange lens
characteristic) with the transfer impedance included. The zone 2 element (i.e., the blue circle)
meets the PRC-026-1 – Attachment B, Criteria A because it is completely contained within the
power swing stability boundary.
In the figure above, the transfer impedance is 5 times the line impedance. The lens characteristic
has expanded out beyond the zone 2 element due to the infeed effect from the parallel current
through the transfer impedance, thus allowing the zone 2 element to meet PRC-026-1 –
Attachment B, Criteria A.
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Table 9. Example Calculation (Transfer Impedance Included)
Calculations for the point at 120 degrees with equal source impedances. The total system
current does not equal the line current. See Figure 11.
Eq. (62)
∠120°
=
√3
230,000∠120°
=
Eq. (63)
√3
= 132,791∠120°
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given impedance data.
= 2 + 10 Ω
Given:
Given:
=
×5
= 4 + 20 Ω
= 4 + 20 Ω
= (4 + 20) Ω × 5
= 20 + 100 Ω
Total impedance between generators.
Eq. (64)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (20 + 100) Ω
(4 + 20) Ω + (20 + 100) Ω
= 3.333 + 16.667 Ω
Total system impedance.
Eq. (65)
=
+
+
= (2 + 10) Ω + (3.333 + 16.667) Ω + (4 + 20) Ω
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Table 9. Example Calculation (Transfer Impedance Included)
= 9.333 + 46.667 Ω
Total system current from sending source.
Eq. (66)
=
=
−
132,791∠120° − 132,791∠0°
9.333 + 46.667 Ω
= 4,832∠71.3°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (67)
=
×
+
= 4,832∠71.3°
= 4,027.4∠71.3°
×
(20 + 100) Ω
(9.333 + 46.667) Ω + (20 + 100) Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (68)
=
−
×
= 132,791∠120°
= 93,417∠104.7°
− [(2 + 10 Ω) × 4,027∠71.3° ]
The impedance seen by the relay on ZL.
Eq. (69)
=
=
93,417∠104.7°
4,027∠71.3°
= 19.366 + 12.767 Ω
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Table 10. Percent Increase of a Lens Due To Parallel Transfer Impedance.
The following demonstrates the percent size increase of the lens characteristic for ZTR in
multiples of ZL with the transfer impedance included.
ZTR in multiples of ZL
Percent increase of lens with equal EMF
sources (Infinite source as reference)
Infinite
N/A
1000
0.05%
100
0.46%
10
4.63%
5
9.27%
2
23.26%
1
46.76%
0.5
94.14%
0.25
189.56%
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Figure 12. The tripping portion not blocked by load encroachment (i.e., the parallel green lines)
of the pilot zone 2 element (i.e., the blue circle) is completely contained within the power swing
stability boundary (i.e., the orange lens characteristic). Therefore, the zone 2 element meets the
PRC-026-1 – Attachment B, Criteria A.
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Figure 13: The infeed diagram shows the impedance in front of the relay R with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes ZL + ZR.
Table 11. Calculations (System Apparent Impedance in the forward direction)
The following equations are provided for calculating the apparent impedance back to the ER
source voltage as seen by relay R. Infeed equations from VS to source ER where ER = 0. See
Figure 13.
Eq. (70)
Eq. (71)
Eq. (72)
Eq. (73)
=
=
=
Eq. (75)
=
Eq. (77)
−
=
Eq. (74)
Eq. (76)
−
=
+
−
×
− [( +
=( ×
=
=0
Since
)×
)+( ×
=
+
Rearranged:
=
×
]
+
)+(
×
×
=
)
+
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 22, 2014)
× 1+
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Table 11. Calculations (System Apparent Impedance in the forward direction)
=
Eq. (78)
Eq. (79)
×
=
+
×
+
=
Eq. (80)
The infeed equations shows the impedance in front of the relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the forward direction becomes ZL + ZR.
=
Eq. (81)
+
× 1+
Figure 14: The infeed diagram shows the impedance behind relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes ZS.
Table 12. Calculations (System Apparent Impedance in the reverse direction)
The following equations are provided for calculating the apparent impedance back to the ES
source voltage as seen by relay R. Infeed equations from VR back to source ES where ES = 0.
See Figure 14.
Eq. (82)
=
−
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Table 12. Calculations (System Apparent Impedance in the reverse direction)
Eq. (83)
Eq. (84)
Eq. (85)
=
=
Eq. (86)
=
Eq. (87)
=
Eq. (88)
Eq. (89)
Eq. (90)
Eq. (91)
Eq. (92)
−
=
+
−
×
− [( +
=( ×
=
=
)×
)+( ×
=
×
=
=0
Since
+
+
Rearranged:
=
×
]
)+(
×
×
=
)
+
× 1+
+
×
+
=
The infeed equations shows the impedance behind relay R with the parallel transfer impedance
included. As the parallel transfer impedance approaches infinity, the impedances seen by the
relay R in the reverse direction becomes ZS.
Eq. (93)
Eq. (94)
=
+
× 1+
=
× 1+
As seen by relay R at the receiving-end of
the line.
Subtract ZL for relay R impedance as seen
at sending-end of the line.
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Figure 15. Out-of-step trip (OST) inner blinder (i.e., the parallel green lines) meets the PRC026-1 – Attachment B, Criteria A because the inner OST blinder initiates tripping either On-TheWay-In or On-The-Way-Out. Since the inner blinder is completely contained within the portion
of the power swing stability boundary (i.e., the orange lens characteristic), the zone 2 element
(i.e., the blue circle) meets the PRC-026-1 – Attachment B, Criteria A.
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Table 13. Example Calculation (Voltage Ratios)
These calculations are based on the loss of synchronism characteristics for the cases of N < 1
and N > 1 as found in the Application of Out-of-Step Blocking and Tripping Relays, GER3180, p. 12, Figure 3.11 The GE illustration shows the formulae used to calculate the radius
and center of the circles that make up the ends of the portion of the lens.
Voltage ratio equations, source impedance equation with infeed formulae applied, and circle
equations.
Given:
Eq. (95)
Eq. (96)
= 0.7
=
=
= 1.0
| | 0.7
=
= 0.7
| | 1.0
| | 1.0
=
= 1.43
| | 0.7
The total system impedance as seen by the relay with infeed formulae applied.
Given:
Given:
Eq. (97)
= 2 + 10 Ω
=
× 10
=
× 1+
= (4 + 20)
Ω
= 4 + 20 Ω
Ω
= 10 + 50 Ω
+
+
= 4 + 20 Ω
× 1+
The calculated coordinates of the lower circle center.
Eq. (98)
=−
× 1+
−
= − (2 + 10) Ω × 1 +
= −11.608 − 58.039 Ω
11
×
1−
(4 + 20) Ω
(4 + 20) Ω
−
0.7 × (10 + 50) Ω
1 − 0.7
http://store.gedigitalenergy.com/faq/Documents/Alps/GER-3180.pdf
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Table 13. Example Calculation (Voltage Ratios)
The calculated radius of the lower circle.
Eq. (99)
=
=
×
1−
0.7 × (10 + 50) Ω
1 − 0.7
= 69.987 Ω
The calculated coordinates of the upper circle center.
Eq. (100)
=
+
× 1+
= − (4 + 20) Ω × 1 +
= 17.608 + 88.039 Ω
+
−1
(4 + 20) Ω
(4 + 20) Ω
+
(10 + 50) Ω
1.43 − 1
The calculated radius of the upper circle.
Eq. (101)
=
=
×
−1
1.43 × (10 + 50) Ω
1.43 − 1
= 69.987 Ω
Application Specific to Criteria B
The PRC-026-1 – Attachment B, Criteria B evaluates overcurrent elements used for tripping.
The same criteria as PRC-026-1 – Attachment B, Criteria A is used except for an additional
criteria (No. 4) that calculates a current magnitude based upon generator terminal voltages of
1.05 per unit. The formula used to calculate the current is as follows:
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Table 14. Example Calculation (Overcurrent)
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps secondary times a CT ratio of 160:1 that equals 8000 amps on the
primary. The following calculation is where VS equals the base line-to-ground sending-end
generator source voltage times 1.05 at an angle of 120 degrees, VR equals the base line-toground receiving-end generator terminal voltage times 1.05 at an angle of 0 degrees, and Zsys
equals the sum of the sending-end, line, and receiving-end source impedances in ohms.
Eq. (102)
∠120°
=
× 1.05
√3
230,000∠120°
=
√3
= 139,430∠120°
× 1.05
Receiving-end generator terminal voltage.
Eq. (103)
=
=
∠0°
√3
× 1.05
230,000∠0°
√3
= 139,430∠0°
× 1.05
The total impedance of the system (Zsys) equals the sum of the sending-end source impedance
(ZS), the impedance of the line (ZL), and receiving-end impedance (ZR) in ohms.
Given:
Eq. (104)
= 3 + 26 Ω
=
+
+
= 1.3 + 8.7 Ω
= 0.3 + 7.3 Ω
= (3 + 26) Ω + (1.3 + 8.7) Ω + (0.3 + 7.3) Ω
= 4.6 + 42 Ω
Total system current from sending source.
Eq. (105)
=
=
(
−
)
(139,430∠120° − 139,430∠0° )
(4.6 + 42) Ω
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Table 14. Example Calculation (Overcurrent)
= 5,715.82∠66.25°
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps-secondary times a CT ratio of 160:1 that equals 8,000 amps-primary.
Here, the phase instantaneous setting of 8,000 amps is greater than the calculated system
current of 5,716 amps, therefore it is compliant with PRC-026-1 – Attachment B, Criteria B.
Application to Generation Elements
As with Transmission Elements, the determination of the apparent impedance seen at an Element
located at, or near, a generation Facility is complex for power swings due to various
interdependent quantities. These variances in quantities are caused by changes in machine
internal voltage, speed governor action, voltage regulator action, the reaction of other local
generators, and the reaction of other interconnected transmission Elements as the event
progresses through the time domain. Though transient stability simulations may be used to
determine the apparent impedance for verifying load-responsive relay settings,12,13 Requirement
R4, PRC-026-1 – Attachment B, Criteria A and B provides a simplified method for evaluating
the load-responsive protective relay’s susceptibility to tripping in response to a stable power
swing without requiring stability simulations.
In general, the electrical center will be in the transmission system for cases where the generator
is connected through a weak transmission system (high external impedance). Other cases where
the generator is connected through a strong transmission system, the electrical center could be
inside the unit connected zone.14 In either case, load-responsive protective relays connected at
the generator terminals or at the high-voltage side of the generator step-up (GSU) transformer
may be challenged by power swings as determined by the Planning Coordinator in Requirement
R1 or a power swing event documented by an actual Disturbance in Requirement R2 and R3.
Load-responsive protective relays such as time over-current, voltage controlled time-overcurrent
or voltage-restrained time-overcurrent relays are excluded from this standard since they are set
based on equipment permissible overload capability. Their operating time is much greater than
15 cycles for the current levels observed during a power swing.
Instantaneous overcurrent and definite-time overcurrent relays with a time delay of less than 15
cycles are included and are required to be evaluated.
The generator loss-of-field protective function is provided by impedance relay(s) connected at
the generator terminals. The settings are applied to protect the generator from a partial or
12
Donald Reimert, Protective Relaying for Power Generation Systems, Boca Raton, FL, CRC Press, 2006.
13
Prabha Kundar, Power System Stability and Control, EPRI, McGraw Hill, Inc., 1994.
14
Ibid, Kundar.
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complete loss of excitation under all generator loading conditions and, at the same time, be
immune to tripping on stable power swings. It is more likely that the relay would operate during
a power swing when the automatic voltage regulator (AVR) is in manual mode rather than when
in automatic mode.15 Figure 16 illustrates in the R-X plot, the loss-of-field relays typically
include up to three zones of protection.
Figure 16. An R-X graph of typical impedance settings for loss-of-field relays.
Loss-of-field characteristic 40-1 has a wider impedance characteristic (positive offset) than
characteristic 40-2 or characteristic 40-3 and provides additional generator protection for a
partial loss of field or a loss of field under low load (less than 10% of rated). The tripping logic
of this protection scheme is established by a directional contact, a voltage setpoint, and a time
delay. The voltage and time delay add security to the relay operation for stable power swings.
Characteristic 40-3 is less sensitive to power swings than characteristic 40-2 and is set outside
the generator capability curve in the leading direction. Regardless of the relay impedance setting,
15
John Burdy, Loss-of-excitation Protection for Synchronous Generators GER-3183, General Electric Company.
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PRC-019 requires that the “in-service limiters operate before Protection Systems to avoid
unnecessary trip” and “in-service Protection System devices are set to isolate or de-energize
equipment in order to limit the extent of damage when operating conditions exceed equipment
capabilities or stability limits.” Time delays for tripping associated with loss-of-field relays16,17
have a range from 15 cycles for characteristic 40-2 to 60 cycles for characteristic 40-1 to
minimize tripping during stable power swings. In the standard, 15 cycles establishes a threshold
for applicability; however, it is the responsibility of the Generator Owner to establish settings
that provide security against stable power swings and, at the same time, dependable protection
for the generator.
The simple two-machine system circuit (method also used in Transmission Element section) is
used to analyze the effect of a power swing at a generator facility for load-responsive relays
pursuant to Requirement R4. In this section, the calculation method is used for calculating the
impedance seen by the relay connected at a point in the circuit.18 The electrical quantities used to
determine the apparent impedance plot using this method are generator saturated transient
reactance (X’d), GSU transformer impedance (XGSU), transmission line impedance (ZL), and the
system equivalent (Ze) at the point of interconnection. All impedance values are known to the
Generator Owner except for the system equivalent. The system equivalent is available from the
Transmission Owner. The sending- and receiving-end source voltages are varied from 0.7 to 1.0
per unit to form a portion of a lens characteristic instead of varying the voltages from 0 to 1.0 per
unit which would form a full lens characteristic. The voltage range of 0.7 – 1.0 results in a ratio
range from 0.7 to 1.43.This ratio range is used in determining the portion of the lens. A system
separation angle of 120 degrees is also used in each load-responsive protective relay evaluation.
Below is an example calculation of the apparent impedance locus method based on Figures 18
and 19.19 In this example, the generator is connected to the 345 kV transmission system through
the GSU transformer and has the ratings listed. The load-responsive protective relay
responsibilities below are divided between the Generator Owner and Transmission Owner.
16
Ibid, Burdy.
17
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
18
Edward Wilson Kimbark, Power System Stability, Volume II: Power Circuit Breakers and Protective Relays,
Published by John Wiley and Sons, 1950.
19
Ibid, Kimbark.
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Figure 17. Simple one-line diagram of the
system to be evaluated.
Figure 18. Simple system equivalent
impedance diagram to be evaluated.20
Table15. Example Data (Generator)
Input Descriptions
Input Values
Synchronous Generator nameplate (MVA)
940 MVA
Sub-transient reactance (940MVA base – per unit)
Generator rated voltage (Line-to-Line)
Generator step-up (GSU) transformer rating
GSU transformer reactance (880 MVA base)
System Equivalent (100 MVA base)
X"d = 0.3845
20
880
X
Generator Owner Load-Responsive Protective Relays
40-1
= 16.05%
= 0.00723∠86° ohms
Positive Offset Impedance
Offset = 0.294 per unit ohms
Diameter = 0.294 per unit ohms
40-2
Negative Offset Impedance
Offset = 0.22 per unit ohms
Diameter = 2.24 per unit ohms
20
Ibid, Kimbark.
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Table15. Example Data (Generator)
Negative Offset Impedance
Offset = 0.22 per unit ohms
40-3
Diameter = 1.00 per unit ohms
Diameter = 0.643 per unit ohms
21-1
MTA = 85°
I (pickup) = 5.0 per unit
50
Transmission Owned Load-Responsive Protective Relays
Diameter = 0.55 per unit ohms
21-2
MTA = 85°
Calculations shown for a 120 degree angle and ES/ER = 1. The equation for calculating ZR is:21
=
Eq. (106)
(1 −
)( ∠ ) + ( )(
∠ −
)
×
Where m is the relay location as a function of the total impedance (real number less than 1)
ES and ER is the sending- and receiving-end voltages
Zsys is the total system impedance
ZR is the complex impedance at the relay location and plotted on an R-X diagram
All of the above are constants (940 MVA base) while the angle δ is varied. Table 16 below
contains calculations for a generator using the data listed in Table 15.
Table16. Example Calculations (Generator)
Given:
Eq. (107)
21
"
= 0.3845 Ω
=
"
+
+
= 0.171 Ω
= 0.06796 Ω
Ibid, Kimbark.
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Table16. Example Calculations (Generator)
= 0.3845 Ω + 0.171 Ω + 0.06796 Ω
= 0.6239 ∠90° Ω
Eq. (108)
=
Eq. (109)
=
=
Z =
"
=
(1 −
0.3845
= 0.61633
0.6239
)( ∠ ) + ( )(
∠ −
)
×
(1 − 0.61633) × (1∠120°) + (0.61633)(1∠0°)
× (0.6234∠90°) Ω
1∠120° − 1∠0°
0.4244 + 0.3323
× (0.6234∠90°) Ω
−1.5 + 0.866
Z = (0.3112 ∠ − 111.94°) × (0.6234∠90°) Ω
Z = 0.194 ∠ − 21.94° Ω
Z = −0.18 − 0.073 Ω
Table 17 lists the swing impedance values at other angles and at ES/ER = 1, 1.43, and 0.7. The
impedance values are plotted on an R-X graph with the center being at the generator terminals
for use in evaluating impedance relay settings.
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Table 17: Sample calculations for a swing impedance chart for varying voltages at the
sending- and receiving-end.
ES/ER=1
ES/ER=1.43
ES/ER=0.7
ZR
ZR
ZR
Angle (δ)
Magnitude
Angle
Magnitude
Angle
Magnitude
Angle
(Degrees)
(PU Ohms)
(Degrees)
(PU Ohms)
(Degrees)
(PU Ohms) (Degrees)
90
0.320
-13.1
0.296
6.3
0.344
-31.5
120
0.194
-21.9
0.173
-0.4
0.227
-40.1
150
0.111
-41.0
0.082
-10.3
0.154
-58.4
210
0.111
-25.9
0.082
190.3
0.154
238.4
240
0.111
221.0
0.173
180.4
0.225
220.1
270
0.320
193.1
0.296
173.7
0.344
211.5
Requirement R4 Generator Examples
Distance Relay Application
Based on PRC-026-1 – Attachment B, Criteria A, the distance relay (21-1) (owned by the
generation entity) characteristic is in the region where a stable power swing would not occur as
shown in Figure 19. There is no further obligation to the owner in this standard for this loadresponsive protective relay.
The distance relay (21-2) (owned by the transmission entity) is connected at the high-voltage
side of the GSU transformer and its impedance characteristic is in the region where a stable
power swing could occur causing the relay to operate. In this example, if the intentional time
delay of this relay is less than 15 cycles, the Transmission Owner is required to create a CAP
(Requirement R5) to meet PRC-026 – Attachment B, Criteria B. Some of the options include, but
are not limited to, changing the relay setting (i.e. impedance reach, angle, time delay), modify
the scheme (i.e. add power swing blocking), or replace the Protection System. Note that the relay
may be excluded from this standard if it has an intentional time delay equal to or greater than 15
cycles.
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Figure 19. Swing impedance graph for impedance relays at a generating facility.
Loss-of-Field Relay Application
In Figure 20, the R-X diagram shows the loss-of-field relay (40-1 and 40-2) characteristics are in
the region where a stable power swing can cause a relay operation. Protective relay 40-1 would
be excluded if it has an intentional time delay equal to or greater than 15 cycles. Similarly, 40-2
would be excluded if its intentional time delay is equal to or greater than 15 cycles. For example,
if 40-1 has a time delay of 1 second and 40-2 has a time delay of 0.25 seconds, they are excluded
and there is no further obligation to the owner in this standard for these relays. The loss-of-field
relay characteristic 40-3 is outside the region where a stable power swing can cause a relay
operation. In this case, the owner may select high speed tripping on operation of the 40-3
impedance element.
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Figure 20: Stable power swing R-X graph for loss-of-field relays.
Instantaneous Overcurrent Relay
In similar fashion to the transmission overcurrent example calculation in Table 14, the
instantaneous overcurrent relay minimum setting is established by PRC-026-1 – Attachment B,
Criteria B. The solution is found by:
Eq. (110)
=
−
sys
As stated in the relay settings in Table 15, the relay is installed on the high-voltage side of the
GSU transformer with a pickup of 5.0 per unit current. The maximum allowable current is
calculated below.
=
=
(1.05∠120° − 1.05∠0°)
0.6234∠90°
1.775∠150°
0.6234∠90° Ω
= 2.84 ∠60°
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The phase instantaneous setting of 5.0 per unit amps is greater than the calculated system current
of 2.84 per unit amps; therefore it is compliant with PRC-026-1 – Attachment B, Criteria B.
Requirement R5
This requirement ensures that all actions associated with any Corrective Action Plan (CAP)
developed in the previous requirement are completed. The requirement also permits the entity to
modify a CAP as necessary, while in the process of fulfilling the purpose of the standard.
To achieve the stated purpose of this standard, which is to ensure that relays are expected to not
trip in response to stable power swings during non-Fault conditions, the applicable entity is
required to develop and complete a CAP that reduces the risk of relays tripping during a stable
power swing that may occur on any applicable Element of the BES. Protection System owners
are required, during the implementation of a CAP, to update it when any action or timetable
changes until the CAP is completed. Accomplishing this objective is intended to reduce the risk
of the relays unnecessarily tripping during stable power swings, thereby improving reliability
and reducing risk to the BES.
The following are examples of actions taken to complete CAPs for a relay that could be exposed
to a stable power swing and a setting change was determined to be acceptable (without
diminishing the ability of the relay to protect for faults within its zone of protection).
Example R5a: Actions: Settings were issued on 6/02/2015 to reduce the zone 2 reach of
the impedance relay used in the permissive overreaching transfer trip (POTT) scheme
from 30 ohms to 25 ohms so that the relay characteristic is completely contained within
the lens characteristic identified by the criterion. The settings were applied to the relay on
6/25/2015. CAP completed on 06/25/2015.
Example R5b: Actions: Settings were issued on 6/02/2015 to enable out-of-step
blocking on the existing microprocessor-based relay to prevent tripping in response to
stable power swings. The setting changes were applied to the relay on 6/25/2015. CAP
completed on 06/25/2015.
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The following is an example of actions taken to complete a CAP for a relay responding to a
stable power swing that required the addition of an electromechanical power swing blocking
relay.
Example R5c: Actions: A project for the addition of an electromechanical power swing
blocking relay to supervise the zone 2 impedance relay was initiated on 6/5/2015 to
prevent tripping in response to stable power swings. The relay installation was completed
on 9/25/2015. CAP completed on 9/25/2015.
The following is an example of actions taken to complete a CAP with a timetable that required
updating for the replacement of the relay.
Example R5d: Actions: A project for the replacement of the impedance relays at both
terminals of line X with line current differential relays was initiated on 6/5/2015 to
prevent tripping in response to stable power swings. The completion of the project was
postponed due to line outage rescheduling from 11/15/2015 to 3/15/2016. Following the
timetable change, the impedance relay replacement was completed on 3/18/2016. CAP
completed on 3/18/2016.
The CAP is complete when all the documented actions to resolve the specific problem (i.e.,
unnecessary tripping during stable power swings) are completed.
Requirement R6
To achieve the stated purpose of this standard, which is to ensure that load-responsive protective
relays are expected to not trip in response to stable power swings during non-Fault conditions,
the applicable entity is required to fully implement any CAP developed pursuant to Requirement
R5 that modifies the Protection System to meet PRC-026-1 – Attachment B, Criteria A and B.
Protection System owners are required in the implementation of a CAP to update it when actions
or timetable change, until all actions are complete. Accomplishing this objective is intended to
reduce the occurrence of Protection System tripping during a stable power swing, thereby
improving reliability and minimizing risk to the BES.
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PRC-026-1 — Relay Performance During Stable Power Swings
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SAR posted for comment from August 19, 2010 through September 19, 2010.
2. SC authorized moving the SAR forward to standard development on August 12, 2010.
3. SC authorized initial posting of draft 1 on April 24, 2014.
4. Draft 1 of PRC-026-1 was posted for a 45-day formal comment period from April 25 –
June 9, 2014 and an initial ballot in the last ten days of the comment period from May 30
– June 9, 2014.
Description of Current Draft
The Protection System Response to Power Swings Standard Drafting Team (PSRPS SDT) is
posting Draft 12 of PRC-026-1 – Relay Performance During Stable Power Swings for a 45-day
initialadditional comment period and concurrent/parallel initialadditonal ballot in the last ten
days of the comment period.
Anticipated Actions
Anticipated Date
45-day Formal Comment Period with Concurrent/Parallel Initial Ballot
April 2014
45-day Formal Comment Period with Concurrent/Parallel Additional
Ballot
JulyAugust 2014
Final Ballot
SeptemberOctober
2014
BOTNERC Board of Trustees Adoption
November 2014
Version History
Version
Date
1.0
TBD
Action
Effective Date
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Change
Tracking
New
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PRC-026-1 — Relay Performance During Stable Power Swings
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Glossary of Terms Used in Reliability Standards are not repeated here.
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.
Term: None.
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PRC-026-1 — Relay Performance During Stable Power Swings
When this standard has received ballot approval, the textrationale boxes will be moved to the
Application Guidelines Section of the Standard.
A. Introduction
1.
Title:
Relay Performance During Stable Power Swings
2.
Number:
PRC-026-1
3.
Purpose: To ensure that load-responsive protective relays doare expected to not trip
in response to stable power swings during non-Fault conditions.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Generator Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
4.1.2
Planning Coordinator.
4.1.3
Reliability Coordinator.
4.1.44.1.3
Transmission Owner that applies load-responsive protective relays
as described in PRC-026-1 – Attachment A at the terminals of the
Elements listed in Section 4.2, Facilities.
4.1.5
Transmission Planner.
4.2. Facilities: The following Bulk Electric System (BES) Elements:
5.
4.2.1
Generators.
4.2.2
Transformers.
4.2.3
Transmission lines.
Background:
This is Phase 3the third phase of a three-phased standard development project that is
focused on developing athis new Reliability Standard, PRC-026-1 – Relay
Performance During Stable Power Swings, to address protective relay operations due
to stable power swings. The March 18, 2010, FERC Order No. 733, approved
Reliability Standard PRC-023-1 – Transmission Relay Loadability. In this Order,
FERC directed NERC to address three areas of relay loadability that include
modifications to the approved PRC-023-1, development of a new Reliability Standard
to address generator protective relay loadability, and a new Reliability Standard to
address the operation of protective relays due to stable power swings. This project’s
SAR addresses these directives with a three-phased approach to standard development.
Phase 1 focused on making the specific modifications to PRC-023-1 and was
completed in the approved Reliability Standard PRC-023-2, which became mandatory
on July 1, 2012.
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PRC-026-1 — Relay Performance During Stable Power Swings
Phase 2 focused on developing a new Reliability Standard, PRC-025-1 – Generator
Relay Loadability, to address generator protective relay loadability; PRC-025-1 is
currently awaiting regulatory approvalwas approved by FERC on July 17, 2014.
This Phase 3 of the project focuses on developing a new Reliability Standard, PRC026-1 – Relay Performance During Stable Power Swings, to address protective relay
operations due to stable power swings. This Reliability Standard will establishThis
Phase 3 of the project establishes requirements aimed at preventing protective relays
from tripping unnecessarily due to stable power swings by requiring each Transmission
Owner and Generator Ownerthe identification of Elements on which a power swing
may affect Protection System operation, and to develop requirements to assess the
security of load-responsive protective relay systems that are susceptible to operation
during power swings, and take actionsrelays to tripping in response to a stable power
swing. Last, to require entities to implement Corrective Action Plans, where necessary,
to improve security of security of load-responsive protective relays for stable power
swings where such actions wouldso they are expected to not compromisetrip in
response to stable power swings during non-Fault conditions while maintaining
dependable operation for faults and unstable power swingsfault detection and
dependable out-of-step tripping.
6.
Effective Date:
Requirements R1-R3, R5, and R6
First day of the first full calendar year that is twelve12 months beyondafter the date that
thisthe standard is approved by an applicable regulatory authorities, orgovernmental
authority or as otherwise provided for in those jurisdictionsa jurisdiction where
regulatory approval by an applicable governmental authority is required for a standard
to go into effect. Where approval by an applicable governmental authority is not
required, the standard becomesshall become effective on the first day of the first full
calendar year that is twelve12 months beyondafter the date thisthe standard is
approvedadopted by the NERC Board of Trustees, or as otherwise madeprovided for in
that jurisdiction.
Requirement R4
First day of the first full calendar year that is 36 months after the date that the standard
is approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is
not required, the standard shall become effective pursuant to the laws applicable to
such ERO governmental authoritieson the first day of the first full calendar year that is
36 months after the date the standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.
B. Requirements and Measures
R1. Each Planning Coordinator, Reliability Coordinator, and Transmission Planner shall,
within the first month ofat least once each calendar year, identify each Element in its area
that meets one or more of the following criteria and provide notification to the respective
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PRC-026-1 — Relay Performance During Stable Power Swings
Generator Owner and Transmission Owner of each Element that meets one or more of the
following criteria, if any: [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning, Long-term Planning]
Criteria:
1. An Element that is located or terminates at a generating plant, Generator(s) where a
generating plantan angular stability constraint exists andthat is addressed by an
operating limit or a Special Protection System (SPS) (including line-out
conditionsRemedial Action Scheme (RAS) and those Elements terminating at the
transmission switching station associated with the generator(s).
2. An Element that is associated with monitored as part of a System Operating Limit
(SOL) that has been established based on angular stability constraints identified in
system planning or operating studies (including line-out conditions)..
3. An Element that has formedforms the boundary of an island due to angular
instability within an angular stability planning simulation where the system
Disturbance(s) that caused the islanding condition continues to be a credible eventthe
most recent underfrequency load shedding (UFLS) assessment.
4. An Element identified in the most recent Planning Assessment where relay
tripping occurred for aoccurs due to a stable or unstable power swing during a
Disturbancesimulated disturbance.
5. An Element reported by the Generator Owner or Transmission Owner pursuant to
Requirement R2 or Requirement R3, unless the Planning Coordinator determines
the Element is no longer susceptible to power swings.
M1. Each Planning Coordinator, Reliability Coordinator, and Transmission Planner shall have
dated evidence that demonstrates identification and the respective notification of the
Element(s), if any, which meet one or more of the criteria in Requirement R1. Evidence
may include, but is not limited to, the following documentation: emails, facsimiles,
records, reports, transmittals, lists, or spreadsheets.
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Rationale for R1: The Planning Coordinator, Reliability Coordinator, has a wide-area view
and Transmission Planner areis in positionsthe position to identify Elements which meet the
criteria, if any. The criterion-based approach is consistent with the NERC System Protection
and Control Subcommittee (SPCS) technical document Protection System Response to Power
Swings, August 2013, (“PSRPS Report”),1 which recommendedrecommends a focused
approach to determine an at-risk Element. Requirements R1, R2, and R3 collectively form an
annual assessment. Identification of the Element(s) in the first month of the calendar year
allows the remaining time in the calendar year for the relay owners to evaluate Protection
Systems (Requirement R3).
R2. Each Generator Owner and Transmission Owner shall, once eachwithin 30 calendar year,
identify each Element for which it applies a load-responsive protective relay at a terminal
ofdays of identifying an Element that meets either of the following criteria, if anyprovide
notification of the Element to its Planning Coordinator: [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning, Long-term Planning]
Criteria:
1. An Element that has tripped since January 1, 2003,trips due to a stable or unstable
power swing during an actual system Disturbance where the Disturbance(s) that
caused the trip due to a power swing continues to be crediblethe operation of its loadresponsive protective relays.
2. An Element that has formedforms the boundary of an island since January 1, 2003,
during an actual system Disturbance where the Disturbance(s) that caused the
islanding condition continues to be credibledue to the operation of its loadresponsive protective relays.
M2. Each Generator Owner and Transmission Owner shall have dated evidence that
demonstrates identification of the Element(s), if any, which meet either of the criteria in
Requirement R2. Evidence may include, but is not limited to, the following
documentation: emails, facsimiles, records, reports, transmittals, lists, or spreadsheets.
1
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
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PRC-026-1 — Relay Performance During Stable Power Swings
Rationale for R2: The Generator Owner and Transmission Owner areis in positionsthe
position to identify whichthe load-responsive protective relays that have tripped due to power
swings, if any. The criterion-based approachcriteria is consistent with the NERC System
Protection and Control Subcommittee (SPCS) technical document Protection System Response
to Power Swings, August 2013, which recommended a focused approach to determine an atrisk Element. Requirements R1, R2, and R3 collectively form an annual assessment.
ThePSRPS Report. A time period in Requirement R2 and R3 allowsto complete a review of
the relay owners to allocate time during the calendar year to identify the Element(s) and to
evaluate Protection Systems based on their particular circumstancestripping is not addressed
here as other NERC Reliability Standards address the review of Protection System operations.
R3. Each Generator Owner and Transmission Owner shall, once eachwithin 30 calendar year,
perform onedays of identifying an Element that meets the following for eachcriterion,
provide notification of the Element identified pursuant to Requirement R1 or R2its
Planning Coordinator: [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning, Long-term Planning]
•
Demonstrate that the existing Protection System is not expected to trip in response
to a stable power swing based on the criterion below.
•
Demonstrate that the existing Protection System is not expected to trip in response
to a stable power swing because power swing blocking is applied.
•
Develop a Corrective Action Plan (CAP) to modify the Protection System so that
the Protection System is not expected to trip in response to a stable power swing
based on the criterion below or by applying power swing blocking.
•
If none of the options above results in dependable fault detection or dependable
out-of-step tripping:
a. obtain agreement from the respective Planning Coordinator, Reliability
Coordinator, and Transmission Planner of the Element that the existing
Protection System design and settings are acceptable, or
b. obtain agreement from the respective Planning Coordinator, Reliability
Coordinator, and Transmission Planner of the Element that a modification
of the Protection System design, settings, or both are acceptable, and
develop a CAP for this modification of the Protection System.
Criterion:
A distance relay impedance characteristic, used for tripping, that is completely
contained within the lens characteristic formed in the impedance (R-X) plane
that connects the endpoints of the total system impedance by varying the
sending end and receiving end voltages from 0 to 1.0 per unit, while
maintaining a constant system separation angle across the total system
impedance where:
1. The system separation angle is:
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PRC-026-1 — Relay Performance During Stable Power Swings
•
At least 120 degrees where power swing blocking is not applied, or
•
An angle less than 120 degrees as agreed upon by the Planning
Coordinator, Reliability Coordinator, and Transmission Planner
where power swing blocking is not applied.
1. All generation is in service and all transmission Elements are in their
normal operating state.
2. Sub-transient reactance is used for all machines.
1. An Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load-responsive protective relays.
M3. Each Generator Owner shall have dated evidence that demonstrates identification of the
Element(s), if any, which the criterion in Requirement R3. Evidence may include, but is
not limited to, the following documentation: emails, facsimiles, records, reports,
transmittals, lists, or spreadsheets.
Rationale for R3: The Generator Owner is in the position to identify the load-responsive
protective relays that have tripped due to power swings, if any. The criterion is consistent with
the PSRPS Report. A requirement or time to complete a review of the relay tripping is not
addressed here as other NERC Reliability Standards address the review of Protection System
operations.
R4. Each Generator Owner and Transmission Owner shall, within 12 full calendar months of
receiving notification of an Element pursuant to Requirement R1 or within 12 full calendar
months of identifying an Element pursuant to Requirement R2 or R3, evaluate each
identified Element’s load-responsive protective relay(s) based on the PRC-026-1 –
Attachment B Criteria where the evaluation has not been performed in the last three
calendar years. [Violation Risk Factor: High] [Time Horizon: Operations Planning]
M3.M4.
Each Generator Owner and Transmission Owner shall have dated evidence that
demonstrates one of the optionsevaluation was performed according to Requirement R3R4.
Evidence may include, but is not limited to, the following documentation: apparent
impedance characteristic plots, email, design drawings, facsimiles, R-X plots, software
output, records, reports, transmittals, lists, settings sheets, or spreadsheets.
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Rationale for R3: Performing one of the options in Requirement R3 assures that the
reliability goal of this standard will be met. The first option ensures that the Generator Owner
and Transmission Owner protective relays are secure from tripping in response to stable power
swings having a system separation angle of up to 120 degrees. The second option allows the
Generator Owner and Transmission Owner to exclude protective relays that have power swing
blocking applied. The third option allows the Generator Owner and Transmission Owner,
where possible, to modify the Protection System to meet the criterion or apply power swing
blocking. The fourth option allows the Generator Owner and Transmission Owner to maintain
a balance between Protection System security and dependability for cases where tripping on
stable power swings may be necessary to maintain the ability to trip for unstable power swings
or faults; however, agreement is required by others to ensure that tripping for a stable power
swing is acceptable. Protection System modifications may be necessary to achieve acceptable
performance. A time period of once each calendar year allows time to evaluate the Protection
System, develop a CAP, or obtain necessary agreement.Rationale for R4: Performing the
evaluation in Requirement R4 is the first step in ensuring that the reliability goal of this
standard will be met. The PRC-026-1 – Attachment B, Criteria provides a basis for
determining if the relays are expected to not trip for a stable power swing. See the Guidelines
and Technical Basis for a detailed explanation of the evaluation.
R4.R5. Each Generator Owner and Transmission Owner shall implement each CAP developed,
within 60 calendar days of an evaluation that identifies load-responsive protective relays
that do not meet the PRC-026-1 – Attachment B Criteria pursuant to Requirement R3,R4,
develop a Corrective Action Plan (CAP) to modify the Protection System to meet the PRC026-1 – Attachment B Criteria while maintaining dependable fault detection and update
each CAP dependable out-of-step tripping (if actions or timetables change, until all actions
are complete.out-of-step tripping is applied at the terminal of the Element). [Violation Risk
Factor: Medium][] [Time Horizon: Operations Planning, Long-Term Planning]]
M4.M5.
The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates implementationthe development of eacha CAP according toin accordance
with Requirement R4, including updates to actions or timetablesR5. Evidence may include,
but is not limited to, the following documentation: corrective action plans, maintenance
records, settings sheets, project or work management program records, or work orders.
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Rationale for R4: Implementation of the CAP must accomplish all identified actions to be
complete to achieve the desired reliability goal. During the course of implementing a CAP,
updates may be necessary for a variety of reasons such as new information, scheduling
conflicts, or resource issues. Documenting changes and completion of activities provides
measurable progress and confirmation of completion.Rationale for R5: To meet the reliability
purpose of the standard, a CAP is necessary to modify the entity’s Protection System to meet
PRC-026-1 – Attachment B so that protective relays are expected to not trip in response to
stable power swings. The phrase, “while maintaining dependable fault detection and
dependable out-of-step tripping” in Requirement R5 describes that the entity is to comply with
this standard while achieving their desired protection goals. Refer to the Guidelines and
Technical Basis, Introduction, for more information.
R6. Each Generator Owner and Transmission Owner shall implement each CAP developed
pursuant to Requirement R5, and update each CAP if actions or timetables change until all
actions are complete. [Violation Risk Factor: Medium][Time Horizon: Long-Term
Planning]
M6. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates implementation of each CAP according to Requirement R6, including
updates to actions or timetables. Evidence may include, but is not limited to, the following
documentation: corrective action plans, maintenance records, settings sheets, project or
work management program records, or work orders.
Rationale for R6: Implementation of the CAP must accomplish all identified actions to be
complete to achieve the desired reliability goal. During the course of implementing a CAP,
updates may be necessary for a variety of reasons such as new information, scheduling
conflicts, or resource issues. Documenting changes and completion of activities provides
measurable progress and confirmation of completion.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods 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
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the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The Generator Owner, Planning Coordinator, Reliability Coordinator,
Transmission Owner, and Transmission PlannerOwner shall keep data or
evidence to show compliance as identified below unless directed by its CEA to
retain specific evidence for a longer period of time as part of an investigation.
•
The Planning Coordinator, Reliability Coordinator, and Transmission
Planner shall retain evidence of RequirementsRequirement R1, Measures
M1 for a minimum of three calendar years following the completion of
each Requirement.
•
The Transmission Owner shall retain evidence of Requirement R2 for a
minimum of three calendar years following the completion of each
Requirement.
•
The Generator Owner shall retain evidence of Requirement R3 for a
minimum of three calendar years following the completion of each
Requirement.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R2 and R3, Measures M2 and M3Requirement R4 for
threea minimum of 36 calendar yearsmonths following completion of each
evaluation.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R4, Measures M4 forR5 and R6, including any supporting
analysis per Requirements R1, R2, R3, and R4, for a minimum of 12
calendar months following completion of each CAP.
If a Generator Owner, Planning Coordinator, Reliability Coordinator,
Transmission Owner, or Transmission PlannerOwner is found non-compliant, it
shall keep information related to the non-compliance until mitigation is complete
and approved, or for the time specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None.
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Table of Compliance Elements
R#
R1
Time
Horizon
Operations
Planning,
Long-term
Planning
Violation Severity Levels
VRF
Medium
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entityPlanning
Coordinator identified
an Element and
provided notification
in accordance with
Requirement R1, but
was less than or equal
to 30 calendar days
late.
The responsible
entityPlanning
Coordinator
identified an
Element and
provided notification
in accordance with
Requirement R1, but
was more than 30
calendar days and
less than or equal to
60 calendar days
late.
The responsible
entityPlanning
Coordinator
identified an
Element and
provided notification
in accordance with
Requirement R1, but
was more than 60
calendar days and
less than or equal to
90 calendar days
late.
The responsible
entityPlanning
Coordinator
identified an
Element and
provided notification
in accordance with
Requirement R1, but
was more than 90
calendar days late.
OR
The responsible
entityPlanning
Coordinator failed to
identify an Element
orin accordance with
Requirement R1.
OR
The Planning
Coordinator failed to
provide notification
in accordance with
Requirement R1.
R2
Operations
Planning,
Medium
The responsible
entityTransmission
The responsible
entityTransmission
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The responsible
entityTransmission
The responsible
entityTransmission
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R#
Time
Horizon
Violation Severity Levels
VRF
Long-term
Planning
Lower VSL
Moderate VSL
High VSL
Severe VSL
Owner identified an
Element and provided
notification in
accordance with
Requirement R2, but
was less than or equal
to 3010 calendar days
late.
Owner identified an
Element and
provided notification
in accordance with
Requirement R2, but
was more than 3010
calendar days and
less than or equal to
6020 calendar days
late.
Owner identified an
Element and
provided notification
in accordance with
Requirement R2, but
was more than 6020
calendar days and
less than or equal to
9030 calendar days
late.
Owner identified an
Element and
provided notification
in accordance with
Requirement R2, but
was more than 9030
calendar days late.
OR
The responsible
entityTransmission
Owner failed to
identify an Element
in accordance with
Requirement R2.
OR
The Transmission
Owner failed to
provide notification
in accordance with
Requirement R2.
R3
Operations
Planning,
Long-term
Planning
Medium
The responsible entity
performed one of the
optionsGenerator
Owner identified an
Element and provided
notification in
accordance with
The responsible
entity performed one
of the
optionsGenerator
Owner identified an
Element and
provided notification
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
The responsible
entity performed one
of the
optionsGenerator
Owner identified an
Element and
provided notification
The responsible
entity performed one
of the
optionsGenerator
Owner identified an
Element and
provided notification
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R#
Time
Horizon
Violation Severity Levels
VRF
Lower VSL
Moderate VSL
High VSL
Severe VSL
Requirement R3, but
was less than or equal
to 3010 calendar days
late.
in accordance with
Requirement R3, but
was more than 3010
calendar days and
less than or equal to
6020 calendar days
late.
in accordance with
Requirement R3, but
was more than 6020
calendar days and
less than or equal to
9030 calendar days
late.
in accordance with
Requirement R3, but
was more than 9030
calendar days late.
OR
The responsible
entityGenerator
Owner failed to
perform one of the
optionsidentify an
Element in
accordance with
Requirement R3.
OR
The Generator
Owner failed to
provide notification
in accordance with
Requirement R3.
R4
Operations
Planning,
Long-term
Planning
MediumHigh The responsible entity
implemented, but
failed to update a
CAP, when
actionsGenerator
Owner or timetables
changed,Transmission
Owner evaluated each
N/AThe Generator
Owner or
Transmission Owner
evaluated each
identified Element’s
load-responsive
protective relay(s) in
accordance with
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
N/AThe Generator
Owner or
Transmission Owner
evaluated each
identified Element’s
load-responsive
protective relay(s) in
accordance with
The responsible
entityGenerator
Owner or
Transmission Owner
evaluated each
identified Element’s
load-responsive
protective relay(s) in
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R5
Time
Horizon
Long-term
Planning
Violation Severity Levels
VRF
Medium
Lower VSL
Moderate VSL
High VSL
Severe VSL
identified Element’s
load-responsive
protective relay(s) in
accordance with
Requirement R4, but
was less than or equal
to 30 calendar days
late.
Requirement R4, but
was more than 30
calendar days and
less than or equal to
60 calendar days
late.
Requirement R4, but
was more than 60
calendar days and
less than or equal to
90 calendar days
late.
accordance with
Requirement R4, but
was more than 90
calendar days late.
The Generator Owner
or Transmission
Owner developed a
CAP in accordance
with Requirement R5,
but in more than 60
calendar days and less
than or equal to 70
calendar days.
The Generator
Owner or
Transmission Owner
developed a CAP in
accordance with
Requirement R5, but
in more than 70
calendar days and
less than or equal to
80 calendar days.
OR
The Generator
Owner or
Transmission Owner
failed to implement a
CAPevaluate each
identified Element’s
load-responsive
protective relay(s) in
accordance with
Requirement R4.
The Generator
Owner or
Transmission Owner
developed a CAP in
accordance with
Requirement R5, but
in more than 80
calendar days and
less than or equal to
90 calendar days.
The Generator
Owner or
Transmission Owner
developed a CAP in
accordance with
Requirement R5, but
in more than 90
calendar days.
OR
The Generator
Owner or
Transmission Owner
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
Time
Horizon
Violation Severity Levels
VRF
Lower VSL
Moderate VSL
High VSL
Severe VSL
failed to develop a
CAP in accordance
with Requirement
R5.
R6
Long-term
Planning
Medium
The Generator Owner
or Transmission
Owner implemented,
but failed to update a
CAP, when actions or
timetables changed, in
accordance with
Requirement R6.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
N/A
N/A
The Generator
Owner or
Transmission Owner
failed to implement a
CAP in accordance
with Requirement
R6.
Page 18 of 105
PRC-026-1 — Relay Performance During Stable Power Swings
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
Burdy, John, Loss-of-excitation Protection for Synchronous Generators GER-3183, General
Electric Company.
IEEE Power System Relaying Committee WG D6., Power Swing and Out-of-Step
Considerations on Transmission Lines., July 2005: http://www.pespsrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20Tr
ansmission%20Lines%20F..pdf..
Kimbark Edward Wilson, Power System Stability, Volume II: Power Circuit Breakers and
Protective Relays, Published by John Wiley and Sons, 1950.
Kundar, Prabha., Power System Stability and Control., 1994., Palo Alto: EPRI, McGraw Hill,
Inc.
NERC System Protection and Control Subcommittee., Protection System Response to Power
Swings., August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf.
Reimert, Donald., Protective Relaying for Power Generation Systems., 2006., Boca Raton:
CRC Press.
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PRC-026-1 — Relay Performance During Stable Power Swings
Guidelines
and
Technical
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
Basis
Page 20 of 105
Application Guidelines
PRC-026-1 – Attachment A
This standard includes any protective functions which could trip instantaneously or with a time
delay of less than 15 cycles, on load current (i.e., “load-responsive”) including, but not limited
to:
•
•
•
•
Phase distance
Phase overcurrent
Out-of-step tripping
Loss-of-field
The following protection functions are excluded from requirements of this standard:
•
•
•
•
•
•
•
•
•
•
•
Relay elements supervised by power swing blocking
Relay elements that are only enabled when other relays or associated systems fail. For
example:
o Overcurrent elements that are only enabled during loss of potential conditions.
o Elements that are only enabled during a loss of communications
Thermal emulation relays which are used in conjunction with dynamic Facility Ratings
Relay elements associated with dc lines
Relay elements associated with dc converter transformers
Phase fault detector relay elements employed to supervise other load-responsive phase
distance elements (e.g., in order to prevent false operation in the event of a loss of
potential) provided the distance element is set in accordance with the criteria outlined in
the standard
Relay elements associated with switch-onto-fault schemes
Reverse power relay on the generator
Generator relay elements that are armed only when the generator is disconnected from
the system, (e.g., non-directional overcurrent elements used in conjunction with
inadvertent energization schemes, and open breaker flashover schemes)
Current differential relay, pilot wire relay, and phase comparison relay
Voltage-restrained or voltage-controlled overcurrent relays
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Application Guidelines
PRC-026-1 – Attachment B
Criteria A:
An impedance-based relay characteristic, used for tripping, that is completely contained
within the portion of the lens characteristic formed in the impedance (R-X) plane that
connects the endpoints of the total system impedance (with the parallel transfer impedance
removed) bounded by varying the sending- and receiving-end voltages from 0.7 to 1.0 per
unit, while maintaining a constant system separation angle across the total system impedance
where:
2. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates the expected maximum stable separation angle is less than 120
degrees.
3. All generation is in service and all transmission Elements are in their normal
operating state when calculating the system impedance.
4. Saturated (transient or sub-transient) reactance is used for all machines.
Rationale for Attachment B (Criteria A): The PRC-026-1, Attachment B, Criteria A
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending-end and receiving-end
voltages varying from 0.7 to 1.0 per unit (See Guidelines and Technical Basis).
Criteria B:
The pickup of an overcurrent relay element used for tripping, that is above the calculated
current value (with the parallel transfer impedance removed) for the conditions below:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
4. Both the sending and receiving voltages at 1.05 per unit.
Rationale for Attachment B (Criteria B): The PRC-026-1, Attachment B, Criteria B
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending and receiving voltages
at 1.05 per unit (See Guidelines and Technical Basis).
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Application Guidelines
Guidelines and Technical Basis
Introduction
The NERC System Protection and Control Subcommittee technical document, Protection System
Response to Power Swings, August 20132 (“PSRPS Report” or “report”) was specifically
prepared to support the development of this NERC Reliability Standard. The report provided a
historical perspective on power swings as early as 1965 up through the approval of the report by
the NERC Planning Committee. The report also addresses reliability issues regarding trade-offs
between security and dependability of protection systems, considerations for this NERC
Reliability Standard, and a collection of technical information about power swing characteristics
and varying issues with practical applications and approaches to power swings. Of these topics,
the PSRPS Reportreport suggests an approach for this NERC Reliability Standard (“standard” or
“PRC-026-1”) which is consistent with addressing two of the three regulatory directives in the
FERC Order No. 733. The first directive concerns the need for “…protective relay systems that
differentiate between faults and stable power swings and, when necessary, phases out protective
relay systems that cannot meet this requirement.”3 Second, is “…to develop a Reliability
Standard addressing undesirable relay operation due to stable power swings.”4 The third
directive “…to consider “islanding” strategies that achieve the fundamental performance for all
islands in developing the new Reliability Standard addressing stable power swings”5 was
considered during development of the standard.
The development of this NERC Reliability Standard implements the majority of the approach
suggested by the PSRPS Report. These guidelines include a narrative of any deviation in the
report’s approach.standard implements the majority of the approach suggested by the report.
However, it is noted that the Reliability Coordinator and Transmission Planner have not been
included in the standard’s Applicability (as suggested by the PSRPS Report). This is so that a
single entity, the Planning Coordinator, may be the single source for identifying Elements
according to Requirement R1. A single source will insure that multiple entities will not identify
Elements in duplicate, nor will one entity fail to provide an Element because it believes the
Element is being provided by another entity. The Planning Coordinator has, or has access to, the
wide-area model and can correctly identify the Elements that may be susceptible to a stable
power swing.
The phrase, “while maintaining dependable fault detection and dependable out-of-step tripping”
in Requirement R1, describes that the Generator Owner and Transmission Owner is to comply
2
NERC System Protection and Control Subcommittee technical document, Protection System Response to Power
Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
3
Transmission Relay Loadability Reliability Standard, Order No. 733, P.150 FERC ¶ 61,221 (2010).
4
Ibid. P.153.
5
Ibid. P.162.
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Application Guidelines
with this standard while achieving its desired protection goals. Load-responsive protective
relays, as addressed within this standard, may be intended to provide a variety of backup
protection functions, both within the generating unit or generating plant and on the Transmission
system, and this standard is not intended to result in the loss of these protection functions.
Instead, it is suggested that the Generator Owner and Transmission Owner consider both the
requirements within this standard and its desired protection goals, and perform modifications to
its protective relays or protection philosophies as necessary to achieve both.
Power Swings
The IEEE Power System Relaying Committee WG D6 developed a technical document called
Power Swing and Out-of-Step Considerations on Transmission Lines (July 2005) that provides
background on power swings. The following are general definitions from that document:6
Power Swing: a variation in three phase power flow which occurs when the generator
rotor angles are advancing or retarding relative to each other in response to changes in
load magnitude and direction, line switching, loss of generation, faults, and other system
disturbances.
Pole Slip: a condition whereby a generator, or group of generators, terminal voltage
angles (or phases) go past 180 degrees with respect to the rest of the connected power
system.
Stable Power Swing: a power swing is considered stable if the generators do not slip
poles and the system reaches a new state of equilibrium, i.e. an acceptable operating
condition.
Unstable Power Swing: a power swing that will result in a generator or group of
generators experiencing pole slipping for which some corrective action must be taken.
Out-of-Step Condition: Same as an unstable power swing.
Electrical System Center or Voltage Zero: it is the point or points in the system where the
voltage becomes zero during an unstable power swing.
Burden to Entities
The PSRPS Report provides a technical basis and approach for focusing on Protection Systems,
which are susceptible to power swings while achieving the reliability objective. The approach
reduces the number of relays for whichthat the requirementsPRC-026-1 Requirements would
apply to by first identifying the Bulk Electric System (BES) Element(s) that need to be
evaluated. The first step uses criteria to identify a BES Element on which a Protection System is
expected to be challenged by power swings. Of those BES Elements, the second step is to
identify the Element(s) that apply aevaluate each load-responsive protective relay that is applied
6
http://www.pes-psrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission
%20Lines%20F..pdf.
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Application Guidelines
on each identified Element. Rather than requiring the Transmission Planner to perform
simulations to obtain information for each identified Element(s),, the Generator Owner and
Transmission Owner will reduce the need for simulation by comparing the load-responsive
protective relay characteristic to a specific criterioncriteria found in PRC-026-1 – Attachment B.
Applicability
The standard is applicable to the Generator Owner, Planning Coordinator, Reliability
Coordinator, Transmission Owner, and Transmission PlannerOwner entities. More specifically,
the Generator Owner and Transmission Owner entities are applicable when applying loadresponsive protective relays at the terminals of the applicable BES Elements. All the entities
have a responsibility to identify the Elements which meet specific criteria. The standard is
applicable to the following BES Elements: generators, transmission lines, and transformers. The
Distribution Provider was considered for inclusion in the standard; however, it is not subject to
the standard because this entity, by functional registration, would not own generators,
transmission lines, or transformers other than load serving.
Load-responsive protective relays include any protective functions which could trip with or
without time delay, on load current.
Requirement R1
In the first month of each calendar year this requirement initiates the identification of the
Elements that meet specific criteria known by the Planning Coordinator, Reliability Coordinator,
and the Transmission Planner.
Because the dynamic studies performed by the Planning Coordinator and the Transmission
Planner vary by region, it is important for both of these entities to have a reliability requirement
to identify such Elements. The Reliability Coordinator is also included because of its wide-area
awareness of the BES and its unique potential to identify Elements susceptible to tripping due to
power swings.
The Planning Coordinator has a wide-area view and is in the positon to identify what, if any,
Elements meet the criteria. The criterion-based approach is consistent with the NERC System
Protection and Control Subcommittee (SPCS) technical document Protection System Response to
Power Swings (August 2013),7 which recommends a focused approach to determine an at-risk
Element. Identification of Elements comes from the annual Planning Assessments pursuant to
the transmission planning (i.e., “TPL”) and other NERC Reliability Standards, and the standard
is not requiring any other assessments to be performed by the Planning Coordinator. The
required annual notification to the respective Generator Owner and Transmission Owner is
7
http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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Application Guidelines
sufficient because it is expected that the Planning Coordinator will make its notifications
following the completion of its annual Planning Assessments.
Criterion 1
The first criterion involves Elements that are located at or terminate at a generator(s) where an
angular stability constraint exists which is addressed by an operating limit or a Remedial Action
Scheme (RAS) and those Elements terminating at the transmission switching station associated
with the generator(s). For example, a scheme to remove generation for specific conditions is
implemented for a four-unit generating plant where an existing stability constraint has been
established and is managed by either a specific operating limit or a Special Protection System
(SPS). For example, assume a (1,100 MW). Two of the units are 500 MW each; one is connected
to the 345 kV system and one is connected to the 230 kV system. The Transmission Owner has
two 230 kV transmission lines and one 345 kV transmission line all terminating at the generating
facility as well as a 345/230 kV autotransformer. The remaining 100 MW consists of two 50
MW combustion turbine (CT) units connected to four 66 kV transmission lines. The 66 kV
transmission is not electrically joined to the 345 kV and 230 kV transmission lines at the plant
contains two 500 MW generating units, one connected to a 345 kV bus and one connected to site
and is not a 230 kV bus. Assume a single transformer connects the 345 kV bus to the 230 kV
bus, and that the plant is connected to the rest of the BES through a single 345 kV transmission
circuit and two 230 kV circuits. Assume a stability constraint exists that part of the operating
limit or RAS. A stability constraint limits the output of the portion of the plant affected by the
RAS to 700 MW for an outage of the 345 kV transmission line, and that a SPS exists to run back
the output. The RAS trips one of the generating plant to 700500 MW units to maintain stability
for a loss of the 345 kV transmission line. when the total output from both 500 MW units is
above 700 MW. For this hypothetical example, both 500 MW generating units would be
included as Elements meeting the criterion. Furthermore,and the associated generator step-up
(GSU) transformers, the generator interconnection, the 345-230 kV power transformer, and the
two 230 kV transmission circuits would be identified as Elements meeting thethis criterion. The
345/230 kV autotransformer, the 345 kV transmission circuitline, and the two 230 kV
transmission lines would also be identified as Elements meeting this criterion. The 50 MW
combustion turbines and 66 kV transmission lines would not be identified as meeting the
criterion since the event that triggered the stability constraint is a loss of the 345 kV transmission
circuitpursuant Criterion 1 because these Elements are not subject to an operating limit or RAS
and do not terminate at the transmission switching station associated with the generators that are
subject to the operating limit and RAS.
Criterion 2
The second criterion involves Elements that have are monitored due to an established System
Operating Limit (SOL) based on aan angular stability limit or issue driven by one or more
specific eventsregardless of the outage conditions that result in the enforcement of the SOL. For
example, if two long parallel 500 kV transmission lines have a combined SOL of 1,200 MW, and
this limit is based on angular instability resulting from a fault and subsequent loss of one of the
two circuitslines, then both circuitslines would be identified as an Element meeting the criterion.
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Application Guidelines
Criterion 3
The third criterion involves the Element that has formedforms the boundary of an island due to
angular instability within an angular stability planning simulation.underfrequency load shedding
(UFLS) assessment. While the island may form due to various transmission circuitslines tripping
for a combination of reasons, such as stable and unstable power swings, faults, and excessive
loading, the criterion requires that all lines that tripped in simulation due to “angular instability”
to form the island be identified as meeting the criterion.
The last criterion allows the Planning Coordinator and Transmission Planner to include any other
Elements revealed in Planning Assessments.
Requirement R2
The approach of Requirement R2 requires the Generator Owner and Transmission Owner to
identify Elements once each calendar year that meet the focused criteria specific to these entities.
The only Elements that are in scope are Elements that meet the criteria and apply a loadresponsive protective relay at the terminal of the Element. Using the criteria focuses the
reliability concern on the Element that is at-risk.
The first criterion involves Elements that have tripped for actual power swings, regardless of
whether the power swing was stable or unstable. In order to ensure previous trips due to power
swings are considered, the entity must consider Disturbances since January 1, 2003 in order to
capture the August 14, 2003 Blackout.8 In consideration that BES topologies change, the
Requirement includes a provision to exclude the Element where a historical Disturbance is no
longer credible; meaning the Disturbance is no longer capable of occurring in the future due to
actual changes to the BES.
The second criterion involves the formation of an island based on an actual Disturbance. While
the island may form due to various transmission circuits tripping for a combination of reasons,
such as power swings (stable or unstable), faults, or excessive loading, the criterion requires that
all lines that tripped to form the island be identified as meeting the criterion. This criterion also
has an exception similar to the first criterion. Any event that caused an actual island to form
since August 1, 2003 that is no longer credible due to actual changes to the BES is not required
be used to identify Elements as meeting the criterion.
For example, assume eight lines connect an area containing
Criterion 4
The fourth criterion involves Elements identified in the most recent Planning Assessment where
relay tripping occurs due to a stable or unstable power swing during a simulated disturbance. The
intent is for the Planning Coordinator to include any Element(s) where relay tripping was
8
http://www.nerc.com/pa/rrm/ea/pages/blackout-august-2003.aspx
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observed during simulations performed for the most recent Planning Assessment associated with
the transmission planning TPL-001-4 Reliability Standard. Note that relay tripping must be
assessed within Planning Assessments per TPL-001-4, R4, Part 4.3.1.3, which indicates that
analysis shall include the “Tripping of Transmission lines and transformers where transient
swings cause Protection System operation based on generic or actual relay models.” Identifying
such Elements according to criterion 4 and notifying the respective Generator Owner and
Transmission Owner will require that the owners of any load-responsive protective relay applied
at the terminals of the identified Element evaluate the relay’s susceptibility to tripping in
response a stable power swing.
Planning Coordinators have discretion to determine whether observed tripping for a power swing
in its Planning Assessments occurs for valid contingencies and system conditions. The Planning
Coordinator will address tripping that is observed in transient analyses on an individual basis;
therefore, the Planning Coordinator is responsible for identifying the Elements based only on
simulation results that are determined to be valid.
Due to the nature of how a Planning Assessment is performed, there may be cases where a
previously identified Element is not identified in the most recent Planning Assessment. If so, this
is acceptable because the Generator Owner and Transmission Owner would have taken action
upon the initial notification of the previously identified Element. When an Element is not
identified in later Planning Assessments, the risk would have already been assessed under
Requirement R4 and mitigated according to Requirements R5 and R6 when appropriate.
According to Requirement R4, the Generator Owner and Transmission Owner are only required
to re-evaluate each load-responsive protective relay for an identified Element where the
evaluation has not been performed in the last three calendar years.
Criterion 5
The fifth criterion involves Elements that have actually tripped due to a stable or unstable power
swing as reported by the Generator Owner and Transmission Owner. The Planning Coordinator
will continue to identify each reported Element until the Planning Coordinator determines that
the Element is expected to not trip in response to power swings due to BES configuration
changes. For example, eight lines interconnecting areas containing both generation and load to
the rest of the BES, and five of the lines terminate on a single straight bus. Assume a as shown in
Figure 1. A forced outage of the straight bus in the past caused an island to form by tripping open
the five lines connecting to the straight bus, and subsequently causing the other three lines into
the area to trip on power swings or excessive loading.. If the BES is reconfigured such that the
five lines into the straight bus are now divided between two different substations, a single
Disturbance that caused the five lines to open is no longer a credible event; therefore, these
Elements should not be identified as meeting the criterion based on this particular event. If any
other event remains credible for the Element, then it would be identified under the criterionthe
Planning Coordinator may determine that the changes eliminated susceptibility to power swings
as shown in Figure 2. If so, the Planning Coordinator is no longer required to identify these
Elements previously reported by either the Transmission Owner pursuant to Requirement R2 or
Generator Owner pursuant to Requirement R3.
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Single Tie-line
Single Tie-line
Area
with generation
and load
Straight Bus
Single Tie-line
Single Tie-line
Single Tie-line
Area
with generation
and load
Straight Bus A
Single Tie-line
Straight Bus B
Figure 1. Criterion five example of an area Figure 2. Criterion five example of an area
with generation and load that experienced a with generation and load that was later
power swing.
reconfigured and determined to no longer be
susceptible to power swings.
Although Requirement R1 requires the Planning Coordinator to notify the respective Generator
Owner and Transmission Owner of any Elements meeting the one or more of the five criteria, it
does not preclude the Planning Coordinator from providing additional information, such as
apparent impedance characteristics, in advance or upon request, that may be useful in evaluating
protective relays. Generator Owners and Transmission Owners are able to complete protective
relay evaluations and perform the required actions without additional information. The standard
does not included any requirement for the entities to provide information that is already being
shared or exchanged between entities for operating needs. While a requirement has not been
included for the exchange of information, entities must recognize that relay performance needs to
be measured against the most current information.
Requirement R2
The approach of Requirement R2 requires the Transmission Owner to identify Elements that
meet the focused criteria. Only the Elements that meet the criteria and apply a load-responsive
protective relay at the terminal of the Element are in scope. Using the criteria focuses the
reliability concern on the Element that is at-risk to power swings.
The first criterion involves Elements that have tripped due to a power swing during an actual
system Disturbance, regardless of whether the power swing was stable or unstable. Elements that
have tripped by unstable power swings are included in this requirement because they were not
identified in Requirement R1 and this forms a basis for evaluating the load responsive relay
operation for stable power swings. After this standard becomes effective, if it is determined in an
outage investigation that an Element tripped because of a power swing condition (either stable or
unstable), this standard will become applicable to the Element. An example of an identified
Element is an Element tripped by a distance relay element (i.e., a relay with a time delay of less
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than 15 cycles) during a power swing condition. Another example that would identify an
Element is where out-of-step (OOS) tripping is applied on the Element, and if a legitimate OOS
trip occurred as expected during a power swing event.
The second criterion involves the formation of an island based on an actual system Disturbance.
While the island may form due to several transmission lines tripping for a combination of
reasons, such as power swings (stable or unstable), faults, or excessive loading, the criterion
requires that all Elements that tripped to form the island be identified as meeting this criterion.
For example, the Disturbance may have been initiated by one line faulting with a second line
being out of service. The outage of those two lines then initiated a swing condition between the
“island” and the rest of the system across the remaining ties causing the remaining ties to open.
A second case might be that the island could have formed by a fault on one of the other ties with
a line out of service with the swing going across the first and second lines mentioned above
resulting in those lines opening due to the swing. Therefore, the inclusion of all the Elements that
formed the boundary of the island are included as Elements to be reported to the Planning
Coordinator.
The owner of the load-responsive protective relay that tripped for either criterion is required to
identify the Element and notify its Planning Coordinator. Notifying the Planning Coordinator of
the Element ensures that the planner is aware of an Element that is susceptible to a power swing
or formed an island. The Planning Coordinator will continue to notify the respective entities of
the identified Element under Requirement R1, Criterion 5 unless the Planning Coordinator
determines the Element is no longer susceptible to power swings.
Requirement R3
The purpose of Requirement R3 is similar to provide alternatives for aRequirement R2, Criterion
1 and requires the Generator Owner or Transmission Owner to demonstrateidentify any Element
that trips due to a power swing condition (stable or unstable) in an actual event. This standard
does not focus on the review of Protection Systems on identified Elements are not because they
are covered by other NERC Reliability Standards. When a review of the Generator Owner’s
Protection System reveals that tripping occurred due to a power swing, it is required to identify
the Element and to notify its Planning Coordinator. Notifying the Planning Coordinator of the
Element ensures that the planner is aware of an Element that was susceptible to tripping in
response to a power swing. The Planning Coordinator will continue to notify entities of the
identified Element under Requirement R1 unless the Planning Coordinator determines the
Element is no longer susceptible to power swings meeting .
Requirement R4
Requirement R4 requires the Generator Owner and Transmission Owner to evaluate its loadresponsive protective relays applied at all of the terminals of an identified Element to ensure that
load-responsive protective relays are expected to not trip in response to stable power swings
during non-Fault conditions. A method is provided within the standard to support consistent
evaluation by Generator Owners and Transmission Owners based on specified conditions. It also
provides alternatives for the Once a Generator Owner or Transmission Owner to obtain
agreement from its Planning Coordinator, Reliability Coordinator, and Transmission Planner that
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an existing or modified Protection System is acceptable when providing security is notified of
Elements pursuant to Requirement R1, or once a Generator Owner or Transmission Owner
identifies an Element pursuant to Requirement R2 or R3, it has 12 full calendar months to
evaluate each Element’s load-responsive protective relays based on the PRC-026-1 – Attachment
B, Criteria A and B if the evaluation hasn’t been performed in the last three calendar years.
Information Common to Both Generation and Transmission Elements
The PRC-026-1 – Attachment A lists the load-responsive protective relays that are subject to this
standard. Generator Owners and Transmission Owners may own load–responsive protective
relays (i.e. distance relays) that directly affect generation or transmission BES Elements and will
require analysis as a result of Elements being identified by Requirements R1, R2 or R3. For
example, distance relays owned by the Transmission Owner may be installed at the high-voltage
side of the generator step-up (GSU) transformer (directional toward the generator) providing
backup to generation protection. Generator Owners may have distance relays applied for back-up
transmission protection or back-up protection for the GSU transformer. The Generator Owner
may have relays installed at the generator terminals or the high-voltage side of the GSU
transformer.
Exclusion of Time Based Load-Responsive Protective Relays
The purpose of the standard is “To ensure that load-responsive protective relays are expected to
not trip in response to stable power swings during non-Fault conditions.” Load-responsive
protective relays with high-speed tripping pose the highest risk of operating during a power
swing. Because of this, high-speed tripping is included in the standard and others (Zone 2 and 3)
with a time a delay of 15 cycles or greater are excluded. The time delay used for the specified
conditionsexclusion on some load-responsive protective relays is recommended based on 1) the
minimum time delay these relays are set in practice, and 2) the maximum expected time that
load-responsive protective relays would compromise dependable tripping be exposed to the
stable swing based on a swing rate.
In order to establish a time delay that strikes a line between a high-risk load-responsive
protective relay and one that has a time delay for faults or unstable power swingstripping, a
sample of swing rates were calculated based on a stable power swing entering and leaving the
impedance characteristic as shown in Table 1. For a relay impedance characteristic that has the
swing entering and leaving beginning at 90 degrees with a termination at 120 before exiting the
zone, calculation of the timer must be greater than the time the stable swing is inside the relay
operate zone.
The first option in Requirement R3 allows the Generator Owner or Transmission Owner to
evaluate Elements identified in Requirements R1 or R2 to determine if load-responsive
protective relays at the terminals of each identified Element are susceptible to tripping in
response to a stable power swing. Specific criteria and system conditions are provided to analyze
the characteristic of the load-responsive protective relays of each Element.
The second option in Requirement R3 allows the Generator Owner or Transmission Owner to
exclude protective relays if they are blocked from tripping by power swing blocking (PSB). If
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PSB is applied, it is expected that the relays were set in consultation with the Transmission
Planner to verify maximum slip rates, so that proper PSB settings can be applied. It is expected
that Elements utilizing PSB relays have been evaluated for susceptibility to tripping in response
to stable power swings, and thus can be excluded.
The third option in Requirement R3 allows the Generator Owner or Transmission Owner to
modify its Protection System to achieve the desired goal of reducing the likelihood of tripping on
a stable power swing. The Generator Owner or Transmission Owner may achieve this goal by
meeting the criterion used in the first option or by applying power swing blocking. Modifications
to the Protection System could include revising settings or logic, or replacing the Protection
System. A Corrective Action Plan (CAP) is employed to allow an entity the flexibility to identify
the actions and timetable to make the necessary adjustments. A CAP allows for outage
scheduling, time for design, procurement, and installation of new relaying or the application of
new settings. The amount of detail regarding the listing of the actions required to make the
necessary changes to the Protection System is left to the discretion and management of the entity.
The fourth option in Requirement R3 allows the Generator Owner or Transmission Owner for
the situation where making the Protection System secure for stable power swings, either through
modified settings or replacement, will either significantly decrease the dependability for tripping
for faults within its zone of protection or for tripping for out-of-step conditions. To ensure the
risks due to tripping for stable power swings are balanced against the risk due to the reduction in
dependability, and that reasonable effort to find viable Protection System modifications has been
made, the applicable Generator Owner and Transmission Owner must obtain agreement from the
Planning Coordinator, Reliability Coordinator, and Transmission Planner that tripping for a
stable power swing is acceptable. The entities may agree that the existing or modified Protection
System design and settings are acceptable. This option allows for cases where the existing
Protection System design and settings are not acceptable, but modifications that do not meet the
criterion in the first option result in an acceptable balance between dependability and security. In
these cases, a CAP is employed to allow an entity the flexibility to identify the actions and
timetable to make the necessary adjustments. A CAP allows for outage scheduling, time for
design, procurement, and installation of new relaying or the application of new settings. The
amount of detail regarding the listing of the actions required to make the necessary changes to
the Protection System is left to the discretion and management of the entity.
Eq. (1)
> 2 ×
(120° −
ℎ
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ℎ
)
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Table 1. Swing Rates
Zone Timer
Slip Rate
(Cycles)
(Hz)
10
1.00
15
0.67
20
0.50
30
0.33
With a minimum zone timer of 15 cycles, the corresponding slip of the system is 0.67 Hz. This
represents an approximation of a slow slip rate during a system Disturbance. This value
corresponds to the typical minimum time delay used for zone 2 distance relays in transmission
line protection. Longer time delays allow for slower slip rates.
Application to Transmission OwnersElements
The criterion describesThe criteria in PRC-026-1 – Attachment B describe a lens characteristic
formed in the impedance (R-X) plane that connects the endpoints of the total system impedance
together by varying the sending and receiving-end system voltages from 0.7 to 1.0 per unit, while
maintaining a constant system separation angle across the total system impedance (with the
parallel transfer impedance removed—see Figures 1 and 23 through 5). The total system
impedance is derived from a two-bus equivalent network and is determined by summing the
sending-end source impedance, the line impedance in parallel with(excluding the
ThévinenThévenin equivalent transfer impedance,), and the receiving-end source impedance
(Figure 3). This as shown in Figures 6 and 7. The goal in establishing the total system source
impedance is minimized to createrepresent a conservative, worst-case condition by including all
transmission Elements that represent a condition that will maximize the security of the relay
against various system conditions. The smallest total system impedance represents a condition
where the size of the lens characteristic in the R-X plane is smallest and is a conservative
operating point from the standpoint of ensuring a load responsive relay will not trip given a
predetermined angular displacement between the sending- and receiving-end voltages. The
smallest total system impedance results when all generation is in service and all transmission
elements are modeled in their “normal” system configuration with generation set at the value
reported to the Transmission Planner. Further, (PRC-026-1 – Attachment B, Criteria A). The
parallel transfer impedance is removed to represent a likely condition where parallel elements
may be lost during the disturbance, and the loss of these elements magnifies the sensitivity of the
load-responsive relays on the parallel line by removing the “infeed effect” (i.e., the apparent
impedance sensed by the relay is decreased as a result of the loss of the transfer impedance, thus
making the relay more likely to trip for a stable power swing).
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The sending- and receiving-end source voltages are varied from 0.7 to 1.0 per unit to form a
portion of a lens characteristic instead of varying the voltages from 0 to 1.0 per unit, which
would form a full-lens characteristic. The ratio of these two voltages is used in the calculation of
the portion of the lens, and result in a ratio range from 0.7 to 1.43.
Eq. (2)
=
0.7
= 0.7
1.0
=
0.85
= 0.739
1.15
Eq. (3):
=
1.0
= 1.43
0.7
=
1.15
= 1.353
0.85
The internal generator voltage during severe power swings or transmission system fault
conditions will be greater than zero, due to voltage regulator support. The voltage ratio of 0.7 to
1.43 is chosen to be more conservative than the PRC-023 and PRC-025 NERC Reliability
Standards, where a lower bound voltage of 0.85 per unit voltage is used. A plus and minus 15%
internal generator voltage range was chosen as a conservative voltage range for calculation of the
voltage ratio that would determine the end points of the portion of the lens. For example, the
voltage ratio using these voltages would result in a ratio range from 0.739 to 1.353.
Eq. (4)
Eq. (5):
The lower ratio is rounded down to 0.7 to be more conservative, allowing a voltage range of 0.7
to 1.0 per unit to be used for the calculation of the lens end points.9
When the parallel transfer impedance is included in the model, the split in current through the
parallel transfer impedance path results in actual measured relay impedances that are larger than
those measured when the parallel transfer impedance is removed (i.e., infeed effect), which
would make it more likely for an impedance relay element to be completely contained within the
applicable portion of the lens characteristic in Figure 11. If the transfer impedance is included in
the lens evaluation, a distance relay element could be deemed as meeting PRC-026-1 –
Attachment B and, in fact would be secure, assuming all elements were in their normal state. In
this case, it could trip for a stable power swing during an actual event if the system was
weakened (i.e., a higher transfer impedance) by the loss of a subset of lines that make up the
parallel transfer impedance. This could happen because those parallel lines tripped on unstable
swings, contained the initiating fault, and/or were lost due to operation of breaker failure or
remote back-up protection schemes in Figure 10.
Either the saturated transient or sub-transient direct axis reactance values may be used for
machines in the evaluation because they are smaller than un-saturated reactance values. Since,
sub-transient saturated generator reactances are used since they are smaller than the transient or
synchronous reactances, and reactance, they result in a smaller source impedance and a smaller
separation anglelens characteristic in the graphical analysis (Figures 4 and 5as shown in Figures
9
Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations,
April 2004, Section 6 (The Cascade Stage of the Blackout), p. 94 under “Why the Generators Tripped Off,” states,
“Some generator undervoltage relays were set to trip at or above 90% voltage. However, a motor stalls out at about
70% voltage and a motor starter contactor drops out around 75%, so if there is a compelling need to protect the
turbine from the system the under-voltage trigger point should be no higher than 80%.”
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8 and 9. Since power swings occur in a time frame where generator transient reactances will be
prevalent, it is acceptable to use saturated transient reactances instead of saturated sub-transient
reactance values. Some short-circuit models may not include transient reactance values, so in this
case, the use of sub-transient is acceptable because it also produces more conservative results
than transient reactances. For this reason, either value is acceptable when determining the system
source impedances (PRC-026-1 – Attachment B, Criteria A and B, No. 3).
Saturated reactance values are also the values used in short-circuit programs that produce the
system impedance mentioned above. Planning and stability software generally use the unsaturated reactance values. Generator models used in transient stability analyses recognize that
the extent of the saturation effect depends upon both rotor (field) and stator currents.
Accordingly, they derive the effective saturated parameters of the machine at each instant by
internal calculation from the specified (constant) unsaturated values of machine reactances and
the instantaneous internal flux level. The specific assumptions regarding which inductances are
affected by saturation, and the relative effect of that saturation, are different for the various
generator models used. Thus, unsaturated values of all machine reactances are used in setting up
planning and stability software data, and the appropriate set of open-circuit magnetization curve
data is provided for each machine.
The source or system equivalent impedances can be obtained by a number of different methods
using commercially available short-circuit calculation tools.10 Most short-circuit tools have a
network reduction feature that allows the user to select the local and remote terminal buses to
retain. The first method reduces the system to one that contains two buses, an equivalent
generator at each bus (representing the source impedance at the sending- and receiving-ends),
and two parallel lines; one being the line impedance of the protected line with relays being
analyzed, the other being the transfer impedance representing all other combinations of lines that
connect the two buses together (in Figure 3).6. Another conservative method is to open both ends
of the line in question, and apply a three-phase bolted fault at each bus. The resulting source
impedance at each end will be less than or equal to the actual source impedance calculated by the
network reduction method. Either method can be used to develop the system source impedances
at both ends.
The first two bullets of criterionPRC-026-1 – Attachment B, Criteria A, No. 1, identify the
system separation angles to be used to identify the shape and size of the power swing stability
boundary to be used to test load-responsive impedance relay elements. Both bullets test
impedance relay elements that are not supervised by power swing blocking. The first bullet of
PRC-026-1 – Attachment B, Criteria A, No. 1 evaluates a system separation angle of at least 120
degrees that is held constant while varying the sending- and receiving-end source voltages from
0.7 to 1.0 per unit, thus creating a power swing stability boundary shaped like a portion of a lens
about the total system impedance in Figure 3. This portion of a lens characteristic is compared to
the tripping portion of the distance relay characteristic, that is, the portion that is not supervised
by load encroachment logic, blinders, or some other form of supervision as shown in Figure 12
10
Demetrios A. Tziouvaras and Daqing Hou, Appendix in Out-Of-Step Protection Fundamentals and
Advancements, by Demetrios A. Tziouvaras and Daqing Hou, available at (April 17, 2014:
https://www.selinc.com)..
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that restricts the distance element from tripping for heavy, balanced load conditions. IfIf the
tripping portion of the impedance characteristics are completely contained within the portion of a
lens characteristic, the Element passes the evaluation (Figures 6 and 7).meets Criteria A in PRC026-1 – Attachment B. A system separation angle of 120 degrees was chosen for the evaluation
where PSB is not applied because it is generally accepted in the industry that recovery for a
swing beyond this angle is unlikely to occur.11
The second bullet of PRC-026-1 – Attachment B, Criteria A, No. 1 evaluates impedance relay
elements at a system separation angle of less than 120 degrees, similar to the first criterion bullet
described above. TheAn angle evaluated mustless than 120 degrees may be agreed upon byused
if a documented stability analysis demonstrates that the Planning Coordinator, Reliability
Coordinator, and Transmission Planner, and tripping of the distance elements for stable power
swings should not occurswing becomes unstable at this angle, as shown bya system planning or
operating studiesseparation angle of less than 120 degrees.
11
“The critical angle for maintaining stability will vary depending on the contingency and the system condition at
the time the contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is
marginal and 120 degrees is generally accepted as an appropriate basis for setting out‐of‐step protection. Given the
importance of separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a
proper balance between dependable tripping for unstable power swings and secure operation for stable power
swings.” NERC System Protection and Control Subcommittee, Protection System Response to Power Swings,
August 2013: http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20
SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdfPSRPS Report at p. 28.), p. 28.
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Figure 1. Graphical output showing the plotted R-X coordinates of the calculated lens
characteristic (orange plot) with a constant angle of 120 degrees and varying source voltages.
The equal EMF (VS = VR, where N = VS / VR = 1) coordinate is shown.Figure 3. The portion
of the lens characteristic that is formed in the impedance (R-X) plane. The pilot zone 2 relay is
completely contained within the portion of the lens (e.g., it does not intersect any portion of
the partial lens), therefore it complies with PRC-026-1 – Attachment B, Criteria A, No. 1.
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Figure 2. Mathematical calculations for4. System impedance as seen by relay R-X coordinate
plot in Figure 1.
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Figure 3. Calculation of total system impedance given sending-end source impedance ZS,
receiving-end source impedance ZR, line impedance ZL, and 5. Lens characteristic with the
transfer impedance ZTRincluded and contains specific points identified for the calculations.
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Table 2. Example Calculation (Lens Point 1)
Figure 4. A strong-source system with a line impedance of ZLine = 16 ohms is shown. This
represents a heavily-loaded system, using a maximum generation profile and using generator
sub-transient reactance. The zone 2 mho circle (set at 125% of ZLine) extends into the power
swing stability boundary (orange lens characteristic). Using the strongest source system is
more conservative because it shrinks the power swing stability boundary, bringing it closer to
the mho circle.This example is for calculating the impedance the first point of the lens
characteristic. Equal source voltages are used for the 230 kV (base) line with the sending
voltage (ES) leading the receiving voltage (ER) by 120 degrees. See Figures 4 and 5.
Eq. (6)
=
∠120°
√3
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Table 2. Example Calculation (Lens Point 1)
=
Eq. (7)
230,000∠120°
√3
= 132,791∠120°
=
=
∠0°
√3
230,000∠0°
√3
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Table 2. Example Calculation (Lens Point 1)
= 132,791∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
Given:
Given:
=
= 2 + 10 Ω
× 10
Ω
= 4 + 20 Ω
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
= 4 + 20 Ω
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Table 2. Example Calculation (Lens Point 1)
Total impedance between generators.
Eq. (8)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
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Table 2. Example Calculation (Lens Point 1)
Total system impedance.
Eq. (9)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
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Table 2. Example Calculation (Lens Point 1)
Total system current from sending source.
Eq. (10)
=
=
−
132,791∠120° − 132,791∠0°
(10 + 50 )Ω
= 4,511∠71.3°
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Table 2. Example Calculation (Lens Point 1)
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (11)
=
×
+
= 4,511∠71.3°
= 4,511∠71.3°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
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Table 2. Example Calculation (Lens Point 1)
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (12)
=
−
×
= 132,791∠120°
= 95,757∠106.1°
− [(2 + 10) Ω × 4,511∠71.3° ]
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Table 2. Example Calculation (Lens Point 1)
The impedance seen by the relay on ZL.
Eq. (13)
=
=
95,757∠106.1°
4,511∠71.3°
= 17.434 + 12.113 Ω
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Table 3. Example Calculation (Lens Point 2)
Figure 5. A weak-source system with a line impedance of ZLine = 16 ohms is shown. This
represents a lightly-loaded system, using a minimum generation profile and/or using generator
transient reactance instead of using generator sub-transient reactance. The zone 2 mho circle
(set at 125% of ZLine) does not extend into the power swing stability boundary (orange lens
characteristic). Using a weaker source system expands the power swing stability boundary
away from the mho circle.This example is for calculating the impedance second point of the
lens characteristic. Unequal source voltages are used for the 230 kV (base) line with the
sending voltage (ES) at 70% of the receiving voltage (ER) and leading the receiving voltage by
120 degrees. See Figures 4 and 5.
Eq. (14)
=
∠120°
√3
× 70%
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Table 3. Example Calculation (Lens Point 2)
=
Eq. (15)
230,000∠120°
√3
= 92,953.7∠120°
=
=
× 0.70
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
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Table 3. Example Calculation (Lens Point 2)
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
Given:
Given:
=
= 2 + 10 Ω
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
Eq. (16)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
Ω
Ω
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Table 3. Example Calculation (Lens Point 2)
= 4 + 20 Ω
Total system impedance.
Eq. (17)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
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Table 3. Example Calculation (Lens Point 2)
Total system current from sending source.
Eq. (18)
=
=
−
92,953.7∠120° − 132,791∠0°
(10 + 50) Ω
= 3,854∠77°
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Table 3. Example Calculation (Lens Point 2)
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (19)
=
×
+
= 3,854∠77°
= 3,854∠77°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
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Table 3. Example Calculation (Lens Point 2)
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (20)
=
−
×
= 92,953∠120°
= 65,271∠99°
− [(2 + 10 )Ω × 3,854∠77° ]
The impedance seen by the relay on ZL.
Eq. (21)
=
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Table 3. Example Calculation (Lens Point 2)
=
65,271∠99°
3,854∠77°
= 15.676 + 6.41 Ω
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Table 4. Example Calculation (Lens Point 3)
Figure 6. The pilot zone 2 element (blue) is completely contained within the power swing
stability boundary (orange). This Element passes the Requirement R3 evaluation.This example
is for calculating the impedance third point of the lens characteristic. Unequal source voltages
are used for the 230 kV (base) line with the receiving voltage (ER) at 70% of the sending
voltage (ES) and the sending voltage leading the receiving voltage by 120 degrees. See Figures
4 and 5.
Eq. (22)
=
=
∠120°
√3
230,000∠120°
√3
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Table 4. Example Calculation (Lens Point 3)
Eq. (23)
= 132,791∠120°
=
=
∠0°
√3
× 70%
230,000∠0°
√3
= 92,953.7∠0°
× 0.70
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
Given:
= 2 + 10 Ω
= 4 + 20 Ω
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= 4 + 20 Ω
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Table 4. Example Calculation (Lens Point 3)
Given:
=
× 10
Ω
Total impedance between generators.
Eq. (24)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
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Table 4. Example Calculation (Lens Point 3)
Total system impedance.
Eq. (25)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Total system current from sending source.
Eq. (26)
=
−
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Table 4. Example Calculation (Lens Point 3)
=
132,791∠120° − 92,953.7∠0°
(10 + 50) Ω
= 3,854∠65.5°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (27)
=
×
+
= 3,854∠65.5°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
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Table 4. Example Calculation (Lens Point 3)
= 3,854∠65.5°
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (28)
=
−(
× )
= 132,791∠120°
= 98,265∠110.6°
− [(2 + 10) Ω × 3,854∠65.5° ]
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Table 4. Example Calculation (Lens Point 3)
The impedance seen by the relay on ZL.
Eq. (29)
=
=
98,265∠110.6°
3,854∠65.5°
= 18.005 + 18.054 Ω
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Table 5. Example Calculation (Lens Point 4)
Figure 7. The tripping portion (not blocked by load encroachment) of the pilot zone 2 element
(blue) is not completely contained within the power swing stability boundary (orange). This
Element does not pass the Requirement R3 evaluation.This example is for calculating the
impedance fourth point of the lens characteristic. Equal source voltages are used for the 230
kV (base) line with the sending voltage (ES) leading the receiving voltage (ER) by 240
degrees. See Figures 4 and 5.
Eq. (30)
=
=
∠240°
√3
230,000∠240°
√3
= 132,791∠240°
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Table 5. Example Calculation (Lens Point 4)
Eq. (31)
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
Given:
Given:
=
= 2 + 10 Ω
× 10
Ω
= 4 + 20 Ω
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= 4 + 20 Ω
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Table 5. Example Calculation (Lens Point 4)
Total impedance between generators.
Eq. (32)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
Total system impedance.
Eq. (33)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
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Table 5. Example Calculation (Lens Point 4)
= 10 + 50 Ω
Total system current from sending source.
Eq. (34)
=
=
−
132,791∠240° − 132,791∠0°
(10 + 50 )Ω
= 4,510∠131.3°
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Table 5. Example Calculation (Lens Point 4)
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (35)
=
×
+
= 4,510∠131.1°
= 4,510∠131.1°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (36)
=
−(
× )
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Table 5. Example Calculation (Lens Point 4)
= 132,791∠240°
− [(2 + 10 ) Ω × 4,510∠131.1° ]
= 95,756∠ − 106.1°
The impedance seen by the relay on ZL.
Eq. (37)
=
=
95,756∠ − 106.1°
4,510∠131.1°
= −11.434 + 17.887 Ω
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Application to Generator Owners
Generators have a variety of load responsive protection relays that protect the generator from
abnormal operation and are subject to incorrect operation caused by stable power swings. They
include protective relays that operate on current or an impedance function. Specific relays are
time overcurrent, voltage controlled/restrained overcurrent, loss of field, and distance relays.
Impedance Type Relays
The
Table 6. Example Calculation (Lens Point 5)
This example is for calculating the impedance fifth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending voltage (ES) at 70% of the
receiving voltage (ER) and leading the receiving voltage by 240 degrees. See Figures 4 and 5.
Eq. (38)
=
=
Eq. (39)
∠240°
√3
× 70%
230,000∠240°
√3
= 92,953.7∠240°
=
=
× 0.70
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
Given:
Given:
=
= 2 + 10 Ω
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
Eq. (40)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
Ω
Ω
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Table 6. Example Calculation (Lens Point 5)
= 4 + 20 Ω
Total system impedance.
=
Eq. (41)
+
+
= (2 + 10 Ω) + (4 + 20 Ω) + (4 + 20 Ω)
= 10 + 50 Ω
Total system current from sending source.
Eq. (42)
=
=
−
92,953.7∠240° − 132,791∠0°
10 + 50 Ω
= 3,854∠125.5°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (43)
=
×
+
= 3,854∠125.5°
= 3,854∠125.5°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (44)
=
−(
× )
= 92,953.7∠240°
− [(2 + 10 ) Ω × 3,854∠125.5° ]
= 65,270.5∠ − 99.4°
The impedance seen by the relay on ZL.
Eq. (45)
=
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Table 6. Example Calculation (Lens Point 5)
=
65,270.5∠ − 99.4°
3,854∠125.5°
= −12.005 + 11.946 Ω
Table 7. Example Calculation (Lens Point 6)
This example is for calculating the impedance sixth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving voltage (ER) at 70% of
the sending voltage (ES) and the sending voltage leading the receiving voltage by 240 degrees.
See Figures 4 and 5.
Eq. (46)
=
=
Eq. (47)
∠240°
√3
230,000∠240°
√3
= 132,791∠240°
=
=
∠0°
√3
× 70%
230,000∠0°
× 0.70
√3
= 92,953.7∠0°
Given positive sequence impedance data (The transfer impedance ZTR is set to infinity).
Given:
Given:
=
= 2 + 10 Ω
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
Eq. (48)
=
(
(
×
+
)
)
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Table 7. Example Calculation (Lens Point 6)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
=
= 4 + 20 Ω
Ω
Ω
Total system impedance.
=
Eq. (49)
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Total system current from sending source.
Eq. (50)
=
=
−
132,791∠240° − 92,953.7∠0°
10 + 50 Ω
= 3,854∠137.1°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (51)
=
×
+
= 3,854∠137.1°
= 3,854∠137.1°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (52)
=
−(
× )
= 132,791∠240°
− [(2 + 10 )Ω × 3,854∠137.1° ]
= 98,265∠ − 110.6°
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Table 7. Example Calculation (Lens Point 6)
The impedance seen by the relay on ZL.
Eq. (53)
=
=
98,265∠ − 110.6°
3,854∠137.1°
= −9.676 + 23.59 Ω
Figure 6. Reduced two bus system with sending-end source impedance ZS, receiving-end source
impedance ZR, line impedance ZL, and transfer impedance ZTR.
Figure 7. Reduced two bus system with sending-end source impedance ZS, receiving-end source
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impedance ZR, line impedance ZL, and transfer impedance ZTR removed.
Figure 8. A strong-source system with a line impedance of ZL = 20.4 ohms (i.e., the thicker
red line). This relay element (i.e., the blue circle) does not meet the PRC-026-1 – Attachment
B, Criteria A because it is not completely contained within the power swing stability boundary
(i.e., the orange lens characteristic).
The figure above represents a heavily loaded system using a maximum generation profile. The
zone 2 mho circle (set at 137% of ZL) extends into the power swing stability boundary (i.e., the
orange partial lens characteristic). Using the strongest source system is more conservative
because it shrinks the power swing stability boundary, bringing it closer to the mho circle. This
figure also graphically represents the effect of a system strengthening over time and this is the
reason for re-evaluation if the relay has not been evaluated in the last three calendar years. Figure
9 below depicts a relay that meets the, PRC-026-1 – Attachment B, Criteria A. Figure 8 depicts
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the same relay with the same setting three years later, where each source has strengthened by
about 10% and now the same zone 2 element does not meet Criteria A.
Figure 9. A weak-source system with a line impedance of ZL = 20.4 ohms (i.e., the thicker red
line). This zone 2 element (i.e., the blue circle) meets the PRC-026-1 – Attachment B, Criteria A
because it is completely contained within the power swing stability boundary (i.e., the orange
lens characteristic).
The figure above represents a lightly loaded system, using a minimum generation profile. The
zone 2 mho circle (set at 137% of ZL) does not extend into the power swing stability boundary
(i.e., the orange lens characteristic). Using a weaker source system expands the power swing
stability boundary away from the mho circle.
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Figure 10. This is an example of a power swing stability boundary (i.e., the orange lens
characteristic) with the transfer impedance removed. This relay zone 2 element (i.e., the blue
circle) does not meet PRC-026-1 – Attachment B, Criteria A because it is not completely
contained within the power swing stability boundary.
Table 8. Example Calculation (Transfer Impedance Removed)
Calculations for the point at 120 degrees with equal source impedances. The total system
current equals the line current. See Figure 10.
Eq. (54)
=
=
∠120°
√3
230,000∠120°
√3
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Table 8. Example Calculation (Transfer Impedance Removed)
Eq. (55)
= 132,791∠120°
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given impedance data.
= 2 + 10 Ω
Given:
Given:
=
× 10
Ω
= 4 + 20 Ω
= 4 + 20 Ω
Total impedance between generators.
=
Eq. (56)
=
(
(
×
+
)
)
(4 + 20) Ω × (4 + 20)
(4 + 20) Ω + (4 + 20)
= 4 + 20 Ω
Ω
Ω
Total system impedance.
Eq. (57)
=
+
+
= (2 + 10) Ω + (4 + 20) Ω + (4 + 20) Ω
= 10 + 50 Ω
Total system current from sending source.
Eq. (58)
=
=
−
132,791∠120° − 132,791∠0°
10 + 50 Ω
= 4,511∠71.3°
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Table 8. Example Calculation (Transfer Impedance Removed)
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (59)
=
×
+
= 4,511∠71.3°
= 4,511∠71.3°
×
(4 + 20) Ω
(4 + 20) Ω + (4 + 20)
Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (60)
=
−
×
= 132,791∠120°
= 95,757∠106.1°
− [(2 + 10 Ω) × 4,511∠71.3° ]
The impedance seen by the relay on ZL.
Eq. (61)
=
=
95,757∠106.1°
4,511∠71.3°
= 17.434 + 12.113 Ω
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Figure 11. This is an example of a power swing stability boundary (i.e., the orange lens
characteristic) with the transfer impedance included. The zone 2 element (i.e., the blue circle)
meets the PRC-026-1 – Attachment B, Criteria A because it is completely contained within the
power swing stability boundary.
In the figure above, the transfer impedance is 5 times the line impedance. The lens characteristic
has expanded out beyond the zone 2 element due to the infeed effect from the parallel current
through the transfer impedance, thus allowing the zone 2 element to meet PRC-026-1 –
Attachment B, Criteria A.
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Table 9. Example Calculation (Transfer Impedance Included)
Calculations for the point at 120 degrees with equal source impedances. The total system
current does not equal the line current. See Figure 11.
Eq. (62)
∠120°
=
√3
230,000∠120°
=
Eq. (63)
√3
= 132,791∠120°
=
=
∠0°
√3
230,000∠0°
√3
= 132,791∠0°
Given impedance data.
= 2 + 10 Ω
Given:
Given:
=
×5
= 4 + 20 Ω
= 4 + 20 Ω
= (4 + 20) Ω × 5
= 20 + 100 Ω
Total impedance between generators.
Eq. (64)
=
=
(
(
×
+
)
)
(4 + 20) Ω × (20 + 100) Ω
(4 + 20) Ω + (20 + 100) Ω
= 3.333 + 16.667 Ω
Total system impedance.
Eq. (65)
=
+
+
= (2 + 10) Ω + (3.333 + 16.667) Ω + (4 + 20) Ω
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Table 9. Example Calculation (Transfer Impedance Included)
= 9.333 + 46.667 Ω
Total system current from sending source.
Eq. (66)
=
=
−
132,791∠120° − 132,791∠0°
9.333 + 46.667 Ω
= 4,832∠71.3°
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (67)
=
×
+
= 4,832∠71.3°
= 4,027.4∠71.3°
×
(20 + 100) Ω
(9.333 + 46.667) Ω + (20 + 100) Ω
The voltage as measured by the relay on ZL is the voltage drop from the sending source
through the sending source impedance.
Eq. (68)
=
−
×
= 132,791∠120°
= 93,417∠104.7°
− [(2 + 10 Ω) × 4,027∠71.3° ]
The impedance seen by the relay on ZL.
Eq. (69)
=
=
93,417∠104.7°
4,027∠71.3°
= 19.366 + 12.767 Ω
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Table 10. Percent Increase of a Lens Due To Parallel Transfer Impedance.
The following demonstrates the percent size increase of the lens characteristic for ZTR in
multiples of ZL with the transfer impedance included.
ZTR in multiples of ZL
Percent increase of lens with equal EMF
sources (Infinite source as reference)
Infinite
N/A
1000
0.05%
100
0.46%
10
4.63%
5
9.27%
2
23.26%
1
46.76%
0.5
94.14%
0.25
189.56%
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Figure 12. The tripping portion not blocked by load encroachment (i.e., the parallel green lines)
of the pilot zone 2 element (i.e., the blue circle) is completely contained within the power swing
stability boundary (i.e., the orange lens characteristic). Therefore, the zone 2 element meets the
PRC-026-1 – Attachment B, Criteria A.
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Figure 13: The infeed diagram shows the impedance in front of the relay R with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes ZL + ZR.
Table 11. Calculations (System Apparent Impedance in the forward direction)
The following equations are provided for calculating the apparent impedance back to the ER
source voltage as seen by relay R. Infeed equations from VS to source ER where ER = 0. See
Figure 13.
Eq. (70)
Eq. (71)
Eq. (72)
Eq. (73)
=
=
=
Eq. (75)
=
Eq. (77)
−
=
Eq. (74)
Eq. (76)
−
=
+
−
×
− [( +
=( ×
=
=0
Since
)×
)+( ×
=
+
Rearranged:
=
×
]
+
)+(
×
×
=
)
+
× 1+
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Table 11. Calculations (System Apparent Impedance in the forward direction)
=
Eq. (78)
Eq. (79)
×
=
+
×
+
=
Eq. (80)
The infeed equations shows the impedance in front of the relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the forward direction becomes ZL + ZR.
=
Eq. (81)
+
× 1+
Figure 14: The infeed diagram shows the impedance behind relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes ZS.
Table 12. Calculations (System Apparent Impedance in the reverse direction)
The following equations are provided for calculating the apparent impedance back to the ES
source voltage as seen by relay R. Infeed equations from VR back to source ES where ES = 0.
See Figure 14.
Eq. (82)
=
−
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Table 12. Calculations (System Apparent Impedance in the reverse direction)
Eq. (83)
Eq. (84)
Eq. (85)
=
=
Eq. (86)
=
Eq. (87)
=
Eq. (88)
Eq. (89)
Eq. (90)
Eq. (91)
Eq. (92)
−
=
+
−
×
− [( +
=( ×
=
=
)×
)+( ×
=
×
=
=0
Since
+
+
Rearranged:
=
×
]
)+(
×
×
=
)
+
× 1+
+
×
+
=
The infeed equations shows the impedance behind relay R with the parallel transfer impedance
included. As the parallel transfer impedance approaches infinity, the impedances seen by the
relay R in the reverse direction becomes ZS.
Eq. (93)
Eq. (94)
=
+
× 1+
=
× 1+
As seen by relay R at the receiving-end of
the line.
Subtract ZL for relay R impedance as seen
at sending-end of the line.
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Figure 15. Out-of-step trip (OST) inner blinder (i.e., the parallel green lines) meets the PRC026-1 – Attachment B, Criteria A because the inner OST blinder initiates tripping either On-TheWay-In or On-The-Way-Out. Since the inner blinder is completely contained within the portion
of the power swing stability boundary (i.e., the orange lens characteristic), the zone 2 element
(i.e., the blue circle) meets the PRC-026-1 – Attachment B, Criteria A.
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Table 13. Example Calculation (Voltage Ratios)
These calculations are based on the loss of synchronism characteristics for the cases of N < 1
and N > 1 as found in the Application of Out-of-Step Blocking and Tripping Relays, GER3180, p. 12, Figure 3.12 The GE illustration shows the formulae used to calculate the radius
and center of the circles that make up the ends of the portion of the lens.
Voltage ratio equations, source impedance equation with infeed formulae applied, and circle
equations.
Given:
Eq. (95)
Eq. (96)
= 0.7
=
=
= 1.0
| | 0.7
=
= 0.7
| | 1.0
| | 1.0
=
= 1.43
| | 0.7
The total system impedance as seen by the relay with infeed formulae applied.
Given:
Given:
Eq. (97)
= 2 + 10 Ω
=
× 10
=
× 1+
= (4 + 20)
Ω
= 4 + 20 Ω
Ω
= 10 + 50 Ω
+
+
= 4 + 20 Ω
× 1+
The calculated coordinates of the lower circle center.
Eq. (98)
=−
× 1+
−
= − (2 + 10) Ω × 1 +
= −11.608 − 58.039 Ω
12
×
1−
(4 + 20) Ω
(4 + 20) Ω
−
0.7 × (10 + 50) Ω
1 − 0.7
http://store.gedigitalenergy.com/faq/Documents/Alps/GER-3180.pdf
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Table 13. Example Calculation (Voltage Ratios)
The calculated radius of the lower circle.
Eq. (99)
=
=
×
1−
0.7 × (10 + 50) Ω
1 − 0.7
= 69.987 Ω
The calculated coordinates of the upper circle center.
Eq. (100)
=
+
× 1+
= − (4 + 20) Ω × 1 +
= 17.608 + 88.039 Ω
+
−1
(4 + 20) Ω
(4 + 20) Ω
+
(10 + 50) Ω
1.43 − 1
The calculated radius of the upper circle.
Eq. (101)
=
=
×
−1
1.43 × (10 + 50) Ω
1.43 − 1
= 69.987 Ω
Application Specific to Criteria B
The PRC-026-1 – Attachment B, Criteria B evaluates overcurrent elements used for tripping.
The same criteria as PRC-026-1 – Attachment B, Criteria A is used except for an additional
criteria (No. 4) that calculates a current magnitude based upon generator terminal voltages of
1.05 per unit. The formula used to calculate the current is as follows:
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Table 14. Example Calculation (Overcurrent)
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps secondary times a CT ratio of 160:1 that equals 8000 amps on the
primary. The following calculation is where VS equals the base line-to-ground sending-end
generator source voltage times 1.05 at an angle of 120 degrees, VR equals the base line-toground receiving-end generator terminal voltage times 1.05 at an angle of 0 degrees, and Zsys
equals the sum of the sending-end, line, and receiving-end source impedances in ohms.
Eq. (102)
∠120°
=
× 1.05
√3
230,000∠120°
=
√3
= 139,430∠120°
× 1.05
Receiving-end generator terminal voltage.
Eq. (103)
=
=
∠0°
√3
× 1.05
230,000∠0°
√3
= 139,430∠0°
× 1.05
The total impedance of the system (Zsys) equals the sum of the sending-end source impedance
(ZS), the impedance of the line (ZL), and receiving-end impedance (ZR) in ohms.
Given:
Eq. (104)
= 3 + 26 Ω
=
+
+
= 1.3 + 8.7 Ω
= 0.3 + 7.3 Ω
= (3 + 26) Ω + (1.3 + 8.7) Ω + (0.3 + 7.3) Ω
= 4.6 + 42 Ω
Total system current from sending source.
Eq. (105)
=
=
(
−
)
(139,430∠120° − 139,430∠0° )
(4.6 + 42) Ω
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Table 14. Example Calculation (Overcurrent)
= 5,715.82∠66.25°
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps-secondary times a CT ratio of 160:1 that equals 8,000 amps-primary.
Here, the phase instantaneous setting of 8,000 amps is greater than the calculated system
current of 5,716 amps, therefore it is compliant with PRC-026-1 – Attachment B, Criteria B.
Application to Generation Elements
As with Transmission Elements, the determination of the apparent impedance seen at the
generator terminalsan Element located at, or near, a generation Facility is complex, especially for
cases where there are multiple generators connectedpower swings due to a high-voltage bus.
There are various quantities that are interdependent as the disturbance progresses through the
time domain whether it is a stable or unstable power swing.quantities. These variances includein
quantities are caused by changes in machine internal voltage, speed governor action, voltage
regulator action, the reaction of other local generators, and the reaction of other interconnected
transmission Elements. A as the event progresses through the time domain. Though transient
stability program issimulations may be used to determine the apparent impedance for best
results, especiallyverifying load-responsive relay settings,13,14 Requirement R4, PRC-026-1 –
Attachment B, Criteria A and B provides a simplified method for relays that are used for
transmission line backup protection. Distance and out-of-step relays that are subjectevaluating
the load-responsive protective relay’s susceptibility to tripping in response to a stable power
swings are connected at generator terminals and/or on the high-voltage side of the generator stepup (GSU) transformer. The loss of field relay(s) is connected at the generator terminalsswing
without requiring stability simulations.
TheIn general, the electrical center will be in the transmission system for cases where the
generator is connected through a weak transmission system (high external system source
impedance). Other cases where the generator is connected through a strong transmission system,
the electrical center willcould be inside the unit connected zone.15 In either case, impedanceloadresponsive protective relays connected at the generator terminals or at the high-voltage side of
the generator step-up (GSU) transformer may be subject to operation in response to
stablechallenged by power swings. Impedance relays used to back-up transmission protection
usually have as determined by the Planning Coordinator in Requirement R1 or a time delay trip
and are coordinated with local transmission line distance relay protection. Out-of-step relaying
subject to a stable power swing may not operate correctly if the settings are not properly applied.
If it is anticipated that the electrical center will be in the unit connected zone or the apparent
13
Donald Reimert, Protective Relaying for Power Generation Systems, Boca Raton, FL, CRC Press, 2006.
14
Prabha Kundar, Power System Stability and Control, EPRI, McGraw Hill, Inc., 1994.
15
Ibid, Kundar.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
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impedance would challenge the relay operation, the Transmission Planner must perform transient
stability studies to validate the existence of a power swing condition that a generator may
experience. The Generator Owner uses the apparent impedance plot in a time domain to verify
correct settingsevent documented by an actual Disturbance in Requirement R2 and R3.
The simplified method used in the Application to Transmission Owners section is also used here
to provide a helpful understanding of a stable power swing on load-responsive protective relays
for those cases where the generator is connected to the transmission system and there are no
infeed effects to be considered. For cases where infeed affects the apparent impedance (multiple
unit connected generators connected to a transmission switchyard), the Generator Owner will
provide the unit and relay data to the Transmission Planner for analysis. The quantities used to
determine the apparent impedance characteristics are the generator unsaturated generator X"d,
GSU impedance, transmission line impedance, and the system equivalent. A voltage range of
0.65 to 1.5 should be considered to cover the delay of internal voltage for generators under
manual or automatic voltage control.
Requirement R4
Load-responsive protective relays such as time over-current, voltage controlled time-overcurrent
or voltage-restrained time-overcurrent relays are excluded from this standard since they are set
based on equipment permissible overload capability. Their operating time is much greater than
15 cycles for the current levels observed during a power swing.
Instantaneous overcurrent and definite-time overcurrent relays with a time delay of less than 15
cycles are included and are required to be evaluated.
The generator loss-of-field protective function is provided by impedance relay(s) connected at
the generator terminals. The settings are applied to protect the generator from a partial or
complete loss of excitation under all generator loading conditions and, at the same time, be
immune to tripping on stable power swings. It is more likely that the relay would operate during
a power swing when the automatic voltage regulator (AVR) is in manual mode rather than when
in automatic mode.16 Figure 16 illustrates in the R-X plot, the loss-of-field relays typically
include up to three zones of protection.
16
John Burdy, Loss-of-excitation Protection for Synchronous Generators GER-3183, General Electric Company.
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Figure 16. An R-X graph of typical impedance settings for loss-of-field relays.
Loss-of-field characteristic 40-1 has a wider impedance characteristic (positive offset) than
characteristic 40-2 or characteristic 40-3 and provides additional generator protection for a
partial loss of field or a loss of field under low load (less than 10% of rated). The tripping logic
of this protection scheme is established by a directional contact, a voltage setpoint, and a time
delay. The voltage and time delay add security to the relay operation for stable power swings.
Characteristic 40-3 is less sensitive to power swings than characteristic 40-2 and is set outside
the generator capability curve in the leading direction. Regardless of the relay impedance setting,
PRC-019 requires that the “in-service limiters operate before Protection Systems to avoid
unnecessary trip” and “in-service Protection System devices are set to isolate or de-energize
equipment in order to limit the extent of damage when operating conditions exceed equipment
capabilities or stability limits.” Time delays for tripping associated with loss-of-field relays17,18
17
Ibid, Burdy.
18
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
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Application Guidelines
have a range from 15 cycles for characteristic 40-2 to 60 cycles for characteristic 40-1 to
minimize tripping during stable power swings. In the standard, 15 cycles establishes a threshold
for applicability; however, it is the responsibility of the Generator Owner to establish settings
that provide security against stable power swings and, at the same time, dependable protection
for the generator.
The simple two-machine system circuit (method also used in Transmission Element section) is
used to analyze the effect of a power swing at a generator facility for load-responsive relays
pursuant to Requirement R4. In this section, the calculation method is used for calculating the
impedance seen by the relay connected at a point in the circuit.19 The electrical quantities used to
determine the apparent impedance plot using this method are generator saturated transient
reactance (X’d), GSU transformer impedance (XGSU), transmission line impedance (ZL), and the
system equivalent (Ze) at the point of interconnection. All impedance values are known to the
Generator Owner except for the system equivalent. The system equivalent is available from the
Transmission Owner. The sending- and receiving-end source voltages are varied from 0.7 to 1.0
per unit to form a portion of a lens characteristic instead of varying the voltages from 0 to 1.0 per
unit which would form a full lens characteristic. The voltage range of 0.7 – 1.0 results in a ratio
range from 0.7 to 1.43.This ratio range is used in determining the portion of the lens. A system
separation angle of 120 degrees is also used in each load-responsive protective relay evaluation.
Below is an example calculation of the apparent impedance locus method based on Figures 18
and 19.20 In this example, the generator is connected to the 345 kV transmission system through
the GSU transformer and has the ratings listed. The load-responsive protective relay
responsibilities below are divided between the Generator Owner and Transmission Owner.
Figure 17. Simple one-line diagram of the
system to be evaluated.
Figure 18. Simple system equivalent
impedance diagram to be evaluated.21
19
Edward Wilson Kimbark, Power System Stability, Volume II: Power Circuit Breakers and Protective Relays,
Published by John Wiley and Sons, 1950.
20
Ibid, Kimbark.
21
Ibid, Kimbark.
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Application Guidelines
Table15. Example Data (Generator)
Input Descriptions
Input Values
Synchronous Generator nameplate (MVA)
940 MVA
Sub-transient reactance (940MVA base – per unit)
Generator rated voltage (Line-to-Line)
Generator step-up (GSU) transformer rating
GSU transformer reactance (880 MVA base)
System Equivalent (100 MVA base)
X"d = 0.3845
20
880
X
Generator Owner Load-Responsive Protective Relays
40-1
= 16.05%
= 0.00723∠86° ohms
Positive Offset Impedance
Offset = 0.294 per unit ohms
Diameter = 0.294 per unit ohms
40-2
Negative Offset Impedance
Offset = 0.22 per unit ohms
Diameter = 2.24 per unit ohms
40-3
Negative Offset Impedance
Offset = 0.22 per unit ohms
Diameter = 1.00 per unit ohms
21-1
50
Diameter = 0.643 per unit ohms
MTA = 85°
I (pickup) = 5.0 per unit
Transmission Owned Load-Responsive Protective Relays
21-2
Diameter = 0.55 per unit ohms
MTA = 85°
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Application Guidelines
Calculations shown for a 120 degree angle and ES/ER = 1. The equation for calculating ZR is:22
(1 −
=
Eq. (106)
)( ∠ ) + ( )(
∠ −
)
×
Where m is the relay location as a function of the total impedance (real number less than 1)
ES and ER is the sending- and receiving-end voltages
Zsys is the total system impedance
ZR is the complex impedance at the relay location and plotted on an R-X diagram
All of the above are constants (940 MVA base) while the angle δ is varied. Table 16 below
contains calculations for a generator using the data listed in Table 15.
Table16. Example Calculations (Generator)
Given:
Eq. (107)
"
= 0.3845 Ω
"
=
+
+
= 0.171 Ω
= 0.06796 Ω
= 0.3845 Ω + 0.171 Ω + 0.06796 Ω
= 0.6239 ∠90° Ω
Eq. (108)
=
Eq. (109)
=
=
Z =
"
=
(1 −
0.3845
= 0.61633
0.6239
)( ∠ ) + ( )(
∠ −
)
×
(1 − 0.61633) × (1∠120°) + (0.61633)(1∠0°)
× (0.6234∠90°) Ω
1∠120° − 1∠0°
0.4244 + 0.3323
× (0.6234∠90°) Ω
−1.5 + 0.866
Z = (0.3112 ∠ − 111.94°) × (0.6234∠90°) Ω
Z = 0.194 ∠ − 21.94° Ω
22
Ibid, Kimbark.
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Application Guidelines
Table16. Example Calculations (Generator)
Z = −0.18 − 0.073 Ω
Table 17 lists the swing impedance values at other angles and at ES/ER = 1, 1.43, and 0.7. The
impedance values are plotted on an R-X graph with the center being at the generator terminals
for use in evaluating impedance relay settings.
Table 17: Sample calculations for a swing impedance chart for varying voltages at the
sending- and receiving-end.
ES/ER=1
ES/ER=1.43
ES/ER=0.7
ZR
ZR
ZR
Angle (δ)
Magnitude
Angle
Magnitude
Angle
Magnitude
Angle
(Degrees)
(PU Ohms)
(Degrees)
(PU Ohms)
(Degrees)
(PU Ohms) (Degrees)
90
0.320
-13.1
0.296
6.3
0.344
-31.5
120
0.194
-21.9
0.173
-0.4
0.227
-40.1
150
0.111
-41.0
0.082
-10.3
0.154
-58.4
210
0.111
-25.9
0.082
190.3
0.154
238.4
240
0.111
221.0
0.173
180.4
0.225
220.1
270
0.320
193.1
0.296
173.7
0.344
211.5
Requirement R4 Generator Examples
Distance Relay Application
Based on PRC-026-1 – Attachment B, Criteria A, the distance relay (21-1) (owned by the
generation entity) characteristic is in the region where a stable power swing would not occur as
shown in Figure 19. There is no further obligation to the owner in this standard for this loadresponsive protective relay.
The distance relay (21-2) (owned by the transmission entity) is connected at the high-voltage
side of the GSU transformer and its impedance characteristic is in the region where a stable
power swing could occur causing the relay to operate. In this example, if the intentional time
delay of this relay is less than 15 cycles, the Transmission Owner is required to create a CAP
(Requirement R5) to meet PRC-026 – Attachment B, Criteria B. Some of the options include, but
are not limited to, changing the relay setting (i.e. impedance reach, angle, time delay), modify
the scheme (i.e. add power swing blocking), or replace the Protection System. Note that the relay
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
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Application Guidelines
may be excluded from this standard if it has an intentional time delay equal to or greater than 15
cycles.
Figure 19. Swing impedance graph for impedance relays at a generating facility.
Loss-of-Field Relay Application
In Figure 20, the R-X diagram shows the loss-of-field relay (40-1 and 40-2) characteristics are in
the region where a stable power swing can cause a relay operation. Protective relay 40-1 would
be excluded if it has an intentional time delay equal to or greater than 15 cycles. Similarly, 40-2
would be excluded if its intentional time delay is equal to or greater than 15 cycles. For example,
if 40-1 has a time delay of 1 second and 40-2 has a time delay of 0.25 seconds, they are excluded
and there is no further obligation to the owner in this standard for these relays. The loss-of-field
relay characteristic 40-3 is outside the region where a stable power swing can cause a relay
operation. In this case, the owner may select high speed tripping on operation of the 40-3
impedance element.
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Application Guidelines
Figure 20: Stable power swing R-X graph for loss-of-field relays.
Instantaneous Overcurrent Relay
In similar fashion to the transmission overcurrent example calculation in Table 14, the
instantaneous overcurrent relay minimum setting is established by PRC-026-1 – Attachment B,
Criteria B. The solution is found by:
Eq. (110)
=
−
sys
As stated in the relay settings in Table 15, the relay is installed on the high-voltage side of the
GSU transformer with a pickup of 5.0 per unit current. The maximum allowable current is
calculated below.
=
=
(1.05∠120° − 1.05∠0°)
0.6234∠90°
1.775∠150°
0.6234∠90° Ω
= 2.84 ∠60°
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
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The phase instantaneous setting of 5.0 per unit amps is greater than the calculated system current
of 2.84 per unit amps; therefore it is compliant with PRC-026-1 – Attachment B, Criteria B.
Requirement R5
This requirement ensures that all actions associated with any Corrective Action Plan (CAP)
developed in the previous requirement is implemented through completion. Having such aare
completed. The requirement allowsalso permits the entity’s work toward making protection
scheme adjustments measurable givenentity to modify a CAP as necessary, while in the
variabilityprocess of fulfilling the timetablespurpose of each CAPthe standard.
To achieve the stated purpose of this standard, which is to ensure that relays doare expected to
not operatetrip in response to stable power swings during non-fault conditions, the responsible
entity is required to implement and complete a CAP that addresses the relays that are at risk of
tripping during a stable power swing for the Fault conditions, the applicable Elements on entity
is required to develop and complete a CAP that reduces the risk of relays tripping during a stable
power swing that may occur on any applicable Element of the BES. Protection System owners
are required in, during the implementation of a CAP, to update it when actionsany action or
timetable change,changes until the CAP is completed. Accomplishing this objective is intended
to reduce the risk of the relays unnecessarily tripping during stable power swings, thereby
improving reliability and reducing risk to the BES.
The following are examples of actions taken to complete CAPs for a relay respondingthat could
be exposed to a stable power swing whereand a setting change was determined to be acceptable
(without diminishing the ability of the relay to protect for faults within its zone of protection).
Example R4aR5a: Actions: Settings were issued on 6/02/20142015 to reduce the zone
32 reach of the KD-10 relayimpedance relay used in the permissive overreaching transfer
trip (POTT) scheme from 30 ohms to 25 ohms so that the relay characteristic is
completely contained within the lens characteristic identified by the criterion. The
settings were applied to the relay on 6/25/20142015. CAP completed on 06/25/20142015.
Example R4bR5b: Actions: Settings were issued on 6/02/20142015 to enable out-ofstep blocking on the SEL-321existing microprocessor-based relay to prevent tripping in
response to stable power swings. The setting changes were applied to the relay on
6/25/20142015. CAP completed on 06/25/20142015.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
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The following is an example of actions taken to complete a CAP for a relay responding to a
stable power swing that required the addition of an out-of-stepelectromechanical power swing
blocking relay.
Example R4cR5c: Actions: A project for the addition of an out-of-stepelectromechanical
power swing blocking relay (KS) to supervise the zone 3 (KD-10)2 impedance relay was
initiated on 6/5/20142015 to prevent tripping in response to stable power swings. The
relay installation was completed on 9/25/20142015. CAP completed on 9/25/20142015.
The following is an example of actions taken to complete a CAP with a timetable that required
updating for the replacement of the relay.
Example R4dR5d: Actions: A project for the replacement of the KD-10impedance
relays at both terminals of line X with GE L90line current differential relays was initiated
on 6/5/20142015 to prevent tripping in response to stable power swings. The completion
of the project was postponed due to line outage rescheduling from 11/15/20142015 to
3/15/20152016. Following the timetable change, the KD-10impedance relay replacement
was completed on 3/18/20152016. CAP completed on 3/18/20152016.
The CAP is complete when all the documented actions to resolve the specific problem (i.e.,
unnecessary tripping during stable power swings) are completed.
Requirement R6
To achieve the stated purpose of this standard, which is to ensure that load-responsive protective
relays are expected to not trip in response to stable power swings during non-Fault conditions,
the applicable entity is required to fully implement any CAP developed pursuant to Requirement
R5 that modifies the Protection System to meet PRC-026-1 – Attachment B, Criteria A and B.
Protection System owners are required in the implementation of a CAP to update it when actions
or timetable change, until all actions are complete. Accomplishing this objective is intended to
reduce the occurrence of Protection System tripping during a stable power swing, thereby
improving reliability and minimizing risk to the BES.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 1: April 252: August 22, 2014)
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Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power
Swings
Requested Approvals
PRC-026-1 – Relay Performance During Stable Power Swings
Requested Retirements
None.
Prerequisite Approvals
None.
General Considerations
There are a number of factors that influence the determination of an implementation period for the
new proposed standard. The following factors may be specific to one or more of the applicable entities
listed below.
1. The effort and resources for all applicable entities to develop or modify internal processes
and/or procedures.
2. The effort and resources for the Planning Coordinator to identify the Element(s) according to
the criterion in Requirement R1.
3. The need for the Generator Owner or Transmission Owner to secure resources (e.g., availability
of consultants, if needed) to evaluate each load-responsive protective relay’s response to a
stable power swing for identified Elements.
4. The period of time for a Generator Owner or Transmission Owner to develop a Corrective
Action Plan to modify its Protection System.1
Applicable Entities
Generator Owner
Planning Coordinator
Transmission Owner
1
The period of time that may be required for a Generator Owner or Transmission Owner to take an Element outage, if
necessary, to modify the Protection System is driven through the Corrective Action Plan (CAP) and is independent of the
standard’s implementation period. The CAP includes its own timetable which is at the discretion of the entity.
Effective Date
Requirements R1-R3, R5, and R6
First day of the first full calendar year that is 12 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 12 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Requirement R4
First day of the first full calendar year that is 36 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 36 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Notifications Prior to the Effective Date of R4
During the implementation of the standard, notifications are likely to occur prior to Requirement R4
becoming effective. Where notification under R1 or identification under Requirement R2 or R3 occurs
prior to the Effective Date of Requirement R4, the 12 month time period in Requirement R4 will begin
from the Effective Date of Requirement R4. Thereafter, entities will follow the 12 month time period in
R4. The intention of the additional time for R4 to become effective is to handle the initial influx of
notifications and identifications.
Justification
The implementation plan is based on the general considerations above and provides sufficient time for
the Generator Owner, Planning Coordinator, and Transmission Owner to begin becoming compliant
with the standard. The Effective date is constructed such that once the standard is adopted or
approved it would become effective in the first whole calendar year after approvals that is 12 months
for Requirements R1-R3, R5, and R6, and 36 months for Requirement R4.
Requirement R1 – The Planning Coordinator will have at least one full calendar year to prepare
itself to identify any Elements that meet the criteria and notify the respective Generator Owner
and Transmission Owner of any identified Elements within the allotted timeframe.
Requirement R2 – The Transmission Owner will have at least one year to prepare itself with
identifying any Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load-responsive protective relays, or any
Element that forms the boundary of an island during an actual system Disturbance due to the
Implementation Plan (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings| August 22, 2014
2
operation of its protective relays. This includes providing the applicable notifications to the
Planning Coordinator within the allotted timeframe.
Requirement R3 – The Generator Owner will have at least one year to prepare itself with
identifying any Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load-responsive protective relays. This includes
providing the applicable notifications to the Planning Coordinator within the allotted
timeframe.
Requirement R4 – The Generator Owner and Transmission Owner will have at least three years
to develop internal processes and procedures for evaluating its load-responsive protective
relays for an identified Element pursuant to Requirements R1, R2, and R3. Also, both entities
are provided an implementation that will allow the entity to conduct initial evaluations of its
load-responsive protective relays for an identified Element during the first 36 calendar months
of approval.
Requirement R5 – The Generator Owner and Transmission Owner will have at least one year to
develop internal processes and procedures for developing a Corrective Action Plan (CAP) for
addressing any Protection System for an identified Element that requires modification to meet
PRC-206-1 – Attachment B, Criteria A and B.
Requirement R6 – The Generator Owner and Transmission Owner will have at least one year to
develop internal processes and procedures for implementing any CAPs developed in
Requirement R5.
Implementation Plan (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings| August 22, 2014
3
Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power
Swings
Requested Approvals
PRC-026-1 – Relay Performance During Stable Power Swings
Requested Retirements
None.
Prerequisite Approvals
None.
General Considerations
There are a number of factors that influence the determination of an implementation period for the
new proposed standard. The following factors may be specific to one or more of the applicable entities
listed below.
1. The effort and resources for all applicable entities to develop or modify internal processes
and/or procedures.
2. The effort and resources for all applicable entitiesthe Planning Coordinator to identify the
Element(s) according to the criterion in the RequirementsRequirement R1.
3. The need for the Generator Owner or Transmission Owner to secure resources (e.g., availability
of consultants, if needed) to evaluate each load-responsive protective relay’s response to a
stable power swing for identified Elements.
4. The need for the Generator Owner or Transmission Owner to obtain agreement from the
Planning Coordinator, Reliability Coordinator, and Transmission Planner where necessary.
5. The amount of work that the Generator Owner or Transmission Owner will need from a
Planning Coordinator or Transmission Planner to perform simulations.
6.4.
The period of time for a Generator Owner or Transmission Owner to take an Element
outage, if necessary, to modify the Protection System is driven through the develop a
Corrective Action Plan (CAP) and is independent of the standard’s implementation period. The
CAP includes to modify its own timetable which is at the discretion of the entity.Protection
System.1
1
The period of time that may be required for a Generator Owner or Transmission Owner to take an Element outage, if
necessary, to modify the Protection System is driven through the Corrective Action Plan (CAP) and is independent of the
standard’s implementation period. The CAP includes its own timetable which is at the discretion of the entity.
Applicable Entities
Generator Owner
Planning Coordinator
Reliability Coordinator
Transmission Owner
Transmission Planner
Effective Date
Requirements R1-R3, R5, and R6
First day of the first full calendar year that is twelve12 months beyondafter the date that thisthe
standard is approved by an applicable regulatory authorities, orgovernmental authority or as otherwise
provided for in those jurisdictionsa jurisdiction where regulatory approval by an applicable
governmental authority is required for a standard to go into effect. Where approval by an applicable
governmental authority is not required, the standard becomesshall become effective on the first day of
the first full calendar year that is twelve12 months beyondafter the date thisthe standard is
approvedadopted by the NERC Board of Trustees, or as otherwise madeprovided for in that
jurisdiction.
Requirement R4
First day of the first full calendar year that is 36 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective pursuanton the
first day of the first full calendar year that is 36 months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Notifications Prior to the laws applicableEffective Date of R4
During the implementation of the standard, notifications are likely to such ERO governmental
authoritiesoccur prior to Requirement R4 becoming effective. Where notification under R1 or
identification under Requirement R2 or R3 occurs prior to the Effective Date of Requirement R4, the 12
month time period in Requirement R4 will begin from the Effective Date of Requirement R4.
Thereafter, entities will follow the 12 month time period in R4. The intention of the additional time for
R4 to become effective is to handle the initial influx of notifications and identifications.
Justification
The implementation plan is based on the general considerations above and provides a minimum of one
full calendar year sufficient time for the Generator Owner, Planning Coordinator, Reliability
Coordinator,and Transmission Owner, and Transmission Planner to begin the annual cycle of becoming
compliant with the standard regardless of the approval timing by the applicable NERC Board of
Implementation Plan (Draft 12: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings| April 25August 22, 2014
2
Trustees or ERO governmental authorities. For example, if. The Effective date is constructed such that
once the standard is adopted or approved on September 1, 2015, the standardit would become
effective on January 1, 2017in the first whole calendar year after approvals that is 12 months for
Requirements R1-R3, R5, and R6, and 36 months for Requirement R4.
Requirement R1 – The Planning Coordinator will have at least one full calendar year to prepare
itself to identify any Elements that meet the criteria and notify the respective Generator Owner
and Transmission Owner of any identified Elements within the allotted timeframe.
Requirement R2 – The Transmission Owner will have at least one year to prepare itself with
identifying any Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load-responsive protective relays, or any
Element that forms the boundary of an island during an actual system Disturbance due to the
operation of its protective relays. This includes providing the applicable notifications to the
Planning Coordinator within the allotted timeframe.
Requirement R3 – The Generator Owner will have at least one year to prepare itself with
identifying any Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load-responsive protective relays. This includes
providing the applicable notifications to the Planning Coordinator within the allotted
timeframe.
Requirement R4 – The Generator Owner and Transmission Owner will have at least three years
to develop internal processes and procedures for evaluating its load-responsive protective
relays for an identified Element pursuant to Requirements R1, R2, and R3. Also, both entities
are provided an implementation that will allow the entity to conduct initial evaluations of its
load-responsive protective relays for an identified Element during the first 36 calendar months
of approval.
Requirement R5 – The Generator Owner and Transmission Owner will have at least one year to
develop internal processes and procedures for developing a Corrective Action Plan (CAP) for
addressing any Protection System for an identified Element that requires modification to meet
PRC-206-1 – Attachment B, Criteria A and B.
Requirement R6 – The Generator Owner and Transmission Owner will have at least one year to
develop internal processes and procedures for implementing any CAPs developed in
Requirement R5.
Implementation Plan (Draft 12: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings| April 25August 22, 2014
3
Unofficial Comment Form
Project 2010-13.3 – Relay Loadability: Stable Power Swings
Please DO NOT use this form for submitting comments. Please use the electronic form electronic form to
submit comments on the Standard. The electronic comment form must be completed by 8:00 p.m. EST
Monday October 6, 2014.
If you have questions please contact Scott Barfield-McGinnis, Standards Developer at
[email protected] or by telephone at 404-446-9689.
http://www.nerc.com/pa/Stand/Pages/Project2010133Phase3ofRelayLoadabilityStablePowerSwings.aspx
Background Information
This posting is soliciting formal comment.
This is Phase 3 of a three-phased standard development that is focused on developing a new Reliability
Standard, PRC-026-1 – Relay Performance During Stable Power Swings, to address protective relay
operations due to stable power swings. The March 18, 2010, FERC Order No. 733, approved Reliability
Standard PRC-023-1 – Transmission Relay Loadability. In this Order, FERC directed NERC to address three
areas of relay loadability that include modifications to the approved PRC-023-1, development of a new
Reliability Standard to address generator protective relay loadability, and a new Reliability Standard to
address the operation of protective relays due to stable power swings. This project’s SAR addresses these
directives with a three-phased approach to standard development.
Phase 1 focused on making the specific modifications to PRC-023-1 and was completed in the approved
Reliability Standard PRC-023-2, which became mandatory on July 1, 2012. Phase 2 focused on developing
a new Reliability Standard, PRC-025-1 – Generator Relay Loadability, to address generator protective relay
loadability; Phase 2 is currently awaiting regulatory approval. This Phase 3 of the project focuses on
developing a new Reliability Standard, PRC-026-1 – Relay Performance During Stable Power Swings, to
address protective relay operations due to stable power swings. This Reliability Standard will establish
requirements aimed at preventing protective relays from tripping unnecessarily due to stable power
swings by requiring the Transmission Owners and Generator Owners to assess the security of protective
relay systems that are susceptible to operation during power swings, and take actions to improve security
for stable power swings where such actions would not compromise dependable operation for faults and
unstable power swings.
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.
Summary of revisions from Draft 1 to Draft 2
Purpose Statement
The standard’s purpose was revised from ensuring “relays do not trip” to “relays are expected to not trip”
… in response to stable power swings during non-Fault conditions.
Applicability
The Reliability Coordinator and Transmission Planner were removed from the standard to address
concerns about overlap and potential gaps when identifying Elements.
Applicability for the Generator Owner and Transmission Owner was augmented to refer to an appended
“Attachment A” which describes load-responsive protective relays that are included in the standard and
associated exclusions.
Requirements
Requirement R1 was revised substantively to remove the Reliability Coordinator and Transmission Planner
functions. The drafting team concurred that having the Planning Coordinator as the single source for
identifying Elements prevents potential duplication of work and a possible gap should an entity believe
another is making the identification and notification. The Requirement now allows a full calendar year to
notify the respective Generator Owner and Transmission Owner of an identified Element. This was done
to eliminate the burden of providing notification each January. The following are changes to each of the
original four criteria and the addition of a fifth criterion.
1. Added “angular” to clarify that this is not referring to other constraints such as voltage. Also
replaced “Special Protection System (SPS)” with “Remedial Action Scheme (RAS)” to comport with
expected changes to these NERC defined terms.
2. Clarified that criterion 2 applies only to “monitored” Elements of a System Operating Limit (SOL).
Also, added “angular” to clarify that this is not referring to other constraints such as voltage.
3. Revised the “islanding” criterion to remove ambiguity about islands that formed during planning
assessments. Islanding is now associated with an Element that forms the boundary of an island
due to angular instability within an underfrequency load shedding (UFLS) assessment. Also, added
“angular” to clarify that this is not referring to other constraints such as voltage.
4. Replaced the term “Disturbance,” because it generally refers to an actual and not simulated event,
with the phrase “simulated disturbance.” The lowercase term “disturbance” was considered to be
consistent with the new TPL-001-4 standard, but it was determined that its usage would continue
Unofficial Comment Form (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings (August 22, 2014)
2
to create questions so “simulated” was added. The phase “stable or unstable” was inserted to
clarify that both are applicable to power swings because the goal of the standard is to identify
Elements susceptible to either.
5. This criterion was added as a mechanism to require the Planning Coordinator to continue
identifying any Element previously reported by a Generator Owner due to a stable or unstable
power swing during an actual system Disturbance or the Transmission Owner due to a stable or
unstable power swing during an actual system Disturbance or islanding event. Reported Elements
will continue to be identified by the Planning Coordinator until the Planning Coordinator
determines the Element is no longer susceptible to power swings.
Requirement R2 was revised to remove the Generator Owner performance because the Generator Owner
does not “island.” Also, the January 1, 2003 date was removed due to industry confusion and concern
about compliance with such a date and how enforcement would be handled should an entity not have
good records. In order to maintain continuity of actual Disturbances and to raise awareness of power
swing and islanding events, the Transmission Owner is required to report the affected Element to its
Planning Coordinator. The only timeframe assigned to the Requirement is following the identification of
the Disturbance which was due to a stable or unstable power swing for reporting to the Planning
Coordinator. There is no requirement to review the Protection System operation as such activities are
addressed by other NERC Reliability Standards.
Requirement R3 is a new requirement created from the previous Requirement R2 specifically for the
Generator Owner. In order to maintain continuity of actual Disturbances and to raise awareness of power
swing events, the Generator Owner is required to report the affected Element to its Planning Coordinator.
The only timeframe assigned to the Requirement is following the identification of the Disturbance which
was due to a stable or unstable power swing for reporting to the Planning Coordinator. There is no
requirement to review the Protection System operation as such activities are addressed by other NERC
Reliability Standards.
Requirement R4 (previously R3) has been rewritten substantially to eliminate multiple and varying
activities such as, demonstrate, develop, and obtain agreement. The Requirement was further simplified
to reference PRC-026-1 – Attachment B which contains the criteria for evaluating load-responsive
protective relays by the Generator Owner and Transmission Owner. The timing for evaluating loadresponsive protective relays, initially, is 12 full calendar month. As identified Elements are reported year
after year, the Generator Owner and Transmission Owner are only required to re-evaluate its loadresponsive protective relays applied on the terminals of the identified Element where the previous
evaluation had not been performed in the last three calendar years. This reduced the burden to the
entities over Draft 1.
Requirement R5 was added to address the requirement for developing a Corrective Action Plan (CAP) that
was contained in the previous Draft 1, Requirement R3.
Requirement R6 was previously R4 and only received comporting updates to references due to numbering
changes.
Unofficial Comment Form (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings (August 22, 2014)
3
PRC-026-1 – Attachment A
The PRC-026-1 – Attachment A was added to the standard due to stakeholder confusion about loadresponsive protective relays and to provide specific exclusions. The attachment is referenced in the
Applicability section of the standard.
PRC-026-1 – Attachment B
The PRC-026-1 – Attachment B was added to the standard to remove the “Criteria” for evaluating loadresponsive protective relays from within Requirement R4 and provide it in a self-contained place for
referencing by Requirement R4. Among other things, the criteria found in the attachment received these
modifications:
1. The sending and receiving voltages were changed to 0.7 to 1.0 from 0 to 1.0 per unit. This
increases the lens characteristic that the impedance characteristic (e.g., zone 2) must be
completely contained within. It was determined that using the 0.7 per unit is not in conflict with
other NERC Reliability Standards or accepted industry practice for setting protective relays.
2. In developing the lens characteristic formed in the impedance (R-X) plane that connects the
endpoints of the total system impedance, the criteria now requires the “parallel transfer
impedance” to be removed.
3. Although previously addressed within the standards’ Application Guidelines, criteria as to whether
the transient or sub-transient may be used are now specified. The criteria are further defined as
the “saturated (transient or sub-transient) reactance. The option to use either transient or subtransient is provided to entities because either will provide a lens characteristic that is sufficiently
conservative to determine the relay’s susceptibility to tripping in response to a stable power
swing. Also, providing this option reduces the burden on entities from changing which value it uses
when it is already using one or the other preset in software applications. Saturated reactances are
specified since they result in lower system impedances. Most notable, the criteria now requires
the “parallel transfer impedance” to be removed when using the criteria to determine the relay’s
susceptibility to tripping in response to a stable power swing.
4. The attachment now includes an additional Criteria B which provides criteria for overcurrentbased protective relays. Like the original criteria for impedance-based relays, it uses the 120
degree system separation angle, all Elements in service, and saturated (transient or sub-transient)
reactance. This criteria also requires the “parallel transfer impedance” to be removed.
You do not have to answer all questions. Enter All Comments in Simple Text Format.
Please note that the official comment form does not retain formatting (even if it appears to transfer
formatting when you copy from the unofficial Word version of the form into the official electronic
Unofficial Comment Form (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings (August 22, 2014)
4
comment form). If you enter extra carriage returns, bullets, automated numbering, symbols, bolding,
italics, or any other formatting, that formatting will not be retained when you submit your comments.
• Separate discrete comments by idea, e.g., preface with (1), (2), etc.
• Use brackets [] to call attention to suggested inserted or deleted text.
• Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
• Do not use formatting such as extra carriage returns, bullets, automated numbering, bolding, or
italics.
• Please do not repeat other entity’s comments. Select the appropriate item to support another
entity’s comments. An opportunity to enter additional or exception comments will be available.
• If supporting other’s comments, be sure the other party submits comments.
Questions
1. Do you agree with the Applicability changes to PRC-026-1 (e.g., removal of the Reliability
Coordinator and Transmission Planner)? If not, please explain why an entity is not appropriate
and/or suggest an alternative that should identify the Elements according to the criteria.
Yes
No
Comments:
2. Do you agree that the revisions to Requirement R1 improved clarity while remaining consistent
with the focused approach of using the Criteria which came from recommendations in the PSRPS
technical document 1 (pg. 21 of 61)? If not, please explain why and provide an alternative, if any.
Yes
No
Comments:
3. The previous Requirement R2 was split into Requirement R2 for the Transmission Owner and
Requirement R3 for the Generator Owner in order to clarify the performance for identifying
Elements that trip. Did this revision improve the understanding of what is required? If not, please
explain why the Requirement(s) need additional clarification.
Yes
No
Comments:
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013, “PSRPS Report,”
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf
1
Unofficial Comment Form (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings (August 22, 2014)
5
4. Requirement R4 (previously R3) contained multiple activities (e.g., demonstrate, develop a
Corrective Action Plan, obtain agreement) and was ambiguous. Do you agree that the revision to
Requirement R4 now provides a clearer understanding of what is required by the Generator
Owner and Transmission Owner for an identified Element? Note: The Criterion is now found in
PRC-026-1 – Attachment B, Criteria A and B. If not, please explain why the Requirement is not
clear.
Yes
No
Comments:
5. The new Requirement R5 (previously R4) and the new Requirement R6 address Corrective Action
Plans (CAP), if any. Do you agree this is an improvement over having the development of the CAP
comingled with other Requirement? If not, please explain.
Yes
No
Comments:
6. Does the “Application Guidelines and Technical Basis” provide sufficient guidance, basis for
approach, and examples to support performance of the requirements? If not, please provide
specific detail that would improve the Guidelines and Technical Basis.
Yes
No
Comments:
7. The Implementation Plan for the proposed standard has been revised, based on comments, to
account for factors such as the initial influx of identified Elements and ongoing burden of entities
to identify Elements and re-evaluate Protection Systems. Does the implementation plan provide
sufficient time for implementing the standard? If not, please provide a justification for changing
the proposed implementation period and for which Requirement.
Yes
No
Comments:
Unofficial Comment Form (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings (August 22, 2014)
6
8. If you have any other comments on PRC-026-1 that have not been stated above, please provide
them here:
Comments:
Unofficial Comment Form (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings (August 22, 2014)
7
Violation Risk Factors and
Violation Severity Level Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
(PRC-026-1 – Relay Performance During Stable Power Swings)
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: PRC-026-1 – Relay
Performance During Stable Power Swings.
Each primary requirement is assigned a VRF and a set of one or more VSLs. 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 ERO
Sanction Guidelines.
The Protection System Response to Power Swings Standard Drafting Team applied the following
NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under
this project.
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric 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 electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
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 electric system, or the
ability to effectively monitor and control the bulk electric 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 electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
The standard drafting team (SDT) also considered consistency with the FERC Violation Risk Factor
Guidelines for setting VRFs:1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors 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: 2
•
•
•
•
•
•
•
•
•
•
•
•
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
Guideline (2) — Consistency within a Reliability Standard
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
2
Id. at footnote 15.
VRF and VSL Justifications (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
2
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk
Factor 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.
NERC Criteria - Violation Severity Levels
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.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets
the full intent of the
requirement.
Moderate
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
High
Severe
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
VRF and VSL Justifications (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
3
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the
following four guidelines for determining whether to approve 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
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: 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.
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 and VSL Justifications (Draft 2: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
4
VRF and VSL Justifications – PRC-026-1, R1
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This Requirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
5
VRF and VSL Justifications – PRC-026-1, R1
The Requirement is consistent with NERC Reliability Standards FAC-014-2, R6 (“…Planning Authority shall
identify the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
The Planning Coordinator
identified an Element and
provided notification in
accordance with Requirement
R1, but was less than or equal
to 30 calendar days late.
Moderate
High
Severe
The Planning Coordinator
identified an Element and
provided notification in
accordance with Requirement
R1, but was more than 30
calendar days and less than or
equal to 60 calendar days late.
The Planning Coordinator
identified an Element and
provided notification in
accordance with Requirement R1,
but was more than 60 calendar
days and less than or equal to 90
calendar days late.
The Planning Coordinator
identified an Element and
provided notification in
accordance with Requirement R1,
but was more than 90 calendar
days late.
OR
The Planning Coordinator failed to
identify an Element in accordance
with Requirement R1.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
6
VRF and VSL Justifications – PRC-026-1, R1
OR
The Planning Coordinator failed to
provide notification in accordance
with Requirement R1.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is Element-driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the Requirement is new.
FERC VSL G2
Violation Severity Level
Assignments 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
Guideline 2a:
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
7
VRF and VSL Justifications – PRC-026-1, R1
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-026-1, R2 and R3
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
8
VRF and VSL Justifications – PRC-026-1, R2 and R3
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This Requirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
9
VRF and VSL Justifications – PRC-026-1, R2 and R3
Proposed VSL
Lower
The Transmission Owner
identified an Element and
provided notification in
accordance with Requirement
R2, but was less than or equal
to 10 calendar days late.
Moderate
High
Severe
The Transmission Owner
identified an Element and
provided notification in
accordance with Requirement
R2, but was more than 10
calendar days and less than or
equal to 20 calendar days late.
The Transmission Owner identified
an Element and provided
notification in accordance with
Requirement R2, but was more
than 20 calendar days and less
than or equal to 30 calendar days
late.
The Transmission Owner identified
an Element and provided
notification in accordance with
Requirement R2, but was more
than 30 calendar days late.
OR
The Transmission Owner failed to
identify an Element in accordance
with Requirement R2.
OR
The Transmission Owner failed to
provide notification in accordance
with Requirement R2.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is Element-driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the Requirement is new.
FERC VSL G2
Guideline 2a:
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
10
VRF and VSL Justifications – PRC-026-1, R2 and R3
Violation Severity Level
Assignments 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
This Requirement is not binary; therefore, this criterion does not apply.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
11
VRF and VSL Justifications – PRC-026-1, R4
Proposed VRF
High
NERC VRF Discussion
A Violation Risk Factor of High is consistent with the NERC VRF Guidelines:
A failure to evaluate that the Protection System is expected to not trip for a stable power swing for an
identified Element could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
If a Protection System is less secure during stable power swings, it increases the risk of tripping should the
Protection System be challenged by a power swing.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance. Identifying Elements prone to power swings and the subsequent mitigation of loadresponsive protective relays applied at the terminals of these Elements will reduce the likelihood of
reoccurrence. This Requirement is consistent with the intent of Recommendation 8: Improve System
Protection to Slow or Limit the Spread of Future Cascading Outages. While the actions associated with
this recommendation did not focus specifically on this issue, the recommendation does note that “power
system protection devices should be set to address the specific condition of concern, such as a fault, outof-step condition, etc., and should not compromise a power system’s inherent physical capability to slow
down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard PRC-023-3, R1 “…Each Transmission Owner,
Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per unit voltage and a
power factor angle of 30 degrees”) which has a VRF of High.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
12
VRF and VSL Justifications – PRC-026-1, R4
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure to ensure the Protection System will not trip in response to a stable power swing for an identified
Element could, under emergency, abnormal, or restorative conditions anticipated by the preparations,
directly cause or contribute to bulk electric system instability, separation, or a cascading sequence of
failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
If a Protection System is less secure during stable power swings, it increases the risk of tripping should the
Protection System be challenged by a power swing.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
The Generator Owner
identified an Element and
provided notification in
accordance with Requirement
R3, but was less than or equal
to 10 calendar days late.
Moderate
High
The Generator Owner
identified an Element and
provided notification in
accordance with Requirement
R3, but was more than 10
calendar days and less than or
equal to 20 calendar days late.
The Generator Owner identified an
Element and provided notification
in accordance with Requirement
R3, but was more than 20 calendar
days and less than or equal to 30
calendar days late.
Severe
The Generator Owner identified
an Element and provided
notification in accordance with
Requirement R3, but was more
than 30 calendar days late.
OR
The Generator Owner failed to
identify an Element in accordance
with Requirement R3.
OR
The Generator Owner failed to
provide notification in accordance
with Requirement R3.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
13
VRF and VSL Justifications – PRC-026-1, R4
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is driven by exception. For example, each
identified Element must be evaluated.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the Requirement is new.
FERC VSL G2
Violation Severity Level
Assignments 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
Guideline 2a:
This Requirement is not binary; therefore, this criterion does not apply.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
14
VRF and VSL Justifications – PRC-026-1, R4
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-004-3, R5
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
Failure to develop a Corrective Action Plan to modify a Protection System of an identified Element that
does not meet the criteria could in the planning time frame, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of
the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric system.
An unmitigated Protection System could affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This Requirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
15
VRF and VSL Justifications – PRC-004-3, R5
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
This Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which requiring corrective actions
or Corrective Action Plans; PRC-016-0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC-003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all three of which have a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for a Protection System of an identified Element could in
the planning time frame, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
16
VRF and VSL Justifications – PRC-004-3, R5
Proposed VSL
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner developed
a CAP in accordance with
Requirement R5, but in more
than 60 calendar days and less
than or equal to 70 calendar
days.
The Generator Owner or
Transmission Owner developed
a CAP in accordance with
Requirement R5, but in more
than 70 calendar days and less
than or equal to 80 calendar
days.
The Generator Owner or
Transmission Owner developed a
CAP in accordance with
Requirement R5, but in more than
80 calendar days and less than or
equal to 90 calendar days.
The Generator Owner or
Transmission Owner developed a
CAP in accordance with
Requirement R5, but in more than
90 calendar days.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to develop the
Corrective Action Plan in a timely fashion and a binary aspect for a complete failure. The VSL is entity sizeneutral because performance is driven by the need to mitigate the Protection System so that it is expected
to not trip on a stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
OR
The Generator Owner or
Transmission Owner failed to
develop a CAP in accordance with
Requirement R5.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
17
VRF and VSL Justifications – PRC-004-3, R5
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
This proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
This proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with this Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
18
VRF and VSL Justifications – PRC-004-3, R5
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-026-1, R6
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for modifying a Protection System of an identified
Element could in the planning time frame, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly and adversely affect the electrical state or capability of the bulk
electric system, or the ability to effectively monitor, control, or restore the bulk electric system.
An unmitigated Protection System could affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This Requirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
19
VRF and VSL Justifications – PRC-026-1, R6
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which requiring corrective actions
or Corrective Action Plans: PRC-016-0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC-003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all of which have a VRF of Medium.
FERC VRF G4 Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for a Protection System of an identified Element could in
the planning time frame, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
The responsible entity
implemented, but failed to
update a CAP, when actions or
Moderate
N/A
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
High
N/A
Severe
The responsible entity failed to
implement a CAP in accordance
with Requirement R4.
20
VRF and VSL Justifications – PRC-026-1, R6
timetables changed, in
accordance with Requirement
R4.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to update the
Corrective Action Plan and a binary aspect for failure to implement. The VSL is entity size-neutral because
performance is driven by the need to mitigate the Protection System so that it is expected to not trip on a
stable power swing.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the Requirement is new.
FERC VSL G2
Violation Severity Level
Assignments 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
Guideline 2a:
This Requirement is not binary; therefore, this criterion does not apply.
FERC VSL G3
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
21
VRF and VSL Justifications – PRC-026-1, R6
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
22
Violation Risk Factors and
Violation Severity Level Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
(PRC-026-1 – Relay Performance During Stable Power Swings)
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: PRC-004-3 — Protection
System Misoperations026-1 – Relay Performance During Stable Power Swings.
Each primary requirement is assigned a VRF and a set of one or more VSLs. 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 ERO
Sanction Guidelines.
The Protection System MisoperationsResponse to Power Swings Standard Drafting Team
applied the following NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the
requirements under this project.
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric 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 electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
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 electric system, or the
ability to effectively monitor and control the bulk electric 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 electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
The standard drafting team (SDT) also considered consistency with the FERC Violation Risk Factor
Guidelines for setting VRFs:1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors 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: 2
•
•
•
•
•
•
•
•
•
•
•
•
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
Guideline (2) — Consistency within a Reliability Standard
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
2
Id. at footnote 15.
VRF and VSL Justifications (Draft 12: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
2
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk
Factor 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.
NERC Criteria - Violation Severity Levels
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.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets
the full intent of the
requirement.
Moderate
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
High
Severe
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
VRF and VSL Justifications (Draft 12: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
3
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the
following four guidelines for determining whether to approve 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
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: 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.
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 and VSL Justifications (Draft 12: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
4
VRF and VSL Justifications – PRC-026-1, R1
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a normal
condition.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area. However, violation of this requirement is unlikely to under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This requirementRequirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
5
VRF and VSL Justifications – PRC-026-1, R1
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirementRequirement has a single reliability activity associated with the reliability objective and
no sub-Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The requirementRequirement is consistent with NERC Reliability Standards FAC-014-2, R6 (“…Planning
Authority shall identify the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a normal
condition.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area. However, violation of this requirement is unlikely to under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirementRequirement does not co-mingle reliability objectives of differing risk; therefore, the
assigned VRF of Medium is consistent.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
6
VRF and VSL Justifications – PRC-026-1, R1
Proposed VSL
Lower
Moderate
High
Severe
The responsible entityPlanning
Coordinator identified an
Element and provided
notification in accordance with
Requirement R1, but was less
than or equal to 30 calendar
days late.
The responsible entityPlanning
Coordinator identified an
Element and provided
notification in accordance with
Requirement R1, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The responsible entityPlanning
Coordinator identified an Element
and provided notification in
accordance with Requirement R1,
but was more than 60 calendar
days and less than or equal to 90
calendar days late.
The responsible entityPlanning
Coordinator identified an Element
and provided notification in
accordance with Requirement R1,
but was more than 90 calendar
days late.
OR
The responsible entityPlanning
Coordinator failed to identify an
Element orin accordance with
Requirement R1.
OR
The Planning Coordinator failed to
provide notification in accordance
with Requirement R1.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is Element-driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
The proposed VSL does not lower the current level of compliance because the requirementRequirement is
new.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
7
VRF and VSL Justifications – PRC-026-1, R1
of Compliance
FERC VSL G2
Violation Severity Level
Assignments 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
Guideline 2a:
This requirementRequirement is not binary; therefore, this criterion does not apply.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the corresponding requirementRequirement,
and is therefore consistent with the requirementRequirement.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
8
VRF and VSL Justifications – PRC-026-1, R2 and R3
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a normal
condition.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area. However, violation of this requirement is unlikely to under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This requirementRequirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
9
VRF and VSL Justifications – PRC-026-1, R2 and R3
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirementRequirement has a single reliability activity associated with the reliability objective and
no sub-Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The requirement is consistent with Reliability Standards FAC-014-2, R6 (“…Planning Authority shall identify
the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load-responsive
protective relay applied at the terminal of the Element. A load-responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a normal
condition.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area. However, violation of this requirement is unlikely to under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirementRequirement does not co-mingle reliability objectives of differing risk; therefore, the
assigned VRF of Medium is consistent.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
10
VRF and VSL Justifications – PRC-026-1, R2 and R3
Proposed VSL
Lower
The responsible
entityTransmission Owner
identified an Element and
provided notification in
accordance with Requirement
R2, but was less than or equal
to 3010 calendar days late.
Moderate
The responsible
entityTransmission Owner
identified an Element and
provided notification in
accordance with Requirement
R2, but was more than 3010
calendar days and less than or
equal to 6020 calendar days
late.
High
Severe
The responsible
entityTransmission Owner
identified an Element and
provided notification in
accordance with Requirement R2,
but was more than 6020 calendar
days and less than or equal to
9030 calendar days late.
The responsible
entityTransmission Owner
identified an Element and
provided notification in
accordance with Requirement R2,
but was more than 9030 calendar
days late.
OR
The responsible
entityTransmission Owner failed
to identify an Element in
accordance with Requirement R2.
OR
The Transmission Owner failed to
provide notification in accordance
with Requirement R2.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is Element-driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
The proposed VSL does not lower the current level of compliance because the requirementRequirement is
new.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
11
VRF and VSL Justifications – PRC-026-1, R2 and R3
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments 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
Guideline 2a:
This requirementRequirement is not binary; therefore, this criterion does not apply.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the corresponding requirementRequirement,
and is therefore consistent with the requirementRequirement.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
12
VRF and VSL Justifications – PRC-026-1, R3R4
Proposed VRF
MediumHigh
NERC VRF Discussion
A Violation Risk Factor of MediumHigh is consistent with the NERC VRF Guidelines:
A failure to ensureevaluate that the Protection System will is expected to not trip in response tofor a
stable power swing for an identified Element could in the planning time frame, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical statecause or capability of the bulk electric system, or the ability to effectively monitor, control,
or restore the bulk electric system. However, violation of a medium risk requirement is unlikely, under
emergency, abnormal, or restoration conditions anticipated by the preparations, to leadcontribute to bulk
electric system instability, separation, or a cascading sequence of failures, nor toor could place the bulk
electric system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
If a Protection System is less secure during stable power swings, it increases the risk of tripping should the
Protection System be challenged by a power swing; However, violation of this requirement is unlikely to
lead to bulk electric system instability, separation, or cascading failures..
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions.. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This requirementRequirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
13
VRF and VSL Justifications – PRC-026-1, R3R4
The requirementRequirement has a single reliability activity associated with the reliability objective and
no sub-Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This requirementThe Requirement is consistent with NERC Reliability Standard FAC-002-1PRC-023-3, R1.3
(“…Evidence that the parties involved in the assessment have coordinated “…Each Transmission Owner,
Generator Owner, and cooperated on…”)Distribution Provider shall evaluate relay loadability at 0.85 per
unit voltage and a power factor angle of 30 degrees”) which has a VRF of MediumHigh.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure to ensure the Protection System will not trip in response to a stable power swing for an identified
Element could in the planning time frame, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly and adversely affect the electrical statecause or capability of the
bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration
conditions anticipated by the preparations, to leadcontribute to bulk electric system instability,
separation, or a cascading sequence of failures, nor toor could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal
condition.
If a Protection System is less secure during stable power swings, it increases the risk of tripping should the
Protection System be challenged by a power swing; However, violation of this requirement is unlikely to
lead to bulk electric system instability, separation, or cascading failures..
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirementRequirement does not co-mingle reliability objectives of differing risk; therefore, the
assigned VRF of Medium is consistent.
Proposed VSL
Lower
The responsible entity
performed one of the
optionsGenerator Owner
Moderate
The responsible entity
performed one of the
optionsGenerator Owner
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
High
The responsible entity performed
one of the optionsGenerator
Owner identified an Element and
Severe
The responsible entity performed
one of the optionsGenerator
Owner identified an Element and
14
VRF and VSL Justifications – PRC-026-1, R3R4
identified an Element and
provided notification in
accordance with Requirement
R3, but was less than or equal
to 3010 calendar days late.
identified an Element and
provided notification in
accordance with Requirement
R3, but was more than 3010
calendar days and less than or
equal to 6020 calendar days
late.
provided notification in
accordance with Requirement R3,
but was more than 6020 calendar
days and less than or equal to
9030 calendar days late.
provided notification in
accordance with Requirement R3,
but was more than 9030 calendar
days late.
OR
The responsible entityGenerator
Owner failed to perform one of
the optionsidentify an Element in
accordance with Requirement R3.
OR
The Generator Owner failed to
provide notification in accordance
with Requirement R3.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is driven by exception. For example, each
identified Element that requires further review must be provided to the Transmission Planner for
simulation to determine the apparent impedance characteristicsevaluated.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the requirementRequirement is
new.
FERC VSL G2
Violation Severity Level
Guideline 2a:
This requirementRequirement is not binary; therefore, this criterion does not apply.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
15
VRF and VSL Justifications – PRC-026-1, R3R4
Assignments 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
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses similar terminology to that used in the corresponding requirementRequirement,
and is therefore consistent with the requirementRequirement.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
16
VRF and VSL Justifications – PRC-026-1, R4004-3, R5
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failureFailure to implement the develop a Corrective Action Plan forto modify a Protection System of an
identified Element that does not meet the criteria could in the planning time frame, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. However, violation of a medium risk requirement is unlikely, under
emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to bulk electric
system instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
An unmitigated Protection System could contribute to affect the severityelectrical state or capability of
future disturbances affecting a wider area, or potential equipment damage. However, violation of this
requirement is unlikely to lead tothe bulk electric system instability, separation, or cascading failuresthe
ability to effectively monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This requirementRequirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
17
VRF and VSL Justifications – PRC-026-1, R4004-3, R5
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirementThis Requirement has a single reliability activity associated with the reliability objective
and no sub-Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The requirementThis Requirement is consistent with the following Reliability Standards which requiring
corrective actions or Corrective Action Plans; PRC-016-0.1, R2 (“…shall take corrective actions to avoid
future Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC003, R5 (“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure
continued vegetation management”) all three of which have a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for a Protection System of an identified Element could in
the planning time frame, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. However, violation of a
medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by
the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage. However, violation of this requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
18
VRF and VSL Justifications – PRC-026-1, R4004-3, R5
Proposed VSL
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner developed
a CAP in accordance with
Requirement R5, but in more
than 60 calendar days and less
than or equal to 70 calendar
days.
The Generator Owner or
Transmission Owner developed
a CAP in accordance with
Requirement R5, but in more
than 70 calendar days and less
than or equal to 80 calendar
days.
The Generator Owner or
Transmission Owner developed a
CAP in accordance with
Requirement R5, but in more than
80 calendar days and less than or
equal to 90 calendar days.
The Generator Owner or
Transmission Owner developed a
CAP in accordance with
Requirement R5, but in more than
90 calendar days.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to develop the
Corrective Action Plan in a timely fashion and a binary aspect for a complete failure. The VSL is entity sizeneutral because performance is driven by the need to mitigate the Protection System so that it is expected
to not trip on a stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
OR
The Generator Owner or
Transmission Owner failed to
develop a CAP in accordance with
Requirement R5.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
19
VRF and VSL Justifications – PRC-026-1, R4004-3, R5
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
This proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
This proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with this Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
20
VRF and VSL Justifications – PRC-026-1, R4004-3, R5
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-026-1, R6
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for modifying a Protection System of an identified
Element could in the planning time frame, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly and adversely affect the electrical state or capability of the bulk
electric system, or the ability to effectively monitor, control, or restore the bulk electric system.
An unmitigated Protection System could affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance; however, protection system operation during stable powers swings could negatively impact
system reliability under different operating conditions. Identifying Elements prone to power swings and
the subsequent mitigation of load-responsive protective relays applied at the terminals of these Elements
will reduce the likelihood of reoccurrence. This Requirement is consistent with the intent of
Recommendation 8: Improve System Protection to Slow or Limit the Spread of Future Cascading Outages.
While the actions associated with this recommendation did not focus specifically on this issue, the
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
21
VRF and VSL Justifications – PRC-026-1, R6
recommendation does note that “power system protection devices should be set to address the specific
condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a power
system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which requiring corrective actions
or Corrective Action Plans: PRC-016-0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC-003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all of which have a VRF of Medium.
FERC VRF G4 Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for a Protection System of an identified Element could in
the planning time frame, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
The responsible entity
implemented, but failed to
update a CAP, when actions or
Moderate
N/A
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
High
N/A
Severe
The responsible entity failed to
implement a CAP in accordance
with Requirement R4.
22
VRF and VSL Justifications – PRC-026-1, R6
timetables changed, in
accordance with Requirement
R4.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardinessfailing to update the
Corrective Action Plan and a binary aspect for failure. to implement. The VSL is entity size-neutral because
performance is driven by exception. For example, each Elementthe need to mitigate the Protection
System so that requires further review must be provided to the Transmission Planner for simulation to
determine the apparent impedance characteristicsit is expected to not trip on a stable power swing.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the requirementRequirement is
new.
FERC VSL G2
Violation Severity Level
Assignments 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
Guideline 2a:
This requirementRequirement is not binary; therefore, this criterion does not apply.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
23
VRF and VSL Justifications – PRC-026-1, R6
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the corresponding requirementRequirement,
and is therefore consistent with the requirementRequirement.
The VSL is based on a single violation and not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 1: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | April 25August 22, 2014
24
Table of Issues and Directives
Project 2010-13.3 – Relay Loadability: Stable Power Swings
Table of Issues and Directives Associated with PRC-026-1
Source
FERC Order
733
1
Issue or Directive Language
(including Para. #)
150. We will not direct the ERO to
modify PRC-023-1 to address stable
power swings. However, because both
NERC and the Task Force have
identified undesirable relay operation
due to stable power swings as a
reliability issue, we direct the ERO to
develop a Reliability Standard that
requires the use of protective relay
systems that can differentiate between
faults and stable power swings and,
when necessary, phases out protective
relay systems that cannot meet this
Section and/or
Requirement(s)
All requirements
Consideration of Issue or Directive
The PRC-026-1 standard is responsive to this
directive because it applies a focused approach for
the Planning Coordinator to identify BES Elements
according to the Requirement R1, Criteria. The
criterion used to identify a BES Element is based on
the NERC System Protection and Control
Subcommittee technical document, Protection
System Response to Power Swings (“PSRPS Report”).1
Specific criterion is based on where power swings
are most likely.
These include (1) Generator(s) where an angular
stability constraint exists which is addressed by an
operating limit or a Remedial Action Scheme (RAS)
NERC System Protection and Control Subcommittee technical document, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
requirement.
We also direct the ERO to file a report
no later than 120 days of this Final Rule
addressing the issue of protective relay
operation due to power swings. The
report should include an action plan
and timeline that explains how and
when the ERO intends to address this
issue through its Reliability Standards
development process.
AND
153. While we recognize that
addressing stable power swings is a
complex issue, we note that more than
six years have passed since the August
2003 blackout and there is still no
Reliability Standard that addresses
relays tripping due to stable power
swings. Additionally, NERC has long
identified undesirable relay operation
due to stable power swings as a
Table of Issues and Directives (Draft 2 | PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
Consideration of Issue or Directive
and those Elements terminating at the transmission
switching station associated with the generator(s);
(2) An Element that is monitored as part of a System
Operating Limit (SOL) that has been established
based on angular stability constraints identified in
system planning or operating studies; (3) An Element
that forms the boundary of an island due to angular
instability within the most recent underfrequency
load shedding (UFLS) assessment; (4) An Element
identified in the most recent Planning Assessment
where relay tripping occurs due to a stable or
unstable power swing during a simulated
disturbance; and (5) An Element reported by the
Generator Owner or Transmission Owner, until the
Planning Coordinator determines the Element is no
longer susceptible to power swings.
Requirement R2 is responsive to the directive by
requiring the Transmission Owner to identify any BES
Elements that trip due to a stable or unstable power
swing during an actual system Disturbance and and
any Element that forms the boundary of an island
during an actual system Disturbance due to the
2
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
reliability issue. Consequently, pursuant
to section 215(d)(5) of the FPA, we find
that undesirable relay operation due to
stable power swings is a specific matter
that the ERO must address to carry out
the goals of section 215, and we direct
the ERO to develop a Reliability
Standard addressing undesirable relay
operation due to stable power swings.
Consideration of Issue or Directive
operation of its load-responsive protective relays.
This insures that any Elements that trip due to actual
system Disturbances are identified, reported to the
Planning Coordinator for awareness, and evaluated
using PRC-026-1 – Attachment B, Criteria A and B.
Requirement R3 is responsive to the directive by
requiring the Generator Owner to identify any BES
Elements that trip due to a stable or unstable power
swing during an actual system Disturbance and due
to the operation of its load-responsive protective
relays. This insures that any Elements that trip due to
actual system Disturbances are identified, reported
to the Planning Coordinator for awareness, and
evaluated using PRC-026-1 – Attachment B, Criteria A
and B.
Requirement R5 requires Generator Owners and
Transmission Owners to evaluate its load-responsive
protective relays that are applied at all of the
terminals of each Element identified by
Requirements R1, R2, and R3. The evalution initially
and periodically according to the Requirement,
ensures that either the load-responsive protectivie
Table of Issues and Directives (Draft 2 | PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
3
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
Consideration of Issue or Directive
relay meets the PRC-026-1 – Attachment B, Criteria A
and B, or that when it is found not to meet the
criteria that the entity develop a Corrective Action
Plan (CAP) in Requirement R5.
Requirement R5 ensures a CAP is developed to
modify the Protection System or apply power swing
blocking so that the Protection System is not
expected to trip in response to a stable power swing.
Requirement R6 requires the entity to implement
each developed CAP to modify its Protection System
to achieve the PRC-026-1 – Attachment B, Criteria A
and B.
Requirement R1, Criterion 3
162. The PSEG Companies also assert
and Requirement R2, Criterion
that the Commission’s approach to
stable power swings should be inclusive 2.
and include “islanding” strategies in
conjunction with out-of-step blocking
or tripping requirements. We agree
with the PSEG Companies and direct
the ERO to consider “islanding”
strategies that achieve the fundamental
Table of Issues and Directives (Draft 2 | PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
Islanding strategies were considered during the
development of the proposed standard. It was
determined that consideration of islanding strategies
does not comport with the purpose and approach of
the proposed standard. The proposed standard’s
purpose is to ensure that load-responsive protective
relays are expected to not trip in response to stable
power swings during non-Fault conditions, not to
determine where the transmission system Elements
4
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
performance for all islands in
developing the new Reliability Standard
addressing stable power swings.
Consideration of Issue or Directive
should form island boundaries.
With respect to considering the islanding concern,
the proposed standard does require that an Element
that was part of a boundary that formed an island
since January 1, 2003 be identified as an that is
within the scope of the proposed standard.
Any identified Element(s) require the Generator
Owner and Transmission Owner entities to
determine whether its load-responsive protective
relays applied at the terminal of such an Element, if
any, are susceptible to tripping in response to a
stable power swing. If so, the Generator Owner and
Transmission Owner is required to take specific
action according to the requirements to reduce the
risk that its load-responsive protective relays would
trip in response to stable power swings during nonFault conditions.
Table of Issues and Directives (Draft 2 | PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | August 22, 2014
5
Standards Announcement Reminder
Project 2010-13.3 Phase 3 of Relay Loadability: Stable
Power Swings
PRC-026-1
Additional Ballot Now Open through October 6, 2014
Now Available
An additional ballot for PRC-026-1 – Relay Performance During Stable Power Swings and nonbinding poll of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) are
open through 8 p.m. Eastern on Monday, October 6, 2014.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
standard and associated VRFs and VSLs by clicking here.
Note: If a member cast a vote in the initial ballot, that vote will not carry over to the additional
ballot. It is the responsibility of the registered voter in the ballot pool to cast a vote again in the
additional ballot. To ensure a quorum is reached, if you do not want to vote affirmative or negative,
please cast an abstention.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider
all comments received during the formal comment period and, if needed, make revisions to the
standard and post it for an additional ballot. If the comments do not show the need for significant
revisions, the standard will proceed to a final ballot.
For information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Scott Barfield-McGinnis
Standards Developer, or at 404-446-9689.
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 2010-13.3 Phase 3 of Relay Loadability: Stable
Power Swings
PRC-026-1
Formal Comment Period Now Open through October 6, 2014
Now Available
A 45-day formal comment period for PRC-026-1 – Relay Performance During Stable Power Swings is
open through 8 p.m. Eastern on Monday, October 6, 2014.
Instructions for Commenting
Please use the electronic form to submit comments on the standard. If you experience any
difficulties in using the electronic form, please contact Arielle Cunningham. An off-line, unofficial
copy of the comment form is posted on the project page.
Next Steps
An additional ballot and non-binding poll of the associated Violation Risk Factor and Violation
Severity Levels will be conducted September 26 through October 6, 2014.
For information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Scott Barfield-McGinnis
Standards Developer, or at 404-446-9689.
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 2010-13.3 Phase 3 of Relay Loadability: Stable
Power Swings
PRC-026-1
Formal Comment Period Now Open through October 6, 2014
Now Available
A 45-day formal comment period for PRC-026-1 – Relay Performance During Stable Power Swings is
open through 8 p.m. Eastern on Monday, October 6, 2014.
Instructions for Commenting
Please use the electronic form to submit comments on the standard. If you experience any
difficulties in using the electronic form, please contact Arielle Cunningham. An off-line, unofficial
copy of the comment form is posted on the project page.
Next Steps
An additional ballot and non-binding poll of the associated Violation Risk Factor and Violation
Severity Levels will be conducted September 26 through October 6, 2014.
For information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Scott Barfield-McGinnis
Standards Developer, or at 404-446-9689.
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 2010-13.3 Phase 3 of Relay Loadability: Stable
Power Swings
PRC-026-1
Additional Ballot and Non-Binding Poll Results
Now Available
An additional ballot for PRC-026-1 – Relay Performance During Stable Power Swings and a non-binding
poll of the associated Violation Risk Factors and Violation Severity Levels concluded at 8 p.m. Eastern on
Monday, October 6, 2014.
The standard achieved a quorum but did not receive sufficient affirmative votes for approval. Voting
statistics are listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Ballot
Non-Binding Poll
Quorum /Approval
Quorum/Supportive Opinions
79.01% / 53.02%
77.71% / 51.71%
Background information for this project can be found on the project page.
Next Steps
The drafting team will consider all comments received during the formal comment period to
determine the next steps.
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Scott Barfield.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC Standards
Newsroom • Site Map • Contact NERC
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Ballot Results
Ballot Name: Project 2010-13.3 Relay Loadability Stable Power Swings PRC-026- 1
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
-Register
Home Page
Ballot Period: 9/26/2014 - 10/6/2014
Ballot Type: Additional
Total # Votes: 286
Total Ballot Pool: 362
Quorum: 79.01 % The Quorum has been reached
Weighted Segment
53.02 %
Vote:
Ballot Results: The Ballot has Closed
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
#
#
No
without a
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
1
2Segment
2
3Segment
3
4Segment
4
5Segment
5
6Segment
6
7Segment
7
8Segment
8
9Segment
104
1
32
0.478
35
0.522
0
6
31
9
0.7
2
0.2
5
0.5
0
0
2
76
1
25
0.41
36
0.59
0
3
12
25
1
8
0.471
9
0.529
0
3
5
79
1
23
0.397
35
0.603
0
5
16
52
1
20
0.455
24
0.545
0
1
7
2
0
0
0
0
0
0
0
2
4
0.4
4
0.4
0
0
0
0
0
2
0.1
1
0.1
0
0
0
0
1
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
NERC Standards
9
10 Segment
10
Totals
9
0.8
8
0.8
0
0
0
1
0
362
7
123
3.711
144
3.289
0
19
76
Individual Ballot Pool Results
Ballot
Segment
Organization
Member
1
Ameren Services
Eric Scott
1
1
1
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Paul B Johnson
Andrew Z Pusztai
Robert Smith
Negative
Associated Electric Cooperative, Inc.
John Bussman
Negative
1
ATCO Electric
Glen Sutton
Negative
1
Austin Energy
James Armke
Negative
1
1
1
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
Affirmative
Affirmative
1
BC Hydro and Power Authority
Patricia Robertson
1
1
1
Black Hills Corp
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
Wes Wingen
Tony Kroskey
John C Fontenot
1
CenterPoint Energy Houston Electric, LLC
John Brockhan
Negative
1
Central Electric Power Cooperative
Michael B Bax
Negative
1
Central Iowa Power Cooperative
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Kevin J Lyons
Affirmative
Chang G Choi
Affirmative
1
City of Tallahassee
Daniel S Langston
Negative
1
Clark Public Utilities
Jack Stamper
Negative
1
1
Colorado Springs Utilities
Consolidated Edison Co. of New York
Shawna Speer
Christopher L de Graffenried Affirmative
1
CPS Energy
Glenn Pressler
1
Dairyland Power Coop.
Robert W. Roddy
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
Abstain
Affirmative
Negative
1
Deseret Power
James Tucker
Negative
1
Dominion Virginia Power
Larry Nash
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
SUPPORTS
THIRD PARTY
COMMENTS (Ameren)
Affirmative
Affirmative
1
1
NERC
Notes
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS -
NERC Standards
1
Duke Energy Carolina
Doug E Hils
1
1
Empire District Electric Co.
Encari
Ralph F Meyer
Steven E Hamburg
1
Entergy Transmission
Oliver A Burke
Negative
1
FirstEnergy Corp.
William J Smith
Affirmative
1
Florida Keys Electric Cooperative Assoc.
Dennis Minton
1
1
1
1
1
1
1
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Muhammed Ali
Martin Boisvert
Molly Devine
1
1
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates
JEA
1
KAMO Electric Cooperative
Walter Kenyon
1
1
Kansas City Power & Light Co.
Keys Energy Services
Daniel Gibson
Stanley T Rzad
1
Michael Moltane
Negative
Negative
(Dominion)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Jim D Cyrulewski
Ted E Hobson
1
Lakeland Electric
Larry E Watt
1
1
Lee County Electric Cooperative
Los Angeles Department of Water & Power
John Chin
faranak sarbaz
1
Lower Colorado River Authority
Martyn Turner
1
1
1
1
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Jo-Anne M Ross
Danny Dees
Terry Harbour
Daniel L Inman
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
1
1
National Grid USA
NB Power Corporation
Michael Jones
Alan MacNaughton
1
Nebraska Public Power District
Jamison Cawley
1
New York Power Authority
Bruce Metruck
1
Northeast Missouri Electric Power
Cooperative
Kevin White
1
Northeast Utilities
William Temple
1
Northern Indiana Public Service Co.
Julaine Dyke
1
1
1
1
1
1
1
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Otter Tail Power Company
Pacific Gas and Electric Company
John Canavan
Scott R Cunningham
Terri Pyle
Doug Peterchuck
Jen Fiegel
Daryl Hanson
Bangalore Vijayraghavan
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Lower
Colorado River
Authority)
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Abstain
Negative
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Joe O'Brien
NIPSCO)
Affirmative
Affirmative
Affirmative
NERC Standards
1
Peak Reliability
Jared Shakespeare
1
Platte River Power Authority
John C. Collins
Negative
1
Portland General Electric Co.
John T Walker
Affirmative
1
Potomac Electric Power Co.
David Thorne
Negative
1
1
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Brenda L Truhe
Laurie Williams
1
Public Service Electric and Gas Co.
Kenneth D. Brown
1
Public Utility District No. 1 of Okanogan
County
Dale Dunckel
1
Puget Sound Energy, Inc.
Denise M Lietz
1
1
1
1
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
SaskPower
John C. Allen
Tim Kelley
Robert Kondziolka
Wayne Guttormson
Negative
Negative
1
Seminole Electric Cooperative, Inc.
Glenn Spurlock
Negative
1
Sho-Me Power Electric Cooperative
Denise Stevens
Negative
1
1
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Long T Duong
Tom Hanzlik
1
South Carolina Public Service Authority
Shawn T Abrams
1
Southern California Edison Company
Steven Mavis
Negative
Southern Company Services, Inc.
Robert A. Schaffeld
Negative
1
1
1
1
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Affirmative
Affirmative
Affirmative
1
Tennessee Valley Authority
Howell D Scott
1
Trans Bay Cable LLC
Tri-State Generation & Transmission
Association, Inc.
Tucson Electric Power Co.
U.S. Bureau of Reclamation
United Illuminating Co.
Vermont Electric Power Company, Inc.
Steven Powell
1
Westar Energy
Allen Klassen
1
1
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Lloyd A Linke
Michelle Clements
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light Paul
Haase's
comment)
SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Corporate
Compliance)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
Affirmative
1
John Tolo
Richard T Jackson
Jonathan Appelbaum
Kim Moulton
SUPPORTS
THIRD PARTY
COMMENTS (Eleanor Ewry,
Puget Sound
Energy)
Affirmative
Affirmative
Affirmative
Pawel Krupa
1
1
1
1
COMMENT
RECEIVED
Abstain
Seattle City Light
Tracy Sliman
COMMENT
RECEIVED
Abstain
Negative
1
1
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
NERC Standards
1
Xcel Energy, Inc.
Gregory L Pieper
Negative
2
BC Hydro
Venkataramakrishnan
Vinnakota
Negative
2
2
California ISO
Electric Reliability Council of Texas, Inc.
Rich Vine
Cheryl Moseley
2
Independent Electricity System Operator
Leonard Kula
Negative
2
ISO New England, Inc.
Matthew F Goldberg
Negative
2
MISO
Marie Knox
Negative
2
2
New York Independent System Operator
PJM Interconnection, L.L.C.
Gregory Campoli
stephanie monzon
Affirmative
2
Southwest Power Pool, Inc.
Charles H. Yeung
Negative
3
AEP
Michael E Deloach
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Amy
Casusceli, Xcel
Energy)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group) (Patricia
Robertson)
Affirmative
3
Alabama Power Company
Robert S Moore
Negative
3
Ameren Corp.
David J Jendras
Negative
3
APS
Sarah Kist
3
Associated Electric Cooperative, Inc.
Todd Bennett
Negative
3
Atlantic City Electric Company
NICOLE BUCKMAN
Negative
3
Avista Corp.
Scott J Kinney
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ISO/RTO
SRC)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
Affirmative
3
BC Hydro and Power Authority
Pat G. Harrington
Negative
3
Central Electric Power Cooperative
Adam M Weber
Negative
3
City of Austin dba Austin Energy
Andrew Gallo
Negative
3
City of Clewiston
Lynne Mila
Negative
3
City of Farmington
Linda R Jacobson
3
City of Green Cove Springs
Mark Schultz
3
City of Redding
Bill Hughes
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Pepco
Holdings Inc.)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Affirmative
SUPPORTS
THIRD PARTY
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
NERC Standards
3
City of Tallahassee
Bill R Fowler
Negative
3
Colorado Springs Utilities
Jean Mueller
Negative
3
3
ComEd
Consolidated Edison Co. of New York
John Bee
Peter T Yost
Affirmative
Affirmative
3
Consumers Energy Company
Gerald G Farringer
3
Cowlitz County PUD
Russell A Noble
Negative
CPS Energy
Jose Escamilla
Negative
3
Delmarva Power & Light Co.
Michael R. Mayer
Negative
3
Dominion Resources, Inc.
Connie B Lowe
Negative
3
DTE Electric
Kent Kujala
Negative
3
3
FirstEnergy Corp.
Florida Keys Electric Cooperative
Cindy E Stewart
Tom B Anthony
3
Florida Municipal Power Agency
Joe McKinney
3
Florida Power & Light Co.
Summer C. Esquerre
3
Florida Power Corporation
Lee Schuster
3
3
3
3
Georgia System Operations Corporation
Great River Energy
Hydro One Networks, Inc.
JEA
Scott McGough
Brian Glover
Ayesha Sabouba
Garry Baker
3
Kansas City Power & Light Co.
Joshua D Bach
Negative
3
Lakeland Electric
Mace D Hunter
Negative
3
Lee County Electric Cooperative
David A Hadzima
3
Lincoln Electric System
Jason Fortik
3
Los Angeles Department of Water & Power
Mike Anctil
Negative
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Charles A. Freibert
Negative
3
3
3
3
3
3
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Greg C. Parent
Roger Brand
Thomas C. Mielnik
Jack W Savage
John S Bos
Brian E Shanahan
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
Negative
Louisville Gas and Electric Co.
Tony Eddleman
SUPPORTS
THIRD PARTY
COMMENTS (Glenn
Pressler's
comments
submitted on
behalf of CPS
Energy)
SUPPORTS
THIRD PARTY
COMMENTS (Pepco
Holdings Inc.)
SUPPORTS
THIRD PARTY
COMMENTS (Dominion's)
COMMENT
RECEIVED
Affirmative
Affirmative
3
Nebraska Public Power District
COMMENT
RECEIVED
Affirmative
3
3
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Kaleb
Brimhall, CSU)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (I support
comments by
Nebraska
NERC Standards
Public Power
District and
Southwest
Power Pool.)
3
New York Power Authority
David R Rivera
Affirmative
3
Northern Indiana Public Service Co.
Ramon J Barany
Negative
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
3
Ocala Utility Services
Randy Hahn
Negative
3
3
3
3
3
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Donald Hargrove
Blaine R. Dinwiddie
Ballard K Mutters
Thomas T Lyons
John H Hagen
3
Platte River Power Authority
Terry L Baker
3
3
PNM Resources
Portland General Electric Co.
Michael Mertz
Thomas G Ward
Affirmative
Affirmative
Affirmative
Negative
Potomac Electric Power Co.
Mark Yerger
Negative
3
Public Service Electric and Gas Co.
Jeffrey Mueller
Negative
3
Puget Sound Energy, Inc.
Mariah R Kennedy
Negative
3
3
Sacramento Municipal Utility District
Salt River Project
James Leigh-Kendall
John T. Underhill
3
Santee Cooper
James M Poston
Negative
3
Seattle City Light
Dana Wheelock
Negative
3
Seminole Electric Cooperative, Inc.
James R Frauen
Negative
3
Sho-Me Power Electric Cooperative
Jeff L Neas
Negative
3
3
3
3
3
3
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Tacoma Power
Tampa Electric Co.
Tennessee Valley Authority
Tri-State Generation & Transmission
Association, Inc.
Mark Oens
Hubert C Young
Lujuanna Medina
Marc Donaldson
Ronald L. Donahey
Ian S Grant
Affirmative
Affirmative
Janelle Marriott
Affirmative
3
Westar Energy
Bo Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Abstain
Affirmative
3
3
SUPPORTS
THIRD PARTY
COMMENTS (See Joe
O'Brien's
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (Pepco
Holdings Inc.)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
COMMENT
RECEIVED
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light Paul
Haase's
comment)
SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
NERC Standards
3
Xcel Energy, Inc.
Michael Ibold
4
4
Alliant Energy Corp. Services, Inc.
Blue Ridge Power Agency
Kenneth Goldsmith
Duane S Dahlquist
4
City of Austin dba Austin Energy
Reza Ebrahimian
4
City of Redding
Nicholas Zettel
Negative
Affirmative
Negative
City Utilities of Springfield, Missouri
John Allen
Negative
4
Consumers Energy Company
Tracy Goble
Negative
4
Cowlitz County PUD
Rick Syring
Affirmative
4
DTE Electric
Daniel Herring
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
4
4
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
Indiana Municipal Power Agency
Jack Alvey
4
4
4
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
4
Oklahoma Municipal Power Authority
Ashley Stringer
4
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Mark Ringhausen
4
4
Negative
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southwest
Power Pool)
John D Martinsen
Mike Ramirez
Affirmative
Seattle City Light
Hao Li
Negative
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
Negative
4
4
4
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Steve McElhaney
Keith Morisette
Brian Evans-Mongeon
Amerenue
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Review Group)
SUPPORTS
THIRD PARTY
COMMENTS (Kurt
LaFrance)
Affirmative
Affirmative
Abstain
4
5
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
Affirmative
4
4
Standards
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Xcel Energy)
Sam Dwyer
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light Paul
Haase's
comment)
SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative
Comments
submitted by
Maryclaire
Yatsko.)
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS -
NERC Standards
(Ameren's
comments)
5
5
American Electric Power
Arizona Public Service Co.
Thomas Foltz
Scott Takinen
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
Negative
5
BC Hydro and Power Authority
Clement Ma
Negative
5
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
5
Bonneville Power Administration
Francis J. Halpin
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
City and County of San Francisco
Daniel Mason
5
City of Austin dba Austin Energy
Jeanie Doty
5
City of Redding
Paul A. Cummings
5
City of Tallahassee
Karen Webb
5
City Water, Light & Power of Springfield
Steve Rose
5
Cleco Power
Stephanie Huffman
5
Cogentrix Energy Power Management, LLC
Mike D Hirst
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (SCL
comments)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See PSEG
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
5
Colorado Springs Utilities
Kaleb Brimhall
Negative
5
Con Edison Company of New York
Brian O'Boyle
Affirmative
5
Consumers Energy Company
David C Greyerbiehl
Negative
5
5
Cowlitz County PUD
Dairyland Power Coop.
Bob Essex
Tommy Drea
Affirmative
5
Dominion Resources, Inc.
Mike Garton
Negative
5
DTE Electric
Mark Stefaniak
Negative
5
Duke Energy
Dale Q Goodwine
Negative
5
Dynegy Inc.
Dan Roethemeyer
Negative
5
E.ON Climate & Renewables North America,
LLC
Dana Showalter
SUPPORTS
THIRD PARTY
COMMENTS (Kurt
LaFrance)
SUPPORTS
THIRD PARTY
COMMENTS (Dominion)
SUPPORTS
THIRD PARTY
COMMENTS (DTE Electric)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
NERC Standards
5
Entergy Services, Inc.
Tracey Stubbs
5
5
5
Exelon Nuclear
First Wind
FirstEnergy Solutions
Mark F Draper
John Robertson
Kenneth Dresner
Affirmative
5
Florida Municipal Power Agency
David Schumann
Negative
5
5
5
5
Great River Energy
Hydro-Québec Production
Ingleside Cogeneration LP
JEA
Preston L Walsh
Roger Dufresne
Michelle R DAntuono
John J Babik
5
Kansas City Power & Light Co.
Brett Holland
Negative
5
Kissimmee Utility Authority
Mike Blough
Negative
5
Lakeland Electric
James M Howard
Negative
5
Liberty Electric Power LLC
Daniel Duff
5
Lincoln Electric System
Dennis Florom
5
Los Angeles Department of Water & Power
Kenneth Silver
5
Lower Colorado River Authority
Dixie Wells
Negative
5
Luminant Generation Company LLC
Rick Terrill
Negative
5
Chris Mazur
5
5
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Muscatine Power & Water
5
Nebraska Public Power District
Don Schmit
5
5
5
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
5
Negative
Affirmative
Negative
David Gordon
Abstain
Steven Grego
Mike Avesing
Affirmative
Affirmative
Negative
Negative
5
5
5
5
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
Pacific Gas and Electric Company
Bernard Johnson
Henry L Staples
Mahmood Z. Safi
Alex Chua
Affirmative
5
Platte River Power Authority
Christopher R Wood
5
Portland General Electric Co.
Matt E. Jastram
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
comments
submitted by
Alshare
Hughes)
SUPPORTS
THIRD PARTY
COMMENTS (NPPD)
Affirmative
Affirmative
Affirmative
Michael D Melvin
Annette M Bannon
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power Agency)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Muncipal
Power Agency)
Affirmative
Northern Indiana Public Service Co.
PPL Generation LLC
COMMENT
RECEIVED
Affirmative
Affirmative
Abstain
5
5
THIRD PARTY
COMMENTS (Entergy
Transmission)
SUPPORTS
THIRD PARTY
COMMENTS (See Joe
O'Brien
NIPSCO
comments.)
Affirmative
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
NERC Standards
5
PSEG Fossil LLC
Tim Kucey
Negative
5
Public Utility District No. 1 of Lewis County
Steven Grega
Negative
5
Public Utility District No. 2 of Grant County,
Washington
Michiko Sell
Abstain
5
Puget Sound Energy, Inc.
Lynda Kupfer
5
5
Sacramento Municipal Utility District
Salt River Project
Susan Gill-Zobitz
William Alkema
5
Santee Cooper
Lewis P Pierce
Negative
5
Seattle City Light
Michael J. Haynes
Negative
5
5
5
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Sam Nietfeld
Edward Magic
Denise Yaffe
Negative
William D Shultz
Negative
5
5
5
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Chris Mattson
RJames Rocha
Scott M. Helyer
Affirmative
Abstain
5
Tennessee Valley Authority
David Thompson
Negative
5
5
Tri-State Generation & Transmission
Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
5
Westar Energy
Bryan Taggart
Negative
5
Xcel Energy, Inc.
Mark A Castagneri
Negative
6
AEP Marketing
Edward P. Cox
6
Ameren Missouri
Robert Quinlivan
Negative
6
APS
Randy A. Young
Affirmative
6
Associated Electric Cooperative, Inc.
Brian Ackermann
6
Bonneville Power Administration
Brenda S. Anderson
City of Austin dba Austin Energy
Lisa Martin
6
City of Redding
Marvin Briggs
Cleco Power LLC
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
Affirmative
Melissa Kurtz
Erika Doot
6
6
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Haase,
Seattle)
Affirmative
Southern Company Generation
Mark Stein
SUPPORTS
THIRD PARTY
COMMENTS (Ewry,
Eleanor)
Affirmative
Affirmative
5
5
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG (John
Seelke))
SUPPORTS
THIRD PARTY
COMMENTS (PSEG
comments)
Robert Hirchak
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
SUPPORTS
THIRD PARTY
COMMENTS (SPP's)
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Ameren)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See PSEG
comments)
SUPPORTS
THIRD PARTY
NERC Standards
6
Colorado Springs Utilities
Shannon Fair
Negative
6
6
Con Edison Company of New York
Constellation Energy Commodities Group
David Balban
David J Carlson
6
Dominion Resources, Inc.
Louis S. Slade
Negative
6
Duke Energy
Greg Cecil
Negative
6
FirstEnergy Solutions
Kevin Querry
6
Florida Municipal Power Agency
Richard L. Montgomery
6
6
6
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
Negative
6
Lakeland Electric
Paul Shipps
Negative
6
Lincoln Electric System
Eric Ruskamp
Negative
6
Lower Colorado River Authority
Michael Shaw
Negative
6
Luminant Energy
Brenda Hampton
Negative
6
6
6
Manitoba Hydro
Modesto Irrigation District
New York Power Authority
Blair Mukanik
James McFall
Shivaz Chopra
Affirmative
Affirmative
Affirmative
6
Northern Indiana Public Service Co.
Joseph O'Brien
Negative
6
6
6
6
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
PacifiCorp
Donna Johnson
Jerry Nottnagel
Douglas Collins
Sandra L Shaffer
Affirmative
6
Platte River Power Authority
Carol Ballantine
Negative
6
6
6
Portland General Electric Co.
Power Generation Services, Inc.
Powerex Corp.
Shawn P Davis
Stephen C Knapp
Gordon Dobson-Mack
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Dominion)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Dixie Wells)
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
COMMENT
RECEIVED
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Affirmative
6
PPL EnergyPlus LLC
Elizabeth Davis
Negative
6
PSEG Energy Resources & Trade LLC
Peter Dolan
Negative
6
6
6
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Hugh A. Owen
Diane Enderby
William Abraham
6
Santee Cooper
Michael Brown
Negative
6
Seattle City Light
Dennis Sismaet
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
COMMENTS (Colorado
Springs
Utilities)
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
Abstain
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS -
NERC Standards
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
6
6
Snohomish County PUD No. 1
Southern California Edison Company
Kenn Backholm
Joseph T Marone
Affirmative
Southern Company Generation and Energy
Marketing
John J. Ciza
6
6
Tacoma Public Utilities
Tampa Electric Co.
Michael C Hill
Benjamin F Smith II
Affirmative
6
Tennessee Valley Authority
Marjorie S. Parsons
Negative
6
Westar Energy
Grant L Wilkerson
Negative
6
Western Area Power Administration - UGP
Marketing
Peter H Kinney
6
Xcel Energy, Inc.
Peter Colussy
7
7
8
8
8
8
Occidental Chemical
Siemens Energy, Inc.
Massachusetts Attorney General
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
New York State Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Venona Greaff
Frank R. McElvain
David L Kiguel
Roger C Zaklukiewicz
Frederick R Plett
Terry Volkmann
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Diane J Barney
Linda C Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Bob Reynolds
Karin Schweitzer
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
9
10
10
10
10
10
10
10
10
10
Negative
6
9
(Paul Haase)
SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative's
Corporate
Compliance
department)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
COMMENT
RECEIVED
Negative
Legal and Privacy : 404.446.2560 voice : 404.467.0474 fax : 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2014 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=85905f2b-d42d-4e87-b0d9-2e08634baeab[10/8/2014 2:46:15 PM]
Non-Binding Poll Results
Project 2010-13.3 Phase 3 of Relay Loadability: Stable
Power Swings
PRC-026-1
Non-Binding Poll Results
Non-Binding Poll
Project 2010-13.3 Relay Loadability Stable Power Swings PRC-026-1
Name:
Poll Period: 9/26/2014 - 10/6/2014
Total # Opinions: 258
Total Ballot Pool: 332
77.71% of those who registered to participate provided an opinion or an
Summaray Results: abstention; 51.71% of those who provided an opinion indicated support for
the VRFs and VSLs.
Individual Ballot Pool Results
Segment
Organization
Member
1
1
Ameren Services
American Electric Power
Eric Scott
Paul B Johnson
1
Arizona Public Service Co.
Robert Smith
Opinions
NERC
Notes
Abstain
Abstain
1
Associated Electric Cooperative, Inc.
John Bussman
Negative
1
ATCO Electric
Glen Sutton
Negative
1
Austin Energy
James Armke
Negative
1
Avista Utilities
Heather Rosentrater
1
1
Balancing Authority of Northern California Kevin Smith
BC Hydro and Power Authority
Patricia Robertson
Affirmative
Abstain
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
1
Brazos Electric Power Cooperative, Inc.
1
1
Bryan Texas Utilities
John C Fontenot
CenterPoint Energy Houston Electric, LLC John Brockhan
Tony Kroskey
1
Central Electric Power Cooperative
Michael B Bax
Negative
1
Central Iowa Power Cooperative
Kevin J Lyons
Negative
1
City of Tacoma, Department of Public
Chang G Choi
Utilities, Light Division, dba Tacoma Power
Affirmative
Abstain
Affirmative
1
City of Tallahassee
Daniel S Langston
Negative
1
Clark Public Utilities
Jack Stamper
Negative
1
Colorado Springs Utilities
Shawna Speer
1
Consolidated Edison Co. of New York
Christopher L de
Graffenried
1
CPS Energy
Glenn Pressler
1
Dairyland Power Coop.
Robert W. Roddy
1
Deseret Power
James Tucker
1
Dominion Virginia Power
Larry Nash
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Affirmative
Negative
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)
Oliver A Burke
Negative
COMMENT
RECEIVED
William J Smith
Affirmative
1
Duke Energy Carolina
Doug E Hils
1
Empire District Electric Co.
Ralph F Meyer
1
Encari
Steven E Hamburg
1
Entergy Transmission
1
FirstEnergy Corp.
1
Florida Keys Electric Cooperative Assoc.
Dennis Minton
1
Florida Power & Light Co.
Mike O'Neil
1
Gainesville Regional Utilities
Richard Bachmeier
1
1
Georgia Transmission Corporation
Great River Energy
Jason Snodgrass
Gordon Pietsch
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Affirmative
Affirmative
2
1
1
1
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
Muhammed Ali
Martin Boisvert
Molly Devine
1
JDRJC Associates
Jim D Cyrulewski
1
JEA
Ted E Hobson
1
Michael Moltane
1
KAMO Electric Cooperative
Walter Kenyon
1
Kansas City Power & Light Co.
Daniel Gibson
1
Lakeland Electric
Larry E Watt
1
Lee County Electric Cooperative
John Chin
1
Los Angeles Department of Water & Power faranak sarbaz
1
Lower Colorado River Authority
Martyn Turner
1
1
Manitoba Hydro
MEAG Power
Jo-Anne M Ross
Danny Dees
1
MidAmerican Energy Co.
Terry Harbour
1
Minnkota Power Coop. Inc.
Daniel L Inman
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
1
1
1
1
National Grid USA
NB Power Corporation
Nebraska Public Power District
New York Power Authority
Michael Jones
Alan MacNaughton
Jamison Cawley
Bruce Metruck
1
Northeast Missouri Electric Power
Cooperative
Kevin White
1
Northeast Utilities
William Temple
1
Northern Indiana Public Service Co.
Julaine Dyke
1
NorthWestern Energy
John Canavan
1
Ohio Valley Electric Corp.
Scott R Cunningham
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Lower
Colorado
River
Authority)
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Abstain
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Joe O'Brien
NIPSCO)
Abstain
3
1
Oklahoma Gas and Electric Co.
Terri Pyle
1
1
Omaha Public Power District
Oncor Electric Delivery
Doug Peterchuck
Jen Fiegel
1
Otter Tail Power Company
Daryl Hanson
1
Pacific Gas and Electric Company
Bangalore Vijayraghavan
1
Peak Reliability
Jared Shakespeare
1
1
Platte River Power Authority
Portland General Electric Co.
John C. Collins
John T Walker
1
PPL Electric Utilities Corp.
Brenda L Truhe
1
1
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Laurie Williams
Kenneth D. Brown
Abstain
Abstain
Dale Dunckel
Abstain
1
1
Puget Sound Energy, Inc.
Denise M Lietz
1
1
1
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
John C. Allen
Tim Kelley
Robert Kondziolka
1
SaskPower
Wayne Guttormson
1
Seminole Electric Cooperative, Inc.
Glenn Spurlock
1
Sho-Me Power Electric Cooperative
Denise Stevens
1
Snohomish County PUD No. 1
Long T Duong
1
South Carolina Electric & Gas Co.
Tom Hanzlik
1
South Carolina Public Service Authority
Shawn T Abrams
1
Southern California Edison Company
Steven Mavis
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
COMMENT
RECEIVED
Affirmative
1
Southern Company Services, Inc.
Robert A. Schaffeld
1
Southern Illinois Power Coop.
William Hutchison
1
Southwest Transmission Cooperative, Inc. John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
Tampa Electric Co.
Beth Young
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
SUPPORTS
THIRD PARTY
COMMENTS (Eleanor
Ewry, Puget
Sound
Energy)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
4
1
Tennessee Valley Authority
Howell D Scott
1
Trans Bay Cable LLC
Steven Powell
1
Tri-State Generation & Transmission
Association, Inc.
Tracy Sliman
1
Tucson Electric Power Co.
John Tolo
1
U.S. Bureau of Reclamation
Richard T Jackson
1
United Illuminating Co.
Jonathan Appelbaum
1
Vermont Electric Power Company, Inc.
Kim Moulton
Abstain
Affirmative
Affirmative
1
Westar Energy
Allen Klassen
Negative
1
Western Area Power Administration
Lloyd A Linke
Affirmative
1
Wolverine Power Supply Coop., Inc.
Michelle Clements
2
BC Hydro
Venkataramakrishnan
Vinnakota
Negative
2
California ISO
Rich Vine
Negative
2
2
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
Cheryl Moseley
Leonard Kula
2
ISO New England, Inc.
Matthew F Goldberg
Negative
2
MISO
Marie Knox
Negative
2
New York Independent System Operator
Gregory Campoli
2
2
3
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
stephanie monzon
Charles H. Yeung
Michael E Deloach
SUPPORTS
THIRD PARTY
COMMENTS (Patricia
Robertson)
COMMENT
RECEIVED
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ISO/RTO
SRC)
Affirmative
Abstain
Abstain
3
Alabama Power Company
Robert S Moore
Negative
3
3
Ameren Corp.
APS
David J Jendras
Sarah Kist
Abstain
Affirmative
3
Associated Electric Cooperative, Inc.
Todd Bennett
3
Avista Corp.
Scott J Kinney
3
BC Hydro and Power Authority
Pat G. Harrington
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
5
3
Central Electric Power Cooperative
Adam M Weber
Negative
3
City of Austin dba Austin Energy
Andrew Gallo
Negative
3
City of Clewiston
Lynne Mila
Negative
3
City of Farmington
Linda R Jacobson
Abstain
3
City of Green Cove Springs
Mark Schultz
Negative
3
City of Tallahassee
Bill R Fowler
Negative
3
Colorado Springs Utilities
Jean Mueller
Negative
3
Consolidated Edison Co. of New York
Peter T Yost
Affirmative
3
Consumers Energy Company
Gerald G Farringer
3
Cowlitz County PUD
Russell A Noble
Negative
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Kaleb
Brimhall,
CSU)
COMMENT
RECEIVED
Affirmative
3
CPS Energy
Jose Escamilla
Negative
3
Dominion Resources, Inc.
Connie B Lowe
Abstain
3
DTE Electric
Kent Kujala
3
3
FirstEnergy Corp.
Florida Keys Electric Cooperative
Cindy E Stewart
Tom B Anthony
3
Florida Municipal Power Agency
Joe McKinney
3
Florida Power & Light Co.
Summer C. Esquerre
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Glenn
Pressler's
comments
submitted on
behalf of CPS
Energy)
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
6
3
Florida Power Corporation
Lee Schuster
Negative
3
3
3
Georgia System Operations Corporation
Great River Energy
Hydro One Networks, Inc.
Scott McGough
Brian Glover
Ayesha Sabouba
3
JEA
Garry Baker
3
Kansas City Power & Light Co.
Joshua D Bach
Negative
3
Lakeland Electric
Mace D Hunter
Negative
3
Lee County Electric Cooperative
David A Hadzima
3
Lincoln Electric System
Jason Fortik
3
Los Angeles Department of Water & Power Mike Anctil
3
Louisville Gas and Electric Co.
Charles A. Freibert
3
3
Manitoba Hydro
MEAG Power
Greg C. Parent
Roger Brand
3
MidAmerican Energy Co.
Thomas C. Mielnik
3
3
Modesto Irrigation District
Muscatine Power & Water
Jack W Savage
John S Bos
3
National Grid USA
Brian E Shanahan
3
3
Nebraska Public Power District
New York Power Authority
Tony Eddleman
David R Rivera
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Public
Service
Enterprise
Group)
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
3
Northern Indiana Public Service Co.
Ramon J Barany
Negative
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
3
Ocala Utility Services
Randy Hahn
Negative
3
Oklahoma Gas and Electric Co.
Donald Hargrove
3
Omaha Public Power District
Blaine R. Dinwiddie
3
Orlando Utilities Commission
Ballard K Mutters
3
3
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Thomas T Lyons
John H Hagen
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)
SUPPORTS
THIRD PARTY
COMMENTS (See Joe
O'Brien's
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Affirmative
Affirmative
Affirmative
7
3
3
3
3
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Public Service Electric and Gas Co.
Terry L Baker
Michael Mertz
Thomas G Ward
Jeffrey Mueller
3
Puget Sound Energy, Inc.
Mariah R Kennedy
3
3
Sacramento Municipal Utility District
Salt River Project
James Leigh-Kendall
John T. Underhill
3
Santee Cooper
James M Poston
Negative
3
Seminole Electric Cooperative, Inc.
James R Frauen
Abstain
3
Sho-Me Power Electric Cooperative
Jeff L Neas
3
Snohomish County PUD No. 1
Mark Oens
3
South Carolina Electric & Gas Co.
Hubert C Young
3
3
Southern California Edison Company
Tacoma Power
Lujuanna Medina
Marc Donaldson
3
Tampa Electric Co.
Ronald L. Donahey
3
Tennessee Valley Authority
Ian S Grant
3
Tri-State Generation & Transmission
Association, Inc.
Janelle Marriott
3
Westar Energy
Bo Jones
3
Xcel Energy, Inc.
Michael Ibold
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
4
Blue Ridge Power Agency
Duane S Dahlquist
Abstain
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (TVA)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
Abstain
Affirmative
4
City of Austin dba Austin Energy
Reza Ebrahimian
Negative
4
City Utilities of Springfield, Missouri
John Allen
Negative
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Review
Group)
8
4
Consumers Energy Company
Tracy Goble
Negative
4
Cowlitz County PUD
Rick Syring
Affirmative
4
DTE Electric
Daniel Herring
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
4
4
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
4
Indiana Municipal Power Agency
Jack Alvey
4
Madison Gas and Electric Co.
Joseph DePoorter
4
Modesto Irrigation District
Spencer Tacke
4
Ohio Edison Company
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power
Association
Tacoma Public Utilities
Utility Services, Inc.
Amerenue
American Electric Power
Arizona Public Service Co.
BC Hydro and Power Authority
Douglas Hohlbaugh
4
4
4
4
4
4
5
5
5
5
Mike Ramirez
Steven R Wallace
Keith Morisette
Brian Evans-Mongeon
Sam Dwyer
Thomas Foltz
Scott Takinen
Clement Ma
Mike D Kukla
5
Bonneville Power Administration
Francis J. Halpin
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
City and County of San Francisco
Daniel Mason
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Public
Service
Enterprise
Group)
Affirmative
Affirmative
Abstain
Steve McElhaney
Boise-Kuna Irrigation District/dba Lucky
peak power plant project
City of Austin dba Austin Energy
COMMENT
RECEIVED
COMMENT
RECEIVED
John D Martinsen
5
5
SUPPORTS
THIRD PARTY
COMMENTS (Kurt
LaFrance)
Jeanie Doty
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SCL
comments)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
9
5
City of Tallahassee
Karen Webb
5
City Water, Light & Power of Springfield
Steve Rose
5
Cleco Power
Stephanie Huffman
5
Cogentrix Energy Power Management, LLC Mike D Hirst
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See PSEG
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
5
Colorado Springs Utilities
Kaleb Brimhall
Negative
5
Con Edison Company of New York
Brian O'Boyle
Affirmative
5
Consumers Energy Company
David C Greyerbiehl
5
Cowlitz County PUD
Bob Essex
5
Dairyland Power Coop.
Tommy Drea
5
Dominion Resources, Inc.
Mike Garton
Negative
Abstain
DTE Electric
Mark Stefaniak
Negative
5
Duke Energy
Dale Q Goodwine
Negative
5
Dynegy Inc.
Dan Roethemeyer
Negative
5
E.ON Climate & Renewables North
America, LLC
Dana Showalter
Entergy Services, Inc.
Tracey Stubbs
5
First Wind
John Robertson
5
FirstEnergy Solutions
Kenneth Dresner
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
SUPPORTS
THIRD PARTY
COMMENTS (Kurt
LaFrance)
Affirmative
5
5
Generation
Company,
LLC)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (DTE Electric)
SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Entergy
Transmission)
Affirmative
10
5
Florida Municipal Power Agency
David Schumann
5
5
5
Great River Energy
Hydro-Québec Production
Ingleside Cogeneration LP
Preston L Walsh
Roger Dufresne
Michelle R DAntuono
5
JEA
John J Babik
5
Kansas City Power & Light Co.
Brett Holland
Negative
5
Kissimmee Utility Authority
Mike Blough
Negative
5
Liberty Electric Power LLC
Daniel Duff
5
Lincoln Electric System
Dennis Florom
5
Los Angeles Department of Water & Power Kenneth Silver
5
Lower Colorado River Authority
Dixie Wells
Negative
5
Luminant Generation Company LLC
Rick Terrill
Negative
5
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Chris Mazur
5
5
5
5
5
5
5
David Gordon
Steven Grego
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
Negative
Affirmative
Affirmative
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
comments
submitted by
Alshare
Hughes)
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
5
Northern Indiana Public Service Co.
Michael D Melvin
Negative
5
Oglethorpe Power Corporation
Bernard Johnson
Affirmative
5
Oklahoma Gas and Electric Co.
Henry L Staples
5
Omaha Public Power District
Mahmood Z. Safi
5
Pacific Gas and Electric Company
Alex Chua
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (See Joe
O'Brien
NIPSCO
comments.)
Affirmative
11
5
Platte River Power Authority
Christopher R Wood
5
Portland General Electric Co.
Matt E. Jastram
5
PPL Generation LLC
Annette M Bannon
5
PSEG Fossil LLC
Tim Kucey
5
Public Utility District No. 1 of Lewis County Steven Grega
5
Public Utility District No. 2 of Grant
County, Washington
Michiko Sell
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PSEG)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Abstain
Negative
Abstain
5
Puget Sound Energy, Inc.
Lynda Kupfer
5
5
Sacramento Municipal Utility District
Salt River Project
Susan Gill-Zobitz
William Alkema
5
Santee Cooper
Lewis P Pierce
Negative
5
Seattle City Light
Michael J. Haynes
Negative
5
Snohomish County PUD No. 1
Sam Nietfeld
5
South Carolina Electric & Gas Co.
Edward Magic
5
Southern California Edison Company
Denise Yaffe
5
Southern Company Generation
William D Shultz
5
5
Tacoma Power
Tampa Electric Co.
Chris Mattson
RJames Rocha
5
Tenaska, Inc.
Scott M. Helyer
5
Tennessee Valley Authority
David Thompson
5
Tri-State Generation & Transmission
Association, Inc.
Mark Stein
5
U.S. Army Corps of Engineers
Melissa Kurtz
5
USDI Bureau of Reclamation
Erika Doot
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
SUPPORTS
THIRD PARTY
COMMENTS (PSEG
comments)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Ewry,
Eleanor)
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Haase,
Seattle,)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Affirmative
Abstain
Negative
COMMENT
RECEIVED
Affirmative
12
5
Xcel Energy, Inc.
Mark A Castagneri
6
6
6
AEP Marketing
Ameren Missouri
APS
Edward P. Cox
Robert Quinlivan
Randy A. Young
6
Associated Electric Cooperative, Inc.
Brian Ackermann
6
Bonneville Power Administration
Brenda S. Anderson
Negative
Abstain
Abstain
Affirmative
Negative
City of Austin dba Austin Energy
Lisa Martin
Negative
6
Cleco Power LLC
Robert Hirchak
Negative
6
Colorado Springs Utilities
Shannon Fair
Negative
6
Con Edison Company of New York
David Balban
Affirmative
6
Duke Energy
Greg Cecil
6
FirstEnergy Solutions
Kevin Querry
6
Florida Municipal Power Agency
Richard L. Montgomery
6
Florida Municipal Power Pool
Thomas Washburn
6
6
Florida Power & Light Co.
Great River Energy
Silvia P Mitchell
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
Negative
6
Lakeland Electric
Paul Shipps
Negative
6
Lincoln Electric System
Eric Ruskamp
Lower Colorado River Authority
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
Michael Shaw
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
6
6
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
SUPPORTS
THIRD PARTY
COMMENTS (See PSEG
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Dixie Wells)
13
6
Luminant Energy
Brenda Hampton
Negative
6
6
6
Manitoba Hydro
Modesto Irrigation District
New York Power Authority
Blair Mukanik
James McFall
Shivaz Chopra
Affirmative
Affirmative
Affirmative
6
Northern Indiana Public Service Co.
Joseph O'Brien
Negative
6
Oglethorpe Power Corporation
Donna Johnson
Affirmative
6
Oklahoma Gas and Electric Co.
Jerry Nottnagel
6
6
6
6
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Douglas Collins
Sandra L Shaffer
Carol Ballantine
Shawn P Davis
6
Power Generation Services, Inc.
Stephen C Knapp
6
Powerex Corp.
Gordon Dobson-Mack
PPL EnergyPlus LLC
Elizabeth Davis
6
6
6
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Peter Dolan
Diane Enderby
William Abraham
6
Santee Cooper
Michael Brown
Negative
6
Seattle City Light
Dennis Sismaet
Negative
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
Abstain
6
Snohomish County PUD No. 1
Kenn Backholm
6
Southern California Edison Company
Joseph T Marone
6
Southern Company Generation and
Energy Marketing
John J. Ciza
6
Tacoma Public Utilities
Michael C Hill
6
Tampa Electric Co.
Benjamin F Smith II
6
Tennessee Valley Authority
Marjorie S. Parsons
Western Area Power Administration - UGP
Peter H Kinney
Marketing
7
Occidental Chemical
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
COMMENT
RECEIVED
Affirmative
Abstain
Abstain
Affirmative
6
6
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Abstain
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Affirmative
Abstain
Venona Greaff
14
8
8
8
8
10
10
10
10
10
10
10
10
Massachusetts Attorney General
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
10
Western Electricity Coordinating Council
9
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | October 2014
David L Kiguel
Roger C Zaklukiewicz
Frederick R Plett
Terry Volkmann
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Linda C Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Bob Reynolds
Karin Schweitzer
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Steven L. Rueckert
Abstain
15
Individual or group. (53 Responses)
Name (33 Responses)
Organization (33 Responses)
Group Name (20 Responses)
Lead Contact (20 Responses)
Question 1 (47 Responses)
Question 1 Comments (53 Responses)
Question 2 (44 Responses)
Question 2 Comments (53 Responses)
Question 3 (44 Responses)
Question 3 Comments (53 Responses)
Question 4 (46 Responses)
Question 4 Comments (53 Responses)
Question 5 (46 Responses)
Question 5 Comments (53 Responses)
Question 6 (37 Responses)
Question 6 Comments (53 Responses)
Question 7 (40 Responses)
Question 7 Comments (53 Responses)
Question 8 (33 Responses)
Question 8 Comments (53 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
Yes
Yes
Comments regarding requirement R1 can be found in the response to Question 8. Additionally,
suggest clarifying requirement R1 by adding the wording “for all design criteria events” so as to
make it read: R1. Each Planning Coordinator shall, for all design criteria events, at least once each
calendar year, identify each Element in its area that meets one or more of the following criteria and
provide notification to the respective Generator Owner and Transmission Owner, if any:
Yes
Comments regarding requirements R2 and R3 can be found in the response to Question 8. Splitting
requirement R2 into two requirements adds clarity.
Yes
Requirement R4 continues to be a combined TO/GO requirement. For clarity, R4 should also be split
into two requirements--one to address the GO obligations by applicable requirement, another to
address the TO obligations by applicable requirement.
No
A CAP is developed to correct a problem after the requirements of a standard are implemented. The
Implementation Plan should address meeting the obligations of the standard’s requirements. The
Implementation Plan would also address the annual identification of Elements. This would allow for
the removal of requirements R5 and R6. Generator Owners and Transmission Owners need more
time subsequent to the identification of load-responsive protective relays to perform a thorough
evaluation. The requirement should provide at least 180 days to perform the evaluation. This will
allow for a more complete response than can be obtained in 60 days. If the CAP is kept, the
Generator or Transmission Owner should provide a copy of the initial Corrective Action Plan and
status updates to the Planning Coordinator. The length of time an entity has to complete corrective
actions should be specified. 180 calendar days is a realistic length of time.
No
Twelve months is not adequate to prepare for this standard as written. The Drafting Team should
change the Implementation Plan to 24 months. The implementation could be improved by adding
when the performance of requirement R1 is due. Is the PC supposed to complete its R1 analysis
based on the effective date of the Standard 12 months after FERC approval, or 12 months after
FERC approves the Standard then the PC has to complete the study for the calendar year? This can
be difficult depending on when FERC approves the Standard. We suggest the revision to 24 months
and stating that the PC is expected to complete the identification required by R1 in the calendar year
that the requirement becomes effective. This removes the concern of what month FERC approves
the Standard.
Yes
The wording of the Purpose should not have been changed. The existing wording” do not trip” is
definitive; the proposed wording “…are expected to…” leaves room for questioning. If the proposed
wording is kept, suggest that the Purpose read: To ensure that load-responsive protective relays are
not expected to trip in response to stable power swings during non-Fault conditions. Regarding
requirements R1, R2 and R3, to be consistent with the format of other NERC standards, the
Criteria/Criterion listings should be made Parts of requirements R1, R2 and R3. Requirement R1 has
the Planning Coordinator notifying the respective Generator Owner and Transmission Owner but a
specific time period to complete the notification following the identification of an Element is not
specified. This may appear as a gap in the process. The Planning Coordinator should have 30 days to
notify the TO and GO. PRC-026 leaves out the use of transfer limits to correct for stable power
swings. Transfer limits are an important tool for use in power system operations, and should be
mentioned in a Rationale Box. Entities should not be exempted from the standard because of the
linkage to Attachment A. Attachment A should not exclude Relay elements supervised by power
swing blocking. Entities may install out of step blocking in order to be exempted from the standard.
An entity may install Out of Step Blocking equipment without validating that it is set correctly
because PRC-026 would not apply. Measure M3 is missing the word “meet”. Measure M3 should
read: M3. Each Generator Owner shall have dated evidence that demonstrates identification of the
Element(s), if any, which meet the criterion in Requirement R3. Evidence may include, but is not
limited to, the following documentation: emails, facsimiles, records, reports, transmittals, lists, or
spreadsheets.
Group
Arizona Public Service Co
Janet Smith
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
The 30 days notification requirements for R2 and R3 is unnecessarily too stringent. We suggest 90
days.
Group
Puget Sound Energy
Eleanor Ewry
Yes
Yes
No
In general, we agree with the comments submitted by PSEG. R2 and R3 require TOs and GOs,
respectively, to notify their Planning Coordinator within 30 days of identifying any Element that trips
due to a power swing during a system disturbance due to the operation of load-responsive
protective relays. PRC-026-1, as drafted, will have consequences with respect to an entity’s
implementation of a different standard: PRC-004-3 - Protection System Misoperation Identification
and Correction – see http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-004-3.pdf. NERC
has filed PRC-004-3 with FERC for approval. In summary, PRC-004-3 requires each operation of an
interrupting device to be evaluated to determine whether a Misoperation occurred. If such a
determination is made, the Protection System owner must investigate the occurrence and either (a)
provide a declaration that a cause could not be determined or (b) if a cause is determined, develop
and implement a Corrective Action Plan (CAP) or explain why corrective actions are beyond its
control or would not improve reliability. PRC-004-3 does not require any action with regard to
Element trips that are not Misoperations, i.e., “correct operations.” We understand that a Protection
System owner would need some documentation to make the distinction between a correct operation
and a Misoperation. However, in order to be fully compliant with PRC-026-1 R2 and R3, every
Element that trips due to the operation of a load-responsive relay must be evaluated by the entity to
determine whether or not the trip was due to a power swing. As discussed on the September 18
webinar on PRC-026-1, the phrase “system Disturbance” has same meaning as the NERC Glossary
term for “Disturbance.” In other words, “system” is unnecessary. In addition, a “Fault” was stated to
be a “Disturbance.” Therefore, every operation of a load-responsive relay due to a Fault must be
examined under PRC-026-1 to identify whether or not the Element tripped due to a power swing. •
If an Elements trips due to a Misoperation, the Misoperation would be investigated under PRC-004-3,
and if it was caused by a power swing that could easily be reported under PRC-026-1 as a result of
the Protection System owner’s compliance with PRC-004-3. Requiring all correct operations be
affirmatively evaluated by the Element owner to determine whether they are attributable to a power
swing would only “make work” for both the Element owners and their auditors, and the added effort
would not improve reliability. Therefore, we propose that the scope of R2 and R3 for correct
operations be reduced to a subset of events that are reported to NERC under EOP-004-2 – Event
Reporting – see http://www.nerc.com/pa/Stand/Reliability%20Standards/EOP-004-2.pdf . For
example, the Disturbances evaluated in PRC-026-1 for correct operations could be limited to some of
the events and associated thresholds listed in EOP-004 - Attachment 1. We believe reasonable
events would include: • Automatic firm load shedding on p. 9 • Loss of firm load (preferably limited
to non-weather related load loss) on p. 10 • System separation (islanding) on p.10 • Generation loss
on p.10, • Complete loss of off-site power to a nuclear plant on p. 10, and • Transmission loss on
p.11. To couple the two standards together, NERC, which receives event reports under EOP-004-2,
would need to notify the applicable TOs and GOs under PRC-026-1 of the time frame of each event.
This would allow the Element owners to evaluate whether any Element trips that occurred during the
event and which were correct operations were associated with a power swing. Without this
notification, Events that happen outside of the Planning Coordinator’s PC Area may not be properly
identified by the affected PC. If this is not the intent of the standard, there needs to be a distinction
made between whether relays should be evaluated against local disturbances (disturbances within
the PC Area) and system-wide disturbances that would be communicated throughout the region.
Yes
No
It should be recognized in the requirement that the appropriate response to a trip due to a stable
power swing might be to take no action. The requirement should be amended to allow the Element
owner to make a declaration that corrective action would not improve BES reliability, therefore
action will not be taken, consistent with PRC-004-3, R5.
Yes
Yes
No
Individual
Gul Khan
Oncor Electric Delivery LLC
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Individual
John Seelke
Public Service Enterprise Group
Yes
No
The Planning Coordinator should be obligated in R1 to provide system impedance data as described
in the Attachment B Criteria for each Element identified in R1 to the TO or GO that owns the
Element. PCs maintain the models that contain this data, and having them provide it will result in
consistency for relays set within the PC’s area.
This question is a duplicate of the prior question. The response below answers Q3 in the unofficial
comment form. R2 and R3 require TOs and GOs, respectively, to notify their Planning Coordinator
within 30 days of identifying any Element that trips due to a power swing during a system
disturbance due to the operation of load-responsive protective relays. PRC-026-1, as drafted, will
have consequences with respect to an entity’s implementation of a different standard: PRC-004-3 Protection System Misoperation Identification and Correction – see
http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-004-3.pdf. NERC has filed PRC-004-3
with FERC for approval. In summary, PRC-004-3 requires each operation of an interrupting device to
be evaluated to determine whether a Misoperation occurred. If such a determination is made, the
Protection System owner must investigate the occurrence and either (a) provide a declaration that a
cause could not be determined or (b) if a cause is determined, develop and implement a Corrective
Action Plan (CAP) or explain why corrective actions are beyond its control or would not improve
reliability. PRC-004-3 does not require any action with regard to Element trips that are not
Misoperations, i.e., “correct operations.” We understand that a Protection System owner would need
some documentation to make the distinction between a correct operation and a Misoperation.
However, in order to be fully compliant with PRC-026-1 R2 and R3, every Element that trips due to
the operation of a load-responsive relay must be evaluated by the entity to determine whether or
not the trip was due to a power swing. As discussed on the September 18 webinar on PRC-026-1,
the phrase “system Disturbance” has same meaning as the NERC Glossary term for “Disturbance.”
In other words, “system” is unnecessary. In addition, a “Fault” was stated to be a “Disturbance.”
Therefore, every operation of a load-responsive relay due to a Fault must be examined under PRC026-1 to identify whether or not the Element tripped due to a power swing. • If an Elements trips
due to a Misoperation, the Misoperation would be investigated under PRC-004-3, and if it was
caused by a power swing that could easily be reported under PRC-026-1 as a result of the Protection
System owner’s compliance with PRC-004-3. Requiring all correct operations be affirmatively
evaluated by the Element owner to determine whether they are attributable to a power swing would
only “make work” for both the Element owners and their auditors, and the added effort would not
improve reliability. Therefore, we propose that the scope of R2 and R3 for correct operations be
reduced to a subset of events that are reported to NERC under EOP-004-2 – Event Reporting – see
http://www.nerc.com/pa/Stand/Reliability%20Standards/EOP-004-2.pdf . For example, the
Disturbances evaluated in PRC-026-1 for correct operations could be limited to some of the events
and associated thresholds listed in EOP-004 - Attachment 1. We believe reasonable events would
include: • Automatic firm load shedding on p. 9 • Loss of firm load (preferably limited to nonweather related load loss) on p. 10 • System separation (islanding) on p.10 • Generation loss on
p.10, • Complete loss of off-site power to a nuclear plant on p. 10, and • Transmission loss on p.11
To couple the two standards together, NERC, which receives event reports under EOP-004-2, would
need to notify the applicable TOs and GOs under PRC-026-1 of the time frame of each event. This
would allow the Element owners to evaluate whether any Element trips that occurred during the
event and which were correct operations were associated with a power swing.
Yes
No
The requirement to develop a CAP in R5 should be amended to allow the Element owner, in lieu of a
developing a CAP, to make a declaration that corrective actions would not improve BES reliability
and therefore will not be taken. This is consistent with PRC-004-3, R5.
Yes
No
Individual
Oliver Burke
Entergy Services, Inc.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Based on the information contained in the SPCS Power Swing Report Dated August 2013, there is
insufficient evidence in the historical study case identified, to warrant implementation of the
proposed PRC-026-1 standard.
Individual
Thomas Foltz
American Electric Power
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Individual
Maryclaire Yatsko
Seminole Electric Cooperative, Inc.
Yes
No
Requirements R2 and R3 appear to require the reporting of trips due to UNSTABLE power swings.
Seminole feels that a better mechanism for collecting information on unstable power swings is
through NERC Section 1600 data requests, not via a Standard. Requirements R2 and R3 utilize the
term “identifying.” Can the SDT add language in the application guidelines that clarifies that
“identifying” means “making a determination,” as the term identifying is somewhat unclear to
Seminole.
No
Requirement R5 requires the development of a CAP. Seminole requests that the ability to submit a
notification to the Entity’s RRO, stating why a CAP cannot or should not be implemented, be added
to R5. Seminole reasons that there may be instances where a CAP is not possible, somewhat akin to
a TFE in the CIP-world. The SDT could make the CAP exception contingent on the RRO’s approval.
Individual
Kayleigh Wilkerson
Lincoln Electric System
Yes
Although aware of the forces driving the development of PRC-026-1, LES cannot support the
standard. LES agrees with the statement in the NERC System Protection and Control
Subcommittee’s technical report titled “Protection System Response to Power Swings” that
recommends against this standard. Reliability Standards PRC-023-3 and PRC-025-1 adequately
ensure that load-responsive protective relays will not trip in response to stable power swings during
non-Fault conditions. Additionally, as stated in this same report, consideration should be given to
potential adverse impacts to Bulk Power System reliability as a result of the standard.
Individual
Mark Wilson
Independent Electricity System Operator
Yes
Yes
Yes
Yes
No
The scope of the proposed standard is directed at blocking the trip for stable power swings only.
However, since existing distance schemes have the ability to trip for both stable and unstable
swings, the standard can be interpreted as permitting a Transmission Owner to remove both trip
abilities in order to comply with this standard. Removing the trip abilities for unstable power swings
may have unintended consequences, such as preventing successful self-generating islands to form,
making the restoration process much more difficult. In order to prevent any unintended
consequence, we suggest that Requirement 5 is modified to have the Transmission Owner consult
with the Planning Coordinator for whether out‐of‐step protection is needed, and if so, whether out of
step tripping or power swing blocking should be applied: R5. Each Generator Owner and
Transmission Owner shall, within 60 calendar days of an evaluation that identifies load-responsive
protective relays that do not meet the PRC-026-1 – Attachment B Criteria pursuant to Requirement
R4, develop a Corrective Action Plan (CAP) to modify the Protection System to meet the PRC-026-1
– Attachment B Criteria while maintaining dependable fault detection and dependable out-of-step
tripping. (Each Generator Owner and Transmission Owner shall consult with their applicable Planning
Coordinator if out of-step tripping should be applied at the terminal of the Element).
Yes
Yes
Individual
Amy Casuscelli
Xcel Energy
Yes
No
Criteria 1 uses the term “operating limit” and Criteria 2 uses the term “System Operating Limit;”
although both are identified by the existence of angular stability constraints, thus seemingly defining
the same type of operating constraint, i.e. operating limit. Xcel Energy would suggest either
explaining the difference between the terms “operating limit” and “System Operating Limit”, or
eliminating the potentially duplicative criterion, since a “Generator” can be an “Element”. In our
opinion, Requirement R1 is organized and written in a manner that makes interpretation difficult.
Xcel Energy suggests that the drafting team consider re-organizing this requirement as suggested
below. R1 could be split so that R1 requires the PC to perform the following at least once per year;
R1.1 would require the PC to identify Elements meeting the bulleted list of criteria; R1.2 would
require notification to the respective Generator Owner and Transmission owner of each Element
identified in R1.1. Regardless of whether this Requirement R1 is re-organized as suggested above or
not, we suggest the following rewrite of of Criteria 1 to minimize ambiguity. Criteria 1 can be split
either at the “or” (as in “…addressed by an operating limit or a Remedial Action Scheme (RAS) and
those Elements…”) or at the “and” (as in “…addressed by an operating limit or a Remedial Action
Scheme (RAS) and those Elements…”). To provide additional clarity, Criteria 1 could be rewritten as:
“Generator(s) and Elements Terminating at associated transmission stations where angular stability
constraint exists that is addressed by an operating limit or a Remedial Action Scheme (RAS).” These
potential modifications would improve the readability of the requirement and provide for easier
alignment with the associated Measures and VSLs. In addition, M1 could be rephrased to state “Each
Planning Coordinator shall have dated evidence that demonstrates identification of Elements meeting
the R1 criteria was performed on a calendar year basis and dated evidence that demonstrates the
respective owners of the identified Elements were notified on a calendar year basis”. The existing M1
phrasing of “identification and respective notification of the Elements” reads as if the Elements are
being notified rather than the owners of the Elements.
No
The Measures M2 & M3 do not match the R2 & R3 requirements. The measures only require that the
TO and GO have evidence of the identification of elements, but do not require evidence of
notification of identified Elements to the PC. The VSLs for R2 & R3 classify it as a Severe VSL if the
TO or GO fails to identify an Element in accordance with R2 & R3. However, the way R2 & R3 are
written, there is no requirement for the TO or GO to identify anything. As the requirements are
currently written, the only requirement is that the PC is notified within 30 calendar days of
identification of an Element meeting the criteria. If a TO or GO does not identify an Element, they
can never be in violation of R2 or R3 as written. Further, if there is no requirement for identification
of Elements meeting R2 or R3 criteria, it is not clear what the starting point is for determining the 30
day notification period. How is the official date of identification of an Element pursuant to R2 & R3
determined? And how is it officially documented for use in establishing PC notification due date in
determining the severity of the violation? It is unclear what action the PC is going to take, upon
notification of the identification of an Element meeting R2 & R3 criteria, beyond adding the Element
to the R1 list for future years that will be provided to the TO and GO. If that is the only resulting
action, the 30 day notification of the PC or the <10 day overdue Lower VSL, <20 day overdue
Moderate VSL, <30 day overdue High VSL or >30 day overdue Severe VSL do not seem to align. R4
directs the TO and GO to analyze the Elements within 12 calendar months of identifying the Element
pursuant to R2 or R3. If the only action taken by the PC is to add the Element to the R1 list for
future years, is would seem to be just as effective from a reliability perspective to give the TO and
GO up to the next calendar year to notify the PC about R2 7 R3 identified elements and to align the
R2 & R3 VSL notification timeframes with those allowed for the PC to TO/GO notifications in R1.
No
We are generally supportive of the revisions to R4 but offer the following observation. We believe
that the way R4 is currently written, an Entity would be allowed to not evaluate an Element’s load
responsive relays if they had been evaluated in the past three calendar years even if the Element
was identified within the last 12 calendar months per R2 or R3 to have tripped in response to a
stable power swing. For example, if an element tripped in January 2015 due to a stable power
swing, the R4 analysis is performed and corrective action taken per R5 and R6. If the device trips
again in 2016 due to a stable power swing, it would appear that there was a problem with the 2015
analysis. But the way R4 is written, the entity would be exempt from performing any analysis or
taking any further action until 2018. We do not believe this is the drafting team’s intent.
Yes
The VSLs for R4 and R5 seem inconsistent. Entities are given 12 calendar months to perform an
analysis with VSLs of increasing severity for being <30, <60, <90, and > 90 days past due. They
are given 60 days to develop a CAP following completion of an evaluation that determines the need
for a protection system modification to meet PRC-026-1 Attachment B criteria, and with an R5 VSL
of increasing severity for being <10, <20, <30 or >30 days past due in the development of a CAP.
Given the 12 month leeway on the completion of analysis following identification of the Element and
the only 60 day leeway on CAP development, why would an entity sign off an R4 analysis as
complete for an element requiring a protection system modification prior to the 12 month deadline,
essentially starting the 60 day clock on the CAP development R5 requirement? We recommend that
all R4 analysis completion and R5 CAP development timeframes be based on the calendar months
from the original date of identification of the susceptible Element and that the same <30 day, <60
day, <90 day and >90 day increments be used both R4 and R5 VSLs. This approach would eliminate
any potential benefit from delaying the officially acknowledged date of completion of the R4 analysis
and not have any effect on the final R5 max CAP development timeframe (ie. months since initial
Element identification) allowable by the standard.
No
In the Application Guidelines, Criteria 1 uses the term “operating limit” and Criteria 2 uses the term
“System Operating Limit” although both are identified by the existence of angular stability
constraints, seemingly defining the same type of operating constraint, i.e. operating limit. Xcel
Energy would suggest either explaining the difference between the terms “operating limit” and
“System Operating Limit”, or eliminating the potentially duplicative criterion, since a “Generator” can
be an “Element”. The lens calculation tool is not validated or authorized for use. Due to the
hypothetical nature of the calculations, a standardized tool should be provided so that industry can
achieve consistent results. There is no requirement that the TO provide the System Equivalent to the
GO. This Standard should provide communication requirements between the GO and TO, similar to
the MOD series standards effective inn 2014. While this may not be necessary due to the typically
amenable working relationships in a vertically integrated utility, it may be required in areas that are
served by several companies.
Yes
We believe there is insufficient technical basis to make this a viable standard for industry to properly
apply, and provide the following comments for consideration: We concur with the NERC concern
noted in #133 of FERC order 733 that careful study and analysis of the relationship between stable
power swings and protective relays is needed and consultation with IEEE and other organizations
should be completed before developing a Reliability Standard addressing stable power swings. The
need basis for this standard is 2003 blackout event data. Since that time, many improvements to
protection systems have occurred, voltage control and frequency control requirements have either
been implemented, are on a staged implementation plan, or are planned in the immediate future.
The need basis data set has changed and should be based on current information, rather than past
uncontrolled system reliability program data. Many improvements over the last 11 years have
changed the probability of this particular need occurring, including: • Use of Generator AVR and PSS
systems • Improved facility equipment ratings • Automatic voltage and frequency ride-through
standards for wind turbines • Coordinated protection system settings amongst all players • Better
system modeling and transmission planning These concerns would be addressed by a carefully
planned study as described. We are aware of FERC’s concerns around undesirable operations due to
stable power swings, per Orders 733, 733A and 733B. The directive in #150 states “…we direct the
ERO to develop a Reliability Standard that requires the use of protective relay systems that can
differentiate between faults and stable power swings and, when necessary, phases out protective
relay systems that cannot meet this requirement.” We are also aware that this requirement was
reinforced on September 4th, in the applicable FERC staff meeting. Due to the real or perceived
urgency in completing this standard, we have offered some proposed wording intended to expedite
the acceptance of the regulation. As written, we believe this draft holds potential opportunities for
improvements towards readability and cohesiveness.
Individual
Alshare Hughes
Luminant Generation Company, LLC
Yes
No
Requirement R1 provides additional clarity of which Elements (including transformers, generators)
are included in a notification by the Transmission Planner. In light of the fact that the purpose of this
standard is “To ensure that load-responsive protective relays are expected to not trip in response to
stable power swings during non-Fault conditions” which is in agreement with the FERC Order 733
(Section 150 of the FERC Order: “requires the use of protective relay systems that can differentiate
between faults and stable power swings and, when necessary, phases out protective relay systems
that cannot meet this requirement”), it is an unnecessary extension of the Order to include unstable
power swings. The Standard Drafting Team stated “The phase “stable or unstable” was inserted to
clarify that both are applicable to power swings because the goal of the standard is to identify
Elements susceptible to either” overreaches the FERC Order. Luminant recommends that unstable
power swings be removed. Additionally, R1 should be modified so that notifications are not required
for elements and relays that were previously identified and are currently in a Corrective Action Plan.
The Planning Assessment referenced in R1, Criteria 4 should be limited to the contingencies in TPL001-0.1 “Table 1 Transmission System Standards – Normal and Emergency Conditions” Category A,
B, C and D to focus the power swing evaluations and corrective action development on activities that
support the reliability of the BES.
Yes
No
Luminant agrees that Criteria A (Attachment B) provides a method for determining a relay setting to
minimize unnecessary trips due to a stable power swing; however, Luminant recommends that the
generation application section include an out-of-step relay example for stable power swings.
Luminant also recommends removal of unstable power swings from the requirement based on the
same comments in question 2.
Yes
No
Luminant recommends that in the Generator Application section, an example of a generator out-ofstep relay application for stable power swings should be provided.
Yes
No
Individual
Barbara Kedrowski
Wisconsin Electric
Yes
Yes
No
: We take issue with this requirement. First, it will be difficult or impossible for the Generator Owner
(GO) to comply with. The requirement in R3 is to notify the Planning Coordinator of an Element that
trips due to a stable or unstable power swing during an actual system Disturbance due to the
operation of its load-responsive protective relays. Without dynamic disturbance recording (DDR), it
may not be possible to determine that the relay tripped due to a power swing. The GO is not
required to have (DDR) capability for every generator. Note that DDR will only be required by the
future PRC-002 standard for a subset of generators, not all of them. The most that a GO may be
able to do is to say that a generator relay may have operated for a power swing, especially when the
Generator Owner does not own or operate the connected transmission system. Second, if an
unstable power swing passes through the generator or generator step-up transformer, the generator
SHOULD trip in order to prevent or limit possible damage. The generator out-of-step relay is used
for this purpose, and it does not appear that this standard will allow the necessary settings on the
Device 78 element to properly protect the generator. Common industry settings for the 78 out-ofstep function do not appear to be possible based on the Application Guidelines in the draft standard.
For these reasons, we believe that this requirement should be removed. If it is retained, then the
scope of the applicability to generators should be limited to those generators where DDR will be
required per the future PRC-002.
No
The limitations imposed in the Application Guidelines will not allow a Generator Owner to set an outof-step relay to properly protect the generator, using commonly applied settings such as for single
blinder schemes, and possibly other out-of-step schemes. The settings must be able to detect a
power swing in the generator or GSU transformer, which appears to violate the setting limits as in
the example of Figure 20.
No
Similar to PRC-004-3 R5, the entity should be allowed to explain in a declaration why corrective
actions would not improve BES reliability and that no further corrective actions will be taken. For
overall BES reliability, It must be left to the equipment Owners to determine when relay settings
which do not meet the Application Guidelines must still be used for proper equipment protection.
No
For generators, the Application Guidelines make reference to using the generator transient reactance
X’d. However, Tables 15 and 16 show the sub-transient reactance X’’d in the calculations. This
appears to be a discrepancy. See also Question 3 above.
Group
Southern Company: Southern Company Services, Inc.; Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi Power Company; Southern Company Generation;
Southern Company Generation and Energy Marketing
Wayne Johnson
Yes
Simplifying the requirement to a single entity clarified the responsibilities.
Yes
Simplifying the requirement to a single entity clarified the responsibilities.
Yes
Since the criteria is not completely the same for the TO and GO, spliting the previous R2 into a new
R2 and new R3 was a good move.
No
Is the Criteria a single page (page 17) or is it pages 17-73? The text in the rationale should be
included in the Criteria paragraph so that there is no doubt what the evaluation is supposed to
demonstrate. The previous draft (R3) presentation of the demonstration, CAP development, and
PC/TP/RC communication was easier to understand just what was expected of the GO and TO.
No
Already discuss in Q4 comment - the requirement to develop a CAP was clear either way. The
addition of the 60 day due date added more detail.
No
The calculations, requiring the extent of material provided in the application guide to explain, appear
to be quite complex and difficult. Is the SDT open to considering an alternative method of
evaluation? It is proposed that GO or TO give relay settings to the entity with the transient analysis
modeling tool (TP/PC), and that entity determine if the GO/TO relay settings need to be modified
based on the power swing characteristics and simulation results for the area being reviewed.
Yes
Yes
Comments for Application Guidelines 1. Page 1 – “The development of this standard implements the
majority of the approaches suggested by the report.” 2. Page 6 – “The standard does not included
any requirement for the entities to provide information that is already being shared or exchanged
between entities for operating needs.” 3. Page 8 – “In order to establish a time delay that strikes a
line between a high-risk…” What is meant by “strikes”? 4. Page 8 – “For a relay impedance
characteristic that has the swing entering and leaving beginning at 90 degrees with a termination at
120 degrees before exiting the zone…” “Add degrees” 5. Page 9 – Title of “Application to
Transmission Elements”, should be “Application Specific to Criteria A”. 6. Page 9 – reference Fig 13
and 14 when discussing “infeed effect” 7. Figure 3 – Update text box “Constant Angle…Boundary
(120 degrees)”. 8. Table 2 through 7 – Do not need to calculate each point, does not provide added
value to the document. 9. There are many tables and figures not referenced in the written portion of
the document which makes the guideline difficult to read and follow. This is the case for Figure 13,
14, 15, and almost all the tables.
Individual
Bill Fowler
City of Tallahassee
Yes
No
The Planning Coordinator should be obligated in R1 to provide system impedance data as described
in the Attachment B Criteria for each Element identified in R1 to the TO or GO that owns the
Element. PCs maintain the models that contain this data, and having them provide it will result in
consistency for relays set within the PC’s area.
No
R2 and R3 require TOs and GOs, respectively, to notify their Planning Coordinator within 30 days of
identifying any Element that trips due to a power swing during a system disturbance due to the
operation of load-responsive protective relays. PRC-026-1, as drafted, will have consequences with
respect to an entity’s implementation of a different standard: PRC-004-3 - Protection System
Misoperation Identification and Correction – see
http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-004-3.pdf. NERC has filed PRC-004-3
with FERC for approval. In summary, PRC-004-3 requires each operation of an interrupting device to
be evaluated to determine whether a Misoperation occurred. If such a determination is made, the
Protection System owner must investigate the occurrence and either (a) provide a declaration that a
cause could not be determined or (b) if a cause is determined, develop and implement a Corrective
Action Plan (CAP) or explain why corrective actions are beyond its control or would not improve
reliability. PRC-004-3 does not require any action with regard to Element trips that are not
Misoperations, i.e., “correct operations.” We understand that a Protection System owner would need
some documentation to make the distinction between a correct operation and a Misoperation.
However, in order to be fully compliant with PRC-026-1 R2 and R3, every Element that trips due to
the operation of a load-responsive relay must be evaluated by the entity to determine whether or
not the trip was due to a power swing. As discussed on the September 18 webinar on PRC-026-1,
the phrase “system Disturbance” has same meaning as the NERC Glossary term for “Disturbance.”
In other words, “system” is unnecessary. In addition, a “Fault” was stated to be a “Disturbance.”
Therefore, every operation of a load-responsive relay due to a Fault must be examined under PRC026-1 to identify whether or not the Element tripped due to a power swing. • If an Elements trips
due to a Misoperation, the Misoperation would be investigated under PRC-004-3, and if it was
caused by a power swing that could easily be reported under PRC-026-1 as a result of the Protection
System owner’s compliance with PRC-004-3. Requiring all correct operations be affirmatively
evaluated by the Element owner to determine whether they are attributable to a power swing would
only “make work” for both the Element owners and their auditors, and the added effort would not
improve reliability. Therefore, we propose that the scope of R2 and R3 for correct operations be
reduced to a subset of events that are reported to NERC under EOP-004-2 – Event Reporting – see
http://www.nerc.com/pa/Stand/Reliability%20Standards/EOP-004-2.pdf . For example, the
Disturbances evaluated in PRC-026-1 for correct operations could be limited to some of the events
and associated thresholds listed in EOP-004 - Attachment 1. We believe reasonable events would
include: • Automatic firm load shedding on p. 9 • Loss of firm load (preferably limited to nonweather related load loss) on p. 10 • System separation (islanding) on p.10 • Generation loss on
p.10, • Complete loss of off-site power to a nuclear plant on p. 10, and • Transmission loss on p.11.
To couple the two standards together, NERC, which receives event reports under EOP-004-2, would
need to notify the applicable TOs and GOs under PRC-026-1 of the time frame of each event. This
would allow the Element owners to evaluate whether any Element trips that occurred during the
event and which were correct operations were associated with a power swing.
Yes
No
The requirement to develop a CAP in R5 should be amended to allow the Element owner, in lieu of a
developing a CAP, to make a declaration that corrective actions would not improve BES reliability
and therefore will not be taken. This is consistent with PRC-004-3, R5
Yes
This standard will cause a large increase in workload for entities with a small trade off of system
reliability.
Group
Associated Electric Cooperative, Inc. - JRO00088
Phil Hart
Yes
AECI agrees with SPP Commments
No
AECI agrees with SPP Commments
No
AECI agrees with SPP Commments
No
AECI agrees with SPP Commments
No
AECI agrees with SPP Commments
AECI agrees with SPP Commments
Individual
Jonathan Meyer
Idaho Power
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
The 30 day time requirement for notification of swing tripping events in R2 and R3 seems a little
short. I think 45 to 60 days would be more appropriate.
Individual
John Pearson/Matt Goldberg
ISO New England
No
While we agree with the removal of the Reliability Coordinator and Transmission Planner, we don’t
believe that entities should be exempted from the standard by the linkage to Attachment A.
Attachment A excludes Relay elements supervised by power swing blocking. An entity could just
install Out of Step Blocking equipment with nothing to ensure that it is set correctly and the
standard would not apply through the exclusion in Attachment A.
No
R1 should be changed to read: R1. Each Planning Coordinator shall, for all design criteria events at
least once each calendar year, identify each Element in its area that meets one or more of the
following criteria and provide notification to the respective Generator Owner and Transmission
Owner, if any:
No
Although splitting the requirement into two adds clarity, what was the underlying uncertainty that
this is intended to address? R4 continues to be a combined TO/GO requirement that was not split.
We ask whether the same uncertainty exists for R4 (previously R3) and should it also be split?
Yes
No
For R5, Generator and Transmission Owners need more time develop a Corrective Action Plan. The
requirement should provide at least 180 days to develop the Corrective Action Plan. This will allow
for a more complete and thoughtful response than can be obtained in 60 days. Also under R5, the
Generator or Transmission Owner should provide a copy of the initial Corrective Action Plan and
status updates to the Planning Coordinator. Right now, the requirement is open ended without the
provision of Corrective Action Plan information.
Yes
No
Twelve months is not adequate to prepare for this standard as written. The drafting team should
change the implementation plan to twenty four months.
Yes
PRC-026 leaves out the use of transfer limits to correct for stable power swings. Transfer limits are
an important tool for use in power system operations. Furthermore, Attachment A should not
exclude Relay elements supervised by power swing blocking. Entities might simply install out of step
blocking in order to be effectively exempted from the standard. An entity could just install Out of
Step Blocking equipment with nothing to ensure that it is set correctly and the standard would not
apply through the exclusion in Attachment A. This will not improve power system reliability.
Group
Colorado Springs Utilities
Kaleb Brimhall
Yes
No Comments
No
We agree with the Public Service Electric and Gas Company comments. Additional Comments: 1.)
Please define a "transmission switching station," is that the same thing as a sub-station? 2.) Please
clarify "angular" stability limit versus just a stability limit. 3.) How are people modeling the relay
settings for R1.4? Our facility ratings take into account relay setting limitations and the facility
ratings are used in the models. Is that sufficient modeling or is there some specific modeling
expected for R1.4?
No
We agree with the Public Service Electric and Gas Company comments.
Yes
No
We agree with the Public Service Electric and Gas Company comments.
No Comments
Yes
No
Individual
Chris Scanlon
Exelon Companies
In the guidelines and technical basis section of the standard, a method for evaluating whether a
distance element is susceptible or not is given. In the previous guidelines and technical basis, a
simpler method of plotting the relay characteristic within the lens drawn at the 120 degree critical
angle was also described. This method seems to have been removed from the current draft
standard. This method works often for our protection schemes and requires no calculations (it is
simpler and less work). The drafting team should consider putting this section back in the guidelines
section to show that this method may also be used.
We agree with the drafting teams’ decision that only those elements that trip in less than 15 cycles
need to be evaluated for susceptibility to tripping during stable power swings. This follows from
actual event experience that shows that the vast majority of relays that trip during power swings are
zone 1s.
Individual
Brett Holland
Kansas City Power & Light
Yes
No
A yearly notification is too often for this requirement since this information will rarely change. We
suggest a yearly notification for any change from the previous year, with a five year notification of
all identified Elements.
No
A trip during a stable power swing is a mis-operation and is covered in PRC-004. A trip during an
unstable power swing is an intended result and not applicable to this standard. We suggest removing
these two requirements.
No
Attachment A includes Out-of-step tripping. This condition is an unstable power swing and should
not be included in the standard. The standard should allow protection relays and philosophies to
protect the equipment first and foremost. The requirement not to trip during a stable power swing
should be reviewed and considered, but not mandatory if deemed that protection will be sacrificed.
No
Out-of-step tripping and tripping for unstable power swings are intended results. Corrective Action
Plans are not needed for these events.
No
The graphs seem not to match the calculations.
Yes
No
Group
Duke Energy
Colby Bellville
Yes
Yes
Yes
Yes
Yes
Duke Energy agrees that this an improvement from the previous draft. However, we seek guidance
or clarification on the boundaries between PRC-026-1 and PRC-004-3. When Misoperations occur
due to a stable power swing, a CAP is required to be developed pursuant to R5 of PRC-004-3. Would
the evaluation and, if needed, Corrective Action Plan from PRC-026-1 R4 through R6 be acceptable
as use for the CAP required in PRC-004-3 R5?
Yes
Duke Energy agrees in part with the revisions made by the SDT on this project. However, due to the
amount of technical information provided in the Application and Guidelines portion of this standard,
more time is needed for our SME(s) to thoroughly review this section before submitting an
“Affirmative” vote.
Individual
David Thorne
Pepco Holdings Inc.
Yes
Yes
No
The 30 day time line provided for Requirement R2 in the standard to determine if an element
operated due to either of the Criteria provided seems aggressive. The shortest amount of time we
have to determine if a protective relaying scheme mis-operated under current quarterly reporting
requirements for PRC-004 is 60 days. It would make sense if the timeline for this standard was
adjusted to match. In addition, the requirement as written does not seem to differentiate if this level
of analysis is required for the operation of all in-scope protective relaying schemes or just those that
were determined to mis-operated. Requiring this level of study for all in-scope protective relaying
schemes would seem to provide a tremendous compliance burden to the Transmission Owners.
Yes
The requirement as written in the latest draft version of the standard is clear on what actions must
be taken. The 12 month timeline is reasonable.
Yes
The requirement as written in the latest draft version of the standard is clear on what actions must
be taken. The 12 month timeline is reasonable.
Yes
Yes
The 36 month time line is sufficient
No
Individual
Glenn Pressler
CPS Energy
Yes
No
In general,
No
In general,
No
In general,
No
In general,
No
In general,
Yes
support Luminant comments.
support PSEG comments.
support Luminant comments.
support PSEG comments.
support Luminant comments.
No
Group
ISO RTO Council Standards Review Committee
Greg Campoli
Yes
The Standards Review Committee (SRC) agrees with the removal of the Reliability Coordinator and
Transmission Planner; however, there remains concern that that entities could be exempted from
the standard by the linkage to Attachment A as it excludes Relay elements supervised by power
swing blocking. The SRC, therefore, recommends that the SDT assure all Applicability is explicit in
the Applicability Section of the standard and that exemptions or other criteria are not embedded in
Attachment A. (note CAISO does not support the response to Question 1)
Yes
The SRC agrees that the revisions improved the clarity of Requirement R1. However, to ensure
consistency with the other requirements within the Standard, the SDT recommends that
Requirement R1 also be broken into two (2) requirements, one addressing identification and one
addressing notification. Additionally, Requirement R1 should be changed to read: R1. Each Planning
Coordinator shall, for all design criteria events at least once each calendar year, identify each
Element in its area that meets one or more of the following criteria and provide notification to the
respective Generator Owner and Transmission Owner, if any: Finally, the SRC recommends the
following revision to Criterion 1 of Requirement R1 to streamline and ensure that the focus remains
on Remedial Action Schemes: 1. Generator(s) where an angular stability constraint exists that is
addressed by a Remedial Action Scheme (RAS) and those Elements terminating at the transmission
switching station associated with the generator(s).
No
The SRC notes that Requirements R2 and R3 are about notification if an element meeting specified
criteria is identified. However, the measures are primarily focused on identification. Accordingly, the
measures should be revised for consistency with the associated Requirements R2 and R3.
Yes
The SRC agrees that the revisions have provided clarity; however, notes the inconsistency within the
standard regarding describing GO and TO requirements separately in Requirements R2 and R3.
No
We agree with consolidating the Corrective Action Plan obligations into Requirements R5 and R6.
However, the SRC recommends that, for R5, Generator and Transmission Owners need more time to
develop a thorough CAP that addresses identified issues with load-responsive protective relays. The
requirement should provide at least 180 days to develop the Corrective Action Plan, which would will
allow for a more complete and thoughtful response than can be obtained in 60 days. Also under R5,
the Generator or Transmission Owner should provide a copy of the initial Corrective Action Plan and
status updates to the Planning Coordinator. Right now, the requirement is open ended without the
provision of Corrective Action Plan information.
No
The SRC notes that twelve (12) months is not adequate to prepare for this standard as written.
Accordingly, it is recommended that the drafting team revise the implementation plan to allow
twenty four months for implementation.
Yes
The SRC respectfully submits that the Purpose statement is unclear and inconsistent with the
requirements in the standard. More specifically, the requirements often refer to stable and unstable
power swings, but such are not addressed in the Purpose statement. This should be clarified. The
following revision is proposed. To protect against tripping by load-responsive protective relays in
response to stable and unstable power swings during non-Fault conditions. The SRC has concerns
with potential inconsistency between the Purpose statement and the time horizons. Specifically,
Requirements R2 and R3 have a time horizon defined as Long Term Planning while the Purpose of
the standard is about expected / forecasted responses. However, the verbiage of Requirements R2
and R3 requires action by the responsible entities within 30 days, which implies that the Time
Horizon should be, at most, the Operations Planning time frame. The SRC requests that the SDT to
review these requirements to assure they are consistent with the purpose of the standard, the Time
Horizons and any changes necessary to the Applicability section.
Group
Dominion
Connie Lowe
Yes
Yes
No
M3 seems to be missing the word ‘meet’; suggest M3 read as; M3. Each Generator Owner shall have
dated evidence that demonstrates identification of the Element(s), if any, which ‘meet’ the criterion
in Requirement R3. Evidence may include, but is not limited to, the following documentation: emails,
facsimiles, records, reports, transmittals, lists, or spreadsheets. Dominion agrees with the split of
R2, however, elements could have their load-responsive protective relays operate prior to the
formation of an island. In the Application Guide, a section should be included to better define
methods used for boundary detection, if we are required to determine if the element was in-fact the
boundary to an island. Otherwise, power swings could cause relays to operate without internal
detection algorithms picking up the swing.
Yes
No
No date is given for CAP implementation. Is it acceptable to work the CAP in with projects regardless
of project execution date? (3-7 years, if no project is in place at the specific location; is it acceptable
to implement the CAP once a project arises?)
No
Under Criterion R4, ‘Exclusion of Time Based Load-Responsive Protective Relays,’ the calculations
here are ambiguous. PRC-026-1 Attachment A explicitly states we are to evaluate protective
functions listed with a delay of 15 cycles or less; however, there is small section outlining the need
to calculate what sort of delays should be evaluated under different slip frequencies. Adding the
‘Exclusion of Time Based Load-Responsive Protective Relays’ section is counter-productive in its
current context. Dominion suggests that the SDT revise the section to make it more understandable
or remove it. No section discusses slip frequencies ranges. The WECC experiences 0.25-0.28 Hz
north-south oscillations, ERCOT experiences 0.6 Hz north-south and 0.3 Hz east-west, Tennessee to
Maine experiences 0.2 Hz oscillations, but Tennessee to Missouri experiences 0.7 Hz oscillations.
Roughly 0.01 to 0.8 Hz oscillations are associated with wide area oscillations, but 3.0 to 10 Hz
oscillations are associated with FACTS devices that may cause wide or local. What is the acceptable
range of oscillations this standard is meant to cover?
Yes
If R4 is a precursor for R5 and R6, R4-R6 should be included in the 36 month implementation plan.
Yes
No part of the standard discusses reasonable slip frequencies that should be used to detect power
swings. If we identify a relay that is susceptible to tripping for stable power swings (based on the
mho impedance characteristic overlapping a portion of the lens), apply a form of power swing
blocking, and then the relay operates again for a different frequency. Are we to go off the most
recent analysis? Slip frequency is an integral part to power swing detection and determination
between a swing and loading can be difficult. There should be some discussion about this topic in
conjunction with loading. Should a section discuss the correlation with PRC-023-2 requirement R2?
PRC-023-2 R2. Each Transmission Owner, Generator Owner, and Distribution Provider shall set its
out-of-step blocking elements to allow tripping of phase protective relays for faults that occur during
the loading conditions used to verify transmission line relay loadability per Requirement R1.
Group
JEA
Tom McElhinney
Yes
Yes
Yes
Yes
No
This standard is not necessary and we agree with the analysis of the NERC SPCS that it may have
unintended consequences which could decrease the reliability of the BES.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
These comments are submitted on behalf of the following PPL NERC Registered Affiliates: LG&E and
KU Energy, LLC; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; PPL Generation, LLC; PPL
Susquehanna, LLC; and PPL Montana, LLC. The PPL NERC Registered Affiliates are registered in six
regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more of the following NERC functions:
BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP.
No
The process of PCs annually performing an analysis and notifying TO/GOs of applicable Elements per
R1, and of TO/GOs then evaluating these Elements per R4, should be clarified to note that where
relays meeting criteria 1-3 of R1 are on the PC’s list year after year a new evaluation is not required
each time unless conditions have materially changed (threshold TBD by the SDT).
No
R4 should state that the 12-month clock for GOs begins when the TO provides the system
impedance data necessary to perform studies, if the GO requests this information from the TO. Also,
the reference to, “full calendar months,” in R4 and Att. B should be changed to just, “calendar
months,” to prevent confusion.
No
: The deadline of 60 calendar days for development of a Corrective Action Plan should be changed to
six months. Many GOs do not have Protection System design expertise, and the process of making a
business case for the expenditure of hiring a contractor, getting this request approved, exploring
alternatives, making a technical selection and again obtaining management approval can take far
more than sixty days.
Individual
Jamison Cawley
Nebraska Public Power District (NPPD)
Yes
No
The PSRPS Recommendations Section states that the SPCS determined a Reliability Standard is not
needed.
No
Both R2 and R3 requirements appear to take a “wait and see” approach rather than a proactive
approach. This doesn’t seem practical when maintaining the reliable operation of the BES. We
recommend elimination of both R2 and R3. Additionally, R2 states that the TO would need to identify
“an Element that forms the boundary of an island during an actual system Disturbance due to the
operation of its load-responsive protective relays.” This type of event would be very complex and
would likely include many contingencies. Thus the statement seems too general and allencompassing. We feel this reliability function might be better served by the Planning Coordinator(s)
or Reliability Entity facilitating an event analysis where better decisions and recommendations can
be made, given their wide-area view and awareness of reliability issues. If a relay did trip on OOS
for a stable power swing, the likelihood of it being part of a larger event or a misoperation is high. If
it were a misoperation, it would then be addressed in another standard or event analysis process. As
noted above it seems R2 and R3 are better served by existing processes or standards.
Yes
Yes
We agree that separation of the CAP requirement is an improvement; however, we feel there should
be a caveat to this requirement. The standard as written could result in reduced sensitivity of fault
detection settings, which would interfere with “maintaining dependable fault detection”. We believe
there should be an option to maintain our ability to operate the BES in a reliable manner and still
remain in compliance with R5. This requirement seems like double-jeopardy.
Yes
Yes
Yes
We are curious why the PC is allowed 1 year to identify elements while the industry is allowed 30
days after a disturbance to identify elements. This does not seem practical in comparison with the
timelines used with other reporting requirements. For example, PRC-004 has quarterly submissions
with 2 additional months after the quarter end; the new PRC-004-3 allows 120 days just to identify
if an operation was a misoperation, root cause determination is not included in that timeframe. In
fact, PRC-004-3 includes no set timeline to determine cause, simply a requirement to actively
investigate by indicating active investigation every two calendar quarters until a cause is determined
or no cause can be found. An out-of-step analysis is more complex, so it would be logical to allow
longer time horizons for this type of investigation and identification, perhaps no less than an annual
interval which would match the PC. Additional clarification on two items is requested: 1) If a relay
has out of step tripping and blocking enabled, does this mean it is excluded from the standard? 2) If
a relay has out of step blocking enabled, does this mean it is excluded from the standard? In
addition to these comments, we support the comments provided by SPP.
Individual
John Merrell
Tacoma Power
Yes
Yes
Yes
Yes
Yes
No
In the Application Guidelines, in the discussion of Figure 11, suggest changing “...thus allowing the
zone 2 element to meet PRC-026-1 – Attachment B, Criteria A” to something like the following:
“...thus allowing the zone 2 element to meet PRC-026-1 – Attachment B, Criterion A. However,
including the transfer impedance in the calculation of the lens characteristic is not compliant with
Requirement R4.” Similarly, update the Figure 11 caption to indicate that the calculation is not
compliant with Requirement R4. In the Application Guidelines, in the discussion of Requirement R5,
the statement “that all actions associated with any Corrective Action Plan (CAP) developed in the
previous requirement [Requirement R4]...” is incorrect. Requirement R4 does not have anything to
do with a CAP.
Yes
Yes
For Requirement R2, consider defining ‘island’ or adding a footnote clarifying the intent of the word.
This requirement should not apply to portions of the system containing both generation and load
that become isolated from the BES but that are not intended to operate apart from the BES. For
example, perhaps there are parallel lines that interconnect one or more remote generation plants
and some load to the rest of the system. It is doubtful that the drafting team intended to include
these types of scenarios as ‘islands’. Should POTT and DCB schemes be specifically called out in
Attachment A as being applicable to PRC-026-1? Attachment B Criterion B may yield current that is
above the phase time overcurrent pickup but, at this level of current, the phase time overcurrent
element may take longer than 15 cycles to operate. Therefore, the approach in Attachment B
Criterion B is potentially conservative. The Response to Issues and Directives still mentions that
“...the proposed standard does require that an Element that was part of a boundary that formed an
island since January 1, 2003 be identified as an that is within the scope of the proposed standard.”
Individual
David Jendras
Ameren
Yes
Yes
No
Ameren adopts the following comment submitted by PSEG. R2 and R3 require TOs and GOs,
respectively, to notify their Planning Coordinator within 30 days of identifying any Element that trips
due to a power swing during a system disturbance due to the operation of load-responsive
protective relays. PRC-026-1, as drafted, will have consequences with respect to an entity’s
implementation of a different standard: PRC-004-3 - Protection System Misoperation Identification
and Correction – see http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-004-3.pdf. NERC
has filed PRC-004-3 with FERC for approval. In summary, PRC-004-3 requires each operation of an
interrupting device to be evaluated to determine whether a Misoperation occurred. If such a
determination is made, the Protection System owner must investigate the occurrence and either (a)
provide a declaration that a cause could not be determined or (b) if a cause is determined, develop
and implement a Corrective Action Plan (CAP) or explain why corrective actions are beyond its
control or would not improve reliability. PRC-004-3 does not require any action with regard to
Element trips that are not Misoperations, i.e., “correct operations.” We understand that a Protection
System owner would need some documentation to make the distinction between a correct operation
and a Misoperation. However, in order to be fully compliant with PRC-026-1 R2 and R3, every
Element that trips due to the operation of a load-responsive relay must be evaluated by the entity to
determine whether or not the trip was due to a power swing. As discussed on the September 18
webinar on PRC-026-1, the phrase “system Disturbance” has same meaning as the NERC Glossary
term for “Disturbance.” In other words, “system” is unnecessary. In addition, a “Fault” was stated to
be a “Disturbance.” Therefore, every operation of a load-responsive relay due to a Fault must be
examined under PRC-026-1 to identify whether or not the Element tripped due to a power swing. •
If an Elements trips due to a Misoperation, the Misoperation would be investigated under PRC-004-3,
and if it was caused by a power swing that could easily be reported under PRC-026-1 as a result of
the Protection System owner’s compliance with PRC-004-3. Requiring all correct operations be
affirmatively evaluated by the Element owner to determine whether they are attributable to a power
swing would only “make work” for both the Element owners and their auditors, and the added effort
would not improve reliability. Therefore, we propose that the scope of R2 and R3 for correct
operations be reduced to a subset of events that are reported to NERC under EOP-004-2 – Event
Reporting – see http://www.nerc.com/pa/Stand/Reliability%20Standards/EOP-004-2.pdf . For
example, the Disturbances evaluated in PRC-026-1 for correct operations could be limited to some of
the events and associated thresholds listed in EOP-004 - Attachment 1. We believe reasonable
events would include: • Automatic firm load shedding on p. 9 • Loss of firm load (preferably limited
to non-weather related load loss) on p. 10 • System separation (islanding) on p.10 • Generation loss
on p.10, • Complete loss of off-site power to a nuclear plant on p. 10, and • Transmission loss on
p.11. To couple the two standards together, NERC, which receives event reports under EOP-004-2,
would need to notify the applicable TOs and GOs under PRC-026-1 of the time frame of each event.
This would allow the Element owners to evaluate whether any Element trips that occurred during the
event and which were correct operations were associated with a power swing.
Yes
No
Ameren adopts the following comment submitted by PSEG. The requirement to develop a CAP in R5
should be amended to allow the Element owner, in lieu of a developing a CAP, to make a declaration
that corrective actions would not improve BES reliability and therefore will not be taken. This is
consistent with PRC-004-3, R5.
Yes
Yes
Yes
We appreciate the SDT’s significant improvements in this draft 2. Our response to question 3 above
captures our primary reason for voting negative.
Individual
Joe O'Brien
NIPSCO
No
We would prefer that the 12 month implementation plan for R1-R3, R5, R6 be set to 24 months; this
is based on the related burden of implementing PRC-025-1.
Individual
Michael Moltane
ITC
Yes
Yes
Yes
Yes
No
A “no CAP declaration” should be added to R5. This option is necessary when enabling power swing
blocking affects the BES reliability. An example is for a Slow Trip – During Fault, in which the highspeed protection scheme has been identified to meet the dynamic stability performance
requirements of the TPL standards. As ITC stated in Draft 1, we are concerned about load/swings
with subsequent phase faults which result in time-delayed tripping when power swing blocking is
enabled.
No
The R2 example of an island forming is insufficient. Suppose a line includes tapped load and a
tapped generator, does this form an island if the line ends trip for a phase fault? R2 Criteria 2 does
not exclude this example, therefore it should be discussed in Application Guidelines and Technical
Basis.
Yes
Yes
In R2, add reference to Attachment A when describing the load-responsive protective relays. R2
Criteria 2 adds no value and should be removed. All Elements which trip due to swings will be
captured under Criteria 1. Criteria 2 only includes islands formed due to phase faults and adds no
value. If you intend to capture boundaries of all islands formed, then remove the “due to the
operation of its load-responsive protective relays” qualifier. If you intend to capture boundaries of all
islands formed due to protective relay operations, then remove the “load-responsive” qualifier.
Application Guidelines, page 63, Application to Generation Elements, change the language to include
generator relays, if they are set based on equipment permissible overload capability. “Loadresponsive protective relays such as time over-current, voltage controlled time-overcurrent or
voltage-restrained time-overcurrent relays are excluded from this standard [if] they are set based
on equipment permissible overload capability.” Application Guidelines, page 72, the first paragraph
under Requirement R5 is more appropriate under Requirement R6.
Individual
Karin Schweitzer
Texas Reliability Entity
No
Texas Reliability Entity, Inc. (Texas RE) has concerns regarding the removal of the Reliability
Coordinator (RC) from the applicability, particularly for Criteria 1 and 2 of R1. The time horizons that
the Planning Coordinator (PC) and RC evaluate are different, with the Planning horizon being > 1
year and the Operations horizon being real-time to < 1 year. When the SDT removed the RC from
the applicability, the Operations Planning time horizon was also removed; however, there is still
language within Criteria 1 and 2 of R1 addressing angular stability constraints as monitored as part
of a System Operating Limit identified in operating studies. Operating studies are not typically
conducted by the PC but are conducted by the RC. Based on the language in the Criteria, it is
unclear to Texas RE whether the intent of the standard is to only identify elements at risk in the
Long-term Planning horizon or to identify elements at risk in both the Operations horizon and the
Long-term Planning horizon. Texas RE requests clarification on this issue from the SDT. Please also
see our comments to Questions 2 and 3 regarding time horizon concerns.
Yes
While Texas RE agrees with the approach of using criteria from the PSRPS technical document, we
have concerns about the stated time horizon. Requirement R1 Criterion 2 states that the PC should
include elements identified in operating studies, but the time horizon for this requirement is Longterm Planning. Texas RE suggests that either the Operations Planning time horizon needs to be
added to this requirement or the reference to operating studies needs to be removed, whichever is
in line with the intent of the SDT.
Yes
While Texas RE agrees with splitting the previous Requirement R2 into Requirement R2 for the
Transmission Owner (TO) and Requirement R3 for the Generator Owner (GO) for clarity, we have
concerns regarding the stated time horizon. Requirement R2 states that the TO shall notify the PC
within 30 calendar days of elements that trip due to an actual disturbance, but the time horizon for
this requirement is Long-term Planning (which is a planning horizon of one year or longer.) Texas RE
suggests that the time horizon should be Operations Planning. Requirement R3 states that the GO
shall notify the PC within 30 calendar days of elements that trip due to an actual disturbance, but
the time horizon for this requirement is Long-term Planning (which is a planning horizon of one year
or longer.) Texas RE suggests that the time horizon should be Operations Planning.
Yes
No comments.
Yes
No comments.
Yes
No comments.
Yes
No comments.
Yes
Texas RE suggests that the PRC-026-1 SDT refer this standard to the Project 2014-01 SDT (if not
done already) for consideration regarding the applicability of BES generators to include dispersed
generation resources so the requirements of the standard pertain primarily to the point of
connection where the resources aggregate to 75 MVA or more, and not to the individual resources.
Since this is a new standard it is not currently included in “Appendix B: List of Standards
Recommended for Further Review” from the draft white paper entitled ”Proposed Revisions to the
Applicability of NERC Reliability Standards NERC Standards Applicability to Dispersed Generation
Resources.”
Group
Florida Municipal Power Agency
Carol Chinn
No
FMPA is comfortable with the removal of the Reliability Coordinator and Transmission Planner,
subject to comments we are making on R2, R3 and in response to question 8.
Yes
No
Requirements R2 and R3 need further clarification. FMPA agrees that splitting the Requirement was
beneficial. However, FMPA finds the following issues left requiring resolution, which point to the need
to better coordinate this standard with PRC-004: 1. The language is crafted as if a typical TO or GO
would easily be able to determine that an element tripped due to a power swing. This only makes
sense for large vertically integrated utilities in which staff with a variety of knowledge bases and skill
sets may be working together. In reality, for smaller utilities that may be only a TO/DP or GO, this
determination will require some involvement from a TP, PC, TOP, or RC, with staff that have a)
access to real time information, event records, and other information beyond what any single TO or
GO may have and b) an understanding of the expected regional stability performance which TO/GO
staff may not have. Realistically it should only be presumed the TO or GO staff will be able to
conclude that their relays did not trip for a fault. 2. The standard sets a 30 day clock which starts
with a piece of information that isn’t required or driven from anywhere – namely, the point in time
at which at TO or GO discovers that any relay operated (either correctly or incorrectly) due to a
power swing. Since there is currently no place where it is required that correct/proper relay
operation be documented, it is not clear what sort of documentation the TO/GO will have and what
process, performed by what staff, would drive the TO/GO to “initially discover” that the relay
operated due to a power swing. The point being- in a normal PRC-004 investigation, at such time as
it is discovered that a relay properly operated, there is no requirement for any formal report, on any
formal schedule, to include that information. At what point does the “official” starting point of this 30
day clock occur? This points to the need for further/better coordination with PRC-004.
No
See comments in response to Question 8 related to Applicability and responsibility for various
requirements.
No
FMPA agrees with the separation of R5 and R6. However, R5 pre-supposes and furthermore directs
that the only acceptable Corrective Action Plan is one which involves modifying the Protection
System. There are a number of other ways to improve stability performance which are therefore
ruled out. In fact, improving the performance to, and reducing the severity of power swings that
result from a given event should be a preferential solution as it has a much wider impact on the
stability and the reliability of the system. It may be true that modifications to microprocessor relay
settings or even replacement of relays might be the least cost or the fastest and simplest solution,
that in no way should dictate that the standard should mandate this be the only corrective action
employed.
No
FMPA commends the drafting team on the amount of material that has been developed to support
the Application of this standard. The various examples used in the Application Guide are generally
good example scenarios. However, the focus of the Guide seems to be more on repetitive
demonstration of basic equations and less on the SDT’s expected interpretation of various scenarios.
One full sample of all the calculations in one scenario is all that is required. Each time the equations
are repeated it takes roughly 11 pages. In general there are a lot of pages of basic equations and
very little “guidance” within the examples. Furthermore, the examples seem to have been developed
to make a supporting case for the Criteria of Attachment B but there is no true discussion of how
these examples should be interpreted to support the Criteria. An easy example of this is Table 10,
where the impact of the system transfer impedance on the lens characteristic is tabulated, but there
is no use of that data to explain why all transfer impedances, no matter what the magnitude, should
be completely ignored. The data is there, but the expectations regarding interpretation of the data
are more important, and these are missing. A couple of additional issues that FMPA believes should
be cleaned up. • The first full paragraph of Page 28 of the Application Guidelines describes the
modeling of generator reactances in stability models, but there is no segue regarding why this
information was presented. Please clarify that the intent of the paragraph is to make it clear that the
reactances that are used by TP’s/PCs (unsaturated reactances) may not be the same reactances as
the ones that are being recommended for use in the application of the criteria (saturated
reactances). • The Application Guide makes frequent reference to “pilot zone 2 element” in the
figures. Strictly speaking the figures show an example of a “distance” or “impedance” mho relay
characteristic curve. The term “pilot” refers colloquially in protection to a communication assisted
scheme, which may be used in conjunction with a mho characteristic or may not. The use of this
term introduces confusion because Attachment A specifically excludes “pilot wire relays”, which are a
specific sub-set of transmission relay that does not use a mho characteristic.
No
The Implementation Plan does not offer compelling evidence that the implementation date for R5
and R6, which are driven exclusively by R4, should be set at 12 months from approval while R4 is at
36 months from approval. Setting R5 and R6 earlier than R4 instead of allowing them to be parallel
to R4 introduces circuitous logic as now the language of these Requirements appears to require R4
to be completed early…There does not appear to be any value in setting R5 and R6 at 12 months
when there is nothing to measure compliance with them against – the implementation plan explains
the 12 months to is to allow entities to develop “internal processes and procedures”, but the
Requirements do not require such procedures nor are these listed in the measures.
FMPA would like to commend the SDT for developing an overall process that is generally reasonable
and does not, in our opinion, add an excessive compliance burden, since the number of identified
circuits and generators should be small. However, we believe more work is required to make the
concept the SDT has come up with successful. 1. First, as mentioned in earlier sections, the standard
is in general written with the perspective of large vertically integrated utilities in mind, and does not
consider the impact on non-vertically integrated TOs and GOs. As such, we believe there is further
coordination that needs to be developed between this standard and PRC-004, that will a) facilitate
communication between PCs, TPs, TOPs, the RC, and respective investigating TOs and GOs and b)
will establish a clear timeline that can cleanly be audited for R2 and R3. As stated in our comments
above on R2, the requirements for keeping records for “correct” relay operations are effectively nonexistent in current standards. FMPA believes it makes sense for all “investigations” and associated
records to occur within PRC-004 and then for “power swing” related activities to occur in PRC-026.
Currently power swings are only discussed in PRC-004 as they relate to failure to trip or slow trip
conditions (and not where operation for a power swing was correct). Furthermore there is presently
no acknowledgment that GOs and TOs may need assistance and information from their TPs, PCs,
associated TOP, or even RC. 2. The Applicability section refers to GO’s and TO’s that apply load
responsive relays to Generators, Transformers, and Transmission Lines. FMPA sees three issues
related to this. a. First, all language in the standard Requirements refers to Elements instead of
Facilities – based on previous comments and the SDT’s response to those comments, the standard
Requirements should be referring to Facilities to draw focus to the BES distinction, which does not
exist for Elements. b. Second, the identification of issues and tracking of issues from entity to entity
is based on Elements. This works from the perspective of identification of risks to the system but
falls short when it comes time to evaluate and modify the Protection Systems, because no
Requirement refers back to the Owner of the Protection Systems applied on the Elements identified
in R1. Instead, Requirements 2 and 3 are directed at the Owner of the Element itself which may or
may not own the Protection System that is actually at risk of operating (or misoperating). The
Requirements need to consider this relationship similar to PRC-004-3. c. Third, it is quite possible for
protective relays applied on a substation bus section or on FACTS devices to be susceptible to power
swings, and in fact, in cases of intentional system separation schemes, this may be an intentional
design (e.g splitting a substation bus when one or a group of transmission lines exceed a measured
condition). The Facilities section does not include such Elements. 3. FMPA is concerned the
conditions under which Criteria A is being calculated may be excessively conservative. Item 3 of the
Criteria states “Saturated (transient or sub-transient) reactance is used for all machines.” Note the
term “all”, which could be confusing if an entity is not considering the context. The documentation
presented does not discuss terms such as “maximum generation dispatch” or any other term that
would relate back to a realistic number of generators being in service. The requirement should be
“all machines that are in service in short circuit model”, and in the Application Guide there should be
some discussion on using maximum reasonable generation dispatches in short circuit cases.
Similarly, but of less consequence, it is not clear that the Transfer Impedance should always be
completely neglected. While this is certainly numerically convenient, FMPA wonders if this does not
produce overly conservative results in cases of well-networked transmission. Would it not be more
prudent to remove other transmission circuits which have significant transfer distribution factors
relative to the line in question, and then re-calculate the transfer impedance, rather than assuming
some exceedingly large number of transmission outages has occurred? This relates to the comment
above that some discussion should be offered surrounding Table 10 in the Application Guide. 4. As
written, the combination of Requirement R4 (which instructs the TO/GO to “evaluate” its relays
against the “Criteria” in Attachment B) and the Criteria in Attachment B, make no definitive
statements about what relays “meet” anything, or “are deficient and require corrective action plans”
etc. Requirements and Criteria should be very clear and straight forward. The “Criteria” is really just
a description. There is no information in the Requirement or in the Attachment that actually involves
making a “judgment” which is the most important part of the definition of the term Criteria. FMPA is
well aware of the intent of these two items and only wishes to point out that the intent is really only
made clear in the Application Guidelines.
Group
DTE Electric Co.
Kathleen Black
Yes
Yes
Yes
No
R4 is clearer in general terms, however, the Criterion and related Guidelines and Technical Basis do
not cover all the various relay scheme configurations that may apply. Since specific criteria must be
evaluated, the concern is that relay scheme configurations not discussed may result in an incorrect
evaluation.
Yes
No
While considerable discussion and examples have been provided, there are variations in relay types
and schemes that are not specifically covered. Perhaps these variations could be submitted at some
point for review and application guidance.
Yes
No comment
Yes
Will this Standard result in any conflicts with PRC-019 or PRC-025 while meeting protection goals in
setting generator relays?
Individual
Muhammed Ali
Hydro One
Yes
Yes
Yes
Please refer to comments for 6.
Yes
Yes
This section now provides clarity for each of the requirements in the standard. However, for
Requirement 4, the “Application Guidelines and Technical Basis,” section does not provide direction
on how to treat multi-terminal configurations (specifically 3-terminal). Providing guidance on how to
approach multi-terminal configuation would be helpful.
Yes
Individual
Ayesha Sabouba
Hydro One
Yes
Yes
Yes
Refer to 6.
Yes
No
This section now provides clarity for each of the requirements in the standard. However, for
Requirement 4, the “Application Guidelines and Technical Basis,” section does not provide direction
on how to treat multi-terminal configurations (specifically 3-terminal). Providing guidance on how to
approach multi-terminal configuation would be helpful.
Yes
Individual
Jo-Anne Ross
Manitoba Hydro
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Group
FirstEnergy Corp.
Richard Hoag
Yes
Yes
FirstEnergy suggests a slight modification to the wording of R1 Criteria 5 for clarity, as follows: “An
Element reported by the Transmission Owner pursuant to Requirement R2 or Generator Owner
pursuant to R3, unless …”.
Yes
Regarding R3, as a Generator Owner in a deregulated / competitive environment, we still have a
concern about being held accountable for events for which we are unaware – power swings or
Disturbances on the system (Criteria 1) – due to FERC Code of Conduct separation with the
regulated system. We are not aware of system events. We realize, however, that R3 says, “… within
30 calendar days of identifying …”; the concern simply relates to the level of responsibility placed on
the GO to “identify” tripping of load-responsive relays caused by “… a stable or unstable power
swing during an actual system Disturbance …”.
No
Attachment B, Criteria A and B might be clearer to a Protection Design Engineer, but are not likely
clear to typical compliance personnel.
Yes
Assuming a situation results in the need for a CAP, what is the purpose of stating that dependable
fault detection (and out-of-step tripping if applied) shall be maintained while developing the CAP?
Maintenance and testing of protection is covered in PRC-005, and any failure of existing protection is
addressed by PRC-004. Why is there further need to address maintaining existing protection, and
how is such a requirement measured in the context of PRC-026-1? Also, what is the anticipated
mechanism for tracking and reporting progress on a CAP?
Yes
Yes
No
Individual
Dixie Wells
Lower Colorado River Authority
Yes
Yes
Yes
The splitting of requirement for GO and TO was good. It would be more clear if R2&R3 can directly
refer to the protective elements being addressed in Attachment A are the elements to look into when
power swings (stable/unstable) occurs. Also, listing some particular in events that power swings
would happen can be helpful.
No
see comments for R4 under application guidelines.
No
R5(part of the previously R3), missed the alternative options in previously R3 which allows entities
owner to obtain agreement from planning coordinator, if a dependable fault detection or out of step
tripping cannot be achieved. R5 in application guideline asks to “develop” and “complete” the CAP,
while R5 in the standard only ask to “develop” within 60 cal day time period. It’s ambiguous with R6
in the standard which asks to ”implement” the CAP without any specific time period . And i assume
this is to allow the “implementation” to be occur during next available plant outage.
No
see comments for application guidelines. It would be helpful to include out of step examples for the
GO and TO.
Yes
No
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
Yes
Yes
Yes
Yes
Yes
Yes
Group
Tennessee Valley Authority
Dennis Chastain
Yes
Yes
The addition of criteria 5 seems circular in that the PC is notifying the GO or TO about Elements they
already know about. If the PC’s analysis applying criteria 1-4 does not identify these Elements
initially, why should the same PC criteria be entrusted to determine that “the Element is no longer
susceptible to power swings”?
Yes
No
While an improvement over the previous draft, we believe the time interval for consideration of
previous evaluations should be extended to the prior five calendar years. We also would prefer to
see more flexibility in the standard to allow entities to use their preferred methods (not strictly
adhering to Attachment B criteria) for determining if a line is likely to trip during a stable power
swing.
Yes
Group
Santee Cooper
S. Tom Abrams
No
There seems to be some overlap between PRC-004 and R2 and R3 of this standard (PRC-026). For
compliance with PRC-004, entities have to analyze all operations in order to prove that all
misoperations are identified. To identify an Element that (according to R2 and R3 of PRC-026) “trips
due to a stable or unstable power swing during an actual system Disturbance due to the operation of
its load-responsive protective relays,” a similar proof could be required, that all trips of load
responsive relays were evaluated under a criteria to rule out operation due to stable or unstable
power swings. The listed Rationale for R2 gives mention to the review of relay tripping is addressed
in other NERC Reliability Standards, so there seems to be a nod given to PRC-004, but it should be
clearer as to the interrelationship between these standards. Significant confusion could result if the
interrelationship or dividing line (whichever is more appropriate) between these two standards is
defined further. Will compliance with R2 and R3 of PRC-026 only involve having the data for the
operations determined to be caused by power swings, or will it require data that entities provide
documentation of the evaluation each operation for power swing implications?
Individual
Jason Snodgrass
Georgia Transmission Corporation
Yes
No
Recommend further clarity and a revision to R1 criteria 1 such as: From this: Generator(s) where an
angular stability constraint exists that is addressed by an operating limit or a Remedial Action
Scheme (RAS) and those Elements terminating at the transmission switching station associated with
the generator(s). To this: Generator(s) and those interconnecting Elements terminating at the
transmission switching station associated with the generator(s), where an angular stability
constraint exists that is addressed by an operating limit or a Remedial Action Scheme (RAS).
Yes
Yes
Yes
Yes
Group
SPP Standards Review Group
Shannon V. Mickens
Yes
Thank you for removing the Reliability Coordinator function. The Reliability Coordinator has no place
in this standard.
No
In light of the fact that the purpose of this standard is “To ensure that load-responsive protective
relays are expected to not trip in response to stable power swings during non-Fault conditions”
which is in agreement with the FERC Order 733 (Section 150 of the FERC Order: “requires the use of
protective relay systems that can differentiate between faults and stable power swings and, when
necessary, phases out protective relay systems that cannot meet this requirement”), it is an
unnecessary extension of the Order to include unstable power swings. The Standard Drafting Team
stated “The phase “stable or unstable” was inserted to clarify that both are applicable to power
swings because the goal of the standard is to identify Elements susceptible to either” overreaches
the FERC Order. We recommend that the term ‘Unstable Power Swing’ be removed from the
standard.
No
What is the difference between ’12 full calendar months’ and ‘12-calendar months’? Delete the ‘full’
in Requirement R4. In the 3rd line of Requirement R4, change ‘Requirement’ to ‘Requirements’.
Refer to our comments in Question #2 as to why we don’t agree with the revisions.
No
Insert a ‘to’ between ‘pursuant’ and Criterion’ in the 3rd line up from the bottom of the paragraph on
Criterion 1. In the 9th line in the 1st paragraph under Criterion 4, capitalize ‘Criterion’. In Figures 1
and 2, change ‘Criterion five’ to ‘Criterion 5’. In the 7th line of the paragraph following Figures 1 and
2, change ‘included’ to ‘include’. In the 8th line of the paragraph under Requirement R4, delete ‘full’
and hyphenate ’12-calendar’. In the 5th line of the 2nd paragraph under Exclusion of Time Based
Load-Responsive Protective Relays, insert ‘degrees’ between ‘120’ and ‘before’. In the 3rd line of the
paragraph immediately following Table 1, capitalize ‘Zone’. In the 15th line of the same paragraph,
delete the same phrase in the parenthetical. In the 4th line of the paragraph following Equation (3),
replace ‘plus and minus’ with ‘±’. Capitalize ‘Zone 2’ in the captions of Figures 10, 11, 12, and 15. In
that same paragraph, capitalize ‘Zone 2’. In the last line of the 2nd paragraph under Application to
Generation Elements, replace ‘Requirement’ with ‘Requirements’. Capitalize ‘Zone 2’ in the 1st line of
Example R5a. Capitalize ‘Zone 2’ in the 1st line of Example R5c.
No
We have a concern that the Implementation Plan doesn’t reflect the changes mentioned by the
drafting team in their response to our comments on Question 4 in the previous posting. That
response states ‘The drafting team increased the Implementation Plan to three years to provide for
the initial influx of identified Elements under Requirement R1. The evaluation of relays under
Requirement R4 previously R3) is to be performed “within 12 full calendar months of receiving
notification of an Element… where the evaluation has not been performed in the last three calendar
years.” Change made’. We request clarification on why this change doesn’t appear in the current
proposed standard and Implementation Plan.
Delete the reference to PRC-026-1 in 4.1.1 and 4.1.3 in the Applicability section. Leave the
references simply as Attachment A. Delete ‘This’ in the 1st line of the 4th paragraph under 5.
Background:. At the end of the 6th line and beginning of the 7th line in the same paragraph, delete
‘of security’. Hyphenate 30-, 60-, 90-calendar days and similar construction with calendar months
throughout the standard. At the end of each of the first three bullets in 1.2 Evidence Retention the
phrase ‘following the completion of each Requirement’ appears. Since each bullet only refers to one
requirement what does this phrase mean when applied to Requirements R1, R2 and R3 individually?
Why is the timing for notification in the VSLs for the Transmission Owner in Requirement R2 and the
Generation Owner in Requirement R3 different from that for the Planning Coordinator in
Requirement R1? Shouldn’t they be the same? We recommend that all changes made to the
standard be reflected in the RSAW as well.
Individual
John Brockhan
CenterPoint Energy
Yes
No
CenterPoint Energy recommends additional clarification be provided for identifying and the reporting,
or not reporting, of Elements that trip from power swings during system disturbances. We believe
certain tripping should be excluded, such as, when reconnecting islands and during black start
restoration. We suggest the following sentence be added to Requirement R1, Criterion 1:
“Notification shall not be provided if an Element trips from a power swing that occurs during
operator-initiated switching to reconnect islands, to restore load during Black Start activities, or to
synchronize a generating unit to the system”. In addition, it may be needed to clarify that tripping of
Elements from voltage or frequency oscillations due to power system stabilizer issues are not to be
reported.
No
CenterPoint Energy recommends that requirements for Corrective Action Plans (CAP) be removed in
the draft PRC-026-1 standard. The operation of a Protection System during a non-fault condition due
to a stable power swing would be a reportable Misoperation under PRC-004. Both the current
enforceable version of PRC-004 and the one under development require a CAP for a Misoperation.
Consistent with one of the recommendations from the NERC Industry Experts initiative, CenterPoint
Energy believes that there should not be duplicative requirements in NERC Reliability Standards.
Yes
CenterPoint Energy recommends removing references to “unstable” power swings in the draft PRC026-1 standard, as we believe tripping from unstable power swings is random and not indicative of
an Element being more susceptible to a stable power swing. Where tripping actually occurs for an
unstable power swing is dependent on the location and nature of the event, system conditions, and
where additional Element outages occur during a disturbance. We are not aware of any available
technical information or analysis to justify that an Element is more susceptible to a stable power
swing if it has tripped from an unstable power swing.
Group
Seattle City Light
Paul Haase
No
Seattle City Light is not convinced that this Standard is warranted, and does not find comfort in the
tortured process associated with developing the recommendations of the PSRPS document. The
changes, as far as they go, do add some clarity to R1.
Yes
Yes
Seattle appreciates the effort of the drafting team to separate auditable activities into an individual
requirement or subrequirement rather than blending them together.
Yes
Seattle appreciates the effort of the drafting team to separate auditable activities into an individual
requirement or subrequirement rather than blending them together.
No
Seattle appreciates the efforts of the drafting team to provide application guidance and technical
basis information and welcomes the trend towards such implementation documentation throughout
the standards development process. For PRC-026, this material has improved somewhat compared
to the original draft, but application of the standard remains insufficiently clear for Seattle to
recommend an affirmative ballot at this time. More examples and/or a flow chart or something
similar to fully delineate the steps in the process are wanted.
Individual
Sergio Banuelos
Tri-State Generation and Transmission Association, Inc.
Yes
Yes
Yes
Yes
Yes
The requirement to develop a CAP in R5 should be edited to allow the owner to make a declaration
that corrective actions would not improve BES reliability if that is the case and therefore action will
not be taken. This is consistent with PRC-004-3, R5.
No
The “Exclusion of Time Based Load-Responsive Protective Relays” on p 25 indicates that time
delayed Zone 2 and Zone 3 relays are intended to be excluded from this standard. However, many
of the figures reference Zone 2 relay compliance or non-compliance; in particular, see Figure 10.
That seems to imply that the Zone 2 relays in the example do need to comply with this standard. If
we are told that time-delayed relay elements are to be excluded, does this imply that the Zone 2
relay is being used in a directional comparison blocking (DCB) scheme? If so, should that not be
clearly identified? (Only Figures 3 and 12 identify the element in question as being a pilot Zone 2,
and pilot could refer to may schemes that would not be impacted by extending beyond the defined
impedance boundary). Similar to that example would be the use of Zone 2 relay elements to assert
permission in a permissive overreaching transfer trip (POTT) scheme. It is likely that Zone 2 relay
elements in a POTT scheme could extend beyond the impedance characteristic defined in Attachment
B, but the only regions that would result in tripping in less than 15 cycles are the overlapping Zone 2
regions that result in POTT scheme activation, which would most likely be fully contained in the
region defined in Attachment B. Tri-State believes that a statement or example clarifying that such a
protection system is compliant would be beneficial to applicable entities as well as the compliance
monitoring entities.
Yes
No
Group
ACES Standards Collaborators
Jason Marshall
Yes
(1) We largely agree with the applicability changes. We thank the drafting team for removing
Transmission Planner and avoiding the confusion that has occurred in so many other standards from
joint responsibility to meet the same requirements as the PC. (2) We are concerned with the
removal of the RC. Per the SDT’s response to our comments regarding which SOLs (planning horizon
is covered FAC-010 and operating horizon is covered in FAC-011), the SDT indicated that they
intended for both to apply. Since the SOL methodology that applies in the operating time horizon is
written by the RC, the PC may not be familiar enough with the RC’s methodology to determine which
operating horizon SOLs are due to angular stability. Wouldn’t it be easier for the RC to notify the PC
of those operating SOLs caused by angular stability?
No
(1) We agree that the clarity of Requirement R1 is improved but we still have a couple of concerns.
(2) Why is the PC required to notify the GO and TO of Elements that were involved in actual events
when the GO and TO are the entities that notify the PC in the first place? Doesn’t the PC just need to
notify the GO and TO when those Elements are no longer susceptible to tripping from stable power
swings? (3) In Criterion 4, why are unstable power swings included? Elements should trip due to
unstable power swings. Why does the GO and TO need to modify relaying for unstable power
swings? Since PRC-006 only requires the PC to simulate the UFLS Program every five years, it seems
that requiring the PC to identify the same Elements that form a UFLS island boundary every year is
unnecessary. Criterion 3 should be modified to clarify that this notification is only necessary once
every five years when the UFLS study is completed.
Yes
(1) We agree with splitting the requirements because the GO simply is not privy to the same
information as the TO to identify island boundaries. However, it is reasonable for the GO to work
with the TO and TOP to determine the cause of the relay operations to be from a stable power
swing. (2) We believe the time horizons for both requirements R2 and R3 need to be modified. Both
are currently long-term planning which is one year or longer into the future. Since this is an
evaluation of actual events, we believe the Operations Assessment time horizon is more accurate.
(3) Why is tripping from unstable power swings included in these two requirements? Relays should
trip due to unstable power swings. The FERC directive compelled NERC to develop a standard that
requires protection systems to be able to differentiate between stable power swings and faults. The
directive did not require NERC to specifically address unstable powers swings. We recommend
removing unstable power swings from both R2 and R3.
Yes
We agree the requirement is much clearer.
No
We agree splitting the requirement into two requirements where one deals with assessing the
Protection System and the other deals with developing a CAP is an improvement. However, we
continue to believe the Requirement R6 is an administrative requirement that meets P81 criteria and
should be removed. The only way the R6 will ever be violated is if an entity fails to update their
paperwork on the CAP. How does failing to update documentation not administrative? How does
ensuring the documentation is updated by enforcing penalties serve reliability? How is this consistent
with RAI which is intended to refocus compliance and enforcement on those risks most important to
reliability and not on documentation issues?
No
(1) The “Application Guidelines and Technical Basis” are quite helpful and definitely do provide
additional insight into the meaning of the requirements. However, we believe additional
modifications are necessary. (2) On page 18 in the second paragraph, we do not believe the
paragraph captures all of the reasons for changing the applicability of the standard. We believe that
changing the applicability makes that standard consistent with the other relay loadability standards
and makes the standard consistent with the functional model. These reasons are important to
capture as they are more substantial than those listed. (3) In the Requirement R1 paragraph on
page 20, please change “and other NERC Reliability Standards” to PRC-006. There are two main
standards (or five depending on which version of TPL are used) that drive identification of Elements
susceptible to stable power swings. They are the UFLS standards and TPL standard(s). As written,
this paragraph is too open ended and could lead to confusion. (4) We suggest that a diagram should
be developed depicting the example in the second paragraph on page 24. (5) In the “lens
characteristic” examples, we suggest that annotating the figure with the actual lens point would be
helpful in understanding the “lens characteristic”.
No
We do believe the 36-month period of implementation for R4 is sufficient. However, we do not
understand why R5 and R6 do not have the same effective date as R4. They are dependent on R4
with the “pursuant to Requirement R4” and “pursuant to Requirement R5” clauses in the
requirements. To avoid the confusion associated with monitoring compliance to R5 and R6 when
they cannot technically be violated, please align the effective date for R5 and R6 to R4 to avoid this
confusion.
Yes
(1) We believe the data retention section is inconsistent with the RAI. RAI is intended to refocus the
ERO’s compliance monitoring and enforcement efforts on those matters that pose the greatest risk
to the reliability to the BES. This involves making compliance monitoring and enforcement forward
looking to provide reasonable assurance of future compliance and reliability. How does a three-year
data retention requirement support this forward looking vision of RAI? We suggest that the data
retention should be no more than one year, based on the annual cycle established in this standard.
(2) Why is 36 calendar months in bullet 4 instead of 3 calendar years that is used in the first three
bullets? It seems they should be the same to avoid confusion. Notwithstanding our earlier comments
regarding making the data retention period no longer than one year, we suggest using consistent
language throughout the data retention section. Thus, use either 36 calendar months or three
calendar years, but not both.
Group
Bonneville Power Administration
Andrea Jessup
Yes
Yes
BPA requests a revision to R1 to separate customer notifications from technical analysis. R1.1 Each
Planning Coordinator shall, at least once each calendar year, identify each Element in its area that
meets one or more of the following criteria…. R1.2 Each Planning Coordinator shall provide
notification to each respective Generator Owner or Transmission Owner that owns an Element
identified in R1.1.
Yes
Yes
BPA agrees that Attachment B is an improvement; however, it could be better. It appears that the
only way to verify compliance is through a graphical comparison of the relay characteristic and a
lens characteristic that is described in the Application Guidelines. The Application Guidelines give one
example of calculating six sample points on the lens characteristic. BPA was able to work our way
through the example, but it was somewhat difficult and required lots of reading between the lines.
BPA requests more explicit explanations of what is expected to show compliance and how to develop
the lens characteristic.
Yes
No
BPA agrees that Attachment B is an improvement; however, it could be better. It appears that the
only way to verify compliance is through a graphical comparison of the relay characteristic and a
lens characteristic that is described in the Application Guidelines. The Application Guidelines give one
example of calculating six sample points on the lens characteristic. BPA was able to work our way
through the example, but it was somewhat difficult and required lots of reading between the lines.
BPA requests more explicit explanations of what is expected to show compliance and how to develop
the lens characteristic.
BPA cannot estimate if the implementation plan provides sufficient time until BPA determines how
many elements that R1 applies to.
Yes
BPA suggests re-ordering the requirements for continuity because the standard is working/designing
the system to prevent trips by load-responsive relays unnecessarily. R1 (PC identify criteria
influenced Elements ANNUALLY) R4 (GO/TO evaluate elements identified by the PC’s identifier of
Gen restraint, line part of SOL angular, UFLS line boundary ) R5 (GO/TO develop a CAP for at risk
protection on R4 elements) R6 (GO/TO implement the CAP) R2 (TO notify PC within 30 days if an
element trips by load-responsive protection due to swings or forms a boundary during a actual
system Disturbance) R3 (GO notifies PC within 30 days if element trips by load-responsive protection
during a swing)
Individual
Kurt LaFrance
Consumers Energy Company
No
The Transmission Owner and Generator Owner on their own do not have the capability to determine
if a trip was caused due to a swing. In most cases the Generator Owner has no knowledge of events
on the transmission system, and in many cases the Transmission Owner may only own one terminal
of a transmission line. Given the available data for a single terminal, there is no reliable way for an
Owner to determine if a trip was due to a fault or a swing. The Transmission Planner and/or
Reliability Coordinator have the broad system perspective to track how a swing moves through the
transmission system and impacts each element and should determine whether any given event was
involved a swing through a specific Element.
Yes
No
R2 and R3 require modification to provide clarity in how the Owner will determine if any given trip is
due to a swing. Without specific guidance on how to identify and document when a swing occurs and
whether that swing caused a trip, we do not believe we are able to comply with R2 or R3. For
instance, if an Owner only has electromechanical relays on a terminal, and does not own the other
terminal(s) of that element, how is it to determine the impedance trajectory and whether or not that
trajectory was a swing or a fault?
Yes
Yes
No
The revised application guidelines are very helpful, but need to be expanded to include guidance on
how to comply with R2 and R3, specifically how Generator Owners and Transmission Owners are
expected to determine whether a trip was due to a swing. Given the lack of guidance we have at this
point, we feel we are unable to comply with R2 or R3.
Yes
No
Individual
Richard Vine
California ISO
No
The California ISO does not agree with the change to remove the Transmission Planner in the
Applicability section and in Requirement R1. The California ISO supports continuing to include the
Transmission Planner in Requirement R1 as suggested by the PSRPS Report.
No
The California ISO does not agree with the change to remove the Transmission Planner in the
Applicability section and in Requirement R1. The California ISO supports continuing to include the
Transmission Planner in Requirement R1 as suggested by the PSRPS Report.
Additional Comments
Oncor
Gul Khan
2. Do you agree that the revisions to Requirement R1 improved clarity while remaining consistent
with the focused approach of using the Criteria which came from recommendations in the
PSRPS technical document 1 (pg. 21 of 61)? If not, please explain why and provide an alternative,
if any.
Yes
No
Comments:
3. The previous Requirement R2 was split into Requirement R2 for the Transmission Owner and
Requirement R3 for the Generator Owner in order to clarify the performance for identifying
Elements that trip. Did this revision improve the understanding of what is required? If not,
please explain why the Requirement(s) need additional clarification.
Yes
No
Comments:
Arizona Public Service
Donna Turner
2. Do you agree that the revisions to Requirement R1 improved clarity while remaining consistent
with the focused approach of using the Criteria which came from recommendations in the
PSRPS technical document 2 (pg. 21 of 61)? If not, please explain why and provide an alternative,
if any.
Yes
No
Comments:
3. The previous Requirement R2 was split into Requirement R2 for the Transmission Owner and
Requirement R3 for the Generator Owner in order to clarify the performance for identifying
Elements that trip. Did this revision improve the understanding of what is required? If not,
please explain why the Requirement(s) need additional clarification.
Yes
No
Comments:
Consideration of Comments
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
The Project 2010‐13.3 Drafting Team thanks all commenters who submitted comments on the
standard. These standards were posted for a 45‐day public comment period from August 22, 2014
through October 6, 2014. Stakeholders were asked to provide feedback on the standards and
associated documents through a special electronic comment form. There were 53 sets of comments,
including comments from approximately 147 different people from approximately 102 companies
representing all 10 Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please 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,
you can contact the Director of Standards, Valerie Agnew, at 404‐446‐2566 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary of Changes to the Standard
The following is a summary of the change made to the proposed PRC‐026‐1 NERC Reliability Standard.
Applicability
Section 4.2, Facilities was revised from “The following Bulk Electric System Elements” to “The following
Elements that are part of the Bulk Electric System (BES)” to clarify that the listed items are the items
being addressed in the Requirements as the “Elements.”
Requirement R1
The Elements from the Applicability 4.2 (i.e., generator, transformer, and transmission line BES
Elements) was added for clarity. Also, the Requirement was modified to specifically require
“notification” rather than “identify and provide notification.” Identification of Elements based on the
criteria is implied and necessary as a part of the Requirement.
Requirement R1, Criterion 1
The term “operating limit” was clarified to be “System Operating Limit (SOL)” to remove ambiguity
between the operating and planning time frame. Also, “transmission switching station” was revised to
The appeals process is in the Standard Processes Manual: http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf
1
be “Transmission station.” The word “switching” did not add any additional clarity and the capitalized
term “Transmission” references the Glossary of Terms Used in NERC Reliability Standards.
Requirement R1, Criterion 2
The phrase “constraints identified in system planning or operating studies” was modified to be “…a SOL
identified by the Planning Coordinator’s methodology.” This allows the Standard to draw a connection
between the FAC‐0102 NERC Reliability Standard applicable to the Planning Coordinator in the planning
horizon.
Requirement R1, Criterion 3
This criterion originally identified Elements that formed the boundary of an island which in many cases
would include Elements that were selected as arbitrary separation points and are not intended to be
included within the scope of the Standard. Therefore, Criterion 3 was rewritten to reflect it is the
Element which tripped on angular stability thus forming the island. Also, the criterion was updated to
reflect the most recent “design assessment” by the Planning Coordinator (i.e., PRC‐006) and when the
Planning Coordinator uses angular stability as a design criteria for identifying islands.
Requirement R1, Criterion 4
The term “annual” was added to provide clarity.
Requirement R1, Criterion 5
Criterion 5 was removed from Requirement R1 because Requirements R2 and R3 in Draft 2 were
eliminated. Those Requirements directed the Transmission Owner and Generator Owner to notify the
Planning Coordinator of Elements that actually tripped due to a stable or unstable power swing.
Criterion 5 created a loopback to the Generator Owner and Transmission Owner to ensure that load‐
responsive protective relays on identified Elements were evaluated on a periodic basis. Actual tripping
events are now included in Requirement R2 (previously Requirement R4) and do not require periodic
review, unless the Element trips due to a stable or unstable power swing.
Measure M1
Measure M1 was updated to reflect changes to Requirement R1 and to clarify that the focus is on
notification and not identification of Elements.
Requirements R2 and R3
These Requirements were removed due to structural changes in Requirement R4 (now Requirement
R2). The evaluation Requirement (now R2) was restructured to have two conditions for performance;
1) upon notification of an Element pursuant to Requirement R1, and 2) an actual event due to a stable
or unstable power swing.
2
System Operating Limits Methodology for the Planning Horizon
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
2 of 148
Requirement R4
This Requirement became Requirement R2 due to the removal of Requirements R2 and R3. Most
significantly, the Requirement was restructured to incorporate the removal of Requirements R2 and
R3. It was determined that Elements that tripped due to a stable or unstable power swing (R2/R3)
would be infrequent and more than likely a significantly large event which the Planning Coordinator
would be aware of through an event analysis. The new structure of the Requirement causes an
evaluation; however, it would not be necessary for the Planning Coordinator to be notified and then to
continue notifying the Generator Owner and Transmission Owner. Elements that actually tripped due
to stable or unstable power swings are not typical and requiring the Generator Owner and
Transmission Owner to do a one‐time analysis is sufficient to address the risk.
Requirements R5 and R6
These Requirements became Requirements R3 and R4 due to the removal of Requirements R2 and R3.
Requirement R3 to develop the Corrective Action Plan (CAP) was inflexible as it only allowed the
modification of a Protection System that did not meet the PRC‐026‐1 – Attachment B criteria. To
correct this issue, Requirement R3 was modified to meet the purpose of the standard which is to
ensure that load‐responsive protective relays are expected to not trip in response to stable power
swings during non‐Fault conditions. First, the Requirement was revised to include two conditions. The
first condition requires a CAP to be developed such that the Protection System will meet the PRC‐026‐1
– Attachment B criteria. For example, this may include a Protection System modification or a system
configuration change which causes the Protection System to meet the criteria. Second, the CAP allows
power swing block to be applied such that the Protection System may be excluded from the Standard.
Also, the development period of the CAP was extended from 90 calendar days to six calendar months
due to the complexities that might be involved with determining appropriate remediation of a
Protection System that did not meet PRC‐026‐1 – Attachment B criteria.
Compliance Section
Section C1.1.2 was modified to conform evidence retention to the Reliability Assurance Initiative (RAI).
Retention periods were set to 12 calendar months.
Violation Severity Levels
The Violation Severity Levels (VSL) were modified to align them with the revisions made to the
Requirements.
PRC-026-1 – Attachments A and B
Attachment A received editorial changes and Attachment B, Criteria A was rewritten to clarify that a
relay characteristic that is completely contained within the unstable power swing region meets the
criteria. The unstable power swing region is formed by the union of three shapes in the impedance (R‐
X) plane.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
3 of 148
Guidelines and Technical Basis
This section was revised substantively in response to comments and due to the removal of
Requirements R2 and R3. Revisions are too numerous to list here effectively. Please see the Guidelines
and Technical Basis redline document for changes.
Implementation Plan
The period for implementing the standard did not change substantively. Based on comments, the
implementation time frame for Requirements R5 and R6 (now Requirements R3 and R4) were
increased from 12 calendar months to 36 calendar months to align them with Requirement R4 (now
Requirement R2).
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
4 of 148
1.
2.
3.
4.
5.
6.
7.
8.
Do you agree with the Applicability changes to PRC-026-1 (e.g.,
removal of the Reliability Coordinator and Transmission Planner)? If
not, please explain why an entity is not appropriate and/or suggest
an alternative that should identify the Elements according to the
criteria.......................................................................................................... 17
Do you agree that the revisions to Requirement R1 improved clarity
while remaining consistent with the focused approach of using the
Criteria which came from recommendations in the PSRPS technical
document (pg. 21 of 61)? If not, please explain why and provide an
alternative, if any. ........................................................................................ 28
The previous Requirement R2 was split into Requirement R2 for the
Transmission Owner and Requirement R3 for the Generator Owner in
order to clarify the performance for identifying Elements that trip. Did
this revision improve the understanding of what is required? If not,
please explain why the Requirement(s) need additional clarification. ........... 46
Requirement R4 (previously R3) contained multiple activities (e.g.,
demonstrate, develop a Corrective Action Plan, obtain agreement)
and was ambiguous. Do you agree that the revision to Requirement
R4 now provides a clearer understanding of what is required by the
Generator Owner and Transmission Owner for an identified Element?
Note: The Criterion is now found in PRC-026-1 – Attachment B,
Criteria A and B. If not, please explain why the Requirement is not
clear. ............................................................................................................ 75
The new Requirement R5 (previously R4) and the new Requirement
R6 address Corrective Action Plans (CAP), if any. Do you agree this is
an improvement over having the development of the CAP comingled
with other Requirement? If not, please explain. ............................................ 87
Does the “Application Guidelines and Technical Basis” provide
sufficient guidance, basis for approach, and examples to support
performance of the requirements? If not, please provide specific
detail that would improve the Guidelines and Technical Basis. .....................104
The Implementation Plan for the proposed standard has been
revised, based on comments, to account for factors such as the initial
influx of identified Elements and ongoing burden of entities to
identify Elements and re-evaluate Protection Systems. Does the
implementation plan provide sufficient time for implementing the
standard? If not, please provide a justification for changing the
proposed implementation period and for which Requirement. ......................119
If you have any other comments on PRC-026-1 that have not been stated above,
please provide them here: ..................................................................................127
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
5 of 148
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
Group/Individual
Commenter
Organization
1. Group
Guy Zito
Northeast Power Coordinating Council
Additional Member
Additional Organization
Region
Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2. David Burke
Orange and Rockland Utilties Inc.
NPCC
3
3. Greg Campoli
New York Independent System Operator
NPCC
2
4. Sylvain Clermont
Hydro‐Quebec TransEnergie
NPCC
1
5. Kelly Dash
Consolidated Edison Co. of New York, Inc.
NPCC
1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
7. Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
8. Kathleen Goodman
ISO ‐ New England
NPCC
2
9. Michael Jones
National Grid
NPCC
1
10. Mark Kenny
Northeast Utilities
NPCC
1
11. Helen Lainis
Independent Electricity System Operator
NPCC
2
12. Alan MacNaughton
New Brunswick Power Corporation
NPCC
9
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
13. Bruce Metruck
New York Power Authority
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
NPCC
6
14. Silvia Parada Mitchell NextEra Energy, LLC
NPCC
5
15. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
16. Robert Pellegrini
The United Illuminating Company
NPCC
1
17. Si Truc Phan
Hydro‐Quebec TransEnergie
NPCC
1
18. David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
19. Brian Robinson
Utility Services
NPCC
8
20. Ayesha Sabouba
Hydro One Networks Inc.
NPCC
1
21. Brian Shanahan
National Grid
NPCC
1
22. Wayne Sipperly
New York Power Authority
NPCC
5
23. Ben Wu
Orange and Rockland Utilities Inc.
NPCC
1
2. Group
Janet Smith
Arizona Public Service Co
X
X
X
X
Eleanor Ewry
Puget Sound Energy
X
X
X
Wayne Johnson
Southern Company: Southern Company
Services, Inc.; Alabama Power Company;
Georgia Power Company; Gulf Power
Company; Mississippi Power Company;
Southern Company Generation; Southern
Company Generation and Energy Marketing
X
X
X
X
Phil Hart
Associated Electric Cooperative, Inc. ‐
JRO00088
X
X
X
X
N/A
3. Group
N/A
4. Group
N/A
5. Group
Additional Member
Additional Organization
Region
Segment
Selection
1.
Central Electric Power Cooperative
SERC
1, 3
2.
KAMO Electric Cooperative
SERC
1, 3
3.
M & A Electric Power Cooperative
SERC
1, 3
4.
Northeast Missouri Electric Power
Cooperative
SERC
1, 3
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
7 of 148
Group/Individual
Commenter
Organization
5.
N.W. Electric Power Cooperative, Inc.
SERC
1, 3
6.
Sho‐Me Power Electric Cooperative
SERC
1, 3
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
6. Group
Kaleb Brimhall
Colorado Springs Utilities
X
X
X
X
Colby Bellville
Duke Energy
X
X
X
X
X
X
X
X
X
N/A
7. Group
Additional
Member
Additional Organization
Region
Segment
Selection
1.
Doug Hils
Duke Energy
RFC
1
2.
Lee Schuster
Duke Energy
FRCC
3
3.
Dale Goodwine
Duke Energy
SERC
5
4.
Greg Cecil
Duke Energy
RFC
6
8. Group
ISO RTO Council Standards Review
Committee
Greg Campoli
Additional Member
1.
Charles Yeung
SPP
SPP
2
2.
Ben Li
IESO
NPCC
2
3.
Matt Goldberg
ISONE
NPCC
2
4.
Mark Holman
PJM
RFC
2
5.
Lori Spence
MISO
MRO
2
6.
Cheryl Moseley
ERCOT
ERCOT
2
7.
Ali Miremadi
CAISO
WECC
2
Additional
Organization
Region
Segment
Selection
9. Group
Connie Lowe
Dominion
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
8 of 148
Group/Individual
Commenter
Organization
Additional
Member
Additional Organization
Region
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
X
X
X
X
X
X
X
Segment
Selection
1.
Larry Nash
Electric Transmission
SERC
1, 3
2.
Mike Garton
NERC Compliance Policy
NPCC
5, 6
3.
Louis Slade
NERC Compliance Policy
RFC
5, 6
4.
Randi Heise
NERC Compliance Policy
SERC
1, 3, 5, 6
5.
Christopher
Mertz
Electric Transmission
SERC
1, 3
10. Group
Tom McElhinney
Additional
Member
JEA
Additional
Organization
Region
Segment
Selection
1.
Ted Hobson
FRCC
1
2.
Garry Baker
FRCC
3
3.
John Babik
FRCC
5
11. Group
Brent Ingebrigtson
Additional Member
PPL NERC Registered Affiliates
Additional Organization
Region
Segment
Selection
1.
Charlie Freibert
LG&E and KU Energy, LLC
SERC
3
2.
Annette Bannon
PPL Generation, LLC
RFC
5
3.
PPL Susquehanna, LLC
RFC
5
4.
PPL Montana, LLC
WECC
5
5.
Brenda Truhe
PPL Electric Utilities
Corporation
RFC
1
6.
Elizabeth Davis
PPL EnergyPlus, LLC
MRO
6
7.
NPCC
6
8.
RFC
6
9.
SERC
6
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
9 of 148
Group/Individual
Commenter
Organization
10.
SPP
6
11.
WECC
6
Registered Ballot Body Segment
1
2
3
4
5
6
7
X
X
X
X
X
X
X
X
8
9
10
12. Group
Carol Chinn
Additional Member
Florida Municipal Power Agency
Additional Organization
Region
Segment Selection
1.
Tim Beyrle
City of New Smyrna Beach
FRCC
4
2.
Jim Howard
Lakeland Electric
FRCC
3
3.
Greg Woessner
Kissimmee Utility Authority
FRCC
3
4.
Lynne Mila
City of Clewiston
FRCC
3
5.
Cairo Vanegas
Fort Pierce Utility Authority
FRCC
4
6.
Randy Hahn
Ocala Utility Services
FRCC
3
7.
Don Cuevas
Beaches Energy Services
FRCC
1
8.
Stanley Rzad
Keys Energy Services
FRCC
4
9.
Mark Schultz
City of Green Cove Springs
FRCC
3
10.
Tom Reedy
Florida Municipal Power Pool
FRCC
6
11.
Steven Lancaster
Beaches Energy Services
FRCC
3
12.
Richard Bachmeier
Gainesville Regional Utilities
FRCC
1
13.
Mike Blough
Kissimmee Utility Authority
FRCC
5
13. Group
Kathleen Black
Additional Member
DTE Electric Co.
Additional Organization
Region
Segment
Selection
1.
Kent Kujala
NERC Compliance
RFC
3
2.
Daniel Herring
NERC Training & Standards Development
RFC
4
3.
Mark Stefaniak
Merchant Operations
RFC
5
4.
Dave Szulczewski
DE‐EE Relay Eng Supv
RFC
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
10 of 148
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
X
X
X
X
X
X
X
X
X
X
X
X
X
X
8
9
10
14. Group
Richard Hoag
FirstEnergy Corp.
Additional Member
Additional Organization
Region
Segment Selection
1.
Wiliam Smith
First Energy Corp
RFC
1
2.
Cindy Stewart
FirstEnergycorp.com
RFC
3
3.
Doug Hohlbaugh
Ohio Edison
RFC
4
4.
Ken Dresner
FirstEnergy Solutions
RFC
5
5.
Kevin Querry
FirstEnergy Solutions
RFC
6
6.
Richard Hoag
First Energy Corp
RFC
NA
15. Group
Dennis Chastain
Additional Member
Tennessee Valley Authority
Additional Organization
Region
Segment Selection
1.
DeWayne Scott
SERC
1
2.
Ian Grant
SERC
3
3.
Brandy Spraker
SERC
5
4.
Marjorie Parsons
SERC
6
16. Group
S. Tom Abrams
Additional Member
Santee Cooper
Additional Organization
Region
Segment Selection
1.
Tom Abrams
Santee Cooper
SERC
1, 3, 5, 6
2.
Rene Free
Santee Cooper
SERC
1, 3, 5, 6
3.
Bridget Coffman
Santee Cooper
SERC
1, 3, 5, 6
17. Group
Shannon V. Mickens
Additional Member
SPP Standards Review Group
Additional Organization
Region
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
Segment Selection
11 of 148
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1.
John Allen
City Utilities of Springfield
SPP
1, 4
2.
Jamison Cawley
Nebraska Power Review Board
SPP
1, 3, 5
3.
Michael Jacobs
Camstex
NA ‐ Not Applicable
NA
4.
Stephanie Johnson
Westar Energy
SPP
1, 3, 5, 6
5.
Bo Jones
Westar Energy
SPP
1, 3, 5, 6
6.
Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
7.
Derek Brown
Westar Energy
SPP
1, 3, 5, 6
8.
Lynn Schroeder
Westar Energy
SPP
1, 3, 5, 6
9.
Charles Lee
Kansas City Power & Light
SPP
1, 3, 5, 6
10.
Mike Kidwell
Empire District Electric
SPP
1, 3, 5
11.
James Nail
City of Independence, MO
SPP
3, 5
12.
Ashley Stringer
Oklahoma Municipal Power Authority
SPP
4
13.
Jonathan Hayes
Southwest Power Pool
SPP
2
14.
Robert Rhodes
Southwest Power Pool
SPP
2
15.
Shannon Mickens
Southwest Power Pool
SPP
2
1
2
3
4
5
6
7
8
9
10
X
X
X
X
X
X
18. Group
Paul Haase
Additional Member
Seattle City Light
Additional Organization
Region
Segment Selection
1.
Pawel Krupa
Seattle City Light
WECC
1
2.
Dana Wheelock
Seattle City Light
WECC
3
3.
Hao Li
Seattle City Light
WECC
4
4.
Mike Haynes
Seattle City Light
WECC
5
5.
Dennis Sismaet
Seattle City Light
WECC
6
19. Group
1.
Jason Marshall
Additional Member
Bob Solomon
ACES Standards Collaborators
Additional Organization
Hoosier Energy
Region
RFC
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
Segment Selection
1
12 of 148
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
2.
John Shaver
Arizona Electric Power Cooperative
WECC
4, 5
3.
John Shaver
Southwest Transmission Cooperative
WECC
1
4.
Shari Heino
Brazos Electric Power Cooperative
ERCOT
1, 5
5.
Kevin Lyons
Central Iowa Power Cooperative
MRO
1
6.
Ellen Watkins
Sunflower Electric Power Cooperative
SPP
1
7.
Ginger Mercier
Prairie Power
SERC
3
8.
Scott Brame
North Carolina Electric Membership
Corporation
SERC
3, 4, 5
9.
Paul Jackson
Buckeye Power
RFC
3, 4, 5
1
2
3
4
5
6
7
8
9
10
X
X
X
X
20. Group
Andrea Jessup
Bonneville Power Administration
Additional Member
Additional Organization
Region
Segment Selection
1.
Jim Burns
Technical Operations
WECC
1
2.
Dean Bender
System Control Engineering
WECC
1
3.
Chuck Matthews
Transmission Planning
WECC
1
4.
Jim Gronquist
Transmission Planning
WECC
1
21. Individual
Gul Khan
Oncor Electric Delivery LLC
X
22. Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
23. Individual
Oliver Burke
Entergy Services, Inc.
X
24. Individual
Thomas Foltz
American Electric Power
X
X
X
X
25. Individual
Maryclaire Yatsko
Seminole Electric Cooperative, Inc.
X
X
X
X
X
26. Individual
Kayleigh Wilkerson
Lincoln Electric System
X
X
X
X
27. Individual
Mark Wilson
Independent Electricity System Operator
X
28. Individual
Amy Casuscelli
Xcel Energy
X
X
X
X
29. Individual
Alshare Hughes
Luminant Generation Company, LLC
X
X
X
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
13 of 148
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
30. Individual
Barbara Kedrowski
Wisconsin Electric
X
X
X
31. Individual
Bill Fowler
City of Tallahassee
X
32. Individual
Idaho Power
X
ISO New England
X
34. Individual
Jonathan Meyer
John Pearson/Matt
Goldberg
Chris Scanlon
Exelon Companies
X
X
X
X
35. Individual
Brett Holland
Kansas City Power & Light
X
X
X
X
36. Individual
David Thorne
Pepco Holdings Inc.
X
X
37. Individual
Glenn Pressler
CPS Energy
X
X
X
38. Individual
Jamison Cawley
Nebraska Public Power District (NPPD)
X
X
X
39. Individual
John Merrell
Tacoma Power
X
40. Individual
David Jendras
Ameren
X
X
X
X
41. Individual
Joe O'Brien
NIPSCO
X
X
X
X
42. Individual
Michael Moltane
ITC
X
43. Individual
Karin Schweitzer
Texas Reliability Entity
X
44. Individual
Muhammed Ali
Hydro One
X
X
45. Individual
Ayesha Sabouba
Hydro One
X
X
46. Individual
Jo‐Anne Ross
Manitoba Hydro
X
X
X
X
47. Individual
Dixie Wells
Lower Colorado River Authority
X
48. Individual
Andrew Z. Pusztai
American Transmission Company, LLC
X
49. Individual
Jason Snodgrass
Georgia Transmission Corporation
X
50. Individual
John Brockhan
X
51. Individual
Sergio Banuelos
X
X
X
52. Individual
Kurt LaFrance
CenterPoint Energy
Tri‐State Generation and Transmission
Association, Inc.
Consumers Energy Company
X
X
X
53. Individual
Richard Vine
California ISO
X
33. Individual
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
14 of 148
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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If you support the comments submitted by another entity and would like to indicate you agree with their comments, please
select "agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade
association, group, or committee, rather than the name of the individual submitter).
Summary Consideration: The drafting team appreciates entities that support the comments of others. Having single sets of
comments with documented support greatly improves the efficiency of the standard drafting team. This format also ensures the
drafting team has a clearer picture of the number of stakeholders supporting the same concerns or suggestions as the case may be.
Please see the responses to the entity’s comments that are being supported here.
Organization
Associated Electric
Cooperative, Inc. ‐ JRO00088
Agree
Yes
Supporting Comments of “Entity Name”
AECI agrees with SPP Commments
Response: The standard drafting team thanks you for participating, please see the
responses to SPP Standard Review Group.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
16 of 148
1.
Do you agree with the Applicability changes to PRC‐026‐1 (e.g., removal of the Reliability Coordinator and Transmission
Planner)? If not, please explain why an entity is not appropriate and/or suggest an alternative that should identify the
Elements according to the criteria.
Summary Consideration: About 87 percent of commenters agree with the Applicability change in Requirement R1 of the Standard to
remove the Reliability Coordinator and Transmission Planner. The following summary discusses the major concerns that resulted in
revisions to the Standard and one minor concern that did not result in a change to the Standard.
There were three significant themes of comments that resulted in a revision to the Standard.
First, there were five comments supported by 35 individuals (includes Questions 1‐8) that were concerned that an applicable
Generator Owner or Transmission Owner would be exempted from the proposed PRC‐026‐1 Standard if the entity applies out‐step‐
blocking. The standard drafting team agrees and when entities implement power swing blocking (PSB) relays, do so using
engineering judgment and accepted industry practices, the reliability purpose of the Standard is met. Draft 3, Requirement R3
(previously Draft 2, Requirement R5) for developing a Corrective Action Plan (CAP) clarifies this as an option to meeting the Purpose
Statement of the Standard.
Second, two comments represented by 11 individuals raised questions about the use of “operating” in conjunction with the
“planning” time horizon in the Requirement R1 criteria. The standard drafting team revised Requirement R1, Criterion 1 that is
applicable to the Planning Coordinator to replace the phrase “an operating limit” with “System Operating Limit (SOL).” Further, the
standard drafting team reworded Requirement R1, Criterion 2 to remove the phrase “identified in system planning or operating
studies” and clarify that the SOL is identified based on the Planning Coordinator’s methodology in the “planning” horizon. This
revision aligns the Glossary of Terms Used in NERC Reliability Standards defined term, “System Operating Limit” or “SOL” with its use
in the Standard. Also, this revision aligns the use of “SOL” with the Planning Coordinator’s methodology of how SOLs are developed
according to the NERC Reliability Standard, FAC‐10 (i.e., System Operating Limits Methodology for the Planning Horizon).
Last, there were two comments supported by five individuals that commented about the overlap between the proposed PRC‐026‐1,
Requirements R2 and R3 and NERC Reliability Standard PRC‐004.3 The concern stemmed from the perception of having to perform
Protection System reviews in both standards. The standard drafting team addressed this concern by removing Requirements R2 and
R3 (notification to the Planning Coordinator) and incorporating a revision to the Draft 3, Requirement R2 (previously Draft 2,
3
Protection System Misoperation Identification and Correction.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
17 of 148
Requirement R4). The revision clarified that the Generator Owner and Transmission Owner must perform an evaluation of its load‐
responsive protective relays according to the Requirement upon becoming aware of a stable or unstable power swing.
The following summarizes a comment that did not result in a change to the Standard. Two comments supported by nine individuals
did not want the Transmission Planner removed from the applicability of the Standard. The standard drafting team removed the
Transmission Planner (and Reliability Coordinator) as applicable entities in the last draft (Draft 2) of the proposed standard in
response to comments to address concerns about overlap and potential gaps when identifying Elements in Requirement R1
according to the criteria. Although the PSRPS Report4 suggested the Transmission Planner and Reliability Coordinator entities along
with the Planning Coordinator for inclusion in the Standard’s Applicability, the standard drafting team agreed with comments
received on Draft 1 that the Planning Coordinator is in the best position to identify Elements to avoid duplication and potential gaps.
Organization
Yes or No
Question 1 Comment
Florida Municipal Power
Agency
No
FMPA is comfortable with the removal of the Reliability Coordinator and Transmission
Planner, subject to comments we are making on R2, R3 and in response to question
8.
Response: Please see comments in Question 8.
Santee Cooper
No
There seems to be some overlap between PRC‐004 and R2 and R3 of this standard
(PRC‐026). For compliance with PRC‐004, entities have to analyze all operations in
order to prove that all misoperations are identified. To identify an Element that
(according to R2 and R3 of PRC‐026) “trips due to a stable or unstable power swing
during an actual system Disturbance due to the operation of its load‐responsive
protective relays,” a similar proof could be required, that all trips of load responsive
4
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
18 of 148
Organization
Yes or No
Question 1 Comment
relays were evaluated under a criteria to rule out operation due to stable or unstable
power swings.
The listed Rationale for R2 gives mention to the review of relay tripping is addressed
in other NERC Reliability Standards, so there seems to be a nod given to PRC‐004, but
it should be clearer as to the interrelationship between these standards. Significant
confusion could result if the interrelationship or dividing line (whichever is more
appropriate) between these two standards is defined further. Will compliance with
R2 and R3 of PRC‐026 only involve having the data for the operations determined to
be caused by power swings, or will it require data that entities provide documentation
of the evaluation each operation for power swing implications?
Response: The standard drafting team has removed the previous Requirements R2
and R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team
revised Requirement R4 (now Requirement R2) for load‐responsive relays to be
evaluated under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element
That Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
ISO New England
No
While we agree with the removal of the Reliability Coordinator and Transmission
Planner, we don’t believe that entities should be exempted from the standard by the
linkage to Attachment A. Attachment A excludes Relay elements supervised by power
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
19 of 148
Organization
Yes or No
Question 1 Comment
swing blocking. An entity could just install Out of Step Blocking equipment with
nothing to ensure that it is set correctly and the standard would not apply through
the exclusion in Attachment A.
Response: The standard drafting team contends that the installation of power swing
blocking relays is an effective means to prevent tripping for stable power swings. The
drafting team contends that entities that implement power swing blocking (PSB)
relays would do so using engineering judgment and accepted industry practices. A
discussion of PSB is in the Application Guidelines. No change made.
Texas Reliability Entity
No
Texas Reliability Entity, Inc. (Texas RE) has concerns regarding the removal of the
Reliability Coordinator (RC) from the applicability, particularly for Criteria 1 and 2 of
R1. The time horizons that the Planning Coordinator (PC) and RC evaluate are
different, with the Planning horizon being > 1 year and the Operations horizon being
real‐time to < 1 year.
When the SDT removed the RC from the applicability, the Operations Planning time
horizon was also removed; however, there is still language within Criteria 1 and 2 of
R1 addressing angular stability constraints as monitored as part of a System Operating
Limit identified in operating studies. Operating studies are not typically conducted by
the PC but are conducted by the RC.
Based on the language in the Criteria, it is unclear to Texas RE whether the intent of
the standard is to only identify elements at risk in the Long‐term Planning horizon or
to identify elements at risk in both the Operations horizon and the Long‐term Planning
horizon. Texas RE requests clarification on this issue from the SDT. Please also see our
comments to Questions 2 and 3 regarding time horizon concerns.
Response: The standard drafting team revised Requirement R1, Criterion 1 to replace
the phrase “an operating limit” with “System Operating Limit (SOL).” Further, the
standard drafting team reworded Requirement R1, Criterion 2 to remove the phrase
“identified in system planning or operating studies” and clarify that the SOL is
identified based on the Planning Coordinator’s methodology in the planning horizon.
Consideration of Comments:
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Organization
Yes or No
Question 1 Comment
This revision aligns use of the term in the standard with the Glossary of Terms Used in
NERC Reliability Standards defined term, “System Operating Limit” or “SOL.” Also, this
revision aligns the use of “SOL” with the Planning Coordinator’s methodology of how
SOLs are developed according to FAC‐10 (System Operating Limits Methodology for
the Planning Horizon). Change made.
Consumers Energy
Company
No
The Transmission Owner and Generator Owner on their own do not have the
capability to determine if a trip was caused due to a swing. In most cases the
Generator Owner has no knowledge of events on the transmission system, and in
many cases the Transmission Owner may only own one terminal of a transmission
line. Given the available data for a single terminal, there is no reliable way for an
Owner to determine if a trip was due to a fault or a swing. The Transmission Planner
and/or Reliability Coordinator have the broad system perspective to track how a swing
moves through the transmission system and impacts each element and should
determine whether any given event was involved a swing through a specific Element.
Response: The standard drafting team has removed the previous Requirements R2
and R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team
revised Requirement R4 (now Requirement R2) for load‐responsive relays to be
evaluated under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element
Consideration of Comments:
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Posted: November 4, 2014
21 of 148
Organization
Yes or No
Question 1 Comment
That Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
California ISO
No
The California ISO does not agree with the change to remove the Transmission Planner
in the Applicability section and in Requirement R1. The California ISO supports
continuing to include the Transmission Planner in Requirement R1 as suggested by
the PSRPS Report.
Response: The standard drafting team removed the Reliability Coordinator and
Transmission Planner as applicable entities in Draft 2 of the proposed standard in
response to comments to address concerns about overlap and potential gaps when
identifying Elements in Requirement R1. Although the PSRPS Report5 suggested
entities for applicability, the standard drafting team agreed with comments received
on Draft 1 and that the Planning Coordinator is in the best position to identify
Elements to avoid duplication and potential gaps. No change made.
Northeast Power
Coordinating Council
Yes
Arizona Public Service Co
Yes
Puget Sound Energy
Yes
Southern Company:
Southern Company
Services, Inc.; Alabama
Power Company; Georgia
Power Company; Gulf
Power Company;
Yes
Simplifying the requirement to a single entity clarified the responsibilities.
Response: The standard drafting team thanks you for your comment.
5
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
22 of 148
Organization
Yes or No
Question 1 Comment
Mississippi Power
Company; Southern
Company Generation;
Southern Company
Generation and Energy
Marketing
Colorado Springs Utilities
Yes
No Comments
Duke Energy
Yes
ISO RTO Council
Standards Review
Committee
Yes
The Standards Review Committee (SRC) agrees with the removal of the Reliability
Coordinator and Transmission Planner; however, there remains concern that that
entities could be exempted from the standard by the linkage to Attachment A as it
excludes Relay elements supervised by power swing blocking. The SRC, therefore,
recommends that the SDT assure all Applicability is explicit in the Applicability Section
of the standard and that exemptions or other criteria are not embedded in
Attachment A. (note CAISO does not support the response to Question 1)
Response: The standard drafting team contends that the installation of power swing
blocking relays is an effective means to prevent tripping for stable power swings. The
drafting team contends that entities that implement power swing blocking (PSB)
relays would do so using engineering judgment and accepted industry practices. A
discussion of PSB is in the Application Guidelines. No change made.
Dominion
Yes
JEA
Yes
DTE Electric Co.
Yes
Consideration of Comments:
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Posted: November 4, 2014
23 of 148
Organization
Yes or No
Question 1 Comment
FirstEnergy Corp.
Yes
Tennessee Valley
Authority
Yes
SPP Standards Review
Group
Yes
Thank you for removing the Reliability Coordinator function. The Reliability
Coordinator has no place in this standard.
Response: The standard drafting team thanks you for your comment.
ACES Standards
Collaborators
Yes
(1) We largely agree with the applicability changes. We thank the drafting team for
removing Transmission Planner and avoiding the confusion that has occurred in so
many other standards from joint responsibility to meet the same requirements as the
PC.
Response: The standard drafting team thanks you for your comment.
(2) We are concerned with the removal of the RC. Per the SDT’s response to our
comments regarding which SOLs (planning horizon is covered FAC‐010 and operating
horizon is covered in FAC‐011), the SDT indicated that they intended for both to apply.
Since the SOL methodology that applies in the operating time horizon is written by
the RC, the PC may not be familiar enough with the RC’s methodology to determine
which operating horizon SOLs are due to angular stability. Wouldn’t it be easier for
the RC to notify the PC of those operating SOLs caused by angular stability?
Response: The standard drafting team revised Requirement R1, Criterion 1 to replace
the phrase “an operating limit” with “System Operating Limit (SOL).” Further, the
standard drafting team reworded Requirement R1, Criterion 2 to remove the phrase
“identified in system planning or operating studies” and clarify that the SOL is
identified based on the Planning Coordinator’s methodology in the planning horizon.
This revision aligns use of the term in the standard with the Glossary of Terms Used in
NERC Reliability Standards defined term, “System Operating Limit” or “SOL.” Also, this
revision aligns the use of “SOL” with the Planning Coordinator’s methodology of how
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Organization
Yes or No
Question 1 Comment
SOLs are developed according to FAC‐10 (System Operating Limits Methodology for
the Planning Horizon). Change made.
Bonneville Power
Administration
Yes
Oncor Electric Delivery
LLC
Yes
Public Service Enterprise
Group
Yes
Entergy Services, Inc.
Yes
American Electric Power
Yes
Seminole Electric
Cooperative, Inc.
Yes
Independent Electricity
System Operator
Yes
Xcel Energy
Yes
Luminant Generation
Company, LLC
Yes
Wisconsin Electric
Yes
City of Tallahassee
Yes
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
25 of 148
Organization
Yes or No
Question 1 Comment
Idaho Power
Yes
Kansas City Power &
Light
Yes
Pepco Holdings Inc.
Yes
CPS Energy
Yes
Nebraska Public Power
District (NPPD)
Yes
Tacoma Power
Yes
Ameren
Yes
ITC
Yes
Hydro One
Yes
Hydro One
Yes
Manitoba Hydro
Yes
Lower Colorado River
Authority
Yes
Georgia Transmission
Corporation
Yes
CenterPoint Energy
Yes
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
26 of 148
Organization
Yes or No
Tri‐State Generation and
Transmission
Association, Inc.
Yes
PPL NERC Registered
Affiliates
Question 1 Comment
These comments are submitted on behalf of the following PPL NERC Registered
Affiliates: LG&E and KU Energy, LLC; PPL Electric Utilities Corporation, PPL EnergyPlus,
LLC; PPL Generation, LLC; PPL Susquehanna, LLC; and PPL Montana, LLC. The PPL NERC
Registered Affiliates are registered in six regions (MRO, NPCC, RFC, SERC, SPP, and
WECC) for one or more of the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA,
PSE, RP, TO, TOP, TP, and TSP.
Response: The standard drafting team thanks you for your comment.
Consideration of Comments:
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Posted: November 4, 2014
27 of 148
2.
Do you agree that the revisions to Requirement R1 improved clarity while remaining consistent with the focused approach of using
the Criteria which came from recommendations in the PSRPS technical document (pg. 21 of 61)? If not, please explain why and
provide an alternative, if any.
Summary Consideration: Two‐thirds of commenters agreed that the revisions improved clarity while remaining consistent with the
focused approach of using the Requirement R1 criteria which is supported by the recommendation in the PSRPS Report6 (pg. 21 of
61). The following summary discusses the most significant concerns that resulted in a revision to the Standard and one minor
concern that did not result in a change to the Standard.
There were only three significant themes of comments that resulted in a revision to the Standard. First, two comments supported by
13 individuals requested that Requirement R1 be split into two Requirements, one for identifying BES Elements and one for notifying
the Generator Owner and Transmission Owner. The drafting team did not agree and alternatively modified Requirement R1 to place
the performance on notification of the Element(s) based on the criteria. Notifying the Generator Owner and Transmission any
Elements that meet the criteria infers that the identification is being performed in order to determine what BES Elements must be
provided in a notification, if any. Second, two comments each from an individual requested clarity between the lowercase phrase
“operating limit” and the NERC defined term, “System Operating Limit” or SOL. The standard drafting team revised the Standard to
use “SOL” exclusively for clarity since the methodology for determining of SOLs is addressed by the NERC Reliability Standard FAC‐
010.7 Third, only one comment provided minor editorial corrections to the Standard which the standard drafting team implemented.
The following summarizes comment themes that did not result in a change to the Standard. First, nine comments supported by 46
individuals (including Questions 1‐8) commented that the Standard is going beyond the intent of the Federal Energy Regulatory
Commission (FERC) Order No. 733. The standard drafting team responded that it is important to note that this Standard does not
require that entities assess Protection System performance during unstable swings and does not require entities to prevent tripping
in response to unstable swings. Therefore, the Standard focuses on the identification of Elements by the Planning Coordinator
(Requirement R1) and Elements where the Generator Owner or Transmission Owner becomes aware of an Element that tripped in
response to either a stable or unstable power swing (Draft 3, Requirement R2, 2nd bullet). Requirements R1 and R2 (2nd bullet) is a
screen to identify Elements that are subject to the Requirements of the Standard, and not require that entities assess Protection
System performance during unstable swings.
6
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
7
System Operating Limits Methodology for the Planning Horizon
Consideration of Comments:
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Posted: November 4, 2014
28 of 148
The FERC Order No. 733 directive is perceived as broad and overreaching and could require all relays to be capable of differentiating
between stable power swings and faults. This standard’s focused approach is based on the PSRPS Report, recommending “...lines
that have tripped due to power swings during system disturbances...” as one of the ways to focus the evaluation. Based on feedback
from the contributors to the PSRPS Report, that recommendation does not exclude “unstable” power swings. Furthermore, it is
reasonable to assume that an Element that experiences an unstable swing (in either a simulation or reality) is likely to experience
large stable power swings for less severe disturbances (that are probably more likely to occur). Thus, the standard drafting team
concluded that addressing Protection Systems for Elements that tripped due to “unstable” power swings provides a reliability
benefit.
Second, eight comments supported by 32 individuals noted that the entities are not persuaded that a Standard is needed, primarily
because of the PSRPS Report. The standard drafting team addressed entity concerns about not pursuing a standard in the previous
posting of the Consideration of Comments to Draft 1.8
Third, six comments represented by 36 individuals submitted general questions and comments about the Standard, which did not
result in a revision based on the comments. For example, why is the Planning Coordinator required to notify the Generator Owner
and Transmission Owner each calendar year of the BES Element(s) that tripped based on Requirement R1, Criterion 3 concerning
underfrequency load shedding (UFLS).9 Since Draft 3, Requirement R2 has a re‐evaluation component driven by the BES Element
notification by the Planning Coordinator and a point in time of the last evaluation, the standard drafting team concluded that not
including additional language for varying assessments done by the Planning Coordinator reduces complexity and does not result in a
significant burden. Another comment questioned why the Standard required the Generator Owner and Transmission Owner to
notify the Planning Coordinator. The reason was to create a loopback for the re‐evaluation; however, the standard drafting team
based on other comments later removed Requirement R1, Criterion 5 and Requirements R2 and R3 due to determining a better way
to address actual events due to stable or unstable power swings. One comment wanted additional work to align the Standard with
TPL‐001‐4 and another to add back in the Transmission Planner to the Standard’s Applicability.
Fourth, four comments supported by 17 individuals (including Questions 1‐8) wanted the Standard to provide a Requirement for the
exchange of information (e.g., system impedance data); however, the standard drafting team concluded that a Requirement for the
information exchange would be administrative and have limited reliability benefit for activities that entities are already performing.
8
http://www.nerc.com/pa/Stand/Project%202010133%20Phase%203%20of%20Relay%20Loadability%20stabl/Project_2010_13.3_Consideration_of_
Comments_2014_08_22_to_Draft_1.pdf
9
NERC Reliability Standard PRC-006-1 – Automatic Underfrequency Load Shedding has a five year periodicity.
Consideration of Comments:
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Posted: November 4, 2014
29 of 148
Last, two comments represented by 32 individuals suggested rewording Requirement R1 to include the phrase “…for all design
criteria events…” The standard drafting team agreed that the suggestion did not add clarity to Requirement R1.
Organization
Yes or No
Colorado Springs Utilities
No
Question 2 Comment
We agree with the Public Service Electric and Gas Company comments.
Response: The standard drafting team thanks you for participating, please see the
responses to Public Service Enterprise Group.
Additional Comments:
1.) Please define a "transmission switching station," is that the same thing as a sub‐
station?
Response: The standard drafting team revised the phrase “transmission switching
station” to be “Transmission station” to refer to the Glossary of Terms Used in NERC
Reliability Standards. Change made.
2.) Please clarify "angular" stability limit versus just a stability limit.
Response: The descriptor “angular” was added in Draft 2 to clarify that the “stability
limit” pertains to an angular stability limit and not a voltage stability limit, for example.
No change made.
3.) How are people modeling the relay settings for R1.4? Our facility ratings take into
account relay setting limitations and the facility ratings are used in the models. Is that
sufficient modeling or is there some specific modeling expected for R1.4?
Response: The standard drafting team notes that Requirement R1, Criterion 4 provides
a mechanism for the Planning Coordinator to identify Element in the most recent
annual Planning Assessment where relay tripping occurs due to a stable or unstable
power swing during a simulated disturbance. As discussed in the Guidelines and
Technical Basis, the soon‐to‐be enforceable TPL‐001‐4 Reliability Standard calls for the
use generic or actual relay models. It will be through a Planning Coordinator’s
compliance with TPL‐001‐4 that Elements will be identified where relay tripping occurs
Consideration of Comments:
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Posted: November 4, 2014
30 of 148
Organization
Yes or No
Question 2 Comment
due to a stable or unstable power swing during a simulated disturbance. PRC‐026‐1
does not require modeling of relays in planning studies. No change made.
PPL NERC Registered
Affiliates
No
The process of PCs annually performing an analysis and notifying TO/GOs of applicable
Elements per R1, and of TO/GOs then evaluating these Elements per R4, should be
clarified to note that where relays meeting criteria 1‐3 of R1 are on the PC’s list year
after year a new evaluation is not required each time unless conditions have materially
changed (threshold TBD by the SDT).
Response: The standard drafting team intends that the Planning Coordinator will notify
the respective Generator Owner and Transmission Owners annually and that Elements
will, from time to time, be added or removed accordingly. In doing so, Requirement R1
supports the re‐evaluation in Requirement R4 (now Requirement R2) every five
(previously three) calendar years should the Element remain on the list.
SPP Standards Review
Group
No
In light of the fact that the purpose of this standard is “To ensure that load‐responsive
protective relays are expected to not trip in response to stable power swings during
non‐Fault conditions” which is in agreement with the FERC Order 733 (Section 150 of
the FERC Order: “requires the use of protective relay systems that can differentiate
between faults and stable power swings and, when necessary, phases out protective
relay systems that cannot meet this requirement”), it is an unnecessary extension of
the Order to include unstable power swings.
The Standard Drafting Team stated “The phase “stable or unstable” was inserted to
clarify that both are applicable to power swings because the goal of the standard is to
identify Elements susceptible to either” overreaches the FERC Order.
We recommend that the term ‘Unstable Power Swing’ be removed from the standard.
Response: It is important to note that this standard does not require that entities
assess Protection System performance during unstable swings and does not require
entities to prevent tripping in response to unstable swings. Such requirements would
exceed the directive stated in the Federal Energy Regulatory Commission (FERC) Order
Consideration of Comments:
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Posted: November 4, 2014
31 of 148
Organization
Yes or No
Question 2 Comment
No. 733. This standard focuses on the identification of Elements by the Planning
Coordinator (Requirement R1) and Elements where the Generator Owner or
Transmission Owner becomes aware of an Element that tripped in response to a stable
or unstable power swing (Draft 3, Requirement R2, 2nd bullet). Requirements R1 and
R2 (2nd bullet) is a screen to identify Elements that are subject to the Requirements of
the standard.
The FERC Order No. 733 directive is perceived as broad and overreaching and could
require all relays to be capable of differentiating between stable power swings and
faults. This standard’s focused approach is based on the PSRPS Report,10
recommending “...lines that have tripped due to power swings during system
disturbances...” as one of the ways to focus the evaluation. Based on feedback from
the contributors to the PSRPS Report, that recommendation does not exclude unstable
power swings. Furthermore, it is reasonable to assume that an Element that
experiences an unstable swing (in either a simulation or reality) is likely to experience
large stable power swings for less severe disturbances (that are probably more likely
to occur). Thus, the standard drafting team concluded that addressing Protection
Systems for Elements that tripped due to unstable power swings provides a reliability
benefit. No change made.
Seattle City Light
No
Seattle City Light is not convinced that this Standard is warranted, and does not find
comfort in the tortured process associated with developing the recommendations of
the PSRPS document. The changes, as far as they go, do add some clarity to R1.
Response: The standard drafting team thanks you for your comment.
ACES Standards
Collaborators
No
(1) We agree that the clarity of Requirement R1 is improved but we still have a couple
of concerns.
10
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
32 of 148
Organization
Yes or No
Question 2 Comment
Response: The standard drafting team thanks you for your comment.
(2) Why is the PC required to notify the GO and TO of Elements that were involved in
actual events when the GO and TO are the entities that notify the PC in the first place?
Doesn’t the PC just need to notify the GO and TO when those Elements are no longer
susceptible to tripping from stable power swings?
Response: The standard drafting team included Criterion 5 in Requirement R1 as a
mechanism to (1) create awareness for the Planning Coordinator that has wide‐area
awareness; and (2) to close the loop back to the Generator Owner or Transmission
Owner to continue to re‐evaluate its load‐responsive protective relays associated with
the identified Element; and (3) should the electric system topology change where the
Element is no longer susceptible to a power swing as determined by the Planning
Coordinator, the Element is no longer required to be identified pursuant to
Requirement R1. However, the standard drafting team has revised the standard such
that Requirement R1, Criterion 5 has been eliminated, along with Requirements R2 and
R3.
(3) In Criterion 4, why are unstable power swings included? Elements should trip due
to unstable power swings. Why does the GO and TO need to modify relaying for
unstable power swings?
Response: It is important to note that this standard does not require that entities
assess Protection System performance during unstable swings and does not require
entities to prevent tripping in response to unstable swings. Such requirements would
exceed the directive stated in the Federal Energy Regulatory Commission (FERC) Order
No. 733. This standard focuses on the identification of Elements by the Planning
Coordinator (Requirement R1) and Elements where the Generator Owner or
Transmission Owner becomes aware of an Element that tripped in response to a stable
or unstable power swing (Draft 3, Requirement R2, 2nd bullet). Requirement R1 and R2
(2nd bullet) is a screen to identify Elements that are subject to the Requirements of the
standard.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
33 of 148
Organization
Yes or No
Question 2 Comment
The FERC Order No. 733 directive is perceived as broad and overreaching and could
require all relays to be capable of differentiating between stable power swings and
faults. This standard’s focused approach is based on the PSRPS Report,11
recommending “...lines that have tripped due to power swings during system
disturbances...” as one of the ways to focus the evaluation. Based on feedback from
the contributors to the PSRPS Report, that recommendation does not exclude unstable
power swings. Furthermore, it is reasonable to assume that an Element that
experiences an unstable swing (in either a simulation or reality) is likely to experience
large stable power swings for less severe disturbances (that are probably more likely
to occur). Thus, the standard drafting team concluded that addressing Protection
Systems for Elements that tripped due to unstable power swings provides a reliability
benefit. No change made.
Since PRC‐006 only requires the PC to simulate the UFLS Program every five years, it
seems that requiring the PC to identify the same Elements that form a UFLS island
boundary every year is unnecessary. Criterion 3 should be modified to clarify that this
notification is only necessary once every five years when the UFLS study is completed.
Response: The standard drafting team contends that the Planning Coordinator must
notify the Generator Owner and Transmission Owner of the identified Elements
annually, even if the specified criteria in Requirement R1 is performed less frequently.
The periodicity is reasonable and practical to ensure timely notification of identified
Elements to the Generator Owner and Transmission Owner. No change made.
The standard drafting team provided additional dialogue about this in the Guidelines
and Technical Basis under the heading “Requirement R1.” Change made.
11
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
34 of 148
Organization
Yes or No
Question 2 Comment
Public Service Enterprise
Group
No
The Planning Coordinator should be obligated in R1 to provide system impedance data
as described in the Attachment B Criteria for each Element identified in R1 to the TO
or GO that owns the Element. PCs maintain the models that contain this data, and
having them provide it will result in consistency for relays set within the PC’s area.
Response: The standard drafting team contends that Generator Owners and
Transmission Owners already obtain this information periodically for other purposes
and for performance under other NERC Reliability Standards. No change made.
Xcel Energy
No
Criteria 1 uses the term “operating limit” and Criteria 2 uses the term “System
Operating Limit;” although both are identified by the existence of angular stability
constraints, thus seemingly defining the same type of operating constraint, i.e.
operating limit. Xcel Energy would suggest either explaining the difference between
the terms “operating limit” and “System Operating Limit”, or eliminating the
potentially duplicative criterion, since a “Generator” can be an “Element”.
Response: The standard drafting team replaced the term “operating limit” with
“System Operating Limit (SOL)” in Criterion 1 to be consistent with Criterion 2. Criterion
1 identifies generators and Elements terminating at the Transmission station
associated with the generator(s), while Criterion 2 identifies transmission Elements
that are monitored as part of an SOL. Change made.
In our opinion, Requirement R1 is organized and written in a manner that makes
interpretation difficult. Xcel Energy suggests that the drafting team consider re‐
organizing this requirement as suggested below.
R1 could be split so that R1 requires the PC to perform the following at least once per
year;
R1.1 would require the PC to identify Elements meeting the bulleted list of criteria;
R1.2 would require notification to the respective Generator Owner and Transmission
owner of each Element identified in R1.1.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
35 of 148
Organization
Yes or No
Question 2 Comment
Regardless of whether this Requirement R1 is re‐organized as suggested above or not,
we suggest the following rewrite of of Criteria 1 to minimize ambiguity. Criteria 1 can
be split either at the “or” (as in “...addressed by an operating limit or a Remedial Action
Scheme (RAS) and those Elements...”) or at the “and” (as in “...addressed by an
operating limit or a Remedial Action Scheme (RAS) and those Elements...”). To provide
additional clarity, Criteria 1 could be rewritten as:
”Generator(s) and Elements Terminating at associated transmission stations where
angular stability constraint exists that is addressed by an operating limit or a Remedial
Action Scheme (RAS).”
These potential modifications would improve the readability of the requirement and
provide for easier alignment with the associated Measures and VSLs.
Response: The standard drafting team thanks you for providing suggestions to improve
clarity; however, the standard drafting team declines to implement the suggestion to
avoid a loss in the intended purpose. No change made.
In addition, M1 could be rephrased to state
“Each Planning Coordinator shall have dated evidence that demonstrates identification
of Elements meeting the R1 criteria was performed on a calendar year basis and dated
evidence that demonstrates the respective owners of the identified Elements were
notified on a calendar year basis”.
Response: The standard drafting team declines to make the modification since
Requirement R1 was not modified according to the previous comment.
The existing M1 phrasing of “identification and respective notification of the Elements”
reads as if the Elements are being notified rather than the owners of the Elements.
Response: The standard drafting team made an editorial revision to Measure M1 to
address the issue raised in the comment. Change made.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Luminant Generation
Company, LLC
Yes or No
Question 2 Comment
No
Requirement R1 provides additional clarity of which Elements (including transformers,
generators) are included in a notification by the Transmission Planner. In light of the
fact that the purpose of this standard is “To ensure that load‐responsive protective
relays are expected to not trip in response to stable power swings during non‐Fault
conditions” which is in agreement with the FERC Order 733 (Section 150 of the FERC
Order: “requires the use of protective relay systems that can differentiate between
faults and stable power swings and, when necessary, phases out protective relay
systems that cannot meet this requirement”), it is an unnecessary extension of the
Order to include unstable power swings. The Standard Drafting Team stated “The
phase “stable or unstable” was inserted to clarify that both are applicable to power
swings because the goal of the standard is to identify Elements susceptible to either”
overreaches the FERC Order. Luminant recommends that unstable power swings be
removed.
Response: It is important to note that this standard does not require that entities
assess Protection System performance during unstable swings and does not require
entities to prevent tripping in response to unstable swings. Such requirements would
exceed the directive stated in the Federal Energy Regulatory Commission (FERC) Order
No. 733. This standard focuses on the identification of Elements by the Planning
Coordinator (Requirement R1) and Elements where the Generator Owner or
Transmission Owner becomes aware of an Element that tripped in response to a stable
or unstable power swing (Draft 3, Requirement R2, 2nd bullet). Requirement R1 and R2
(2nd bullet) is a screen to identify Elements that are subject to the Requirements of the
standard.
The FERC Order No. 733 directive is perceived as broad and overreaching and could
require all relays to be capable of differentiating between stable power swings and
faults. This standard’s focused approach is based on the PSRPS Report,12
12
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 2 Comment
recommending “...lines that have tripped due to power swings during system
disturbances...” as one of the ways to focus the evaluation. Based on feedback from
the contributors to the PSRPS Report, that recommendation does not exclude unstable
power swings. Furthermore, it is reasonable to assume that an Element that
experiences an unstable swing (in either a simulation or reality) is likely to experience
large stable power swings for less severe disturbances (that are probably more likely
to occur). Thus, the standard drafting team concluded that addressing Protection
Systems for Elements that tripped due to unstable power swings provides a reliability
benefit. No change made.
Additionally, R1 should be modified so that notifications are not required for elements
and relays that were previously identified and are currently in a Corrective Action Plan.
Response: The standard drafting team contends that providing additional caveats and
stipulations in the requirements does not provide a reliability benefit and only
complicates the clarity and intent of the Requirements. No change made.
The Planning Assessment referenced in R1, Criteria 4 should be limited to the
contingencies in TPL‐001‐0.1 “Table 1 Transmission System Standards ‐ Normal and
Emergency Conditions” Category A, B, C and D to focus the power swing evaluations
and corrective action development on activities that support the reliability of the BES.
Response: The standard drafting team contends that the proposed standard is in
alignment with the TPL‐001‐4 Reliability Standard, which becomes effective on January
1, 2015. Furthermore, the contingencies to which the Planning Coordinator will
consider have not been specified in the Requirement R1 criteria because there is no
certainty to what system conditions may produce a stable or unstable power swing on
a particular Element within the study. The criterion do not require the Planning
Coordinator to specifically evaluate for a power swing, only identify the Element if
observed as tripping during a simulated Disturbance. No change made.
City of Tallahassee
No
The Planning Coordinator should be obligated in R1 to provide system impedance data
as described in the Attachment B Criteria for each Element identified in R1 to the TO
Consideration of Comments:
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Organization
Yes or No
Question 2 Comment
or GO that owns the Element. PCs maintain the models that contain this data, and
having them provide it will result in consistency for relays set within the PC’s area.
Response: The standard drafting team contends that Generator Owners and
Transmission Owners already obtain this information periodically for other purposes
and for performance under other NERC Reliability Standards. No change made.
ISO New England
No
R1 should be changed to read:
R1. Each Planning Coordinator shall, for all design criteria events at least once each
calendar year, identify each Element in its area that meets one or more of the following
criteria and provide notification to the respective Generator Owner and Transmission
Owner, if any:
Response: The standard drafting team contends that the provided suggestion “…for all
design criteria events…” does not add clarity to Requirement R1. No change made.
Kansas City Power &
Light
No
A yearly notification is too often for this requirement since this information will rarely
change. We suggest a yearly notification for any change from the previous year, with a
five year notification of all identified Elements.
Response: The standard drafting team contends that the Planning Coordinator must
notify the Generator Owner and Transmission Owner of the identified Elements
annually, even if the specified criteria in Requirement R1 is performed less frequently.
The periodicity is reasonable and practical to ensure timely notification of identified
Elements to the Generator Owner and Transmission Owner. No change made.
CPS Energy
No
In general, support Luminant comments.
Response: The standard drafting team thanks you for your comment.
Nebraska Public Power
District (NPPD)
No
The PSRPS Recommendations Section states that the SPCS determined a Reliability
Standard is not needed.
Consideration of Comments:
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Organization
Yes or No
Question 2 Comment
Response: The standard drafting team thanks you for your comment and provided a
detailed explanation in the previous Consideration of Comments13 in the introductory
remarks regarding the need for a standard to meet regulatory directives.
Georgia Transmission
Corporation
No
Recommend further clarity and a revision to R1 criteria 1 such as:
From this:
Generator(s) where an angular stability constraint exists that is addressed by an
operating limit or a Remedial Action Scheme (RAS) and those Elements terminating at
the transmission switching station associated with the generator(s).
To this:
Generator(s) and those interconnecting Elements terminating at the transmission
switching station associated with the generator(s), where an angular stability
constraint exists that is addressed by an operating limit or a Remedial Action Scheme
(RAS).
Response: The standard drafting team thanks you for providing suggestions to improve
clarity; however, the standard drafting team declines to implement the suggestion to
avoid a loss in the intended purpose. No change made.
California ISO
No
The California ISO does not agree with the change to remove the Transmission Planner
in the Applicability section and in Requirement R1. The California ISO supports
continuing to include the Transmission Planner in Requirement R1 as suggested by the
PSRPS Report.
Response: The standard drafting team removed the Reliability Coordinator and
Transmission Planning as applicable entities in Draft 2 of the proposed standard in
response to comments to address concerns about overlap and potential gaps when
13
http://www.nerc.com/pa/Stand/Project%202010133%20Phase%203%20of%20Relay%20Loadability%20stabl/Project_2010_13.3_Consideration_of_
Comments_2014_08_22_to_Draft_1.pdf
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 2 Comment
identifying Elements in Requirement R1. Although the v suggested entities for
applicability, the standard drafting team agreed with comments on Draft 2 and that
the Planning Coordinator is in the best position to identify Elements to avoid
duplication and potential gaps. No change made.
Northeast Power
Coordinating Council
Yes
Comments regarding requirement R1 can be found in the response to Question 8.
Additionally, suggest clarifying requirement R1 by adding the wording “for all design
criteria events” so as to make it read: R1. Each Planning Coordinator shall, for all design
criteria events, at least once each calendar year, identify each Element in its area that
meets one or more of the following criteria and provide notification to the respective
Generator Owner and Transmission Owner, if any:
Response: The standard drafting team contends that the provided suggestion “…for all
design criteria events…” does not add clarity to Requirement R1. No change made.
Arizona Public Service Co
Yes
Puget Sound Energy
Yes
Southern Company:
Southern Company
Services, Inc.; Alabama
Power Company; Georgia
Power Company; Gulf
Power Company;
Mississippi Power
Company; Southern
Company Generation;
Southern Company
Generation and Energy
Marketing
Yes
Simplifying the requirement to a single entity clarified the responsibilities.
Response: The standard drafting team thanks you for your comment.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 2 Comment
Duke Energy
Yes
ISO RTO Council
Standards Review
Committee
Yes
The SRC agrees that the revisions improved the clarity of Requirement R1. However,
to ensure consistency with the other requirements within the Standard, the SDT
recommends that Requirement R1 also be broken into two (2) requirements, one
addressing identification and one addressing notification.
Response: The standard drafting team revised Requirement R1 to focus on the
notification of Elements to the Generator Owner and Transmission Owner that meet
one or more of the criteria, not on the identification of the Elements which are
identified by other studies. Change made.
Additionally, Requirement R1 should be changed to read:
R1. Each Planning Coordinator shall, for all design criteria events at least once each
calendar year, identify each Element in its area that meets one or more of the following
criteria and provide notification to the respective Generator Owner and Transmission
Owner, if any:
Response: The standard drafting team contends that the provided suggestion “…for all
design criteria events…” does not add clarity to Requirement R1. No change made.
Finally, the SRC recommends the following revision to Criterion 1 of Requirement R1
to streamline and ensure that the focus remains on Remedial Action Schemes:
1. Generator(s) where an angular stability constraint exists that is addressed by a
Remedial Action Scheme (RAS) and those Elements terminating at the transmission
switching station associated with the generator(s).
Response: The standard drafting team thanks you for providing suggestions to improve
clarity; however, the standard drafting team declines to implement the suggestion to
avoid a loss in the intended purpose. No change made.
Dominion
Yes
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 2 Comment
Florida Municipal Power
Agency
Yes
DTE Electric Co.
Yes
FirstEnergy Corp.
Yes
FirstEnergy suggests a slight modification to the wording of R1 Criteria 5 for clarity, as
follows: “An Element reported by the Transmission Owner pursuant to Requirement
R2 or Generator Owner pursuant to R3, unless ...”.
Response: The standard drafting team has revised the standard such that Requirement
R1, Criterion 5 has been eliminated, along with Requirements R2 and R3.
Tennessee Valley
Authority
Yes
The addition of criteria 5 seems circular in that the PC is notifying the GO or TO about
Elements they already know about. If the PC’s analysis applying criteria 1‐4 does not
identify these Elements initially, why should the same PC criteria be entrusted to
determine that “the Element is no longer susceptible to power swings”?
Response: The standard drafting team has revised the standard such that Requirement
R1, Criterion 5 has been eliminated, along with Requirements R2 and R3.
Bonneville Power
Administration
Yes
BPA requests a revision to R1 to separate customer notifications from technical
analysis.
R1.1 Each Planning Coordinator shall, at least once each calendar year, identify each
Element in its area that meets one or more of the following criteria
R1.2 Each Planning Coordinator shall provide notification to each respective Generator
Owner or Transmission Owner that owns an Element identified in R1.1.
Response: The standard drafting team revised Requirement R1 to focus on the
notification of Elements to the Generator Owner and Transmission Owner that meet
one or more of the criteria, not on the identification of the Elements which are
identified by other studies. Change made.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
43 of 148
Organization
Yes or No
Question 2 Comment
Oncor Electric Delivery
LLC
Yes
Entergy Services, Inc.
Yes
American Electric Power
Yes
Independent Electricity
System Operator
Yes
Wisconsin Electric
Yes
Idaho Power
Yes
Pepco Holdings Inc.
Yes
Tacoma Power
Yes
Ameren
Yes
ITC
Yes
Texas Reliability Entity
Yes
While Texas RE agrees with the approach of using criteria from the PSRPS technical
document, we have concerns about the stated time horizon. Requirement R1 Criterion
2 states that the PC should include elements identified in operating studies, but the
time horizon for this requirement is Long‐term Planning. Texas RE suggests that either
the Operations Planning time horizon needs to be added to this requirement or the
reference to operating studies needs to be removed, whichever is in line with the
intent of the SDT.
Response: The standard drafting team revised Requirement R1, Criterion 1 to replace
the phrase “an operating limit” with “System Operating Limit (SOL).” Further, the
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 2 Comment
standard drafting team reworded Requirement R1, Criterion 2 to remove the phrase
“identified in system planning or operating studies” and clarify that the SOL is identified
based on the Planning Coordinator’s methodology in the planning horizon. This
revision aligns use of the term in the standard with the Glossary of Terms Used in NERC
Reliability Standards defined term, “System Operating Limit” or “SOL.” Also, this
revision aligns the use of “SOL” with the Planning Coordinator’s methodology of how
SOLs are developed according to FAC‐10 (System Operating Limits Methodology for
the Planning Horizon). Change made.
Manitoba Hydro
Yes
Lower Colorado River
Authority
Yes
American Transmission
Company, LLC
Yes
Tri‐State Generation and
Transmission
Association, Inc.
Yes
Consumers Energy
Company
Yes
Arizona Public Service
Yes
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
45 of 148
3.
The previous Requirement R2 was split into Requirement R2 for the Transmission Owner and Requirement R3 for the Generator Owner
in order to clarify the performance for identifying Elements that trip. Did this revision improve the understanding of what is required? If
not, please explain why the Requirement(s) need additional clarification.
Summary Consideration: Almost two‐thirds of entities providing comment agree that Requirements R2 and R3 provided clarity over
the previous Draft 2. Below is a summary of the comments received about the two Requirements that required the Transmission
Owner (Requirement R2) and the Generator Owner (Requirement R3) to provide notification of any BES Element that tripped due to
a stable or unstable power swing.
There were two significant themes of comments that resulted in a revision to the Standard. First, fifteen comments supported by 55
individuals expressed concerns about a number of issues regarding Requirements R2 and R3. These concerns included, but are not
limited to: 1) the 30 day notification time frame by the Generator Owner and Transmission Owner to the Planning Coordinator was
too short; 2) the Measures (M2 and M3) focused on identification of the BES Elements whereas the Requirements only addressed
notification; 3) additional detail about BES Elements that form a boundary of an island; 4) the ability to “identify a stable or unstable
power swing;” 5) the review of a Protection System within PRC‐026‐1 and potential conflicts or overlaps with NERC Reliability
Standard PRC‐00414 that addresses identification of Misoperations of Protection Systems; 6) how is the starting point established for
the purpose of measuring performance of the Requirement; 7) inconsistency with the Violation Severity Levels (VSL); and 8) more
information needed on how to identify powers swings.
To address these concerns, the standard drafting team removed the previous Requirements R2 (Transmission Owner) and R3
(Generator Owner) that required notification to the Planning Coordinator, in Requirement R1, of Element that tripped due to stable
or unstable power swings. In deleting Requirements R2 and R3, the standard drafting team revised Draft 3, Requirement R2
(previously Draft 2, Requirement R4) for load‐responsive relays to be evaluated under two conditions:
•
Notification of an Element pursuant to Requirement R1 where the evaluation of the Element has not been performed
in the last five calendar years, or
•
Becoming aware of an Element that tripped in response to a stable or unstable power swing.
The standard drafting team provided supporting detail on the second bullet (above) in the Guidelines and Technical Basis under the
heading “Becoming Aware of an Element That Tripped in Response to a Power Swing” on how an entity would “become aware.”
14
Protection System Misoperation Identification and Correction.
Consideration of Comments:
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Second, six comments supported by 19 individuals commented that the Standard should not require the Generator Owner and
Transmission Owners to identify “unstable” power swings. Comments stemmed from concerns over the ability to identify (e.g.,
needing digital fault recording), overstepping the Federal Energy Regulatory Commission (FERC) Order No. 733 directive to address
only stable, and that the Standard seems to require that entities track every BES Element trip to prove that the entity reviewed it for
stable and unstable power swing. To address this concern, the standard drafting team removed Requirements R2 and R3 and
incorporated a change to Requirement R2 (previously R4) for when an entity “becomes aware” of a stable or unstable power swing
that tripped its BES Element. Performance is required when the entity “becomes aware” of a generator, transformer, or transmission
line BES Element that tripped in response to a stable or unstable power swing due to the operation of its protective relay(s).
The following summarizes comments did not result in a change to the Standard. First, two comments each from an individual
concerned that the Standard is limiting an entity’s ability to trip for “unstable” power swings. The Draft 3, Requirement R2
(previously Draft 2, Requirement R4) ensures that the Protection System will be evaluated after tripping for an “unstable” power
swing to ensure that the Protection System is expected to not trip for a “stable” power swing. The Protection System is not
precluded from tripping in response to an unstable power swing. The standard drafting team contends that any out‐of‐step tripping
requirements would be identified independent of this standard and, if required, would need to remain in service.
Last, an individual commented that the Standard should exclude trips during black‐starting and system restoration. The standard
drafting team disagreed because trips that occur during these circumstances should be evaluated to ensure that load‐responsive
protective relays are expected to not trip in response to a stable power swing during non‐Fault conditions.
Organization
Puget Sound Energy
Yes or No
No
Question 3 Comment
In general, we agree with the comments submitted by PSEG.
R2 and R3 require TOs and GOs, respectively, to notify their Planning Coordinator within
30 days of identifying any Element that trips due to a power swing during a system
disturbance due to the operation of load‐responsive protective relays. PRC‐026‐1, as
drafted, will have consequences with respect to an entity’s implementation of a
different standard: PRC‐004‐3 ‐ Protection System Misoperation Identification and
Correction ‐ see http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC‐004‐
3.pdf. NERC has filed PRC‐004‐3 with FERC for approval.
Consideration of Comments:
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Posted: November 4, 2014
47 of 148
Organization
Yes or No
Question 3 Comment
In summary, PRC‐004‐3 requires each operation of an interrupting device to be
evaluated to determine whether a Misoperation occurred. If such a determination is
made, the Protection System owner must investigate the occurrence and either
(a) provide a declaration that a cause could not be determined or
(b) if a cause is determined, develop and implement a Corrective Action Plan (CAP) or
explain why corrective actions are beyond its control or would not improve reliability.
PRC‐004‐3 does not require any action with regard to Element trips that are not
Misoperations, i.e., “correct operations.” We understand that a Protection System
owner would need some documentation to make the distinction between a correct
operation and a Misoperation. However, in order to be fully compliant with PRC‐026‐1
R2 and R3, every Element that trips due to the operation of a load‐responsive relay must
be evaluated by the entity to determine whether or not the trip was due to a power
swing.
As discussed on the September 18 webinar on PRC‐026‐1, the phrase “system
Disturbance” has same meaning as the NERC Glossary term for “Disturbance.” In other
words, “system” is unnecessary. In addition, a “Fault” was stated to be a “Disturbance.”
Therefore, every operation of a load‐responsive relay due to a Fault must be examined
under PRC‐026‐1 to identify whether or not the Element tripped due to a power swing.
o If an Elements trips due to a Misoperation, the Misoperation would be investigated
under PRC‐004‐3, and if it was caused by a power swing that could easily be reported
under PRC‐026‐1 as a result of the Protection System owner’s compliance with PRC‐
004‐3.
Requiring all correct operations be affirmatively evaluated by the Element owner to
determine whether they are attributable to a power swing would only “make work” for
both the Element owners and their auditors, and the added effort would not improve
reliability. Therefore, we propose that the scope of R2 and R3 for correct operations be
reduced to a subset of events that are reported to NERC under EOP‐004‐2 ‐ Event
Reporting ‐ see http://www.nerc.com/pa/Stand/Reliability%20Standards/EOP‐004‐
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 3 Comment
2.pdf. For example, the Disturbances evaluated in PRC‐026‐1 for correct operations
could be limited to some of the events and associated thresholds listed in EOP‐004 ‐
Attachment 1. We believe reasonable events would include:
o Automatic firm load shedding on p. 9
o Loss of firm load (preferably limited to non‐weather related load loss) on p. 10
o System separation (islanding) on p.10
o Generation loss on p.10,
o Complete loss of off‐site power to a nuclear plant on p. 10, and
o Transmission loss on p.11.
To couple the two standards together, NERC, which receives event reports under EOP‐
004‐2, would need to notify the applicable TOs and GOs under PRC‐026‐1 of the time
frame of each event. This would allow the Element owners to evaluate whether any
Element trips that occurred during the event and which were correct operations were
associated with a power swing.
Without this notification, Events that happen outside of the Planning Coordinator’s PC
Area may not be properly identified by the affected PC. If this is not the intent of the
standard, there needs to be a distinction made between whether relays should be
evaluated against local disturbances (disturbances within the PC Area) and system‐wide
disturbances that would be communicated throughout the region.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 3 Comment
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
The standard drafting team made revisions to the standard which eliminated the term
“Disturbance” as defined by the Glossary of Terms Used in NERC Reliability Standards.
Colorado Springs
Utilities
No
ISO RTO Council
Standards Review
Committee
No
We agree with the Public Service Electric and Gas Company comments.
Response: The standard drafting team thanks you for participating, please see the
responses to Public Service Enterprise Group.
The SRC notes that Requirements R2 and R3 are about notification if an element
meeting specified criteria is identified. However, the measures are primarily focused on
identification. Accordingly, the measures should be revised for consistency with the
associated Requirements R2 and R3.
Response: The standard drafting team removed Requirements R2 and R3; therefore,
the conflict is no longer present. Change made.
Dominion
No
M3 seems to be missing the word ‘meet’; suggest M3 read as; M3. Each Generator
Owner shall have dated evidence that demonstrates identification of the Element(s), if
any, which ‘meet’ the criterion in Requirement R3. Evidence may include, but is not
limited to, the following documentation: emails, facsimiles, records, reports,
transmittals, lists, or spreadsheets.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 3 Comment
Response: The standard drafting team removed Requirements R2 and R3; therefore,
the issue is no longer present. Change made.
Dominion agrees with the split of R2, however, elements could have their load‐
responsive protective relays operate prior to the formation of an island. In the
Application Guide, a section should be included to better define methods used for
boundary detection, if we are required to determine if the element was in‐fact the
boundary to an island. Otherwise, power swings could cause relays to operate without
internal detection algorithms picking up the swing.
Response: The standard drafting team removed Requirements R2 and R3; therefore,
the issue is no longer present. Change made.
Florida Municipal Power
Agency
No
Requirements R2 and R3 need further clarification. FMPA agrees that splitting the
Requirement was beneficial. However, FMPA finds the following issues left requiring
resolution, which point to the need to better coordinate this standard with PRC‐004:
1. The language is crafted as if a typical TO or GO would easily be able to determine that
an element tripped due to a power swing. This only makes sense for large vertically
integrated utilities in which staff with a variety of knowledge bases and skill sets may be
working together. In reality, for smaller utilities that may be only a TO/DP or GO, this
determination will require some involvement from a TP, PC, TOP, or RC, with staff that
have a) access to real time information, event records, and other information beyond
what any single TO or GO may have and b) an understanding of the expected regional
stability performance which TO/GO staff may not have. Realistically it should only be
presumed the TO or GO staff will be able to conclude that their relays did not trip for a
fault.
Response: The standard drafting team contends that PRC‐026‐1 does not require an
entity to determine whether an Element tripped due to a power swing. This is
accomplished in the revision to Requirement R2 (previously Requirement R4) that when
an entity “becomes aware” it would evaluate the relay(s). The identification of a power
swing that causes a BES Element trip could be determined through an entity’s
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 3 Comment
Protection System analysis process (e.g., PRC‐00415), event analysis review by the entity,
region, or NERC.
2. The standard sets a 30 day clock which starts with a piece of information that isn’t
required or driven from anywhere ‐ namely, the point in time at which at TO or GO
discovers that any relay operated (either correctly or incorrectly) due to a power swing.
Since there is currently no place where it is required that correct/proper relay operation
be documented, it is not clear what sort of documentation the TO/GO will have and
what process, performed by what staff, would drive the TO/GO to “initially discover”
that the relay operated due to a power swing. The point being‐ in a normal PRC‐004
investigation, at such time as it is discovered that a relay properly operated, there is no
requirement for any formal report, on any formal schedule, to include that information.
At what point does the “official” starting point of this 30 day clock occur? This points to
the need for further/better coordination with PRC‐004.
Response: The standard drafting team removed Requirements R2 and R3 and notes it
is up to the entity to determine when it becomes aware of the condition upon which
performance is measured. Change made.
Seminole Electric
Cooperative, Inc.
No
Requirements R2 and R3 appear to require the reporting of trips due to UNSTABLE
power swings. Seminole feels that a better mechanism for collecting information on
unstable power swings is through NERC Section 1600 data requests, not via a Standard.
Requirements R2 and R3 utilize the term “identifying.” Can the SDT add language in the
application guidelines that clarifies that “identifying” means “making a determination,”
as the term identifying is somewhat unclear to Seminole.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator in, Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
15
Protection System Misoperation Identification and Correction.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Organization
Yes or No
Question 3 Comment
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
Xcel Energy
No
The Measures M2 & M3 do not match the R2 & R3 requirements. The measures only
require that the TO and GO have evidence of the identification of elements, but do not
require evidence of notification of identified Elements to the PC.
The VSLs for R2 & R3 classify it as a Severe VSL if the TO or GO fails to identify an Element
in accordance with R2 & R3. However, the way R2 & R3 are written, there is no
requirement for the TO or GO to identify anything. As the requirements are currently
written, the only requirement is that the PC is notified within 30 calendar days of
identification of an Element meeting the criteria. If a TO or GO does not identify an
Element, they can never be in violation of R2 or R3 as written. Further, if there is no
requirement for identification of Elements meeting R2 or R3 criteria, it is not clear what
the starting point is for determining the 30 day notification period. How is the official
date of identification of an Element pursuant to R2 & R3 determined? And how is it
officially documented for use in establishing PC notification due date in determining the
severity of the violation?
It is unclear what action the PC is going to take, upon notification of the identification
of an Element meeting R2 & R3 criteria, beyond adding the Element to the R1 list for
future years that will be provided to the TO and GO. If that is the only resulting action,
Consideration of Comments:
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Posted: November 4, 2014
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Yes or No
Question 3 Comment
the 30 day notification of the PC or the <10 day overdue Lower VSL, <20 day overdue
Moderate VSL, <30 day overdue High VSL or >30 day overdue Severe VSL do not seem
to align. R4 directs the TO and GO to analyze the Elements within 12 calendar months
of identifying the Element pursuant to R2 or R3. If the only action taken by the PC is to
add the Element to the R1 list for future years, is would seem to be just as effective from
a reliability perspective to give the TO and GO up to the next calendar year to notify the
PC about R2 7 R3 identified elements and to align the R2 & R3 VSL notification
timeframes with those allowed for the PC to TO/GO notifications in R1.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings, thus eliminating the connection with PRC‐004.16 In deleting
Requirements R2 and R3, the standard drafting team revised Requirement R4 (now
Requirement R2) for load‐responsive relays to be evaluated under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
The standard drafting team has revised the standard such that Requirement R1,
Criterion 5 has been eliminated, along with Requirements R2 and R3. Change made.
16
Protection System Misoperation Identification and Correction.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
54 of 148
Organization
Yes or No
Question 3 Comment
The standard drafting team removed Requirements R2 and R3 and notes it is up to the
entity to determine when it becomes aware of the condition upon which performance
is measured. Change made.
Wisconsin Electric
No
: We take issue with this requirement.
First, it will be difficult or impossible for the Generator Owner (GO) to comply with. The
requirement in R3 is to notify the Planning Coordinator of an Element that trips due to
a stable or unstable power swing during an actual system Disturbance due to the
operation of its load‐responsive protective relays. Without dynamic disturbance
recording (DDR), it may not be possible to determine that the relay tripped due to a
power swing. The GO is not required to have (DDR) capability for every generator. Note
that DDR will only be required by the future PRC‐002 standard for a subset of
generators, not all of them. The most that a GO may be able to do is to say that a
generator relay may have operated for a power swing, especially when the Generator
Owner does not own or operate the connected transmission system.
Response: The standard drafting team contends that PRC‐026‐1 does not require an
entity to determine whether an Element tripped due to a power swing. This is
accomplished in the revision to Requirement R2 (previously Requirement R4) that when
an entity “becomes aware” it would evaluate the relay(s). The identification of a power
swing that causes a BES Element trip could be determined through an entity’s
Protection System analysis process (e.g., PRC‐00417), event analysis review by the entity,
region, or NERC.
The standard drafting team removed Requirements R2 and R3 and notes it is up to the
entity to determine when it becomes aware of the condition upon which performance
is measured. Change made.
Second, if an unstable power swing passes through the generator or generator step‐up
transformer, the generator SHOULD trip in order to prevent or limit possible damage.
17
Protection System Misoperation Identification and Correction.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
55 of 148
Organization
Yes or No
Question 3 Comment
The generator out‐of‐step relay is used for this purpose, and it does not appear that this
standard will allow the necessary settings on the Device 78 element to properly protect
the generator. Common industry settings for the 78 out‐of‐step function do not appear
to be possible based on the Application Guidelines in the draft standard. For these
reasons, we believe that this requirement should be removed. If it is retained, then the
scope of the applicability to generators should be limited to those generators where
DDR will be required per the future PRC‐002.
Response: Requirement R2 (previously R4) ensures that the Protection System will be
evaluated after tripping for an unstable power swing to ensure that the Protection
System is expected to not trip for a stable power swing. The Protection System is not
precluded from tripping in response to an unstable power swing. The standard drafting
team contends that any out‐of‐step tripping requirements would be identified
independent of this standard and, if required, would need to remain in service.
Examples have been added to the Guidelines and Technical Basis to illustrate an entity
complying with the standard while using out‐of‐step trip relaying.
City of Tallahassee
No
R2 and R3 require TOs and GOs, respectively, to notify their Planning Coordinator within
30 days of identifying any Element that trips due to a power swing during a system
disturbance due to the operation of load‐responsive protective relays. PRC‐026‐1, as
drafted, will have consequences with respect to an entity’s implementation of a
different standard: PRC‐004‐3 ‐ Protection System Misoperation Identification and
Correction ‐ see http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC‐004‐
3.pdf. NERC has filed PRC‐004‐3 with FERC for approval.
In summary, PRC‐004‐3 requires each operation of an interrupting device to be
evaluated to determine whether a Misoperation occurred. If such a determination is
made, the Protection System owner must investigate the occurrence and either
(a) provide a declaration that a cause could not be determined or
(b) if a cause is determined, develop and implement a Corrective Action Plan (CAP) or
explain why corrective actions are beyond its control or would not improve
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Yes or No
Question 3 Comment
reliability.PRC‐004‐3 does not require any action with regard to Element trips that are
not Misoperations, i.e., “correct operations.” We understand that a Protection System
owner would need some documentation to make the distinction between a correct
operation and a Misoperation. However, in order to be fully compliant with PRC‐026‐1
R2 and R3, every Element that trips due to the operation of a load‐responsive relay must
be evaluated by the entity to determine whether or not the trip was due to a power
swing.
As discussed on the September 18 webinar on PRC‐026‐1, the phrase “system
Disturbance” has same meaning as the NERC Glossary term for “Disturbance.” In other
words, “system” is unnecessary. In addition, a “Fault” was stated to be a “Disturbance.”
Therefore, every operation of a load‐responsive relay due to a Fault must be examined
under PRC‐026‐1 to identify whether or not the Element tripped due to a power swing.
o If an Elements trips due to a Misoperation, the Misoperation would be investigated
under PRC‐004‐3, and if it was caused by a power swing that could easily be reported
under PRC‐026‐1 as a result of the Protection System owner’s compliance with PRC‐
004‐3.
Requiring all correct operations be affirmatively evaluated by the Element owner to
determine whether they are attributable to a power swing would only “make work” for
both the Element owners and their auditors, and the added effort would not improve
reliability. Therefore, we propose that the scope of R2 and R3 for correct operations be
reduced to a subset of events that are reported to NERC under EOP‐004‐2 ‐ Event
Reporting ‐ see http://www.nerc.com/pa/Stand/Reliability%20Standards/EOP‐004‐
2.pdf. For example, the Disturbances evaluated in PRC‐026‐1 for correct operations
could be limited to some of the events and associated thresholds listed in EOP‐004 ‐
Attachment 1. We believe reasonable events would include:
o Automatic firm load shedding on p. 9
o Loss of firm load (preferably limited to non‐weather related load loss) on p. 10
o System separation (islanding) on p.10
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Organization
Yes or No
Question 3 Comment
o Generation loss on p.10,
o Complete loss of off‐site power to a nuclear plant on p. 10, and
o Transmission loss on p.11.
To couple the two standards together, NERC, which receives event reports under EOP‐
004‐2, would need to notify the applicable TOs and GOs under PRC‐026‐1 of the time
frame of each event. This would allow the Element owners to evaluate whether any
Element trips that occurred during the event and which were correct operations were
associated with a power swing.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
The standard drafting team made revisions to the standard which eliminated the term
“Disturbance” as defined by the Glossary of Terms Used in NERC Reliability Standards.
ISO New England
No
Although splitting the requirement into two adds clarity, what was the underlying
uncertainty that this is intended to address? R4 continues to be a combined TO/GO
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Yes or No
Question 3 Comment
requirement that was not split. We ask whether the same uncertainty exists for R4
(previously R3) and should it also be split?
Response: The standard drafting team notes that the previous splitting of the Draft 1
Requirement into the Draft 2, Requirements R2 and R3 was intended for clarifying that
the “islanding” criteria was only related to the Transmission Owner. The evaluation of
load‐responsive protective relays under the new Requirement R2 (previously
Requirement R4) applies to both the Generator Owner and Transmission Owner in
evaluating the 120 degree separation angle.
Kansas City Power &
Light
No
A trip during a stable power swing is a mis‐operation and is covered in PRC‐004. A trip
during an unstable power swing is an intended result and not applicable to this
standard. We suggest removing these two requirements.
Response: The standard drafting team thanks you for your comment and notes that
Requirements R2 and R3 have been removed and changes were made to the previous
R4 (now Requirement R2) to address other comments and concerns. Change made.
This Requirement ensures that the Protection System will be evaluated after tripping
for an unstable power swing to ensure that the Protection System is expected to not
trip for a stable power swing. The Protection System is not precluded from tripping in
response to an unstable power swing.
Pepco Holdings Inc.
No
The 30 day time line provided for Requirement R2 in the standard to determine if an
element operated due to either of the Criteria provided seems aggressive. The shortest
amount of time we have to determine if a protective relaying scheme mis‐operated
under current quarterly reporting requirements for PRC‐004 is 60 days. It would make
sense if the timeline for this standard was adjusted to match.
In addition, the requirement as written does not seem to differentiate if this level of
analysis is required for the operation of all in‐scope protective relaying schemes or just
those that were determined to mis‐operated. Requiring this level of study for all in‐
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
59 of 148
Organization
Yes or No
Question 3 Comment
scope protective relaying schemes would seem to provide a tremendous compliance
burden to the Transmission Owners.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
CPS Energy
No
In general, support PSEG comments.
Response: The standard drafting team thanks you for participating, please see the
responses to Public Service Enterprise Group.
Nebraska Public Power
District (NPPD)
No
Both R2 and R3 requirements appear to take a “wait and see” approach rather than a
proactive approach. This doesn’t seem practical when maintaining the reliable
operation of the BES. We recommend elimination of both R2 and R3.Additionally, R2
states that the TO would need to identify “an Element that forms the boundary of an
island during an actual system Disturbance due to the operation of its load‐responsive
protective relays.” This type of event would be very complex and would likely include
many contingencies. Thus the statement seems too general and all‐encompassing. We
feel this reliability function might be better served by the Planning Coordinator(s) or
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Organization
Yes or No
Question 3 Comment
Reliability Entity facilitating an event analysis where better decisions and
recommendations can be made, given their wide‐area view and awareness of reliability
issues. If a relay did trip on OOS for a stable power swing, the likelihood of it being part
of a larger event or a misoperation is high. If it were a misoperation, it would then be
addressed in another standard or event analysis process. As noted above it seems R2
and R3 are better served by existing processes or standards.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
Ameren
No
Ameren adopts the following comment submitted by PSEG.
R2 and R3 require TOs and GOs, respectively, to notify their Planning Coordinator within
30 days of identifying any Element that trips due to a power swing during a system
disturbance due to the operation of load‐responsive protective relays. PRC‐026‐1, as
drafted, will have consequences with respect to an entity’s implementation of a
different standard: PRC‐004‐3 ‐ Protection System Misoperation Identification and
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
61 of 148
Organization
Yes or No
Question 3 Comment
Correction ‐ see http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC‐004‐
3.pdf. NERC has filed PRC‐004‐3 with FERC for approval.
In summary, PRC‐004‐3 requires each operation of an interrupting device to be
evaluated to determine whether a Misoperation occurred. If such a determination is
made, the Protection System owner must investigate the occurrence and either
(a) provide a declaration that a cause could not be determined or
(b) if a cause is determined, develop and implement a Corrective Action Plan (CAP) or
explain why corrective actions are beyond its control or would not improve reliability.
PRC‐004‐3 does not require any action with regard to Element trips that are not
Misoperations, i.e., “correct operations.” We understand that a Protection System
owner would need some documentation to make the distinction between a correct
operation and a Misoperation. However, in order to be fully compliant with PRC‐026‐1
R2 and R3, every Element that trips due to the operation of a load‐responsive relay must
be evaluated by the entity to determine whether or not the trip was due to a power
swing.
As discussed on the September 18 webinar on PRC‐026‐1, the phrase “system
Disturbance” has same meaning as the NERC Glossary term for “Disturbance.” In other
words, “system” is unnecessary. In addition, a “Fault” was stated to be a “Disturbance.”
Therefore, every operation of a load‐responsive relay due to a Fault must be examined
under PRC‐026‐1 to identify whether or not the Element tripped due to a power swing.
o If an Elements trips due to a Misoperation, the Misoperation would be investigated
under PRC‐004‐3, and if it was caused by a power swing that could easily be reported
under PRC‐026‐1 as a result of the Protection System owner’s compliance with PRC‐
004‐3.
Requiring all correct operations be affirmatively evaluated by the Element owner to
determine whether they are attributable to a power swing would only “make work” for
both the Element owners and their auditors, and the added effort would not improve
reliability. Therefore, we propose that the scope of R2 and R3 for correct operations be
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
62 of 148
Organization
Yes or No
Question 3 Comment
reduced to a subset of events that are reported to NERC under EOP‐004‐2 ‐ Event
Reporting ‐ see http://www.nerc.com/pa/Stand/Reliability%20Standards/EOP‐004‐
2.pdf. For example, the Disturbances evaluated in PRC‐026‐1 for correct operations
could be limited to some of the events and associated thresholds listed in EOP‐004 ‐
Attachment 1. We believe reasonable events would include:
o Automatic firm load shedding on p. 9
o Loss of firm load (preferably limited to non‐weather related load loss) on p. 10
o System separation (islanding) on p.10
o Generation loss on p.10,
o Complete loss of off‐site power to a nuclear plant on p. 10, and
o Transmission loss on p.11.
To couple the two standards together, NERC, which receives event reports under EOP‐
004‐2, would need to notify the applicable TOs and GOs under PRC‐026‐1 of the time
frame of each event. This would allow the Element owners to evaluate whether any
Element trips that occurred during the event and which were correct operations were
associated with a power swing.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
63 of 148
Organization
Yes or No
Question 3 Comment
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
The standard drafting team made revisions to the standard which eliminated the term
“Disturbance” as defined by the Glossary of Terms Used in NERC Reliability Standards.
CenterPoint Energy
No
CenterPoint Energy recommends additional clarification be provided for identifying and
the reporting, or not reporting, of Elements that trip from power swings during system
disturbances. We believe certain tripping should be excluded, such as, when
reconnecting islands and during black start restoration. We suggest the following
sentence be added to Requirement R1, Criterion 1: “Notification shall not be provided
if an Element trips from a power swing that occurs during operator‐initiated switching
to reconnect islands, to restore load during Black Start activities, or to synchronize a
generating unit to the system”. In addition, it may be needed to clarify that tripping of
Elements from voltage or frequency oscillations due to power system stabilizer issues
are not to be reported.
Response: The standard drafting team has revised Requirement R4 (now Requirement
R2) to require the Generator Owner and Transmission Owner to evaluate its load‐
responsive protective relays applied at the terminals of an Element that trips upon
“becoming aware of an Element that tripped in response to a stable or unstable power
swing.” The standard drafting team has provided supporting detail on the second bullet
in the Guidelines and Technical Basis on how an entity would “become aware.”
The standard drafting team concluded exclusions for system restoration or black‐
starting should not be provided because it could be detrimental to reliability. Any
Element that tripped in response to a stable or unstable power swing must be
addressed, especially involving restoration and black‐starting because those are
conditions where power swings would be expected and it is critical that load‐responsive
protective relays are secure for stable power swings.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Organization
Consumers Energy
Company
Yes or No
No
Question 3 Comment
R2 and R3 require modification to provide clarity in how the Owner will determine if
any given trip is due to a swing. Without specific guidance on how to identify and
document when a swing occurs and whether that swing caused a trip, we do not believe
we are able to comply with R2 or R3. For instance, if an Owner only has
electromechanical relays on a terminal, and does not own the other terminal(s) of that
element, how is it to determine the impedance trajectory and whether or not that
trajectory was a swing or a fault?
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
Northeast Power
Coordinating Council
Yes
Comments regarding requirements R2 and R3 can be found in the response to Question
8.
Response: The standard drafting team thanks you for your comment, please see
response in Question 8.
Splitting requirement R2 into two requirements adds clarity.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
65 of 148
Organization
Yes or No
Question 3 Comment
Response: The standard drafting team thanks you for your comment and notes that
Requirements R2 and R3 have been removed and changes were made to the previous
R4 (now Requirement R2) to address other comments and concerns. Change made.
Arizona Public Service
Co
Yes
Southern Company:
Southern Company
Services, Inc.; Alabama
Power Company;
Georgia Power
Company; Gulf Power
Company; Mississippi
Power Company;
Southern Company
Generation; Southern
Company Generation
and Energy Marketing
Yes
Since the criteria is not completely the same for the TO and GO, spliting the previous R2
into a new R2 and new R3 was a good move.
Duke Energy
Yes
JEA
Yes
DTE Electric Co.
Yes
FirstEnergy Corp.
Yes
Regarding R3, as a Generator Owner in a deregulated / competitive environment, we
still have a concern about being held accountable for events for which we are unaware
‐ power swings or Disturbances on the system (Criteria 1) ‐ due to FERC Code of Conduct
separation with the regulated system. We are not aware of system events. We realize,
however, that R3 says, “... within 30 calendar days of identifying ...”; the concern simply
Response: The standard drafting team thanks you for your comment and notes that
Requirements R2 and R3 have been removed and changes were made to the previous
R4 (now Requirement R2) to address other comments and concerns. Change made.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Question 3 Comment
relates to the level of responsibility placed on the GO to “identify” tripping of load‐
responsive relays caused by “... a stable or unstable power swing during an actual
system Disturbance ...”.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
Tennessee Valley
Authority
Yes
Seattle City Light
Yes
ACES Standards
Collaborators
Yes
(1) We agree with splitting the requirements because the GO simply is not privy to the
same information as the TO to identify island boundaries. However, it is reasonable for
the GO to work with the TO and TOP to determine the cause of the relay operations to
be from a stable power swing.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
67 of 148
Organization
Yes or No
Question 3 Comment
Response: The standard drafting team thanks you for your comment and notes that
Requirements R2 and R3 have been removed and changes were made to the previous
R4 (now Requirement R2) to address other comments and concerns. Change made.
(2) We believe the time horizons for both requirements R2 and R3 need to be modified.
Both are currently long‐term planning which is one year or longer into the future. Since
this is an evaluation of actual events, we believe the Operations Assessment time
horizon is more accurate.
Response: The standard drafting team removed Requirements R2 and R3; therefore,
the issue is no longer present. Change made.
(3) Why is tripping from unstable power swings included in these two requirements?
Relays should trip due to unstable power swings. The FERC directive compelled NERC to
develop a standard that requires protection systems to be able to differentiate between
stable power swings and faults. The directive did not require NERC to specifically
address unstable powers swings. We recommend removing unstable power swings
from both R2 and R3.
Response: It is important to note that this standard does not require that entities assess
Protection System performance during unstable swings and does not require entities to
prevent tripping in response to unstable swings. Such requirements would exceed the
directive stated in the Federal Energy Regulatory Commission (FERC) Order No. 733.
This standard focuses on the identification of Elements by the Planning Coordinator
(Requirement R1) and Elements where the Generator Owner or Transmission Owner
becomes aware of an Element that tripped in response to a stable or unstable power
swing (Draft 3, Requirement R2, 2nd bullet). Requirement R1 and R2 (2nd bullet) is a
screen to identify Elements that are subject to the Requirements of the standard.
The FERC Order No. 733 directive is perceived as broad and overreaching and could
require all relays to be capable of differentiating between stable power swings and
Consideration of Comments:
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Organization
Yes or No
Question 3 Comment
faults. This standard’s focused approach is based on the PSRPS Report,18 recommending
“...lines that have tripped due to power swings during system disturbances...” as one of
the ways to focus the evaluation. Based on feedback from the contributors to the PSRPS
Report, that recommendation does not exclude unstable power swings. Furthermore,
it is reasonable to assume that an Element that experiences an unstable swing (in either
a simulation or reality) is likely to experience large stable power swings for less severe
disturbances (that are probably more likely to occur). Thus, the standard drafting team
concluded that addressing Protection Systems for Elements that tripped due to unstable
power swings provides a reliability benefit. No change made.
Bonneville Power
Administration
Yes
Oncor Electric Delivery
LLC
Yes
Entergy Services, Inc.
Yes
American Electric Power
Yes
Independent Electricity
System Operator
Yes
Luminant Generation
Company, LLC
Yes
Idaho Power
Yes
18
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System
%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 3 Comment
Tacoma Power
Yes
ITC
Yes
Texas Reliability Entity
Yes
While Texas RE agrees with splitting the previous Requirement R2 into Requirement R2
for the Transmission Owner (TO) and Requirement R3 for the Generator Owner (GO)
for clarity, we have concerns regarding the stated time horizon. Requirement R2 states
that the TO shall notify the PC within 30 calendar days of elements that trip due to an
actual disturbance, but the time horizon for this requirement is Long‐term Planning
(which is a planning horizon of one year or longer.) Texas RE suggests that the time
horizon should be Operations Planning. Requirement R3 states that the GO shall notify
the PC within 30 calendar days of elements that trip due to an actual disturbance, but
the time horizon for this requirement is Long‐term Planning (which is a planning horizon
of one year or longer.) Texas RE suggests that the time horizon should be Operations
Planning.
Response: The standard drafting team removed Requirements R2 and R3; therefore,
the issue is no longer present. Change made.
Hydro One
Yes
Hydro One
Yes
Manitoba Hydro
Yes
Lower Colorado River
Authority
Yes
The splitting of requirement for GO and TO was good. It would be more clear if R2 & R3
can directly refer to the protective elements being addressed in Attachment A are the
elements to look into when power swings (stable/unstable) occurs. Also, listing some
particular in events that power swings would happen can be helpful.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Consideration of Comments:
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Organization
Yes or No
Question 3 Comment
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
Additionally, the 2nd bullet is not intended to provide the entity specific exclusions to
having to evaluate load‐responsive protective relays in PRC‐026‐1 – Attachment A.
American Transmission
Company, LLC
Yes
Georgia Transmission
Corporation
Yes
Tri‐State Generation
and Transmission
Association, Inc.
Yes
Public Service
Enterprise Group
This question is a duplicate of the prior question. The response below answers Q3 in the
unofficial comment form.
R2 and R3 require TOs and GOs, respectively, to notify their Planning Coordinator within
30 days of identifying any Element that trips due to a power swing during a system
Consideration of Comments:
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Organization
Yes or No
Question 3 Comment
disturbance due to the operation of load‐responsive protective relays. PRC‐026‐1, as
drafted, will have consequences with respect to an entity’s implementation of a
different standard: PRC‐004‐3 ‐ Protection System Misoperation Identification and
Correction ‐ see http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC‐004‐
3.pdf. NERC has filed PRC‐004‐3 with FERC for approval.
In summary, PRC‐004‐3 requires each operation of an interrupting device to be
evaluated to determine whether a Misoperation occurred. If such a determination is
made, the Protection System owner must investigate the occurrence and either
(a) provide a declaration that a cause could not be determined or
(b) if a cause is determined, develop and implement a Corrective Action Plan (CAP) or
explain why corrective actions are beyond its control or would not improve reliability.
PRC‐004‐3 does not require any action with regard to Element trips that are not
Misoperations, i.e., “correct operations.” We understand that a Protection System
owner would need some documentation to make the distinction between a correct
operation and a Misoperation. However, in order to be fully compliant with PRC‐026‐1
R2 and R3, every Element that trips due to the operation of a load‐responsive relay must
be evaluated by the entity to determine whether or not the trip was due to a power
swing.
As discussed on the September 18 webinar on PRC‐026‐1, the phrase “system
Disturbance” has same meaning as the NERC Glossary term for “Disturbance.” In other
words, “system” is unnecessary. In addition, a “Fault” was stated to be a “Disturbance.”
Therefore, every operation of a load‐responsive relay due to a Fault must be examined
under PRC‐026‐1 to identify whether or not the Element tripped due to a power swing.
o If an Elements trips due to a Misoperation, the Misoperation would be investigated
under PRC‐004‐3, and if it was caused by a power swing that could easily be reported
under PRC‐026‐1 as a result of the Protection System owner’s compliance with PRC‐
004‐3.
Consideration of Comments:
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Organization
Yes or No
Question 3 Comment
Requiring all correct operations be affirmatively evaluated by the Element owner to
determine whether they are attributable to a power swing would only “make work” for
both the Element owners and their auditors, and the added effort would not improve
reliability. Therefore, we propose that the scope of R2 and R3 for correct operations be
reduced to a subset of events that are reported to NERC under EOP‐004‐2 ‐ Event
Reporting ‐ see http://www.nerc.com/pa/Stand/Reliability%20Standards/EOP‐004‐
2.pdf. For example, the Disturbances evaluated in PRC‐026‐1 for correct operations
could be limited to some of the events and associated thresholds listed in EOP‐004 ‐
Attachment 1. We believe reasonable events would include:
o Automatic firm load shedding on p. 9
o Loss of firm load (preferably limited to non‐weather related load loss) on p. 10
o System separation (islanding) on p.10
o Generation loss on p.10,
o Complete loss of off‐site power to a nuclear plant on p. 10, and
o Transmission loss on p.11
To couple the two standards together, NERC, which receives event reports under EOP‐
004‐2, would need to notify the applicable TOs and GOs under PRC‐026‐1 of the time
frame of each event. This would allow the Element owners to evaluate whether any
Element trips that occurred during the event and which were correct operations were
associated with a power swing.
Response: The standard drafting team has removed the previous Requirements R2 and
R3 (Transmission Owner and Generator Owner) that required notification to the
Planning Coordinator, in Requirement R1, of Element trips due to stable or unstable
power swings. In deleting Requirements R2 and R3, the standard drafting team revised
Requirement R4 (now Requirement R2) for load‐responsive relays to be evaluated
under two conditions:
Consideration of Comments:
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Organization
Yes or No
Question 3 Comment
Notification of an Element pursuant to Requirement R1 where the evaluation of the
Element has not been performed in the last five calendar years, or
Becoming aware of an Element that tripped in response to a stable or unstable power
swing.
The standard drafting team has provided supporting detail on the second bullet in the
Guidelines and Technical Basis under the heading “Becoming Aware of an Element That
Tripped in Response to a Power Swing” on how an entity would “become aware.”
Changes made.
The standard drafting team made revisions to the standard which eliminated the term
“Disturbance” as defined by the Glossary of Terms Used in NERC Reliability Standards.
Arizona Public Service
Yes
Consideration of Comments:
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Posted: November 4, 2014
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4.
Requirement R4 (previously R3) contained multiple activities (e.g., demonstrate, develop a Corrective Action Plan, obtain
agreement) and was ambiguous. Do you agree that the revision to Requirement R4 now provides a clearer understanding
of what is required by the Generator Owner and Transmission Owner for an identified Element? Note: The Criterion is now
found in PRC‐026‐1 – Attachment B, Criteria A and B. If not, please explain why the Requirement is not clear.
Summary Consideration: Seventy percent of entities commenting agree that the revision to Draft 2, Requirement R4 (now Draft 3,
Requirement R2) provides a clearer understanding of what is required by the Generator Owner and Transmission Owner for an
identified Element.
There were five minor themes of comments that resulted in a revision to the Standard. First, One comment supported by eight
individuals noted that the PRC‐026‐1 – Attachment B criteria appeared to be part of the Application Guidelines due to the page
header. This was an editorial error and has been corrected to correctly include the criteria within the Standard itself. Second, three
comments each from individuals requested the Standard Guidelines and Technical Basis include generator based out‐of‐step
protection example for stable power swings. The standard drafting team provided an example. Third, one comment supported by
five individuals requested that the re‐evaluation period checking load‐responsive protective relays against the PRC‐026‐1 –
Attachment B criteria be extended from three to five years. The standard drafting team agreed that the BES would not be expected
to change significantly during five years and revised the Requirement to allow a five‐year re‐evaluation period. Fourth, one comment
supported by five individuals were concerned that the Guidelines and Technical Basis was not adequate. The standard drafting team
added additional information to improve clarity on applying the PRC‐026‐1 – Attachment B criteria. Fifth, two comments each from
individuals revealed that Draft 2 had an unintended circumstance in that an entity could skip the re‐evaluation for an actual event if
it had previously evaluated its load‐responsive protective relays for a BES Element within the re‐evaluation time frame. The standard
drafting team agreed that it was important to re‐evaluate the load‐responsive protective relays for a BES Element for every actual
BES Element trip due to stable or unstable power swings regardless of the frequency. The revisions made to Draft 3, Requirement R2
(previously Draft 2, Requirement R4) based on other comments have addressed these problems.
The following summarizes four comment themes that did not result in a change to the Standard. First, four comments represented
by 40 individuals commented (includes Questions 1‐8) that they would like more flexibility over the criteria in PRC‐026‐1 –
Attachment B. The standard drafting team maintains that the method provided in the PRC‐026‐1 – Attachment B criteria is well
documented, easily implemented, and provides a consistent method for determining a relay’s susceptibility to tripping for stable
power swings. Requiring Planning Coordinators and possibly Transmission Planners to run additional stability studies to determine a
relay’s susceptibility to tripping for a stable power swing will be more time consuming than applying the PRC‐026‐1 – Attachment B
criteria. Further, the selected contingency study cases for stability analysis may not produce results to adequately ascertain a relay’s
susceptibility to tripping for a stable power swing.
Consideration of Comments:
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Second, three comments represented by 35 individuals suggested removing “full” from the phrase “full calendar months.” The
standard drafting team disagreed because comments to Draft 1 requested clarification on calendar months and using full make it
clear that partial months are not considered in the time frame.
Third, one comment supported by 12 individuals requested that the evaluation time period begin upon receipt of the system
impedance data from other entities. The standard drafting team did not agree because the Draft 3, Requirement R2 provides
sufficient time to obtain such information, if not already on hand.
Fourth, one comment supported by an individual commented that the Guidelines and Technical Basis does not cover all the load‐
responsive protective relays in PRC‐026‐1 protection schemes and configurations. The standard drafting team responded that PRC‐
026‐1 – Attachment B criteria applies to load‐responsive protective relays irrespective of the type of protective scheme to which
they are applied.
Organization
Yes or No
Southern Company:
Southern Company
Services, Inc.; Alabama
Power Company;
Georgia Power
Company; Gulf Power
Company; Mississippi
Power Company;
Southern Company
Generation; Southern
Company Generation
and Energy Marketing
No
Question 4 Comment
Is the Criteria a single page (page 17) or is it pages 17‐73?
Response: The standard drafting team corrected the page headers to correctly associate
the Attachments A and B with the standard and not the Guidelines and Technical Basis.
Change made.
The text in the rationale should be included in the Criteria paragraph so that there is no
doubt what the evaluation is supposed to demonstrate.
Response: The standard drafting team revised the Criteria A paragraph to provide
additional clarity on what the entity must achieve. Change made.
The previous draft (R3) presentation of the demonstration, CAP development, and
PC/TP/RC communication was easier to understand just what was expected of the GO
and TO.
Response: The standard drafting team made revisions to the standard based on previous
comments and identified problems with the approach in Requirement R3 (Draft 1). The
standard drafting team believes that Draft 3 will provide additional clarity over both
Drafts 1 and 2. No change made.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
PPL NERC Registered
Affiliates
Yes or No
No
Question 4 Comment
R4 should state that the 12‐month clock for GOs begins when the TO provides the
system impedance data necessary to perform studies, if the GO requests this
information from the TO.
Response: The standard drafting team contends that 12 months is sufficient for
evaluating relays (and obtaining other data) based on the conditions that start the time
period for the Requirement which are when the entity is notified of an Element or
becomes aware of a stable or unstable power swing. No change made.
Also, the reference to, “full calendar months,” in R4 and Att. B should be changed to
just, “calendar months,” to prevent confusion.
Response: The standard drafting team uses the clarifier “full” to be clear that partial
months are not counted. For example, if the starting point is in the middle of a calendar
month, the entity will have until the end of the last month of the stated period.
Florida Municipal Power
Agency
No
See comments in response to Question 8 related to Applicability and responsibility for
various requirements.
Response: The standard drafting team thanks you for your comment, please see
response in Question 8.
DTE Electric Co.
No
R4 is clearer in general terms, however, the Criterion and related Guidelines and
Technical Basis do not cover all the various relay scheme configurations that may apply.
Since specific criteria must be evaluated, the concern is that relay scheme configurations
not discussed may result in an incorrect evaluation.
Response: The standard drafting team notes that Attachment B applies to load‐
responsive protective relays irrespective of the type of protective scheme to which they
are applied. No change made.
FirstEnergy Corp.
No
Attachment B, Criteria A and B might be clearer to a Protection Design Engineer, but are
not likely clear to typical compliance personnel.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 4 Comment
Response: The standard drafting team contends the standard is written so that the
performance under the requirements are clear to protection engineering staff that have
the expertise to understand the application. Based upon the Measures provided in the
Requirements, compliance staff should be able collaborate with their subject matter
experts to determine correct and appropriate evidence for compliance. No change
made.
Tennessee Valley
Authority
No
While an improvement over the previous draft, we believe the time interval for
consideration of previous evaluations should be extended to the prior five calendar
years.
Response: Requirement R2 (formerly R4) requires the Generator Owner and
Transmission Owner evaluate its load‐responsive protective relays on an identified
Element by the Planning Coordinator pursuant to Requirement R1, initially and
thereafter, where the evaluation has not been performed in the last five (previously
three) calendar years. Change made.
We also would prefer to see more flexibility in the standard to allow entities to use their
preferred methods (not strictly adhering to Attachment B criteria) for determining if a
line is likely to trip during a stable power swing.
Response: The standard drafting team maintains that the method provided in the
Criteria of Attachment B is well documented and easily implemented. Additionally, it
provides a consistent method for determining a relay’s susceptibility to tripping for
stable power swings. Requiring Planning Coordinators or Transmission Planners to run
additional stability studies to determine a relay’s susceptibility to tripping for a stable
power swing will be more time consuming than applying the Criteria in Attachment B.
Further, the contingencies assessed may not be severe enough to adequately ascertain
a relay’s susceptibility to tripping for a stable power swing. No change made.
SPP Standards Review
Group
No
What is the difference between ‘12 full calendar months’ and ‘12‐calendar months’?
Delete the ‘full’ in Requirement R4.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 4 Comment
Response: The standard drafting team uses the clarifier “full” to be clear that partial
months are not counted. For example, if the starting point is in the middle of a calendar
month, the entity will have until the end of the last month of the stated period.
In the 3rd line of Requirement R4, change ‘Requirement’ to ‘Requirements’.
Response: The standard drafting team has revised Requirement R4 (now Requirement
R2) such that this issue is resolved. Change made.
Refer to our comments in Question #2 as to why we don’t agree with the revisions.
Response: The standard drafting team thanks you for your comment, please see
response in Question 2.
Xcel Energy
No
We are generally supportive of the revisions to R4 but offer the following observation.
We believe that the way R4 is currently written, an Entity would be allowed to not
evaluate an Element’s load responsive relays if they had been evaluated in the past three
calendar years even if the Element was identified within the last 12 calendar months per
R2 or R3 to have tripped in response to a stable power swing. For example, if an element
tripped in January 2015 due to a stable power swing, the R4 analysis is performed and
corrective action taken per R5 and R6. If the device trips again in 2016 due to a stable
power swing, it would appear that there was a problem with the 2015 analysis. But the
way R4 is written, the entity would be exempt from performing any analysis or taking
any further action until 2018. We do not believe this is the drafting team’s intent.
Response: The standard drafting team thanks you for this keen observation and believes
that the revisions made to Requirement R4 (now Requirement R2) address this and
other concerns raised in comments. The restructuring of Requirement R4 (now
Requirement R2) will require the Generator Owner and Transmission Owner to re‐
evaluate the load‐responsive protective relay should another event occur.
Luminant Generation
Company, LLC
No
Luminant agrees that Criteria A (Attachment B) provides a method for determining a
relay setting to minimize unnecessary trips due to a stable power swing; however,
Consideration of Comments:
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Organization
Yes or No
Question 4 Comment
Luminant recommends that the generation application section include an out‐of‐step
relay example for stable power swings.
Response: The standard drafting team has provided an out‐of‐step example in the
Guidelines and Technical Basis. Change made.
Luminant also recommends removal of unstable power swings from the requirement
based on the same comments in question 2.
Response: It is important to note that this standard does not require that entities assess
Protection System performance during unstable swings and does not require entities to
prevent tripping in response to unstable swings. Such requirements would exceed the
directive stated in the Federal Energy Regulatory Commission (FERC) Order No. 733. This
standard focuses on the identification of Elements by the Planning Coordinator
(Requirement R1) and Elements where the Generator Owner or Transmission Owner
becomes aware of an Element that tripped in response to a stable or unstable power
swing (Draft 3, Requirement R2, 2nd bullet). Requirement R1 and R2 (2nd bullet) is a
screen to identify Elements that are subject to the Requirements of the standard.
The FERC Order No. 733 directive is perceived as broad and overreaching and could
require all relays to be capable of differentiating between stable power swings and
faults. This standard’s focused approach is based on the PSRPS Report,19 recommending
“...lines that have tripped due to power swings during system disturbances...” as one of
the ways to focus the evaluation. Based on feedback from the contributors to the PSRPS
Report, that recommendation does not exclude unstable power swings. Furthermore, it
is reasonable to assume that an Element that experiences an unstable swing (in either a
simulation or reality) is likely to experience large stable power swings for less severe
disturbances (that are probably more likely to occur). Thus, the standard drafting team
19
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
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Posted: November 4, 2014
80 of 148
Organization
Yes or No
Question 4 Comment
concluded that addressing Protection Systems for Elements that tripped due to unstable
power swings provides a reliability benefit. No change made.
Wisconsin Electric
No
The limitations imposed in the Application Guidelines will not allow a Generator Owner
to set an out‐of‐step relay to properly protect the generator, using commonly applied
settings such as for single blinder schemes, and possibly other out‐of‐step schemes. The
settings must be able to detect a power swing in the generator or GSU transformer,
which appears to violate the setting limits as in the example of Figure 20.
Response: The standard drafting team has provided an out‐of‐step example in the
Guidelines and Technical Basis. Change made.
Kansas City Power &
Light
No
Attachment A includes Out‐of‐step tripping. This condition is an unstable power swing
and should not be included in the standard. The standard should allow protection relays
and philosophies to protect the equipment first and foremost. The requirement not to
trip during a stable power swing should be reviewed and considered, but not mandatory
if deemed that protection will be sacrificed.
Response: It is important to note that this standard does not require that entities assess
Protection System performance during unstable swings and does not require entities to
prevent tripping in response to unstable swings. Such requirements would exceed the
directive stated in the Federal Energy Regulatory Commission (FERC) Order No. 733. This
standard focuses on the identification of Elements by the Planning Coordinator
(Requirement R1) and Elements where the Generator Owner or Transmission Owner
becomes aware of an Element that tripped in response to a stable or unstable power
swing (Draft 3, Requirement R2, 2nd bullet). Requirement R1 and R2 (2nd bullet) is a
screen to identify Elements that are subject to the Requirements of the standard.
The FERC Order No. 733 directive is perceived as broad and overreaching and could
require all relays to be capable of differentiating between stable power swings and
Consideration of Comments:
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Organization
Yes or No
Question 4 Comment
faults. This standard’s focused approach is based on the PSRPS Report,20 recommending
“...lines that have tripped due to power swings during system disturbances...” as one of
the ways to focus the evaluation. Based on feedback from the contributors to the PSRPS
Report, that recommendation does not exclude unstable power swings. Furthermore, it
is reasonable to assume that an Element that experiences an unstable swing (in either a
simulation or reality) is likely to experience large stable power swings for less severe
disturbances (that are probably more likely to occur). Thus, the standard drafting team
concluded that addressing Protection Systems for Elements that tripped due to unstable
power swings provides a reliability benefit. No change made.
CPS Energy
No
In general, support Luminant comments.
Response: The standard drafting team thanks you for your comment, please see
response to Luminant.
Lower Colorado River
Authority
No
Northeast Power
Coordinating Council
Yes
see comments for R4 under application guidelines.
Response: The standard drafting team thanks you for your comment, please see
response in Question 6 concerning the Application Guidelines.
Requirement R4 continues to be a combined TO/GO requirement. For clarity, R4 should
also be split into two requirements‐‐one to address the GO obligations by applicable
requirement, another to address the TO obligations by applicable requirement.
Response: The standard drafting team notes that the previous splitting of the Draft 1
Requirement into the Draft 2, Requirements R2 and R3 was intended for clarifying that
the “islanding” criteria was only related to the Transmission Owner. The evaluation of
load‐responsive protective relays under the new Requirement R2 (previously
20
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 4 Comment
Requirement R4) applies to both the Generator Owner and Transmission Owner in
evaluating the 120 degree separation angle.
Arizona Public Service
Co
Yes
Puget Sound Energy
Yes
Colorado Springs
Utilities
Yes
Duke Energy
Yes
ISO RTO Council
Standards Review
Committee
Yes
The SRC agrees that the revisions have provided clarity; however, notes the
inconsistency within the standard regarding describing GO and TO requirements
separately in Requirements R2 and R3.
Response: The standard drafting team notes that the previous splitting of the Draft 1
Requirement into the Draft 2, Requirements R2 and R3 was intended for clarifying that
the “islanding” criteria was only related to the Transmission Owner. The evaluation of
load‐responsive protective relays under the new Requirement R2 (previously
Requirement R4) applies to both the Generator Owner and Transmission Owner in
evaluating the 120 degree separation angle.
Dominion
Yes
JEA
Yes
Seattle City Light
Yes
Seattle appreciates the effort of the drafting team to separate auditable activities into
an individual requirement or subrequirement rather than blending them together.
Response: The standard drafting team thanks you for your comment.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
ACES Standards
Collaborators
Yes
Bonneville Power
Administration
Yes
Question 4 Comment
We agree the requirement is much clearer.
Response: The standard drafting team thanks you for your comment.
BPA agrees that Attachment B is an improvement; however, it could be better. It appears
that the only way to verify compliance is through a graphical comparison of the relay
characteristic and a lens characteristic that is described in the Application Guidelines.
The Application Guidelines give one example of calculating six sample points on the lens
characteristic. BPA was able to work our way through the example, but it was somewhat
difficult and required lots of reading between the lines. BPA requests more explicit
explanations of what is expected to show compliance and how to develop the lens
characteristic.
Response: More detailed point calculations have been added to the Application
Guidelines to show more point‐by‐point calculations of the lens (see Figures 5a, 15d,
15h, and 15i). Change made.
Oncor Electric Delivery
LLC
Yes
Public Service
Enterprise Group
Yes
Entergy Services, Inc.
Yes
American Electric Power
Yes
Independent Electricity
System Operator
Yes
City of Tallahassee
Yes
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 4 Comment
Idaho Power
Yes
ISO New England
Yes
Pepco Holdings Inc.
Yes
The requirement as written in the latest draft version of the standard is clear on what
actions must be taken. The 12 month timeline is reasonable.
Response: The standard drafting team thanks you for your comment.
Nebraska Public Power
District (NPPD)
Yes
Tacoma Power
Yes
Ameren
Yes
ITC
Yes
Texas Reliability Entity
Yes
No comments.
Hydro One
Yes
Please refer to comments for 6.
Response: The standard drafting team thanks you for your comment, please see
response in Question 6.
Hydro One
Yes
Refer to 6.
Response: The standard drafting team thanks you for your comment, please see
response in Question 6.
Manitoba Hydro
Yes
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Organization
Yes or No
American Transmission
Company, LLC
Yes
Georgia Transmission
Corporation
Yes
Tri‐State Generation
and Transmission
Association, Inc.
Yes
Consumers Energy
Company
Yes
Question 4 Comment
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5.
The new Requirement R5 (previously R4) and the new Requirement R6 address Corrective Action Plans (CAP), if any. Do
you agree this is an improvement over having the development of the CAP comingled with another Requirement? If not,
please explain.
Summary Consideration: More than half of the entities that commented agree that Draft 2, Requirements R5 and R6 were an
improvement over the previous Draft 1. The following summarizes the comments received starting with the comments that resulted
in a change to the Standard and followed by a summary of comments that did not result in a change to the Standard.
There were three significant themes of comments that resulted in a revision to the Standard. First, twelve comments represented by
25 individuals were concerned that the Corrective Action Plan (CAP) was limited to only modifying the Protection System and did not
provide an alternative. The standard drafting team modified the Draft 2, Requirement R5 (now Draft 3, Requirement R3) to make it
clear that the development of a CAP may include; 1) modifications to the Protection System to meet the PRC‐026‐1 – Attachment B
criteria, 2) modifications to the system configuration (e.g., splitting a bus such that the Protection System meets the PRC‐026‐1 –
Attachment B criteria), and 3) modifications so that the Protection System is excluded under the PRC‐026‐1 – Attachment A criteria
(e.g., modifying the Protection System so that relay functions are supervised by power swing blocking or using relay systems that are
immune to power swings), while maintaining dependable fault detection and dependable out‐of‐step tripping (if out‐of‐step tripping
is applied at the terminal of the BES Element).
Second, five comments supported by 35 individuals were concerned that 90 calendar days was insufficient for determining
corrective actions for inclusion in a CAP. Entities are concerned that development of the necessary modifications could be very
complex and take longer than 90 calendar days. The standard drafting team agreed and extended the time period for developing the
CAP to six full calendar months.
Third, one comment supported by ten individuals requested that evidence retention periods be set to 12 calendar months to be
consistent with the Reliability Assurance Initiative (RAI). The standard drafting team consulted with NERC staff and made the
revisions.
The following summarizes four comments that did not result in a change to the standard. First, two comments represented by 25
individuals requested that the Generator Owner and Transmission Owner have a Requirement to provide notification of the status
of its CAP to the Planning Coordinator. The standard drafting team disagreed because such notification is administrative and has
limited reliability benefit for something entities may request on their own outside of the Standard.
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Second, two comments supported by 11 individuals believed that the Draft 3, Requirement R4 (previously Draft 2, Requirement R6)
to implement the CAP is administrative due to updating actions and timetables to demonstrate compliance. The standard drafting
team disagreed that updating paperwork is not the intent and is not the sole source for having evidence of implementation.
Updating actions and timetables are an essential part of the CAP for when the actions (i.e., tasks) that are required to remedy the
problem change. Implementation may be demonstrated by providing work order showing a particular action (i.e., task) was
completed, but the work order was not necessarily updated as “complete” in the CAP or tracking system.
Third, two comments supported by six individuals were concerned that a CAP could be required under both PRC‐00421 and this PRC‐
026 Standard. The standard drafting team agrees that in rare cases, the entity may be doing a CAP in both Standards. An entity may
use a single CAP to demonstrate compliance with both Standards or create separate CAPs. In some cases, an entity’s CAP for
resolving a Misoperation could be different from a longer term CAP for meeting the reliability purpose of PRC‐026‐1.
Fourth, two comments each from individuals believe that a CAP would prevent the Protection System from tripping for unstable
power swings. The standard drafting team noted that the Standard does not preclude tripping for unstable power swings.
Organization
Northeast Power
Coordinating Council
Yes or No
Question 5 Comment
No
A CAP is developed to correct a problem after the requirements of a standard are
implemented. The Implementation Plan should address meeting the obligations of the
standard’s requirements. The Implementation Plan would also address the annual
identification of Elements. This would allow for the removal of requirements R5 and R6.
Generator Owners and Transmission Owners need more time subsequent to the
identification of load‐responsive protective relays to perform a thorough evaluation.
The requirement should provide at least 180 days to perform the evaluation. This will
allow for a more complete response than can be obtained in 60 days. If the CAP is kept,
the Generator or Transmission Owner should provide a copy of the initial Corrective
Action Plan and status updates to the Planning Coordinator. The length of time an entity
has to complete corrective actions should be specified. 180 calendar days is a realistic
length of time.
21
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Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment. The standard drafting team has extended the
time for the Corrective Action Plan (CAP) development to six calendar months. The
length of time to implement the CAP is included in the CAP. Change made.
Response: The standard drafting team contends notification of the CAP has no reliability
benefit and would only add to the compliance burden as an administrative function.
Puget Sound Energy
No
It should be recognized in the requirement that the appropriate response to a trip due
to a stable power swing might be to take no action. The requirement should be amended
to allow the Element owner to make a declaration that corrective action would not
improve BES reliability, therefore action will not be taken, consistent with PRC‐004‐3,
R5.
Response: The standard drafting team contends that all trips in response to stable
power swings require the relays to be evaluated and, if required, a Corrective Action
Plan (CAP) be developed so that the Protection System meets the PRC‐026‐1 –
Attachment B criteria while maintaining dependable fault detection and dependable
out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the Element).
Eliminating unnecessary future tripping of Elements in response stable power swings
does improve BES reliability.
Southern Company:
Southern Company
Services, Inc.; Alabama
Power Company;
Georgia Power
Company; Gulf Power
Company; Mississippi
Power Company;
Southern Company
Generation; Southern
No
Already discuss in Q4 comment ‐ the requirement to develop a CAP was clear either
way. The addition of the 60 day due date added more detail.
Response: Thank you for your comment.
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Organization
Yes or No
Question 5 Comment
Company Generation
and Energy Marketing
Colorado Springs
Utilities
No
ISO RTO Council
Standards Review
Committee
No
We agree with the Public Service Electric and Gas Company comments.
Response: The standard drafting team thanks you for participating, please see the
responses to Public Service Enterprise Group.
We agree with consolidating the Corrective Action Plan obligations into Requirements
R5 and R6. However, the SRC recommends that, for R5, Generator and Transmission
Owners need more time to develop a thorough CAP that addresses identified issues with
load‐responsive protective relays. The requirement should provide at least 180 days to
develop the Corrective Action Plan, which would will allow for a more complete and
thoughtful response than can be obtained in 60 days.
Response: Thank you for your comment. The standard drafting team has extended the
time for the Corrective Action Plan (CAP) development to six calendar months. The
length of time to implement the CAP is included in the CAP. Change made.
Also under R5, the Generator or Transmission Owner should provide a copy of the initial
Corrective Action Plan and status updates to the Planning Coordinator. Right now, the
requirement is open ended without the provision of Corrective Action Plan information.
Response: The SDT contends notification of the CAP has no reliability benefit and would
only add to the compliance burden as an administrative function.
Dominion
No
No date is given for CAP implementation. Is it acceptable to work the CAP in with
projects regardless of project execution date? (3‐7 years, if no project is in place at the
specific location; is it acceptable to implement the CAP once a project arises?)
Response: In the event that a Corrective Action Plan (CAP) is necessary based on future
system conditions, the CAP can specify a time frame that does not enact changes until
the actual system modifications will be made. No change made.
Consideration of Comments:
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Organization
PPL NERC Registered
Affiliates
Yes or No
Question 5 Comment
No
: The deadline of 60 calendar days for development of a Corrective Action Plan should
be changed to six months. Many GOs do not have Protection System design expertise,
and the process of making a business case for the expenditure of hiring a contractor,
getting this request approved, exploring alternatives, making a technical selection and
again obtaining management approval can take far more than sixty days.
Response: Thank you for your comment. The standard drafting team has extended the
time for the Corrective Action Plan (CAP) development to six calendar months. The
length of time to implement the CAP is included in the CAP. Change made.
Florida Municipal Power
Agency
No
FMPA agrees with the separation of R5 and R6. However, R5 pre‐supposes and
furthermore directs that the only acceptable Corrective Action Plan is one which
involves modifying the Protection System. There are a number of other ways to improve
stability performance which are therefore ruled out. In fact, improving the performance
to, and reducing the severity of power swings that result from a given event should be
a preferential solution as it has a much wider impact on the stability and the reliability
of the system. It may be true that modifications to microprocessor relay settings or even
replacement of relays might be the least cost or the fastest and simplest solution, that
in no way should dictate that the standard should mandate this be the only corrective
action employed.
Response: Thank you for your comment. The standard drafting team has modified the
requirement so that a Corrective Action Plan (CAP) can include any modifications that
ensure that the Protection Systems meet the criteria in Attachment B. Change made.
ACES Standards
Collaborators
No
We agree splitting the requirement into two requirements where one deals with
assessing the Protection System and the other deals with developing a CAP is an
improvement. However, we continue to believe the Requirement R6 is an administrative
requirement that meets P81 criteria and should be removed. The only way the R6 will
ever be violated is if an entity fails to update their paperwork on the CAP. How does
failing to update documentation not administrative?
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Organization
Yes or No
Question 5 Comment
Response: The standard drafting team intends the entity to be capable of demonstrating
implementation of a Corrective Action Plan (CAP) based on evidence specified in the
Measure. For example, evidence showing completion of the various actions of the CAP
would demonstrate the entity’s effort toward remedying the specific problem. The
updating of actions and timetables in Requirement R4 (previously Requirement R6) is
not intended to specify an administrative exercise to show compliance with
implementation. The updating of actions and timetables refers to the entity revising the
CAP during the implementation as needed following its initial development. The
standard drafting team has suggested to NERC Compliance modifications to the
Reliability Standard Audit Worksheet (RSAW) in the approach section to Requirement
R4 (previously Requirement R6) concerning the implementation of the CAP.
How does ensuring the documentation is updated by enforcing penalties serve
reliability? How is this consistent with RAI which is intended to refocus compliance and
enforcement on those risks most important to reliability and not on documentation
issues?
Response: The standard drafting team has revised the minimum periods to retain
evidence to 12 calendar months in the Evidence Retention section to address Risk
Assurance Initiative (RAI) concerns. Change made.
Public Service
Enterprise Group
No
The requirement to develop a CAP in R5 should be amended to allow the Element owner,
in lieu of a developing a CAP, to make a declaration that corrective actions would not
improve BES reliability and therefore will not be taken. This is consistent with PRC‐004‐
3, R5.
Response: The standard drafting team contends that all trips in response to stable
power swings require the relays to be evaluated and, if required, a Corrective Action
Plan (CAP) be developed so that the Protection System meets the PRC‐026‐1 –
Attachment B criteria while maintaining dependable fault detection and dependable
out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the Element).
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Organization
Yes or No
Question 5 Comment
Eliminating unnecessary future tripping of Elements in response stable power swings
does improve BES reliability.
Seminole Electric
Cooperative, Inc.
No
Requirement R5 requires the development of a CAP. Seminole requests that the ability
to submit a notification to the Entity’s RRO, stating why a CAP cannot or should not be
implemented, be added to R5. Seminole reasons that there may be instances where a
CAP is not possible, somewhat akin to a TFE in the CIP‐world. The SDT could make the
CAP exception contingent on the RRO’s approval.
Response: The standard drafting team contends that all trips in response to stable
power swings require the relays to be evaluated and, if required, a Corrective Action
Plan (CAP) be developed so that the Protection System meets the PRC‐026‐1 –
Attachment B criteria while maintaining dependable fault detection and dependable
out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the Element).
Eliminating unnecessary future tripping of Elements in response stable power swings
does improve BES reliability.
Independent Electricity
System Operator
No
The scope of the proposed standard is directed at blocking the trip for stable power
swings only. However, since existing distance schemes have the ability to trip for both
stable and unstable swings, the standard can be interpreted as permitting a
Transmission Owner to remove both trip abilities in order to comply with this standard.
Removing the trip abilities for unstable power swings may have unintended
consequences, such as preventing successful self‐generating islands to form, making the
restoration process much more difficult. In order to prevent any unintended
consequence, we suggest that Requirement 5 is modified to have the Transmission
Owner consult with the Planning Coordinator for whether out‐of‐step protection is
needed, and if so, whether out of step tripping or power swing blocking should be
applied:
R5. Each Generator Owner and Transmission Owner shall, within 60 calendar days of an
evaluation that identifies load‐responsive protective relays that do not meet the PRC‐
026‐1 ‐ Attachment B Criteria pursuant to Requirement R4, develop a Corrective Action
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Organization
Yes or No
Question 5 Comment
Plan (CAP) to modify the Protection System to meet the PRC‐026‐1 ‐ Attachment B
Criteria while maintaining dependable fault detection and dependable out‐of‐step
tripping. (Each Generator Owner and Transmission Owner shall consult with their
applicable Planning Coordinator if out of‐step tripping should be applied at the terminal
of the Element).
Response: A Corrective Action Plan (CAP), when implemented, does not preclude the
relay from tripping in response to an unstable power swing. The standard drafting team
contends that any out‐of‐step tripping requirements would be identified independent
of this standard and, if required, would need to remain in service. This standard is not
intended to create a requirement to prevent out‐of‐step tripping for unstable power
swings nor to evaluate where out‐of‐step tripping should be applied.
It is important to note that this standard does not require that entities assess Protection
System performance during unstable swings and does not require entities to prevent
tripping in response to unstable swings. Such requirements would exceed the concern
stated in Order No. 733. This standard focuses on the identification of Elements by the
Planning Coordinator (Requirement R1) and Elements where the Generator Owner or
Transmission Owner becomes aware of an Element that tripped in response to a stable
or unstable power swing (Draft 3, Requirement R2, 2nd bullet). Identification of Elements
is a screen to identify Elements with load‐responsive protective relays that are subject
to the Requirements of the standard. No change made.
Wisconsin Electric
No
Similar to PRC‐004‐3 R5, the entity should be allowed to explain in a declaration why
corrective actions would not improve BES reliability and that no further corrective
actions will be taken. For overall BES reliability, It must be left to the equipment Owners
to determine when relay settings which do not meet the Application Guidelines must
still be used for proper equipment protection.
Response: The standard drafting team contends that all trips in response to stable
power swings require the relays to be evaluated and, if required, a Corrective Action
Plan (CAP) be developed so that the Protection System meets the PRC‐026‐1 –
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Organization
Yes or No
Question 5 Comment
Attachment B criteria while maintaining dependable fault detection and dependable
out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the Element).
Eliminating unnecessary future tripping of Elements in response stable power swings
does improve BES reliability.
City of Tallahassee
No
The requirement to develop a CAP in R5 should be amended to allow the Element owner,
in lieu of a developing a CAP, to make a declaration that corrective actions would not
improve BES reliability and therefore will not be taken. This is consistent with PRC‐004‐
3, R5.
Response: The standard drafting team contends that all trips in response to stable
power swings require the relays to be evaluated and, if required, a Corrective Action
Plan (CAP) be developed so that the Protection System meets the PRC‐026‐1 –
Attachment B criteria while maintaining dependable fault detection and dependable
out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the Element).
Eliminating unnecessary future tripping of Elements in response stable power swings
does improve BES reliability.
ISO New England
No
For R5, Generator and Transmission Owners need more time develop a Corrective
Action Plan. The requirement should provide at least 180 days to develop the Corrective
Action Plan. This will allow for a more complete and thoughtful response than can be
obtained in 60 days.
Response: Thank you for your comment. The standard drafting team has extended the
time for the Corrective Action Plan (CAP) development to six calendar months. The
length of time to implement the CAP is included in the CAP. Change made.
Also under R5, the Generator or Transmission Owner should provide a copy of the initial
Corrective Action Plan and status updates to the Planning Coordinator. Right now, the
requirement is open ended without the provision of Corrective Action Plan information.
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Organization
Yes or No
Question 5 Comment
Response: The standard drafting team contends notification of the Corrective Action
Plan (CAP) has limited reliability benefit, if any, and would only add to the compliance
burden as an administrative function. No change made.
Kansas City Power &
Light
No
Out‐of‐step tripping and tripping for unstable power swings are intended results.
Corrective Action Plans are not needed for these events.
Response: A Corrective Action Plan (CAP), when implemented, does not preclude the
relay from tripping in response to an unstable power swing. The standard drafting team
contends that any out‐of‐step tripping requirements would be identified independent
of this standard and, if required, would need to remain in service. There is no
requirement to create a CAP to prevent tripping for unstable power swings.
It is important to note that this standard does not require that entities assess Protection
System performance during unstable swings and does not require entities to prevent
tripping in response to unstable swings. Such requirements would exceed the concern
stated in Order No. 733. This standard focuses on the identification of Elements by the
Planning Coordinator (Requirement R1) and Elements where the Generator Owner or
Transmission Owner becomes aware of an Element that tripped in response to a stable
or unstable power swing (Draft 3, Requirement R2, 2nd bullet). Identification of Elements
is a screen to identify Elements with load‐responsive protective relays that are subject
to the Requirements of the standard. No change made.
CPS Energy
No
In general, support PSEG comments.
Response: The standard drafting team thanks you for participating, please see the
responses to the Public Service Enterprise Group.
Ameren
No
Ameren adopts the following comment submitted by PSEG.
The requirement to develop a CAP in R5 should be amended to allow the Element owner,
in lieu of a developing a CAP, to make a declaration that corrective actions would not
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Organization
Yes or No
Question 5 Comment
improve BES reliability and therefore will not be taken. This is consistent with PRC‐004‐
3, R5.
Response: The standard drafting team contends that all trips in response to stable
power swings require the relays to be evaluated and, if required, a Corrective Action
Plan (CAP) be developed so that the Protection System meets the PRC‐026‐1 –
Attachment B criteria while maintaining dependable fault detection and dependable
out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the Element).
Eliminating unnecessary future tripping of Elements in response stable power swings
does improve BES reliability.
ITC
No
A “no CAP declaration” should be added to R5. This option is necessary when enabling
power swing blocking affects the BES reliability. An example is for a Slow Trip ‐ During
Fault, in which the high‐speed protection scheme has been identified to meet the
dynamic stability performance requirements of the TPL standards. As ITC stated in Draft
1, we are concerned about load/swings with subsequent phase faults which result in
time‐delayed tripping when power swing blocking is enabled.
Response: The standard drafting team contends that all trips in response to stable
power swings require the relays to be evaluated and, if required, a Corrective Action
Plan (CAP) be developed so that the Protection System meets the PRC‐026‐1 –
Attachment B criteria while maintaining dependable fault detection and dependable
out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the Element).
Eliminating unnecessary future tripping of Elements in response stable power swings
does improve BES reliability. In cases where tripping for a fault that occurs while out‐of‐
step blocking is enabled is a concern, then other methods may need to be considered in
order to meet the criteria of Attachment B.
Lower Colorado River
Authority
No
R5(part of the previously R3), missed the alternative options in previously R3 which
allows entities owner to obtain agreement from planning coordinator, if a dependable
fault detection or out of step tripping cannot be achieved.
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Organization
Yes or No
Question 5 Comment
Response: The standard drafting team contends that relays that do not meet
Attachment B criteria can be modified by changing relay settings or changing the
Protection System to meet the criteria. Attachment B includes an alternative method to
meet the criteria at a system separation angle less than 120 degrees. No change made.
R5 in application guideline asks to “develop” and “complete” the CAP, while R5 in the
standard only ask to “develop” within 60 cal day time period.
Response: The standard drafting team deleted the “complete” from the Guidelines and
Technical Basis. Note that Requirement R5 is now Requirement R3. Change made.
It’s ambiguous with R6 in the standard which asks to “implement” the CAP without any
specific time period. And i assume this is to allow the “implementation” to be occur
during next available plant outage.
Response: The Corrective Action Plan (CAP) has its own timetable and set of actions that
are determined by the entity. The work necessary under the CAP may vary greatly
depending on the work being performed; therefore, the standard drafting team has not
specified any time frames. No change made.
CenterPoint Energy
No
CenterPoint Energy recommends that requirements for Corrective Action Plans (CAP) be
removed in the draft PRC‐026‐1 standard. The operation of a Protection System during
a non‐fault condition due to a stable power swing would be a reportable Misoperation
under PRC‐004. Both the current enforceable version of PRC‐004 and the one under
development require a CAP for a Misoperation. Consistent with one of the
recommendations from the NERC Industry Experts initiative, CenterPoint Energy
believes that there should not be duplicative requirements in NERC Reliability Standards.
Response: The Corrective Action Plan (CAP) would be required under PRC‐00422 for an
identified Misoperation; however, for an Element that trips due to a stable or unstable
power swing whether or not it was a Misoperation, a CAP would be required under PRC‐
22
Protection System Misoperation Identification and Correction.
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Organization
Yes or No
Question 5 Comment
026‐1 if the entity determined that its load‐responsive protective relays did not meet
PRC‐026‐1 – Attachment B criteria. No change made.
Arizona Public Service
Co
Yes
Duke Energy
Yes
Duke Energy agrees that this an improvement from the previous draft. However, we
seek guidance or clarification on the boundaries between PRC‐026‐1 and PRC‐004‐3.
When Misoperations occur due to a stable power swing, a CAP is required to be
developed pursuant to R5 of PRC‐004‐3. Would the evaluation and, if needed, Corrective
Action Plan from PRC‐026‐1 R4 through R6 be acceptable as use for the CAP required in
PRC‐004‐3 R5?
Response: A Corrective Action Plan (CAP) would be required pursuant to PRC‐00423 if a
Misoperation has occurred. If the CAP is developed so that the Protection System meets
the PRC‐026‐1 – Attachment B criteria while maintaining dependable fault detection and
dependable out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the
Element), then it could also be used for PRC‐026‐1. It is up to the discretion of the entity
as to how it demonstrates compliance with the CAP requirements in each standard.
JEA
Yes
DTE Electric Co.
Yes
FirstEnergy Corp.
Yes
Assuming a situation results in the need for a CAP, what is the purpose of stating that
dependable fault detection (and out‐of‐step tripping if applied) shall be maintained
while developing the CAP?
Maintenance and testing of protection is covered in PRC‐005, and any failure of existing
protection is addressed by PRC‐004. Why is there further need to address maintaining
23
Protection System Misoperation Identification and Correction.
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Organization
Yes or No
Question 5 Comment
existing protection, and how is such a requirement measured in the context of PRC‐026‐
1?
Also, what is the anticipated mechanism for tracking and reporting progress on a CAP?
Response: The standard drafting team included the clause “dependable fault detection
(and out‐of‐step tripping if applied)” to express that certain protection may not simply
be disabled to comply with this standard.
The standard requires the development and implementation of a Corrective Action Plan
(CAP) to, by definition, which is “[a] list of actions and an associated timetable for
implementation to remedy a specific problem.” In this case, to ensure that the
Protection System meets the PRC‐026‐1 – Attachment B criteria while maintaining
dependable fault detection and dependable out‐of‐step tripping (if out‐of‐step tripping
is applied at the terminal of the Element).
There is no tracking and reporting of a Corrective Action Plan (CAP) progress to other
parties. The entity must demonstrate implementation of its CAP(s). No change made.
Tennessee Valley
Authority
Yes
Seattle City Light
Yes
Seattle appreciates the effort of the drafting team to separate auditable activities into
an individual requirement or subrequirement rather than blending them together.
Response: Thank you for your support.
Bonneville Power
Administration
Yes
Oncor Electric Delivery
LLC
Yes
Entergy Services, Inc.
Yes
Consideration of Comments:
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Organization
Yes or No
Question 5 Comment
American Electric Power
Yes
Xcel Energy
Yes
The VSLs for R4 and R5 seem inconsistent. Entities are given 12 calendar months to
perform an analysis with VSLs of increasing severity for being <30, <60, <90, and > 90
days past due. They are given 60 days to develop a CAP following completion of an
evaluation that determines the need for a protection system modification to meet PRC‐
026‐1 Attachment B criteria, and with an R5 VSL of increasing severity for being <10,
<20, <30 or >30 days past due in the development of a CAP. Given the 12 month leeway
on the completion of analysis following identification of the Element and the only 60 day
leeway on CAP development, why would an entity sign off an R4 analysis as complete
for an element requiring a protection system modification prior to the 12 month
deadline, essentially starting the 60 day clock on the CAP development R5 requirement?
We recommend that all R4 analysis completion and R5 CAP development timeframes be
based on the calendar months from the original date of identification of the susceptible
Element and that the same <30 day, <60 day, <90 day and >90 day increments be used
both R4 and R5 VSLs. This approach would eliminate any potential benefit from delaying
the officially acknowledged date of completion of the R4 analysis and not have any effect
on the final R5 max CAP development timeframe (ie. months since initial Element
identification) allowable by the standard.
Response: Thank you for your comment. The standard drafting team considered your
suggested approach, but contends that the current approach is more concise.
The standard drafting team has extended the time for the Corrective Action Plan (CAP)
development to six calendar months. The length of time to implement the CAP is
included in the CAP. Change made.
Luminant Generation
Company, LLC
Yes
Idaho Power
Yes
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Organization
Pepco Holdings Inc.
Yes or No
Question 5 Comment
Yes
The requirement as written in the latest draft version of the standard is clear on what
actions must be taken. The 12 month timeline is reasonable.
Response: The SDT thanks you for your support.
Nebraska Public Power
District (NPPD)
Yes
We agree that separation of the CAP requirement is an improvement; however, we feel
there should be a caveat to this requirement. The standard as written could result in
reduced sensitivity of fault detection settings, which would interfere with “maintaining
dependable fault detection”. We believe there should be an option to maintain our
ability to operate the BES in a reliable manner and still remain in compliance with R5.
This requirement seems like double‐jeopardy.
Response: The standard drafting team contends that all trips in response to stable
power swings require the relays to be evaluated and, if required, a Corrective Action
Plan (CAP) be developed so that the Protection System meets the PRC‐026‐1 –
Attachment B criteria while maintaining dependable fault detection and dependable
out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the Element).
Eliminating unnecessary future tripping of Elements in response stable power swings
does improve BES reliability.
Tacoma Power
Yes
Texas Reliability Entity
Yes
No comments.
Hydro One
Yes
Hydro One
Yes
Manitoba Hydro
Yes
American Transmission
Company, LLC
Yes
Consideration of Comments:
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Organization
Yes or No
Question 5 Comment
Georgia Transmission
Corporation
Yes
Tri‐State Generation
and Transmission
Association, Inc.
Yes
The requirement to develop a CAP in R5 should be edited to allow the owner to make a
declaration that corrective actions would not improve BES reliability if that is the case
and therefore action will not be taken. This is consistent with PRC‐004‐3, R5.
Response: The standard drafting team contends that all trips in response to stable
power swings require the relays to be evaluated and, if required, a Corrective Action
Plan (CAP) be developed so that the Protection System meets the PRC‐026‐1 –
Attachment B criteria while maintaining dependable fault detection and dependable
out‐of‐step tripping (if out‐of‐step tripping is applied at the terminal of the Element).
Eliminating unnecessary future tripping of Elements in response stable power swings
does improve BES reliability.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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6.
Does the “Application Guidelines and Technical Basis” provide sufficient guidance, basis for approach, and examples to
support performance of the requirements? If not, please provide specific detail that would improve the Guidelines and
Technical Basis.
Summary Consideration: Slightly less than half of the entities that commented agreed that the Application Guidelines and Technical
Basis” provide sufficient guidance, basis for approach, and examples to support performance of the Requirements. The following
summarizes the comments received starting with the comments that resulted in a change to the Standard and followed by a
summary of comments that did not result in a change to the Standard.
There were two significant themes of comments that resulted in a revision to the Standard. First, twelve comments supported by 38
individuals requested clarifications in Guidelines and Technical Basis. The standard drafting team provided additional discussion,
figures, and tables. Second, three comments represented by 24 individuals suggested a number of editorial, formatting, and style
edits for the Guidelines and Technical Basis. The standard drafting team implemented corrections those items that were errors and
consistent with the NERC style guide for writing.
There were two minor themes of comments that did not result in a revision to the Standard. First, one comment supported by six
individuals questioned the Standard’s exclusion of relays with a time delay greater than 15 cycles with regard to slip rates. The
standard drafting team noted that a time delay of 15 cycles was chosen because it equates to a conservatively low, stable power
swing slip rate of 0.67 Hz. As a consequence of using this slip rate and corresponding time delay, most zone 2 relays are excluded.
Second, one comment represented by five individuals had general questions or observations. The standard drafting team provided
informative feedback to questions and observations.
Organization
Yes or No
Question 6 Comment
Southern Company:
Southern Company
Services, Inc.; Alabama
Power Company;
Georgia Power
Company; Gulf Power
Company; Mississippi
No
The calculations, requiring the extent of material provided in the application guide to
explain, appear to be quite complex and difficult.
Is the SDT open to considering an alternative method of evaluation? It is proposed that
GO or TO give relay settings to the entity with the transient analysis modeling tool
(TP/PC), and that entity determine if the GO/TO relay settings need to be modified
Consideration of Comments:
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Posted: November 4, 2014
104 of 148
Organization
Yes or No
Power Company;
Southern Company
Generation; Southern
Company Generation
and Energy Marketing
Dominion
Question 6 Comment
based on the power swing characteristics and simulation results for the area being
reviewed.
Response: The standard drafting team maintains that the method provided in the
Criteria of Attachment B is well documented and easily implemented. Additionally, it
provides a consistent method for determining a relay’s susceptibility to tripping for
stable power swings. Requiring Planning Coordinators or Transmission Planners to run
additional stability studies to determine a relay’s susceptibility to tripping for a stable
power swing will be more time consuming than applying the Criteria in Attachment B.
Further, the contingencies assessed may not be severe enough to adequately ascertain
a relay’s susceptibility to tripping for a stable power swing. Also, additional
“communication” Requirements would have to be added to the Standard requiring the
Generator Owner or Transmission Owner to provide relay settings to the Planning
Coordinator or Transmission Planner and requiring the Planning Coordinator or
Transmission Planner to provide the results of their studies back to the Generator
Owner or Transmission Owner. Each of these new Requirements would need time
horizons giving each applicable entity a limited amount of time to communicate the
pertinent data. These new Requirements would add additional compliance burden to
the Applicable Entities. No change made.
No
Under Criterion R4, ‘Exclusion of Time Based Load‐Responsive Protective Relays,’ the
calculations here are ambiguous. PRC‐026‐1 Attachment A explicitly states we are to
evaluate protective functions listed with a delay of 15 cycles or less; however, there is
small section outlining the need to calculate what sort of delays should be evaluated
under different slip frequencies. Adding the ‘Exclusion of Time Based Load‐Responsive
Protective Relays’ section is counter‐productive in its current context. Dominion
suggests that the SDT revise the section to make it more understandable or remove it.
No section discusses slip frequencies ranges. The WECC experiences 0.25‐0.28 Hz
north‐south oscillations, ERCOT experiences 0.6 Hz north‐south and 0.3 Hz east‐west,
Tennessee to Maine experiences 0.2 Hz oscillations, but Tennessee to Missouri
experiences 0.7 Hz oscillations. Roughly 0.01 to 0.8 Hz oscillations are associated with
Consideration of Comments:
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Organization
Yes or No
Question 6 Comment
wide area oscillations, but 3.0 to 10 Hz oscillations are associated with FACTS devices
that may cause wide or local. What is the acceptable range of oscillations this standard
is meant to cover?
Response: The “Exclusion of Time Based Load‐Responsive Protective Relays” section in
the Application Guidelines is a technical justification for excluding load‐responsive
protective relays that have a time delay of 15 cycles or greater. It does not require an
Entity to evaluate relay time delays for varying system slip rates. Various relay time
delays were evaluated for an expected worst case stable power swing that enters a
mho characteristic at a system angle of 90 degrees and turns back around 120 degrees.
The total traversal time (relay time delay) was then converted to a system slip rate for
comparison purposes. The time delay of 15 cycles was chosen because it equates to a
conservatively low, stable power swing slip rate of 0.67 Hz. As a consequence of using
this slip rate and corresponding time delay, most zone 2 relays are excluded. The slip
rate analysis was done to validate a minimum time delay that could be used to exclude
certain load‐responsive relay elements (e.g., zone 3 mho, zone 4 mho, phase time
overcurrent, etc.), that are set with larger reaches and longer time delays. The Standard
is not establishing minimum or maximum slip rate criteria that must be adhered to. The
chosen time delay is not intended to cover all possible slip rates.
JEA
No
This standard is not necessary and we agree with the analysis of the NERC SPCS that it
may have unintended consequences which could decrease the reliability of the BES.
Response: The standard drafting team thanks you for your comment and provided a
detailed explanation in the previous Consideration of Comments24 in the introductory
remarks regarding the need for a standard to meet regulatory directives.
Florida Municipal Power
Agency
No
FMPA commends the drafting team on the amount of material that has been developed
to support the Application of this standard. The various examples used in the
24
http://www.nerc.com/pa/Stand/Project%202010133%20Phase%203%20of%20Relay%20Loadability%20stabl/Project_2010_13.3_Consideration_of_
Comments_2014_08_22_to_Draft_1.pdf
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 6 Comment
Application Guide are generally good example scenarios. However, the focus of the
Guide seems to be more on repetitive demonstration of basic equations and less on the
SDT’s expected interpretation of various scenarios. One full sample of all the
calculations in one scenario is all that is required. Each time the equations are repeated
it takes roughly 11 pages.
Response: The standard drafting team has left the detailed calculations for the six
critical points of the lens characteristic. No change made.
In general there are a lot of pages of basic equations and very little “guidance” within
the examples. Furthermore, the examples seem to have been developed to make a
supporting case for the Criteria of Attachment B but there is no true discussion of how
these examples should be interpreted to support the Criteria. An easy example of this
is Table 10, where the impact of the system transfer impedance on the lens
characteristic is tabulated, but there is no use of that data to explain why all transfer
impedances, no matter what the magnitude, should be completely ignored. The data is
there, but the expectations regarding interpretation of the data are more important,
and these are missing.
Response: More detail has been added to the Application Guidelines to better clarify
the equations. Additionally, a clarifying paragraph has been added with a discussion of
the data in Table 10. Change made.
A couple of additional issues that FMPA believes should be cleaned up.
o The first full paragraph of Page 28 of the Application Guidelines describes the
modeling of generator reactances in stability models, but there is no segue regarding
why this information was presented. Please clarify that the intent of the paragraph is
to make it clear that the reactances that are used by TP’s/PCs (unsaturated reactances)
may not be the same reactances as the ones that are being recommended for use in
the application of the criteria (saturated reactances).
Response: A clarifying paragraph has been added to the Application Guidelines after
the paragraph mentioned above. Change made.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 6 Comment
o The Application Guide makes frequent reference to “pilot zone 2 element” in the
figures. Strictly speaking the figures show an example of a “distance” or “impedance”
mho relay characteristic curve. The term “pilot” refers colloquially in protection to a
communication assisted scheme, which may be used in conjunction with a mho
characteristic or may not. The use of this term introduces confusion because
Attachment A specifically excludes “pilot wire relays”, which are a specific sub‐set of
transmission relay that does not use a mho characteristic.
Response: The figures have been updated to generically refer to Pilot Zone 2 and Zone
2 impedance characteristics as “mho element characteristics.” A clarifying paragraph
has also been added discussing the types of “pilot” or communications relay schemes
that need to be considered. Change made.
DTE Electric Co.
No
While considerable discussion and examples have been provided, there are variations
in relay types and schemes that are not specifically covered. Perhaps these variations
could be submitted at some point for review and application guidance.
Response: The standard drafting team agrees that there are various relay types (e.g.,
mho, quadrilateral, lens, loss of field, out‐of‐step, over current, etc.) that must meet
the criteria of this Standard. The standard drafting team attempted to illustrate the
application of the criteria in PRC‐026‐1 – Attachment B using only the most common
relay types for brevity. There are other types of relays not specifically discussed in the
Application Guidelines, but the criteria in PRC‐026‐1 – Attachment B can be applied to
them similarly.
SPP Standards Review
Group
No
Insert a ‘to’ between ‘pursuant’ and Criterion’ in the 3rd line up from the bottom of the
paragraph on Criterion 1.In the 9th line in the 1st paragraph under Criterion 4, capitalize
‘Criterion’.
In Figures 1 and 2, change ‘Criterion five’ to ‘Criterion 5’.In the 7th line of the paragraph
following Figures 1 and 2, change ‘included’ to ‘include’.
Response: Changes made.
Consideration of Comments:
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Posted: November 4, 2014
108 of 148
Organization
Yes or No
Question 6 Comment
In the 8th line of the paragraph under Requirement R4, delete ‘full’ and hyphenate ‘12‐
calendar’.
Response: The SDT is retaining the word “full.” Change not made.
In the 5th line of the 2nd paragraph under Exclusion of Time Based Load‐Responsive
Protective Relays, insert ‘degrees’ between ‘120’ and ‘before’.
Response: Change made.
In the 3rd line of the paragraph immediately following Table 1, capitalize ‘Zone’.
Response: Changes made.
In the 15th line of the same paragraph, delete the same phrase in the parenthetical.
Response: The standard drafting team could not locate the source of the comment.
In the 4th line of the paragraph following Equation (3), replace ‘plus and minus’ with a
‘+/‐’.
Response: Change made.
Capitalize ‘Zone 2’ in the captions of Figures 10, 11, 12, and 15.
Response: Changes made.
In that same paragraph, capitalize ‘Zone 2’.
Response: Change made.
In the last line of the 2nd paragraph under Application to Generation Elements, replace
‘Requirement’ with ‘Requirements’.
Response: Change made.
Capitalize ‘Zone 2’ in the 1st line of Example R5a.
Response: Change made.
Capitalize ‘Zone 2’ in the 1st line of Example R5c.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 6 Comment
Response: Changes made.
Seattle City Light
No
Seattle appreciates the efforts of the drafting team to provide application guidance and
technical basis information and welcomes the trend towards such implementation
documentation throughout the standards development process. For PRC‐026, this
material has improved somewhat compared to the original draft, but application of the
standard remains insufficiently clear for Seattle to recommend an affirmative ballot at
this time. More examples and/or a flow chart or something similar to fully delineate
the steps in the process are wanted.
Response: Thank you for your comments. The standard drafting team has made
changes to the Standard to clarify industry issues. We don’t believe that the
Requirements of the Standard require a flow chart. More clarifying examples have been
added to the Application Guidelines.
ACES Standards
Collaborators
No
(1) The “Application Guidelines and Technical Basis” are quite helpful and definitely do
provide additional insight into the meaning of the requirements. However, we believe
additional modifications are necessary.
(2) On page 18 in the second paragraph, we do not believe the paragraph captures all
of the reasons for changing the applicability of the standard. We believe that changing
the applicability makes that standard consistent with the other relay loadability
standards and makes the standard consistent with the functional model. These reasons
are important to capture as they are more substantial than those listed.
Response: The standard drafting team agrees and has incorporated the change in the
Introduction section. Change made.
(3) In the Requirement R1 paragraph on page 20, please change “and other NERC
Reliability Standards” to PRC‐006. There are two main standards (or five depending on
which version of TPL are used) that drive identification of Elements susceptible to stable
power swings. They are the UFLS standards and TPL standard(s). As written, this
paragraph is too open ended and could lead to confusion.
Consideration of Comments:
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Posted: November 4, 2014
110 of 148
Organization
Yes or No
Question 6 Comment
Response: The standard drafting team has added a reference to PRC‐006 and left the
reference to “other NERC Reliability Standards” to capture future Standards that may
be developed or existing Standards that may be modified. Change made.
(4) We suggest that a diagram should be developed depicting the example in the second
paragraph on page 24.
Response: Requirements R2 and R3 were removed and their intent (actual events) is
now captured in Requirement R2 (previously Requirement R4). The paragraph referring
to the formation of an island in the R2 section of the Application Guidelines has been
removed. Change made.
(5) In the “lens characteristic” examples, we suggest that annotating the figure with the
actual lens point would be helpful in understanding the “lens characteristic”.
Response: More detailed point calculations have been added to the Application
Guidelines to show more point‐by‐point calculations of the lens (see Figures 5a, 15d,
15h, and 15i). Change made.
Bonneville Power
Administration
No
BPA agrees that Attachment B is an improvement; however, it could be better. It
appears that the only way to verify compliance is through a graphical comparison of
the relay characteristic and a lens characteristic that is described in the Application
Guidelines. The Application Guidelines give one example of calculating six sample
points on the lens characteristic. BPA was able to work our way through the example,
but it was somewhat difficult and required lots of reading between the lines. BPA
requests more explicit explanations of what is expected to show compliance and how
to develop the lens characteristic.
Response: More detailed point calculations have been added to the Application
Guidelines to show more point‐by‐point calculations of the lens (see Figures 5a, 15d,
15h, and 15i). Change made.
Xcel Energy
No
In the Application Guidelines, Criteria 1 uses the term “operating limit” and Criteria 2
uses the term “System Operating Limit” although both are identified by the existence
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 6 Comment
of angular stability constraints, seemingly defining the same type of operating
constraint, i.e. operating limit. Xcel Energy would suggest either explaining the
difference between the terms “operating limit” and “System Operating Limit”, or
eliminating the potentially duplicative criterion, since a “Generator” can be an
“Element”.
Response: The standard drafting team replaced the term “operating limit” with
“System Operating Limit (SOL)” in Criterion 1 to be consistent with Criterion 2. Criterion
1 identifies generators and Elements terminating at the Transmission station associated
with the generator(s), while Criterion 2 identifies transmission Elements that are
monitored as part of an SOL. Change made.
The lens calculation tool is not validated or authorized for use. Due to the hypothetical
nature of the calculations, a standardized tool should be provided so that industry can
achieve consistent results.
Response: It is each Entity’s responsibility to obtain or create necessary tools to prove
compliance with NERC Standards. The Application Guidelines sufficiently document and
detail the necessary calculations to prove compliance. Additionally, a sample tool has
been made available on the PRC‐026‐1 project page to help guide entities. No change
made.
There is no requirement that the TO provide the System Equivalent to the GO. This
Standard should provide communication requirements between the GO and TO, similar
to the MOD series standards effective inn 2014. While this may not be necessary due
to the typically amenable working relationships in a vertically integrated utility, it may
be required in areas that are served by several companies.
Response: The standard drafting team chose not to include communication
requirements between the Generator Owner and TO for the exchange of source
impedance data at a given transmission interconnection point, because the standard
drafting team is confident this exchange of source impedance data is already occurring
outside of Reliability Standard requirements. A communication Requirement for the
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 6 Comment
exchange of source impedance data would be administrative in nature, and would
create additional compliance tracking burdens for both entities. No change made.
Luminant Generation
Company, LLC
No
Luminant recommends that in the Generator Application section, an example of a
generator out‐of‐step relay application for stable power swings should be provided.
Response: A generation out‐of‐step relay example has been added to the Application
Guidelines. Change made.
Wisconsin Electric
No
For generators, the Application Guidelines make reference to using the generator
transient reactance X’d. However, Tables 15 and 16 show the sub‐transient reactance
X’’d in the calculations. This appears to be a discrepancy. See also Question 3 above.
Response: The discrepancies in Tables 15 and 16 have been corrected. Change made.
See response to Question 3 above.
Kansas City Power &
Light
No
CPS Energy
No
The graphs seem not to match the calculations.
Response: The detailed point calculations for all graphs have been re‐checked, and one
error was found in Table 17 (ES/ER = 1; magnitude should be 0.194 at 201.9 degrees
rather than 0.111 at 201.9 degrees.) Change made.
In general, support Luminant comments.
Response: A generation out‐of‐step relay example has been added to the Application
Guidelines. Change made.
Tacoma Power
No
In the Application Guidelines, in the discussion of Figure 11, suggest changing “...thus
allowing the zone 2 element to meet PRC‐026‐1 ‐ Attachment B, Criteria A” to
something like the following: “...thus allowing the zone 2 element to meet PRC‐026‐1 ‐
Attachment B, Criterion A. However, including the transfer impedance in the
calculation of the lens characteristic is not compliant with Requirement R4.” Similarly,
Consideration of Comments:
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Organization
Yes or No
Question 6 Comment
update the Figure 11 caption to indicate that the calculation is not compliant with
Requirement R4.
Response: The suggested changes have been made. Please note that Requirement R4
is now Requirement R2.
In the Application Guidelines, in the discussion of Requirement R5, the statement “that
all actions associated with any Corrective Action Plan (CAP) developed in the previous
requirement [Requirement R4]...” is incorrect. Requirement R4 does not have anything
to do with a CAP.
Response: The lead paragraph was a leftover duplicate from a prior version of the
Application Guidelines. This lead paragraph has been removed. Change made.
ITC
No
The R2 example of an island forming is insufficient. Suppose a line includes tapped load
and a tapped generator, does this form an island if the line ends trip for a phase fault?
R2 Criteria 2 does not exclude this example, therefore it should be discussed in
Application Guidelines and Technical Basis.
Response: Requirements R2 and R3 were removed and their intent (actual events) is
now captured in Requirement R2 (previously Requirement R4). The paragraph referring
to the formation of an island in the R2 section of the Application Guidelines has been
removed. Change made.
Hydro One
No
This section now provides clarity for each of the requirements in the standard.
However, for Requirement 4, the “Application Guidelines and Technical Basis,” section
does not provide direction on how to treat multi‐terminal configurations (specifically
3‐terminal). Providing guidance on how to approach multi‐terminal configuation would
be helpful.
Response: A 3‐terminal line example has been added to the Application Guidelines.
Change made.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Lower Colorado River
Authority
Yes or No
Question 6 Comment
No
see comments for application guidelines. It would be helpful to include out of step
examples for the GO and TO.
Response: A generation out‐of‐step relay example has been added to the generation
section of the Application Guidelines. A transmission out‐of‐step trip example is shown
in Figure 15 of the Application Guidelines. Change made.
Tri‐State Generation
and Transmission
Association, Inc.
No
The “Exclusion of Time Based Load‐Responsive Protective Relays” on p 25 indicates that
time delayed Zone 2 and Zone 3 relays are intended to be excluded from this standard.
However, many of the figures reference Zone 2 relay compliance or non‐compliance; in
particular, see Figure 10. That seems to imply that the Zone 2 relays in the example do
need to comply with this standard. If we are told that time‐delayed relay elements are
to be excluded, does this imply that the Zone 2 relay is being used in a directional
comparison blocking (DCB) scheme? If so, should that not be clearly identified? (Only
Figures 3 and 12 identify the element in question as being a pilot Zone 2, and pilot could
refer to may schemes that would not be impacted by extending beyond the defined
impedance boundary). Similar to that example would be the use of Zone 2 relay
elements to assert permission in a permissive overreaching transfer trip (POTT)
scheme. It is likely that Zone 2 relay elements in a POTT scheme could extend beyond
the impedance characteristic defined in Attachment B, but the only regions that would
result in tripping in less than 15 cycles are the overlapping Zone 2 regions that result in
POTT scheme activation, which would most likely be fully contained in the region
defined in Attachment B. Tri‐State believes that a statement or example clarifying that
such a protection system is compliant would be beneficial to applicable entities as well
as the compliance monitoring entities.
Response: The figures have been updated to generically refer to Pilot Zone 2 and Zone
2 impedance characteristics as “mho element characteristics.” A clarifying paragraph
has also been added discussing the types of “pilot” or communications relay schemes
that need to be considered. Change made.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Consumers Energy
Company
Yes or No
Question 6 Comment
No
The revised application guidelines are very helpful, but need to be expanded to include
guidance on how to comply with R2 and R3, specifically how Generator Owners and
Transmission Owners are expected to determine whether a trip was due to a swing.
Given the lack of guidance we have at this point, we feel we are unable to comply with
R2 or R3.
Response: The standard drafting team contends that PRC‐026‐1 does not require an
entity to determine whether an Element tripped due to a power swing. This is
accomplished in the revision to Requirement R2 (previously Requirement R4) that
when an entity “becomes aware” it would evaluate the relay(s). The identification of a
power swing that causes a BES Element trip could be determined through an entity’s
Protection System analysis process (e.g., PRC‐00425), event analysis review by the
entity, region, or NERC.
25
Arizona Public Service
Co
Yes
Puget Sound Energy
Yes
FirstEnergy Corp.
Yes
Oncor Electric Delivery
LLC
Yes
Entergy Services, Inc.
Yes
American Electric Power
Yes
Protection System Misoperation Identification and Correction.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 6 Comment
Independent Electricity
System Operator
Yes
Idaho Power
Yes
ISO New England
Yes
Pepco Holdings Inc.
Yes
Nebraska Public Power
District (NPPD)
Yes
Ameren
Yes
Texas Reliability Entity
Yes
No comments.
Hydro One
Yes
This section now provides clarity for each of the requirements in the standard.
However, for Requirement 4, the “Application Guidelines and Technical Basis,” section
does not provide direction on how to treat multi‐terminal configurations (specifically
3‐terminal). Providing guidance on how to approach multi‐terminal configuation would
be helpful.
Response: A 3‐terminal line example has been added to the Application Guidelines.
Change made.
Manitoba Hydro
Yes
American Transmission
Company, LLC
Yes
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Yes or No
Question 6 Comment
Colorado Springs
Utilities
No Comments
Exelon Companies
In the guidelines and technical basis section of the standard, a method for evaluating
whether a distance element is susceptible or not is given. In the previous guidelines and
technical basis, a simpler method of plotting the relay characteristic within the lens
drawn at the 120 degree critical angle was also described. This method seems to have
been removed from the current draft standard. This method works often for our
protection schemes and requires no calculations (it is simpler and less work). The
drafting team should consider putting this section back in the guidelines section to
show that this method may also be used.
Response: A method for evaluating distance elements is provided in the Application
Guidelines as shown in Figure 5 and Tables 2 – 7. It is a modified, more realistic method
than the one presented in Draft 1. The illustration of the lens calculation is now only
for a portion of a lens and the interior intersection with the un‐equal EMF power swing
trajectories. This approach is more realistic, because it accounts for the fact that the
generator voltages won’t be zero during a power swing. The generator voltages are
varied from 0.7 to 1.0 per unit to create a realistic and adequately conservative portion
of a lens against which mho circle distance elements are compared to determine their
susceptibility to tripping for stable power swings. The evaluation using the portion of a
lens is not more work once an application tool has been developed using the formulae
in the Application Guidelines. Additional clarifying examples have been included to the
Application Guidelines.
Consideration of Comments:
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7.
The Implementation Plan for the proposed standard has been revised, based on comments, to account for factors such as
the initial influx of identified Elements and ongoing burden of entities to identify Elements and re‐evaluate Protection
Systems. Does the implementation plan provide sufficient time for implementing the standard? If not, please provide a
justification for changing the proposed implementation period and for which Requirement.
Summary Consideration: Over 80 percent of the entities that commented agreed that the Implementation Plan provides sufficient
time for implementing the Standard. Several commenters that disagreed with the Implementation Plan noted that 12 months is not
sufficient to prepare studies under Requirement R1. The standard drafting team noted that PRC‐026‐1 is not requiring the
preparation of any studies and only requires the use of the most recent assessments according to the Requirements. The following
summarizes the comments received starting with the comments that resulted in a change to the Standard and followed by a
summary of comments that did not result in a change to the Standard.
There was one significant theme that resulted in a revision to the Standard. Four comments supported by 31 individuals commented
that development and implementation of the Corrective Action Plan (CAP) in Draft 2, Requirements R5 and R6 (now Draft 3,
Requirements R3 and R4) should have the same implementation time frame as Draft 2, Requirement R4 (now Draft 3, Requirement
R2). This is because the development and implementation of the CAP cannot be enforceable when the Requirement that causes the
CAP to be developed has yet to be enforceable. The standard drafting team modified the Implementation Plan so that Draft 3,
Requirements R2, R3, and R4 (previously Draft 2, Requirements R4, R5, and R6) have the same implementation period.
There one significant and one minor comment did not result in a revision to the Standard. Most significantly, two comments
supported by 32 individuals believe the implementation period should be longer due to having to prepare studies. The standard
drafting team noted that the preparation of new studies are not required and the Requirements use the most recent assessments. A
minor theme, two comments represented by six individuals requested that Requirement R1 be increased from 12 to 24 calendar
months. The standard drafting team disagreed because the Requirement relies on the most recent assessment and not the
preparation of new studies.
Organization
Northeast Power
Coordinating Council
Yes or No
Question 7 Comment
No
Twelve months is not adequate to prepare for this standard as written. The Drafting
Team should change the Implementation Plan to 24 months.
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Organization
Yes or No
Question 7 Comment
The implementation could be improved by adding when the performance of
requirement R1 is due.
Is the PC supposed to complete its R1 analysis based on the effective date of the
Standard 12 months after FERC approval, or 12 months after FERC approves the
Standard then the PC has to complete the study for the calendar year?
This can be difficult depending on when FERC approves the Standard. We suggest the
revision to 24 months and stating that the PC is expected to complete the identification
required by R1 in the calendar year that the requirement becomes effective. This
removes the concern of what month FERC approves the Standard.
Response: The Implementation Plan provides sufficient justification for the
implementation periods and allows for 12 calendar months for the Planning Coordinator
and 36 calendar months for the Generator Owner and Transmission Owner.
Requirement R1 must be performed each calendar year (January‐December); therefore,
the Planning Coordinator must complete its notification of BES generators,
transformers, and transmission line Elements to the respective Generator Owner and
Transmission Owner by December 31 of each calendar year. The Implementation Plan
states that the Planning Coordinator will begin its performance on the first day of a
calendar year 12 calendar months following adoption or approval of the standard. For
example, if the standard is approved on September 17, 2015 the 12 calendar month
clock starts on the first of the following year (2016); therefore, the year in which the
Planning Coordinator must be compliant with the standard will be January 1, 2017. No
change made.
ISO RTO Council
Standards Review
Committee
No
The SRC notes that twelve (12) months is not adequate to prepare for this standard as
written. Accordingly, it is recommended that the drafting team revise the
implementation plan to allow twenty four months for implementation.
Response: The standard drafting team has provided additional information in the
Implementation Plan document to clarify when certain activities must be implemented.
Change made.
Consideration of Comments:
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Organization
Yes or No
Question 7 Comment
Florida Municipal Power
Agency
No
The Implementation Plan does not offer compelling evidence that the implementation
date for R5 and R6, which are driven exclusively by R4, should be set at 12 months from
approval while R4 is at 36 months from approval. Setting R5 and R6 earlier than R4
instead of allowing them to be parallel to R4 introduces circuitous logic as now the
language of these Requirements appears to require R4 to be completed early...There
does not appear to be any value in setting R5 and R6 at 12 months when there is nothing
to measure compliance with them against ‐ the implementation plan explains the 12
months to is to allow entities to develop “internal processes and procedures”, but the
Requirements do not require such procedures nor are these listed in the measures.
Response: The standard drafting team has modified the Implementation Plan so that
Requirements R3 and R4 (previously Requirements R5 and R6) have the same
implementation period of R2 (previously Requirement R4). Change made.
SPP Standards Review
Group
No
We have a concern that the Implementation Plan doesn’t reflect the changes mentioned
by the drafting team in their response to our comments on Question 4 in the previous
posting.
That response states ‘The drafting team increased the Implementation Plan to three
years to provide for the initial influx of identified Elements under Requirement R1. The
evaluation of relays under Requirement R4 previously R3) is to be performed “within 12
full calendar months of receiving notification of an Element... where the evaluation has
not been performed in the last three calendar years.” Change made’.
We request clarification on why this change doesn’t appear in the current proposed
standard and Implementation Plan.
Response: The standard drafting team notes that the reference to “changes made” in
the previous posting related to the changes made to the Implementation Plan. In
response to additional time for Requirement R1, the standard drafting team notes that
studies are not required by the standard (i.e., Requirement R1). The criteria in
Requirement R1 are based on existing studies (i.e., annual Planning Assessments) and
that the Planning Coordinator will have minimal effort to notify the respective Generator
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Organization
Yes or No
Question 7 Comment
Owner and Transmission Owner of Elements that meet the Requirement R1 criteria. No
change made.
ACES Standards
Collaborators
No
We do believe the 36‐month period of implementation for R4 is sufficient. However, we
do not understand why R5 and R6 do not have the same effective date as R4. They are
dependent on R4 with the “pursuant to Requirement R4” and “pursuant to Requirement
R5” clauses in the requirements. To avoid the confusion associated with monitoring
compliance to R5 and R6 when they cannot technically be violated, please align the
effective date for R5 and R6 to R4 to avoid this confusion.
Response: The standard drafting team has modified the Implementation Plan so that
Requirements R3 and R4 (previously Requirements R5 and R6) have the same
implementation period of R2 (previously Requirement R4). Change made.
ISO New England
No
Twelve months is not adequate to prepare for this standard as written. The drafting
team should change the implementation plan to twenty four months.
Response: The standard drafting team contends that a 36 calendar month
implementation of Requirement R4 (now Requirement R2) provides ample time for
entities to address the initial influx of identified Elements, if any. Entities should keep in
mind that, for example, that Requirement R4 (now Requirement R2) allows a 12
calendar month period to evaluate load‐responsive protective relays on the Element
which means the entity will have nearly 48 months for completion depending on
identification of the Element. No change made.
NIPSCO
No
We would prefer that the 12 month implementation plan for R1‐R3, R5, R6 be set to 24
months; this is based on the related burden of implementing PRC‐025‐1.
Response: The standard drafting team has modified the Implementation Plan so that
Requirements R3 and R4 (previously Requirements R5 and R6) have the same
implementation period of R2 (previously Requirement R4). Change made.
Consideration of Comments:
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Organization
Yes or No
Question 7 Comment
Arizona Public Service
Co
Yes
Puget Sound Energy
Yes
Southern Company:
Southern Company
Services, Inc.; Alabama
Power Company;
Georgia Power
Company; Gulf Power
Company; Mississippi
Power Company;
Southern Company
Generation; Southern
Company Generation
and Energy Marketing
Yes
Colorado Springs
Utilities
Yes
Duke Energy
Yes
Dominion
Yes
If R4 is a precursor for R5 and R6, R4‐R6 should be included in the 36 month
implementation plan.
Response: The standard drafting team has modified the Implementation Plan so that
Requirements R3 and R4 (previously Requirements R5 and R6) have the same
implementation period of R2 (previously Requirement R4). Change made.
DTE Electric Co.
Yes
No comment
Consideration of Comments:
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Organization
Yes or No
Question 7 Comment
FirstEnergy Corp.
Yes
Oncor Electric Delivery
LLC
Yes
Public Service
Enterprise Group
Yes
Entergy Services, Inc.
Yes
American Electric Power
Yes
Independent Electricity
System Operator
Yes
Luminant Generation
Company, LLC
Yes
City of Tallahassee
Yes
Idaho Power
Yes
Kansas City Power &
Light
Yes
Pepco Holdings Inc.
Yes
The 36 month time line is sufficient
Response: The standard drafting team thanks you for your comment.
CPS Energy
Yes
Consideration of Comments:
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Organization
Yes or No
Question 7 Comment
Nebraska Public Power
District (NPPD)
Yes
Tacoma Power
Yes
Ameren
Yes
ITC
Yes
Texas Reliability Entity
Yes
No comments.
Hydro One
Yes
Hydro One
Yes
Manitoba Hydro
Yes
Lower Colorado River
Authority
Yes
American Transmission
Company, LLC
Yes
Georgia Transmission
Corporation
Yes
Tri‐State Generation
and Transmission
Association, Inc.
Yes
Consideration of Comments:
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Organization
Yes or No
Consumers Energy
Company
Yes
Bonneville Power
Administration
Question 7 Comment
BPA cannot estimate if the implementation plan provides sufficient time until BPA
determines how many elements that R1 applies to.
Response: The standard drafting team contends that a 36 calendar month
implementation of Requirement R4 (now Requirement R2) provides ample time for
entities to address the initial influx of identified Elements, if any. Entities should keep in
mind that, for example, that Requirement R4 (now Requirement R2) allows a 12
calendar month period to evaluate load‐responsive protective relays on the Element
which means the entity will have nearly 48 months for completion depending on
identification of the Element. No change made.
Consideration of Comments:
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8.
If you have any other comments on PRC‐026‐1 that have not been stated above, please provide them here:
Summary Consideration: The following summarizes all other comments received starting with the comments that resulted in a
change to the Standard and followed by a summary of comments that did not result in a change to the Standard. Comments
summarized in Questions 1‐7 are not summarized in this section. See the summaries to the first seven questions.
There were two minor themes of comments that resulted in a revision to the Standard. First, one comment supported by 14
individuals expressed concern about the use of “Elements” rather than “Facilities.” The standard drafting team modified the
language in the Applicability section and Draft 3, Requirements R1 and R2 to more clearly note “generator, transformer, and
transmission line BES Elements to resolve the concern between the two terms defined in the Glossary of Terms Used in NERC
Reliability Standards. Also, one comment supported by 14 individuals revealed that Draft 2, Requirement R4 (now Draft 3,
Requirement R2) was not clear as to what “meets” the PRC‐026‐1 – Attachment B criteria. The standard drafting team revised the
text in PRC‐026‐1 – Attachment B, Criterion A to clarify that an impedance‐based relay used for tripping is expected to not trip for a
stable power swing, when the relay characteristic is completely contained within the unstable power swing region. Draft 3,
Requirement R2 (previously Draft 2, Requirement R4) was revised to evaluate and “to determine whether” relays meet the criteria.
There was on significant and two minor themes of comments that did not result in a revision to the Standard. The significant theme
included three comments represented by 47 individuals which suggested changes that are inconsistent with the NERC style for
writing; therefore, the suggested changes were not implemented.
The first minor theme included one comment supported by 24 individuals that pointed out that PRC‐026‐1 leaves out the use of
transfer limits to correct for stable power swings. The standard drafting team notes that transfer limits are an important tool in the
operation of the BES and are a form of operating limits, but not applicable to the Standard. The PRC‐026‐1 standard is addressing the
risk from a planning standpoint regarding System Operating Limits (SOL) and actual events where the Generator Owner and
Transmission Owner becomes aware of a generator, transformer, or transmission line BES Element that tripped in response to a
stable or unstable power swing due to the operation of its protective relay(s).
Second, one comment represented by 14 individuals commented that it is possible for protective relays applied on a substation bus
section or on a FACTS26 device to be susceptible to power swings, and in fact, in cases of intentional system separation schemes, this
may be an intentional design (e.g., splitting a substation bus when one or a group of transmission lines exceed a measured
condition). The standard drafting team investigated this concern with a few entities and determined there was not a concern that
26
Flexiable AC Transmission System
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would lead to these Elements being added to the Standard’s Applicability. Also, these devices were not suggested as applicable
Elements in the PSRPS Report,27 which recommended an approach to a Reliability Standard.
Organization
Northeast Power
Coordinating Council
Question 8 Comment
The wording of the Purpose should not have been changed. The existing wording” do not trip” is
definitive; the proposed wording “...are expected to...” leaves room for questioning. If the proposed
wording is kept, suggest that the Purpose read:
To ensure that load‐responsive protective relays are not expected to trip in response to stable power
swings during non‐Fault conditions.
Response: The standard drafting team phrased the purpose statement to “expected to ‘not’ trip”
because the expectation is that relays “not trip” in response to a power swing. No change made.
Regarding requirements R1, R2 and R3, to be consistent with the format of other NERC standards, the
Criteria/Criterion listings should be made Parts of requirements R1, R2 and R3.
Response: The standard drafting team contends that Requirement R1 is written in a clear manner to
provide the criterion for which the Planning Coordinator must identify certain Elements to be notified
to the respective Generator Owner and Transmission Owner. No change made.
The standard drafting team removed Requirements R2 and R3. Change made.
Requirement R1 has the Planning Coordinator notifying the respective Generator Owner and
Transmission Owner but a specific time period to complete the notification following the identification
of an Element is not specified. This may appear as a gap in the process. The Planning Coordinator should
have 30 days to notify the TO and GO.
Response: The standard drafting team contends that it is sufficient for the Planning Coordinator to
notify the respective Generator Owner and Transmission Owner on a calendar‐year basis. Notification
27
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20
131015.pdf)
Consideration of Comments:
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Organization
Question 8 Comment
is at the discretion of the PC based on when it identifies Elements, if any, according to the most recent
annual Planning Assessment. Based on the time horizons of the Requirements and the objectives of the
standard, adding a specified time frame to complete the notification adds no reliability benefit. No
change made.
PRC‐026 leaves out the use of transfer limits to correct for stable power swings. Transfer limits are an
important tool for use in power system operations, and should be mentioned in a Rationale Box.
Response: The standard drafting team notes that transfer limits are an important tool in the operation
of the Bulk Electric System and are a form of operating limits. The PRC‐026‐1 standard is addressing the
risk from a planning standpoint regarding System Operating Limits (SOL) and actual events where the
Generator Owner and Transmission Owner become aware of a stable or unstable power swing that
trips an Element.
Entities should not be exempted from the standard because of the linkage to Attachment A.
Attachment A should not exclude Relay elements supervised by power swing blocking. Entities may
install out of step blocking in order to be exempted from the standard. An entity may install Out of Step
Blocking equipment without validating that it is set correctly because PRC‐026 would not apply.
Response: The standard drafting team contends that the installation of power swing blocking relays is
an effective means to prevent tripping for stable power swings. The drafting team contends that
entities that implement power swing blocking (PSB) relays would do so using engineering judgment
and accepted industry practices. A discussion of PSB is in the Application Guidelines. No change made.
Measure M3 is missing the word “meet”. Measure M3 should read: M3. Each Generator Owner shall
have dated evidence that demonstrates identification of the Element(s), if any, which meet the
criterion in Requirement R3. Evidence may include, but is not limited to, the following documentation:
emails, facsimiles, records, reports, transmittals, lists, or spreadsheets.
Response: This Measure was deleted; therefore, eliminated the error. Change made.
Arizona Public Service
Co
The 30 days notification requirements for R2 and R3 is unnecessarily too stringent. We suggest 90 days.
Consideration of Comments:
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Organization
Question 8 Comment
Response: The standard drafting team removed Requirements R2 and R3; therefore, the issue is no
longer present. Change made.
Southern Company:
Southern Company
Services, Inc.; Alabama
Power Company;
Georgia Power
Company; Gulf Power
Company; Mississippi
Power Company;
Southern Company
Generation; Southern
Company Generation
and Energy Marketing
The NERC SPCS report, Protection System Response to Power Swings (dated August 2013),
recommended that NERC reliability standard to address relay performance during stable swings is not
needed, and could result in unintended adverse impacts to Bulk‐Power System reliability. This report
also noted that relay tripping on stable power swings were not casual or contributory in any of the
historical events reviewed. According to report it appears that SPCS team did get an input from SAMS
team and other industry experts before arriving to the conclusion. So, there is no need of this standard.
Response: The standard drafting team thanks you for your comment and provided a detailed
explanation in the previous Consideration of Comments28 in the introductory remarks regarding the
need for a standard to meet regulatory directives.
The calculation criteria in Attachment B, reduces the probability of relay tripping for stable swings but
is not completely fool proof. The swing characteristics vary a lot based on system conditions, such as,
system load, topology, generation status and amount of generation etc. So, it is proposed that the relay
settings are reviewed and modified as needed by PC or TP based on transient stability analysis instead
of setting them based on criteria in attachment B.
Response: The Attachment B criteria provides a consistent and conservative method for determining a
relay’s susceptibility to tripping for stable power swings. Requiring Planning Coordinators or
Transmission Planners to run additional stability studies to determine a relay’s susceptibility to tripping
for a stable power swing will be more time consuming than applying the Criteria in Attachment B.
Further, the contingencies assessed may not be severe enough to adequately ascertain a relay’s
susceptibility to tripping for a stable power swing.
The option to use an angle less than 120 degrees where a documented transient stability analysis
demonstrates the expected maximum stable separation angle is less than 120 degrees is intended to
28
http://www.nerc.com/pa/Stand/Project%202010133%20Phase%203%20of%20Relay%20Loadability%20stabl/Project_2010_13.3_Consideration_of_
Comments_2014_08_22_to_Draft_1.pdf
Consideration of Comments:
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Organization
Question 8 Comment
allow entities to reduce the separation angle where it is supported by a transient stability analysis. No
change made.
Editorial comments:
Comments for PRC‐026‐1
1.
Page 5 – Background Section29
Response: Correction made.
Comments for Application Guidelines
1. Page 1 ‐ “The development of this standard implements the majority of the approaches suggested
by the report.”
Response: Correction made, added “es” to approach.
2. Page 6 ‐ “The standard does not included any requirement for the entities to provide information
that is already being shared or exchanged between entities for operating needs.”
Response: The standard drafting team chose not to include communication requirements between the
Generator Owner and Transmission Owner for the exchange of source impedance data at a given
transmission interconnection point, because the standard drafting team is confident this exchange of
29
The graphic and the text above the graph were appended to the stakeholder’s comment original comment due to a technical problem with the electronic
submittal.
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Organization
Question 8 Comment
source impedance data is already occurring outside of Reliability Standard requirements. A
communication Requirement for the exchange of source impedance data would be administrative in
nature, and would create additional compliance tracking burdens for both entities. No change made.
3. Page 8 ‐ “In order to establish a time delay that strikes a line between a high‐risk...”
What is meant by “strikes”?
Response: The SDT revised the language in this sentence removing the word “strikes”. It now reads “In
order to establish a time delay that distinguishes a high‐risk load‐responsive protective relay from one
that has a time delay for tripping (lower‐risk), a sample of swing rates were calculated based on a stable
power swing entering and leaving the impedance characteristic as shown in Table 1.” Change made.
4. Page 8 ‐ “For a relay impedance characteristic that has the swing entering and leaving beginning at
90 degrees with a termination at 120 degrees before exiting the zone...” “Add degrees”
Response: Addition made.
5. Page 9 ‐ Title of “Application to Transmission Elements”, should be “Application Specific to Criteria
A”.
Response: Thank you for suggestion; however, the standard drafting team prefers to leave the heading
as is.
6. Page 9 ‐ reference Fig 13 and 14 when discussing “infeed effect”
Response: Added reference to Figures 13 and 14 at the end of the “infeed‐effect” text under
“Application to Transmission Elements.”
7. Figure 3 ‐ Update text box “Constant Angle...Boundary (120 degrees)”.
Response: The standard drafting team was unable to determine the change needed.
8. Table 2 through 7 ‐ Do not need to calculate each point, does not provide added value to the
document.
Response: Thank you for comment. The standard drafting team considered other approaches to reduce
the redundancy of the calculations. For example, having the six points in a six column table, but the
Consideration of Comments:
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Organization
Question 8 Comment
font became too small for readability. Six points are considered the critical points to which an entity
would need to calculate the lens characteristic.
9. There are many tables and figures not referenced in the written portion of the document which
makes the guideline difficult to read and follow. This is the case for Figure 13, 14, 15, and almost all the
tables.
Response: Several of the Tables and Figures are standalone by design and where a figure is used in
discussion, it is referenced.
ISO RTO Council
Standards Review
Committee
The SRC respectfully submits that the Purpose statement is unclear and inconsistent with the
requirements in the standard. More specifically, the requirements often refer to stable and unstable
power swings, but such are not addressed in the Purpose statement. This should be clarified. The
following revision is proposed. To protect against tripping by load‐responsive protective relays in
response to stable and unstable power swings during non‐Fault conditions.
Response: The standard drafting team believes the Purpose Statement appropriately captures the
intent of the standard according to the directives the standard is responding to in the FERC Order No.
733.
It is important to note that this standard does not require that entities assess Protection System
performance during unstable swings and does not require entities to prevent tripping in response to
unstable swings. Such requirements would exceed the directive stated in the Federal Energy Regulatory
Commission (FERC) Order No. 733. This standard focuses on the identification of Elements by the
Planning Coordinator (Requirement R1) and Elements where the Generator Owner or Transmission
Owner becomes aware of an Element that tripped in response to a stable or unstable power swing
(Draft 3, Requirement R2, 2nd bullet). Requirement R1 and R2 (2nd bullet) is a screen to identify Elements
that are subject to the Requirements of the standard.
The FERC Order No. 733 directive is perceived as broad and overreaching and could require all relays
to be capable of differentiating between stable power swings and faults. This standard’s focused
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Organization
Question 8 Comment
approach is based on the PSRPS Report,30 recommending “...lines that have tripped due to power
swings during system disturbances...” as one of the ways to focus the evaluation. Based on feedback
from the contributors to the PSRPS Report, that recommendation does not exclude unstable power
swings. Furthermore, it is reasonable to assume that an Element that experiences an unstable swing
(in either a simulation or reality) is likely to experience large stable power swings for less severe
disturbances (that are probably more likely to occur). Thus, the standard drafting team concluded that
addressing Protection Systems for Elements that tripped due to unstable power swings provides a
reliability benefit. No change made.
The SRC has concerns with potential inconsistency between the Purpose statement and the time
horizons. Specifically, Requirements R2 and R3 have a time horizon defined as Long Term Planning
while the Purpose of the standard is about expected / forecasted responses. However, the verbiage of
Requirements R2 and R3 requires action by the responsible entities within 30 days, which implies that
the Time Horizon should be, at most, the Operations Planning time frame. The SRC requests that the
SDT to review these requirements to assure they are consistent with the purpose of the standard, the
Time Horizons and any changes necessary to the Applicability section.
Response: The standard drafting team removed Requirements R2 and R3; therefore, the issue is no
longer present. Change made.
Dominion
No part of the standard discusses reasonable slip frequencies that should be used to detect power
swings. If we identify a relay that is susceptible to tripping for stable power swings (based on the mho
impedance characteristic overlapping a portion of the lens), apply a form of power swing blocking, and
then the relay operates again for a different frequency. Are we to go off the most recent analysis?
Slip frequency is an integral part to power swing detection and determination between a swing and
loading can be difficult. There should be some discussion about this topic in conjunction with loading.
Should a section discuss the correlation with PRC‐023‐2 requirement R2?
30
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
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Organization
Question 8 Comment
PRC‐023‐2 R2. Each Transmission Owner, Generator Owner, and Distribution Provider shall set its out‐
of‐step blocking elements to allow tripping of phase protective relays for faults that occur during the
loading conditions used to verify transmission line relay loadability per Requirement R1.
Response: The standard drafting team notes that the use of slip frequencies in the setting of power
swing blocking relay(s) is outside the scope of the standard. No change made.
DTE Electric Co.
Will this Standard result in any conflicts with PRC‐019 or PRC‐025 while meeting protection goals in
setting generator relays?
Response: The standard drafting team is unaware of any conflicts.
ACES Standards
Collaborators
(1) We believe the data retention section is inconsistent with the RAI. RAI is intended to refocus the
ERO’s compliance monitoring and enforcement efforts on those matters that pose the greatest risk to
the reliability to the BES. This involves making compliance monitoring and enforcement forward looking
to provide reasonable assurance of future compliance and reliability. How does a three‐year data
retention requirement support this forward looking vision of RAI? We suggest that the data retention
should be no more than one year, based on the annual cycle established in this standard.
Response: The standard drafting team has revised the minimum periods to retain evidence to 12
calendar months in the Evidence Retention section to address Risk Assurance Initiative (RAI) concerns.
Change made.
(2) Why is 36 calendar months in bullet 4 instead of 3 calendar years that is used in the first three
bullets? It seems they should be the same to avoid confusion. Notwithstanding our earlier comments
regarding making the data retention period no longer than one year, we suggest using consistent
language throughout the data retention section. Thus, use either 36 calendar months or three calendar
years, but not both.
Response: The standard drafting team has revised the minimum periods to retain evidence to 12
calendar months in the Evidence Retention section to address Risk Assurance Initiative (RAI) concerns.
Change made.
Consideration of Comments:
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Organization
Bonneville Power
Administration
Question 8 Comment
BPA suggests re‐ordering the requirements for continuity because the standard is working/designing
the system to prevent trips by load‐responsive relays unnecessarily.
R1 (PC identify criteria influenced Elements ANNUALLY)
R4 (GO/TO evaluate elements identified by the PC’s identifier of Gen restraint, line part of SOL angular,
UFLS line boundary )R5 (GO/TO develop a CAP for at risk protection on R4 elements)
R6 (GO/TO implement the CAP)
R2 (TO notify PC within 30 days if an element trips by load‐responsive protection due to swings or forms
a boundary during a actual system Disturbance)
R3 (GO notifies PC within 30 days if element trips by load‐responsive protection during a swing)
Response: The standard drafting team thanks you for your comment and notes that Requirements R2
and R3 have been removed and changes were made to the previous R4 (now Requirement R2) to
address other comments and concerns. Change made.
Entergy Services, Inc.
Based on the information contained in the SPCS Power Swing Report Dated August 2013, there is
insufficient evidence in the historical study case identified, to warrant implementation of the proposed
PRC‐026‐1 standard.
Response: The standard drafting team thanks you for your comment and provided a detailed
explanation in the previous Consideration of Comments31 in the introductory remarks regarding the
need for a standard to meet regulatory directives.
Lincoln Electric System
Although aware of the forces driving the development of PRC‐026‐1, LES cannot support the standard.
LES agrees with the statement in the NERC System Protection and Control Subcommittee’s technical
report titled “Protection System Response to Power Swings” that recommends against this standard.
Reliability Standards PRC‐023‐3 and PRC‐025‐1 adequately ensure that load‐responsive protective
31
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Question 8 Comment
relays will not trip in response to stable power swings during non‐Fault conditions. Additionally, as
stated in this same report, consideration should be given to potential adverse impacts to Bulk Power
System reliability as a result of the standard.
Response: The standard drafting team thanks you for your comment and provided a detailed
explanation in the previous Consideration of Comments32 in the introductory remarks regarding the
need for a standard to meet regulatory directives.
Xcel Energy
We believe there is insufficient technical basis to make this a viable standard for industry to properly
apply, and provide the following comments for consideration:
We concur with the NERC concern noted in #133 of FERC order 733 that careful study and analysis of
the relationship between stable power swings and protective relays is needed and consultation with
IEEE and other organizations should be completed before developing a Reliability Standard addressing
stable power swings. The need basis for this standard is 2003 blackout event data. Since that time,
many improvements to protection systems have occurred, voltage control and frequency control
requirements have either been implemented, are on a staged implementation plan, or are planned in
the immediate future. The need basis data set has changed and should be based on current
information, rather than past uncontrolled system reliability program data. Many improvements over
the last 11 years have changed the probability of this particular need occurring, including:
o Use of Generator AVR and PSS systems
o Improved facility equipment ratings
o Automatic voltage and frequency ride‐through standards for wind turbines
o Coordinated protection system settings amongst all players
o Better system modeling and transmission planning
These concerns would be addressed by a carefully planned study as described.
32
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Consideration of Comments:
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Question 8 Comment
We are aware of FERC’s concerns around undesirable operations due to stable power swings, per
Orders 733, 733A and 733B. The directive in #150 states “...we direct the ERO to develop a Reliability
Standard that requires the use of protective relay systems that can differentiate between faults and
stable power swings and, when necessary, phases out protective relay systems that cannot meet this
requirement.” We are also aware that this requirement was reinforced on September 4th, in the
applicable FERC staff meeting. Due to the real or perceived urgency in completing this standard, we
have offered some proposed wording intended to expedite the acceptance of the regulation.
As written, we believe this draft holds potential opportunities for improvements towards readability
and cohesiveness.
Response: The standard drafting team thanks you for your comment and provided a detailed
explanation in the previous Consideration of Comments33 in the introductory remarks regarding the
need for a standard to meet regulatory directives.
Idaho Power
The 30 day time requirement for notification of swing tripping events in R2 and R3 seems a little short.
I think 45 to 60 days would be more appropriate.
Response: The standard drafting team thanks you for your comment and notes that Requirements R2
and R3 have been removed and changes were made to the previous R4 (now Requirement R2) to
address other comments and concerns. Change made.
ISO New England
PRC‐026 leaves out the use of transfer limits to correct for stable power swings. Transfer limits are an
important tool for use in power system operations.
Response: The standard drafting team notes that transfer limits are an important tool in the operation
of the Bulk Electric System and are a form of operating limits. The PRC‐026‐1 standard is addressing the
risk from a planning standpoint regarding System Operating Limits (SOL) and actual events where the
Generator Owner and Transmission Owner become aware of a stable or unstable power swing that
trips an Element.
33
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Question 8 Comment
Furthermore, Attachment A should not exclude Relay elements supervised by power swing blocking.
Entities might simply install out of step blocking in order to be effectively exempted from the standard.
An entity could just install Out of Step Blocking equipment with nothing to ensure that it is set correctly
and the standard would not apply through the exclusion in Attachment A. This will not improve power
system reliability.
Response: The standard drafting team contends that the installation of power swing blocking relays is
an effective means to prevent tripping for stable power swings. The drafting team contends that
entities that implement power swing blocking (PSB) relays would do so using engineering judgment
and accepted industry practices. A discussion of PSB is in the Application Guidelines. No change made.
Nebraska Public Power
District (NPPD)
We are curious why the PC is allowed 1 year to identify elements while the industry is allowed 30 days
after a disturbance to identify elements. This does not seem practical in comparison with the timelines
used with other reporting requirements. For example, PRC‐004 has quarterly submissions with 2
additional months after the quarter end; the new PRC‐004‐3 allows 120 days just to identify if an
operation was a misoperation, root cause determination is not included in that timeframe. In fact, PRC‐
004‐3 includes no set timeline to determine cause, simply a requirement to actively investigate by
indicating active investigation every two calendar quarters until a cause is determined or no cause can
be found. An out‐of‐step analysis is more complex, so it would be logical to allow longer time horizons
for this type of investigation and identification, perhaps no less than an annual interval which would
match the PC.
Response: The standard drafting team contends that PRC‐026‐1 does not require an entity to
determine whether an Element tripped due to a power swing. This is accomplished in the revision to
Requirement R2 (previously Requirement R4) that when an entity “becomes aware” it would evaluate
the relay(s). The identification of a power swing that causes a BES Element trip could be determined
through an entity’s Protection System analysis process (e.g., PRC‐00434), event analysis review by the
entity, region, or NERC.
Additional clarification on two items is requested:
34
Protection System Misoperation Identification and Correction.
Consideration of Comments:
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Organization
Question 8 Comment
1) If a relay has out of step tripping and blocking enabled, does this mean it is excluded from the
standard?
Response: The standard drafting team notes that out‐of‐step trip relaying must still comply with the
criteria in Attachment B of the standard.
2) If a relay has out of step blocking enabled, does this mean it is excluded from the standard?
Response: The standard drafting team notes that relay elements that are supervised by power swing
blocking are excluded from the Requirements of this standard based on Attachment A.
In addition to these comments, we support the comments provided by SPP.
Response: The standard drafting team thanks you for your comments, please see response to SPP
Standards Review Group.
Tacoma Power
For Requirement R2, consider defining ‘island’ or adding a footnote clarifying the intent of the word.
This requirement should not apply to portions of the system containing both generation and load that
become isolated from the BES but that are not intended to operate apart from the BES. For example,
perhaps there are parallel lines that interconnect one or more remote generation plants and some load
to the rest of the system. It is doubtful that the drafting team intended to include these types of
scenarios as ‘islands’.
Response: The standard drafting team removed Requirements R2 and R3; therefore, the issue is no
longer present. Change made.
Should POTT and DCB schemes be specifically called out in Attachment A as being applicable to PRC‐
026‐1?
Response: The figures have been updated to generically refer to Pilot Zone 2 and Zone 2 impedance
characteristics as “mho element characteristics.” A clarifying paragraph has also been added to the
Guidelines and Technical Basis under the Requirement R2 heading which discusses the types of “pilot”
or communications relay schemes that need to be considered. Change made.
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Question 8 Comment
Attachment B Criterion B may yield current that is above the phase time overcurrent pickup but, at this
level of current, the phase time overcurrent element may take longer than 15 cycles to operate.
Therefore, the approach in Attachment B Criterion B is potentially conservative.
Response: The standard drafting team thanks you for your comment.
The Response to Issues and Directives still mentions that “...the proposed standard does require that
an Element that was part of a boundary that formed an island since January 1, 2003 be identified as an
that is within the scope of the proposed standard.”
Ameren
We appreciate the SDT’s significant improvements in this draft 2. Our response to question 3 above
captures our primary reason for voting negative.
Response: Correction made.
ITC
In R2, add reference to Attachment A when describing the load‐responsive protective relays. R2 Criteria
2 adds no value and should be removed. All Elements which trip due to swings will be captured under
Criteria 1. Criteria 2 only includes islands formed due to phase faults and adds no value. If you intend
to capture boundaries of all islands formed, then remove the “due to the operation of its load‐
responsive protective relays” qualifier. If you intend to capture boundaries of all islands formed due to
protective relay operations, then remove the “load‐responsive” qualifier.
Response: The standard drafting team removed Requirements R2 and R3; therefore, the issue is no
longer present. Change made.
Application Guidelines, page 63, Application to Generation Elements, change the language to include
generator relays, if they are set based on equipment permissible overload capability. “Load‐responsive
protective relays such as time over‐current, voltage controlled time‐overcurrent or voltage‐restrained
time‐overcurrent relays are excluded from this standard [if] they are set based on equipment
permissible overload capability.”
Response: Correction made.
Consideration of Comments:
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Posted: November 4, 2014
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Question 8 Comment
Application Guidelines, page 72, the first paragraph under Requirement R5 is more appropriate under
Requirement R6.
Response: The standard drafting team eliminated the text.
Texas Reliability Entity
Texas RE suggests that the PRC‐026‐1 SDT refer this standard to the Project 2014‐01 SDT (if not done
already) for consideration regarding the applicability of BES generators to include dispersed generation
resources so the requirements of the standard pertain primarily to the point of connection where the
resources aggregate to 75 MVA or more, and not to the individual resources. Since this is a new
standard it is not currently included in “Appendix B: List of Standards Recommended for Further
Review” from the draft white paper entitled “Proposed Revisions to the Applicability of NERC Reliability
Standards NERC Standards Applicability to Dispersed Generation Resources.”
Response: The standard drafting team has been coordinating with the dispersed generation resources
project team. No conflicts have been identifies.
CenterPoint Energy
CenterPoint Energy recommends removing references to “unstable” power swings in the draft PRC‐
026‐1 standard, as we believe tripping from unstable power swings is random and not indicative of an
Element being more susceptible to a stable power swing. Where tripping actually occurs for an unstable
power swing is dependent on the location and nature of the event, system conditions, and where
additional Element outages occur during a disturbance. We are not aware of any available technical
information or analysis to justify that an Element is more susceptible to a stable power swing if it has
tripped from an unstable power swing.
Response: It is important to note that this standard does not require that entities assess Protection
System performance during unstable swings and does not require entities to prevent tripping in
response to unstable swings. Such requirements would exceed the directive stated in the Federal
Energy Regulatory Commission (FERC) Order No. 733. This standard focuses on the identification of
Elements by the Planning Coordinator (Requirement R1) and Elements where the Generator Owner or
Transmission Owner becomes aware of an Element that tripped in response to a stable or unstable
power swing (Draft 3, Requirement R2, 2nd bullet). Requirement R1 and R2 (2nd bullet) is a screen to
identify Elements that are subject to the Requirements of the standard.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Question 8 Comment
The FERC Order No. 733 directive is perceived as broad and overreaching and could require all relays
to be capable of differentiating between stable power swings and faults. This standard’s focused
approach is based on the PSRPS Report,35 recommending “...lines that have tripped due to power
swings during system disturbances...” as one of the ways to focus the evaluation. Based on feedback
from the contributors to the PSRPS Report, that recommendation does not exclude unstable power
swings. Furthermore, it is reasonable to assume that an Element that experiences an unstable swing
(in either a simulation or reality) is likely to experience large stable power swings for less severe
disturbances (that are probably more likely to occur). Thus, the standard drafting team concluded that
addressing Protection Systems for Elements that tripped due to unstable power swings provides a
reliability benefit. No change made.
Duke Energy
Duke Energy agrees in part with the revisions made by the SDT on this project. However, due to the
amount of technical information provided in the Application and Guidelines portion of this standard,
more time is needed for our SME(s) to thoroughly review this section before submitting an
“Affirmative” vote.
Response: The standard drafting team thanks you for your comment.
Florida Municipal Power
Agency
FMPA would like to commend the SDT for developing an overall process that is generally reasonable
and does not, in our opinion, add an excessive compliance burden, since the number of identified
circuits and generators should be small. However, we believe more work is required to make the
concept the SDT has come up with successful.
1. First, as mentioned in earlier sections, the standard is in general written with the perspective of large
vertically integrated utilities in mind, and does not consider the impact on non‐vertically integrated TOs
and GOs. As such, we believe there is further coordination that needs to be developed between this
standard and PRC‐004, that will
35
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
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Posted: November 4, 2014
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Question 8 Comment
a) facilitate communication between PCs, TPs, TOPs, the RC, and respective investigating TOs and GOs
and
b) will establish a clear timeline that can cleanly be audited for R2 and R3. As stated in our comments
above on R2, the requirements for keeping records for “correct” relay operations are effectively non‐
existent in current standards.
FMPA believes it makes sense for all “investigations” and associated records to occur within PRC‐004
and then for “power swing” related activities to occur in PRC‐026. Currently power swings are only
discussed in PRC‐004 as they relate to failure to trip or slow trip conditions (and not where operation
for a power swing was correct). Furthermore there is presently no acknowledgment that GOs and TOs
may need assistance and information from their TPs, PCs, associated TOP, or even RC.
Response: The standard drafting team contends that PRC‐026‐1 does not require an entity to
determine whether an Element tripped due to a power swing. This is accomplished in the revision to
Requirement R2 (previously Requirement R4) that when an entity “becomes aware” it would evaluate
the relay(s). The identification of a power swing that causes a BES Element trip could be determined
through an entity’s Protection System analysis process (e.g., PRC‐00436), event analysis review by the
entity, region, or NERC.
There is no requirement to track “correct” operations now that Requirement R2 (previously
Requirement R4) is triggered on becoming aware of a trip that is due to a power swing. The entity
would maintain records demonstrating compliance with the Requirement upon becoming aware of the
trip.
The standard drafting team chose not to include communication requirements between the Generator
Owner and Transmission Owner for the exchange of source impedance data at a given transmission
interconnection point, because the standard drafting team is confident this exchange of source
impedance data is already occurring outside of Reliability Standard requirements. A communication
Requirement for the exchange of source impedance data would be administrative in nature, and would
create additional compliance tracking burdens for both entities. No change made.
36
Protection System Misoperation Identification and Correction.
Consideration of Comments:
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Organization
Question 8 Comment
2. The Applicability section refers to GO’s and TO’s that apply load responsive relays to Generators,
Transformers, and Transmission Lines. FMPA sees three issues related to this.
a. First, all language in the standard Requirements refers to Elements instead of Facilities ‐ based on
previous comments and the SDT’s response to those comments, the standard Requirements should be
referring to Facilities to draw focus to the BES distinction, which does not exist for Elements.
Response: The standard drafting team has modified the language in the Applicability section and
Requirements R1 and R2 (previously Requirement R4) to more clearly note “BES generator,
transformer, and transmission line Elements. Change made.
b. Second, the identification of issues and tracking of issues from entity to entity is based on Elements.
This works from the perspective of identification of risks to the system but falls short when it comes
time to evaluate and modify the Protection Systems, because no Requirement refers back to the Owner
of the Protection Systems applied on the Elements identified in R1. Instead, Requirements 2 and 3 are
directed at the Owner of the Element itself which may or may not own the Protection System that is
actually at risk of operating (or misoperating). The Requirements need to consider this relationship
similar to PRC‐004‐3.
Response: The standard drafting team removed Requirements R2 and R3; therefore, the issue is no
longer present. Change made.
c. Third, it is quite possible for protective relays applied on a substation bus section or on FACTS devices
to be susceptible to power swings, and in fact, in cases of intentional system separation schemes, this
may be an intentional design (e.g splitting a substation bus when one or a group of transmission lines
exceed a measured condition). The Facilities section does not include such Elements.
Response: The standard drafting team notes that these devices are not suggested as applicable
Elements in the PSRPS Report37 which recommended an approach to a Reliability Standard. No change
made.
37
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
Consideration of Comments:
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Posted: November 4, 2014
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Organization
Question 8 Comment
3. FMPA is concerned the conditions under which Criteria A is being calculated may be excessively
conservative. Item 3 of the Criteria states “Saturated (transient or sub‐transient) reactance is used for
all machines.” Note the term “all”, which could be confusing if an entity is not considering the context.
The documentation presented does not discuss terms such as “maximum generation dispatch” or any
other term that would relate back to a realistic number of generators being in service. The requirement
should be “all machines that are in service in short circuit model”, and in the Application Guide there
should be some discussion on using maximum reasonable generation dispatches in short circuit cases.
Similarly, but of less consequence, it is not clear that the Transfer Impedance should always be
completely neglected. While this is certainly numerically convenient, FMPA wonders if this does not
produce overly conservative results in cases of well‐networked transmission. Would it not be more
prudent to remove other transmission circuits which have significant transfer distribution factors
relative to the line in question, and then re‐calculate the transfer impedance, rather than assuming
some exceedingly large number of transmission outages has occurred? This relates to the comment
above that some discussion should be offered surrounding Table 10 in the Application Guide.
Response: The standard drafting team contends that the Attachment B criteria provides a consistent
and conservative approach to achieving the intent of the standard. The Guidelines and Technical Basis
have additional text regarding the transfer impedance and Table 10.
4. As written, the combination of Requirement R4 (which instructs the TO/GO to “evaluate” its relays
against the “Criteria” in Attachment B) and the Criteria in Attachment B, make no definitive statements
about what relays “meet” anything, or “are deficient and require corrective action plans” etc.
Requirements and Criteria should be very clear and straight forward. The “Criteria” is really just a
description. There is no information in the Requirement or in the Attachment that actually involves
making a “judgment” which is the most important part of the definition of the term Criteria. FMPA is
well aware of the intent of these two items and only wishes to point out that the intent is really only
made clear in the Application Guidelines.
Response: The standard drafting team has revised the text in Attachment B, Criterion A to clarify that
an impedance‐based relay used for tripping is expected to not trip for a stable power swing, when the
relay characteristic is completely contained within the unstable power swing region. Requirement R2
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Organization
Question 8 Comment
(previously Requirement R4) was revised to evaluate and “to determine whether” relays meet the
criteria. Change made.
SPP Standards Review
Group
Delete the reference to PRC‐026‐1 in 4.1.1 and 4.1.3 in the Applicability section. Leave the references
simply as Attachment A.
Response: The standard drafting team prefers to leave the reference in because it maintains
consistency with the other two relay loadability standards (i.e., PRC‐023 and PRC‐025) and provides an
appropriate reference to the attachment is separated from the standard itself. No change made.
Delete ‘This’ in the 1st line of the 4th paragraph under 5. Background:.
Response: The standard drafting team correction made.
At the end of the 6th line and beginning of the 7th line in the same paragraph, delete ‘of security’.
Response: The standard drafting team correction made.
Hyphenate 30‐, 60‐, 90‐calendar days and similar construction with calendar months throughout the
standard.
Response: The standard drafting team notes that the current formatting of days noted above is
consistent with the NERC document style guide. No change made.
At the end of each of the first three bullets in 1.2 Evidence Retention the phrase ‘following the
completion of each Requirement’ appears. Since each bullet only refers to one requirement what does
this phrase mean when applied to Requirements R1, R2 and R3 individually?
Response: The standard drafting team has replaced “each” with “the” for clarity. Change made.
Why is the timing for notification in the VSLs for the Transmission Owner in Requirement R2 and the
Generation Owner in Requirement R3 different from that for the Planning Coordinator in Requirement
R1? Shouldn’t they be the same?
Response: The standard drafting team removed Requirements R2 and R3; therefore, the issue is no
longer present. Change made.
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
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Organization
Question 8 Comment
We recommend that all changes made to the standard be reflected in the RSAW as well.
Response: The standard drafting team will provide input to NERC Compliance regarding the RSAW.
City of Tallahassee
This standard will cause a large increase in workload for entities with a small trade off of system
reliability.
Response: The standard drafting team notes that the standard is presenting an equally effective and
efficient approach to the Federal Energy Regulatory Commission (FERC) Order No. 733 directive, and is
narrowly focused on specific Elements, and reduces the burden to entities when compared to the
directive in Order No. 733. See the “Table of Issues and Directives” document in the posting for FERC’s
original directive. NERC is obligated to respond to FERC’s directive.
Exelon Companies
We agree with the drafting teams’ decision that only those elements that trip in less than 15 cycles
need to be evaluated for susceptibility to tripping during stable power swings. This follows from actual
event experience that shows that the vast majority of relays that trip during power swings are zone 1s.
Response: The standard drafting team thanks you for your support.
END OF REPORT
Consideration of Comments:
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
Posted: November 4, 2014
148 of 148
Agenda Item: 6b
Notice of Request to Waive the Standard
Process
Project 2010-13.3 – Phase 3 of Relay Loadability: Stable Power Swings
As required by Section 16 of the NERC Standard Processes Manual (SPM), this is official notice to
stakeholders that the leadership of the Project 2010-13.3 Protection System Response to Power Swings
Standards Drafting Team (PSRPS SDT), the Project Management and Oversight Subcommittee liaison,
the Standards Committee (SC) chair, and NERC Standards staff (Requesters) are requesting that the SC
consider a waiver of the SPM. The Requesters ask to shorten the next formal comment and ballot
period for draft standard PRC-026-1 – Relay Performance During Stable Power Swings, and any
subsequent formal comment and ballot periods for that standard, from forty-five days to twenty-one
days, with a ballot and non-binding poll during the last seven days, and to shorten the final ballot for
PRC-026-1 from ten days to seven days, in order to meet a Federal Energy Regulatory Commission
(FERC) regulatory deadline. Section 16 of the SPM provides for the granting of a waiver for a
regulatory deadline.
The SC will meet via teleconference to consider this waiver on its regularly scheduled Wednesday,
October 22, 2014 call (to comply with the five business days’ notice required by Section 16 of the SPM,
this notice and its accompanying one-pager were submitted to the SC on October 15, 2014). The SC’s
teleconference will be noticed through an announcement and posted on the NERC website. Additional
details about the waiver request are included below, and should a waiver be granted by the SC, it will
be posted on the project page.
Justification for Current Waiver Request
In Order No. 733, FERC directed the development of a Reliability Standard to address the use of
protective relay systems that can differentiate between faults and stable power swings. 1 The PSRSP
SDT is proposing an equally efficient and effective Reliability Standard to address the directive. The
proposed PRC-026-1 Reliability Standard is consistent with guidance provided in the NERC System
Protection and Control Subcommittee report Protection System Response to Power Swings, August
2013. PRC-026-1 has been posted for two 45-day formal comment periods and ballots, receiving
approval ratings of 17.02% and 53.02%, respectively.
The shortened comment period and ballot for PRC-026-1 serves several important purposes. First, the
shortened comment period will allow for one additional formal comment period and ballot, while still
allowing the standard to be filed with FERC by the December 31, 2014 deadline. This will also enable
the drafting team to conduct additional outreach prior to the start of the ballot which may be
important to ensure stakeholder support. Shortening the final ballot period from ten days to seven
1
Transmission Relay Loadability Reliability Standard, Order No. 733, P150, 130 FERC ¶ 61,221 (2010)(“Order No. 733”).
days also provides scheduling flexibility that may be required to achieve the necessary milestones
including scheduling a special call for NERC Board of Trustees adoption, while still allowing NERC and
the industry to successfully meet the filing deadline.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Scott Barfield-McGinnis,
Standards Developer, at [email protected] or at 404-446-9689.
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 2010-13.3 – Phase 3 of Relay Loadability: Stable Power Swings
2
Agenda Item 6
Standards Committee
October 22, 2014
Waiver Authorization for Project 2010-13.3 Phase 3 of Relay Loadability:
Stable Power Swings
Action
Authorize a waiver of the Standard Process Manual (SPM) to:
a) Shorten the next additional formal comment period (and any subsequent additional
formal comment periods) for draft standard PRC-026-1 – Relay Performance During
Stable Power Swings from forty-five days to twenty-one days, with a ballot and nonbinding poll during the last seven days of the twenty-one day period; and
b) Shorten the final ballot period from ten days to seven days.
Background
The leadership of the Protection System Response to Power Swings Standard Drafting Team
(PSRPS SDT), NERC Staff, and the Project Management and Oversight Subcommittee liaison and
chair of the Standards Committee (SC) have requested a waiver of the NERC Standards Processes
Manual (SPM) as described in the actions above. Section 16 of the SPM provides for the
granting of waivers to meet a regulatory deadline. As required in Section 16, NERC provided
stakeholders with five business days’ notice of this waiver. If a waiver is authorized, NERC will
post notice of the waiver and notify the NERC Board of Trustees Standards Oversight and
Technology Committee.
In Order No. 733, The Federal Energy Regulatory Commission (FERC) directed the development
of a Reliability Standard to address the use of protective relay systems that can differentiate
between faults and stable power swings. 1 The PSRSP SDT is proposing an equally efficient and
effective Reliability Standard to address the directive. The proposed PRC-026-1 Reliability
Standard is consistent with guidance provided in the NERC System Protection and Control
Subcommittee report Protection System Response to Power Swings, August 2013. PRC-026-1
has been posted for two 45-day formal comment periods and ballots, receiving approval ratings
of 17.02% and 53.02, respectively.
The shortened comment period and ballot for PRC-026-1 serves several important purposes.
First, the shortened comment period will allow for one additional formal comment period and
ballot, while still allowing the standard to be filed with FERC by the December 31, 2014
deadline. This will also enable the drafting team to conduct additional outreach prior to the
start of the ballot which may be important to ensure stakeholder support. Shortening the final
ballot period from ten days to seven days also provides scheduling flexibility that may be
Transmission Relay Loadability Reliability Standard, Order No. 733, P150, 130 FERC ¶ 61,221 (2010)(“Order No.
733”).
1
required to achieve the necessary milestones including scheduling a special call for NERC Board
adoption, while still allowing NERC and the industry to successfully meet the filing deadline.
PRC-026-1 — Relay Performance During Stable Power Swings
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. Standards Authorization Request (SAR) posted for comment from August 19, 2010
through September 19, 2010.
2. Standards Committee (SC) authorized moving the SAR forward into standard
development on August 12, 2010.
3. SC authorized initial posting of Draft 1 on April 24, 2014.
4. Draft 1 of PRC-026-1 was posted for a 45-day formal comment period from April 25 –
June 9, 2014 with a concurrent/parallel initial ballot in the last ten days of the comment
period from May 30 – June 9, 2014.
5. Draft 2 of PRC-026-1 was posted for an additional 45-day formal comment period from
August 22 – October 6, 2014 with a concurrent/parallel additional ballot in the last ten
days of the comment period from September 26 – October 6, 2014.
6. SC authorized a waiver of the Standards Process Manual on October 22, 2014 to reduce
the Draft 3 additional formal comment period of PRC-026-1 from 45 days to 21 days
with a concurrent/additional ballot period in the last ten days of the comment period.
Description of Current Draft
The Protection System Response to Power Swings Standard Drafting Team (PSRPS SDT) is
posting Draft 3 of PRC-026-1 – Relay Performance During Stable Power Swings for a 21-day
additional comment period and concurrent/parallel additional ballot in the last ten days of the
comment period.
Anticipated Actions
Anticipated Date
45-day Formal Comment Period with Concurrent/Parallel Initial 10-day
Ballot
April 2014
45-day Formal Comment Period with Concurrent/Parallel Additional 10day Ballot
August 2014
21-day Formal Comment Period with Concurrent/Parallel Additional 10day Ballot (Standards Committee authorized a waiver of the Standards
Process Manual, October 22, 2014)
October 2014
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
Final Ballot
December 2014
NERC Board of Trustees Adoption
December 2014
Version History
Version
Date
1.0
TBD
Action
Effective Date
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
Change
Tracking
New
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PRC-026-1 — Relay Performance During Stable Power Swings
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Glossary of Terms Used in Reliability Standards (Glossary) are not repeated
here. 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.
Term: None.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
When this standard has received ballot approval, the rationale boxes will be moved to the
Application Guidelines Section of the standard.
A. Introduction
1. Title:
Relay Performance During Stable Power Swings
2. Number:
PRC-026-1
3. Purpose:
To ensure that load-responsive protective relays are expected to not trip in
response to stable power swings during non-Fault conditions.
4. Applicability:
4.1.
4.2.
Functional Entities:
4.1.1
Generator Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
4.1.2
Planning Coordinator.
4.1.3
Transmission Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
Facilities: The following Elements that are part of the Bulk Electric System
(BES):
4.2.1
Generators.
4.2.2
Transformers.
4.2.3
Transmission lines.
5. Background:
This is the third phase of a three-phased standard development project that focused on
developing this new Reliability Standard to address protective relay operations due to
stable power swings. The March 18, 2010, Federal Energy Regulatory Commission
(FERC) Order No. 733, approved Reliability Standard PRC-023-1 – Transmission Relay
Loadability. In this Order, FERC directed NERC to address three areas of relay loadability
that include modifications to the approved PRC-023-1, development of a new Reliability
Standard to address generator protective relay loadability, and a new Reliability Standard
to address the operation of protective relays due to stable power swings. This project’s
SAR addresses these directives with a three-phased approach to standard development.
Phase 1 focused on making the specific modifications to PRC-023-1 and was completed in
the approved Reliability Standard PRC-023-2, which became mandatory on July 1, 2012.
Phase 2 focused on developing a new Reliability Standard, PRC-025-1 – Generator Relay
Loadability, to address generator protective relay loadability. PRC-025-1 became
mandatory on October 1, 2014 along with PRC-023-3, which was modified to harmonize
PRC-023-2 with PRC-025-1.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
Phase 3 of the project establishes Requirements aimed at preventing protective relays from
tripping unnecessarily due to stable power swings by requiring the identification of
Elements on which a stable or unstable power swing may affect Protection System
operation, and to develop Requirements to assess the security of load-responsive protective
relays to tripping in response to only a stable power swing. Last, to require entities to
implement Corrective Action Plans (CAP), where necessary, to improve security of loadresponsive protective relays for stable power swings so they are expected to not trip in
response to stable power swings during non-Fault conditions, while maintaining
dependable fault detection and dependable out-of-step tripping.
6. Effective Dates:
Requirement R1
First day of the first full calendar year that is 12 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 12 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
Requirements R2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 36 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
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PRC-026-1 — Relay Performance During Stable Power Swings
B. Requirements and Measures
R1. Each Planning Coordinator shall, at least once each calendar year, provide notification
of each generator, transformer, and transmission line BES Element in its area that meet
one or more of the following criteria, if any, to the respective Generator Owner and
Transmission Owner: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
Criteria:
1. Generator(s) where an angular stability constraint exists that is addressed by a
System Operating Limit (SOL) or a Remedial Action Scheme (RAS) and those
Elements terminating at the Transmission station associated with the generator(s).
2. An Element that is monitored as part of a SOL identified by the Planning
Coordinator’s methodology1 based on an angular stability constraint.
3. An Element that forms the boundary of an island in the most recent
underfrequency load shedding (UFLS) design assessment based on application of
the Planning Coordinator’s criteria for identifying islands, where the island is
formed by tripping the Element due to angular instability.
4. An Element identified in the most recent annual Planning Assessment where relay
tripping occurs due to a stable or unstable power swing during a simulated
disturbance.
M1. Each Planning Coordinator shall have dated evidence that demonstrates notification of
the generator, transformer, and transmission line BES Element(s) that meet one or
more of the criteria in Requirement R1, if any, to the respective Generator Owner and
Transmission Owner. Evidence may include, but is not limited to, the following
documentation: emails, facsimiles, records, reports, transmittals, lists, or spreadsheets.
Rationale for R1: The Planning Coordinator has a wide-area view and is in the position to
identify generator, transformer, and transmission line BES Elements which meet the criteria, if
any. The criteria-based approach is consistent with the NERC System Protection and Control
Subcommittee (SPCS) technical document Protection System Response to Power Swings,
August 2013 (“PSRPS Report”), 2 which recommends a focused approach to determine an atrisk BES Element. See the Guidelines and Technical Basis for a detailed discussion of the
criteria.
1
NERC Reliability Standard FAC-10 – System Operating Limits Methodology for the Planning Horizon
2
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R2. Each Generator Owner and Transmission Owner shall determine: [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
2.1 Within 12 full calendar months of notification of a BES Element pursuant to
Requirement R1, determine whether its load-responsive protective relay(s)
applied to that BES Element meets the criteria in PRC-026-1 – Attachment B
where an evaluation of that Element’s load-responsive protective relay(s) based
on PRC-026-1 – Attachment B criteria has not been performed in the last five
calendar years.
2.2 Within 12 full calendar months of becoming aware of a generator, transformer, or
transmission line BES Element that tripped in response to a stable or unstable
power swing due to the operation of its protective relay(s), determine whether its
load-responsive protective relay(s) applied to that BES Element meets the criteria
in PRC-026-1 – Attachment B.
M2. Each Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the evaluation was performed according to Requirement R2. Evidence
may include, but is not limited to, the following documentation: apparent impedance
characteristic plots, email, design drawings, facsimiles, R-X plots, software output,
records, reports, transmittals, lists, settings sheets, or spreadsheets.
Rationale for R2: The Generator Owner and Transmission Owner are in a position to determine
whether its load-responsive protective relays meet the PRC-026-1 – Attachment B criteria.
Generator, transformer, and transmission line BES Elements are identified by the Planning
Coordinator in Requirement R1 and by the Generator Owner and Transmission Owner
following an actual event where the Generator Owner and Transmission Owner became aware
(i.e., through an event analysis or Protection System review) tripping was due to stable or
unstable power swing. A period of 12 calendar months allows sufficient time for protection staff
to conduct the evaluation.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R3. Each Generator Owner and Transmission Owner shall, within six full calendar months
of determining a load-responsive protective relay does not meet the PRC-026-1 –
Attachment B criteria, develop a Corrective Action Plan (CAP) to meet one or more of
the following [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
•
The Protection System meets the PRC-026-1 – Attachment B criteria, while
maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the BES Element); or
•
The Protection System is excluded under the PRC-026-1 – Attachment A criteria
(e.g., modifying the Protection System so that relay functions are supervised by
power swing blocking or using relay systems that are immune to power swings),
while maintaining dependable fault detection and dependable out-of-step tripping
(if out-of-step tripping is applied at the terminal of the BES Element).
M3. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the development of a CAP in accordance with Requirement R3. Evidence
may include, but is not limited to, the following documentation: corrective action
plans, maintenance records, settings sheets, project or work management program
records, or work orders.
Rationale for R3: To meet the reliability purpose of the standard, a CAP is necessary to ensure
the entity’s Protection System meets the PRC-026-1 – Attachment B criteria so that protective
relays are expected to not trip in response to stable power swings. The phrase, “…while
maintaining dependable fault detection and dependable out-of-step tripping…” in Requirement
R2 describes that the entity is to comply with this standard, while achieving their desired
protection goals. Refer to the Guidelines and Technical Basis, Introduction, for more
information.
R4. Each Generator Owner and Transmission Owner shall implement each CAP developed
pursuant to Requirement R3 and update each CAP if actions or timetables change until
all actions are complete. [Violation Risk Factor: Medium][Time Horizon: Long-Term
Planning]
M4. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates implementation of each CAP according to Requirement R4, including
updates to the CAP when actions or timetables change. Evidence may include, but is
not limited to, the following documentation: corrective action plans, maintenance
records, settings sheets, project or work management program records, or work orders.
Rationale for R4: Implementation of the CAP must accomplish all identified actions to be
complete to achieve the desired reliability goal. During the course of implementing a CAP,
updates may be necessary for a variety of reasons such as new information, scheduling conflicts,
or resource issues. Documenting CAP changes and completion of activities provides measurable
progress and confirmation of completion.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention
The following evidence retention periods 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 CEA may ask an entity to provide other evidence to show that it was
compliant for the full time period since the last audit.
The Generator Owner, Planning Coordinator, and Transmission Owner shall keep
data or evidence to show compliance as identified below unless directed by its CEA
to retain specific evidence for a longer period of time as part of an investigation.
•
The Planning Coordinator shall retain evidence of Requirement R1 for a
minimum of one calendar year following the completion of the
Requirement.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirement R2 evaluation for a minimum of 12 calendar months following
completion of each evaluation where a CAP is not developed.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R2, R3 and R4 for a minimum of 12 calendar months
following completion of each CAP.
If a Generator Owner, Planning Coordinator, or Transmission Owner is found noncompliant, it shall keep information related to the non-compliance until mitigation
is complete and approved, or for the time specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3.
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure; “Compliance Monitoring and
Assessment Processes” 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.
1.4.
Additional Compliance Information
None.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
Table of Compliance Elements
R#
R1
Time
Horizon
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was less than or equal
to 30 calendar days
late.
Moderate VSL
High VSL
Severe VSL
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 90
calendar days late.
OR
The Planning
Coordinator failed to
provide notification
of the BES
Element(s) in
accordance with
Requirement R1.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R2
Time
Horizon
Operations
Planning
Violation Severity Levels
VRF
High
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was less than or equal
to 30 calendar days
late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 90
calendar days late.
OR
The Generator Owner
or Transmission
Owner failed to
evaluate its loadresponsive protective
relay(s) in accordance
with Requirement R2.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R3
R4
Time
Horizon
Long-term
Planning
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than six
calendar months and
less than or equal to
seven calendar
months.
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than seven
calendar months and
less than or equal to
eight calendar
months.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than eight
calendar months and
less than or equal to
nine calendar months.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than nine
calendar months.
Medium The Generator Owner
or Transmission
Owner implemented a
Corrective Action
Plan (CAP), but failed
to update a CAP when
actions or timetables
changed, in
accordance with
Requirement R4.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
N/A
OR
The Generator Owner
or Transmission
Owner failed to
develop a CAP in
accordance with
Requirement R3.
N/A
The Generator Owner
or Transmission
Owner failed to
implement a
Corrective Action
Plan (CAP) in
accordance with
Requirement R4.
Page 12 of 82
PRC-026-1 — Relay Performance During Stable Power Swings
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
Burdy, John, Loss-of-excitation Protection for Synchronous Generators GER-3183, General
Electric Company.
IEEE Power System Relaying Committee WG D6, Power Swing and Out-of-Step
Considerations on Transmission Lines, July 2005: http://www.pes-psrc.org/Reports
/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission%20
Lines%20F..pdf.
Kimbark Edward Wilson, Power System Stability, Volume II: Power Circuit Breakers and
Protective Relays, Published by John Wiley and Sons, 1950.
Kundur, Prabha, Power System Stability and Control, 1994, Palo Alto: EPRI, McGraw Hill,
Inc.
NERC System Protection and Control Subcommittee, Protection System Response to Power
Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf.
Reimert, Donald, Protective Relaying for Power Generation Systems, 2006, Boca Raton: CRC
Press.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
Page 13 of 82
PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment A
This standard applies to any protective functions which could trip instantaneously or with a time
delay of less than 15 cycles on load current (i.e., “load-responsive”) including, but not limited to:
•
•
•
•
Phase distance
Phase overcurrent
Out-of-step tripping
Loss-of-field
The following protection functions are excluded from Requirements of this standard:
•
•
•
•
•
•
•
•
•
•
•
Relay elements supervised by power swing blocking
Relay elements that are only enabled when other relays or associated systems fail. For
example:
o Overcurrent elements that are only enabled during loss of potential conditions.
o Relay elements that are only enabled during a loss of communications
Thermal emulation relays which are used in conjunction with dynamic Facility Ratings
Relay elements associated with direct current (dc) lines
Relay elements associated with dc converter transformers
Phase fault detector relay elements employed to supervise other load-responsive phase
distance elements (e.g., in order to prevent false operation in the event of a loss of potential)
provided the distance element is set in accordance with the criteria outlined in the standard
Relay elements associated with switch-onto-fault schemes
Reverse power relay on the generator
Generator relay elements that are armed only when the generator is disconnected from the
system, (e.g., non-directional overcurrent elements used in conjunction with inadvertent
energization schemes, and open breaker flashover schemes)
Current differential relay, pilot wire relay, and phase comparison relay
Voltage-restrained or voltage-controlled overcurrent relays
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
Criteria A:
An impedance-based relay used for tripping is expected to not trip for a stable power swing,
when the relay characteristic is completely contained within the unstable power swing region. 3
The unstable power swing region is formed by the union of three shapes in the impedance (RX) plane; (1) a lower loss-of-synchronism circle based on a ratio of the sending-end to
receiving-end voltages of 0.7; (2) an upper loss-of-synchronism circle based on a ratio of the
receiving-end to sending-end voltages of 1.43; (3) a lens that connects the endpoints of the
total system impedance (with the parallel transfer impedance removed) bounded by varying
the sending-end and receiving-end voltages from 0.0 to 1.0 per unit, while maintaining a
constant system separation angle across the total system impedance where:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
Rationale for Attachment B (Criteria A): The PRC-026-1 – Attachment B, Criteria A
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending-end and receiving-end
voltages varying from 0.7 to 1.0 per unit (See Guidelines and Technical Basis).
3
Guidelines and Technical Basis, Figures 1 and 2.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
Criteria B:
The pickup of an overcurrent relay element used for tripping, that is above the calculated
current value (with the parallel transfer impedance removed) for the conditions below:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
4. Both the sending-end and receiving-end voltages at 1.05 per unit.
Rationale for Attachment B (Criteria B): The PRC-026-1 – Attachment B, Criteria B
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending-end and receiving-end
voltages at 1.05 per unit (See Guidelines and Technical Basis).
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4, 2014)
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PRC-026-1 – Application Guidelines
Guidelines and Technical Basis
Introduction
The NERC System Protection and Control Subcommittee technical document, Protection System
Response to Power Swings, August 2013 4 (“PSRPS Report” or “report”) was specifically prepared
to support the development of this NERC Reliability Standard. The report provided a historical
perspective on power swings as early as 1965 up through the approval of the report by the NERC
Planning Committee. The report also addresses reliability issues regarding trade-offs between
security and dependability of Protection Systems, considerations for this NERC Reliability
Standard, and a collection of technical information about power swing characteristics and varying
issues with practical applications and approaches to power swings. Of these topics, the report
suggests an approach for this NERC Reliability Standard (“standard” or “PRC-026-1”) which is
consistent with addressing two of the three regulatory directives in the FERC Order No. 733. The
first directive concerns the need for “…protective relay systems that differentiate between faults
and stable power swings and, when necessary, phases out protective relay systems that cannot meet
this requirement.” 5 Second, is “…to develop a Reliability Standard addressing undesirable relay
operation due to stable power swings.” 6 The third directive “…to consider “islanding” strategies
that achieve the fundamental performance for all islands in developing the new Reliability
Standard addressing stable power swings” 7 was considered during development of the standard.
The development of this standard implements the majority of the approaches suggested by the
report. However, it is noted that the Reliability Coordinator and Transmission Planner have not
been included in the standard’s Applicability section (as suggested by the PSRPS Report). This is
so that a single entity, the Planning Coordinator, may be the single source for identifying Elements
according to Requirement R1. A single source will insure that multiple entities will not identify
Elements in duplicate, nor will one entity fail to provide an Element because it believes the
Element is being provided by another entity. The Planning Coordinator has, or has access to, the
wide-area model and can correctly identify the Elements that may be susceptible to a stable or
unstable power swing. Additionally, not including the Reliability Coordinator and Transmission
Planner is consistent with the applicability of other relay loadability NERC Reliability Standards
(e.g., PRC-023 and PRC-025). It is also consistent with the NERC Functional Model.
The phrase, “while maintaining dependable fault detection and dependable out-of-step tripping”
in Requirement R2, describes that the Generator Owner and Transmission Owner is to comply
with this standard, while achieving its desired protection goals. Load-responsive protective relays,
as addressed within this standard, may be intended to provide a variety of backup protection
functions, both within the generating unit or generating plant and on the transmission system, and
4
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
5
Transmission Relay Loadability Reliability Standard, Order No. 733, P.150 FERC ¶ 61,221 (2010).
6
Ibid. P.153.
7
Ibid. P.162.
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this standard is not intended to result in the loss of these protection functions. Instead, it is
suggested that the Generator Owner and Transmission Owner consider both the Requirements
within this standard and its desired protection goals, and perform modifications to its protective
relays or protection philosophies as necessary to achieve both.
Power Swings
The IEEE Power System Relaying Committee WG D6 developed a technical document called
Power Swing and Out-of-Step Considerations on Transmission Lines (July 2005) that provides
background on power swings. The following are general definitions from that document: 8
Power Swing: a variation in three phase power flow which occurs when the generator rotor
angles are advancing or retarding relative to each other in response to changes in load
magnitude and direction, line switching, loss of generation, faults, and other system
disturbances.
Pole Slip: a condition whereby a generator, or group of generators, terminal voltage angles
(or phases) go past 180 degrees with respect to the rest of the connected power system.
Stable Power Swing: a power swing is considered stable if the generators do not slip poles
and the system reaches a new state of equilibrium, i.e. an acceptable operating condition.
Unstable Power Swing: a power swing that will result in a generator or group of generators
experiencing pole slipping for which some corrective action must be taken.
Out-of-Step Condition: Same as an unstable power swing.
Electrical System Center or Voltage Zero: it is the point or points in the system where the
voltage becomes zero during an unstable power swing.
Burden to Entities
The PSRPS Report provides a technical basis and approach for focusing on Protection Systems,
which are susceptible to power swings, while achieving the purpose of the standard. The approach
reduces the number of relays to which the PRC-026-1 Requirements would apply by first
identifying the BES Element(s) on which load-responsive protective relays must be evaluated. The
first step uses criteria to identify the Elements on which a Protection System is expected to be
challenged by power swings. Of those Elements, the second step is to evaluate each loadresponsive protective relay that is applied on each identified Element. Rather than requiring the
Planning Coordinator or Transmission Planner to perform simulations to obtain information for
each identified Element, the Generator Owner and Transmission Owner will reduce the need for
simulation by comparing the load-responsive protective relay characteristic to specific criteria in
PRC-026-1 – Attachment B.
8
http://www.pes-psrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission
%20Lines%20F..pdf.
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Applicability
The standard is applicable to the Generator Owner, Planning Coordinator, and Transmission
Owner entities. More specifically, the Generator Owner and Transmission Owner entities are
applicable when applying load-responsive protective relays at the terminals of the applicable BES
Elements. The standard is applicable to the following BES Elements: generators, transformers, and
transmission lines. The Distribution Provider was considered for inclusion in the standard;
however, it is not subject to the standard because this entity, by functional registration, would not
own generators, transmission lines, or transformers other than load serving.
Load-responsive protective relays include any protective functions which could trip with or
without time delay, on load current.
Requirement R1
The Planning Coordinator has a wide-area view and is in the positon to identify what, if any,
Elements meet the criteria. The criterion-based approach is consistent with the NERC System
Protection and Control Subcommittee (SPCS) technical document Protection System Response to
Power Swings (August 2013), 9 which recommends a focused approach to determine an at-risk
Element. Identification of Elements comes from the annual Planning Assessments pursuant to the
transmission planning (i.e., “TPL”) and other NERC Reliability Standards (e.g., PRC-006), and
the standard is not requiring any other assessments to be performed by the Planning Coordinator.
The required notification on a calendar year basis to the respective Generator Owner and
Transmission Owner is sufficient because it is expected that the Planning Coordinator will make
its notifications following the completion of its annual Planning Assessments. The Planning
Coordinator will continue to provide notification of Elements on a calendar year basis even if a
study is performed less frequently (e.g., PRC-006 – Automatic Underfrequency Load Shedding,
which is five years) and has not changed. It is possible that the Planning Coordinator provided
notification of Elements in two different calendar years using the same annual Planning
Assessment.
Criterion 1
The first criterion involves generator(s) where an angular stability constraint exists that is
addressed by a System Operating Limit (SOL) or a Remedial Action Scheme (RAS) and those
Elements terminating at the Transmission station associated with the generator(s). For example, a
scheme to remove generation for specific conditions is implemented for a four-unit generating
plant (1,100 MW). Two of the units are 500 MW each; one is connected to the 345 kV system and
one is connected to the 230 kV system. The Transmission Owner has two 230 kV transmission
lines and one 345 kV transmission line all terminating at the generating facility as well as a 345/230
kV autotransformer. The remaining 100 MW consists of two 50 MW combustion turbine (CT)
units connected to four 66 kV transmission lines. The 66 kV transmission line is not electrically
joined to the 345 kV and 230 kV transmission lines at the plant site and is not a part of the operating
9
http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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limit or RAS. A stability constraint limits the output of the portion of the plant affected by the RAS
to 700 MW for an outage of the 345 kV transmission line. The RAS trips one of the 500 MW units
to maintain stability for a loss of the 345 kV transmission line when the total output from both 500
MW units is above 700 MW. For this example, both 500 MW generating units and the associated
generator step-up (GSU) transformers would be identified as Elements meeting this criterion. The
345/230 kV autotransformer, the 345 kV transmission line, and the two 230 kV transmission lines
would also be identified as Elements meeting this criterion. The 50 MW combustion turbines and
66 kV transmission lines would not be identified pursuant to Criterion 1 because these Elements
are not subject to an operating limit or RAS and do not terminate at the Transmission station
associated with the generators that are subject to the SOL or RAS.
Criterion 2
The second criterion involves Elements that are monitored as a part of an established System
Operating Limit (SOL) based on an angular stability limit regardless of the outage conditions that
result in the enforcement of the SOL. For example, if two long parallel 500 kV transmission lines
have a combined SOL of 1,200 MW, and this limit is based on angular instability resulting from a
fault and subsequent loss of one of the two lines, then both lines would be identified as an Element
meeting the criterion.
Criterion 3
The third criterion involves Elements that form the boundary of an island within an underfrequency
load shedding (UFLS) design assessment. The criterion applies to islands identified based on
application of the Planning Coordinator’s criteria for identifying islands, where the island is
formed by tripping the Elements based on angular instability. The criterion applies if the angular
instability is modeled in the UFLS design assessment, or if the boundary is identified “off-line”
(i.e., the Elements are selected based on angular instability considerations, but the Elements are
tripped in the UFLS design assessment without modeling the initiating angular instability). In cases
where an out-of-step condition is detected and tripping is initiated at an alternate location, the
criterion applies to the Element on which the power swing is detected. The criterion does not apply
to islands identified based on other considerations that do not involve angular instability, such as
excessive loading.
Criterion 4
The fourth criterion involves Elements identified in the most recent annual Planning Assessment
where relay tripping occurs due to a stable or unstable power swing during a simulated disturbance.
The intent is for the Planning Coordinator to include any Element(s) where relay tripping was
observed during simulations performed for the most recent annual Planning Assessment associated
with the transmission planning TPL-001-4 Reliability Standard. Note that relay tripping must be
assessed within those annual Planning Assessments per TPL-001-4, R4, Part 4.3.1.3, which
indicates that analysis shall include the “Tripping of Transmission lines and transformers where
transient swings cause Protection System operation based on generic or actual relay models.”
Identifying such Elements according to Criterion 4 and notifying the respective Generator Owner
and Transmission Owner will require that the owners of any load-responsive protective relay
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PRC-026-1 – Application Guidelines
applied at the terminals of the identified Element evaluate the relay’s susceptibility to tripping in
response a stable power swing.
Planning Coordinators have discretion to determine whether observed tripping for a power swing
in its Planning Assessments occurs for valid contingencies and system conditions. The Planning
Coordinator will address tripping that is observed in transient analyses on an individual basis;
therefore, the Planning Coordinator is responsible for identifying the Elements based only on
simulation results that are determined to be valid.
Due to the nature of how a Planning Assessment is performed, there may be cases where a
previously-identified Element is not identified in the most recent annual Planning Assessment. If
so, this is acceptable because the Generator Owner and Transmission Owner would have taken
action upon the initial notification of the previously identified Element. When an Element is not
identified in later Planning Assessments, the risk of load-responsive protective relays tripping in
response to a stable power swing during non-Fault conditions would have already been assessed
under Requirement R2 and mitigated according to Requirements R3 and R4 where the relays did
not meet the PRC-026-1 – Attachment B criteria. According to Requirement R2, the Generator
Owner and Transmission Owner are only required to re-evaluate each load-responsive protective
relay for an identified Element where the evaluation has not been performed in the last five
calendar years.
Although Requirement R1 requires the Planning Coordinator to notify the respective Generator
Owner and Transmission Owner of any Elements meeting one or more of the four criteria, it does
not preclude the Planning Coordinator from providing additional information, such as apparent
impedance characteristics, in advance or upon request, that may be useful in evaluating protective
relays. Generator Owners and Transmission Owners are able to complete protective relay
evaluations and perform the required actions without additional information. The standard does
not include any requirement for the entities to provide information that is already being shared or
exchanged between entities for operating needs. While a Requirement has not been included for
the exchange of information, entities should recognize that relay performance needs to be
measured against the most current information.
Requirement R2
Requirement R2 requires the Generator Owner and Transmission Owner to evaluate its loadresponsive protective relays to ensure that they are expected to not trip in response to stable power
swings.
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The PRC-026-1 – Attachment A lists the applicable load-responsive relays that must be evaluated.
These relays include phase distance, phase overcurrent, out-of-step tripping, and loss-of-field.
Phase distance relays can include the following:
•
•
Mho element characteristics such as Zone 1, Zone 2, or Zone 3 with intentional time delays
of 15 cycles or less.
Mho element characteristics that overreach the remote line terminal used in high-speed,
communications assisted tripping schemes including:
Directional Comparison Blocking (DCB) schemes
Directional Comparison Un-Blocking (DCUB) schemes
Permissive Overreach Transfer Trip (POTT) schemes
A method is provided within the standard to support consistent evaluation by Generator Owners
and Transmission Owners based on specified conditions. Once a Generator Owner or Transmission
Owner is notified of Elements pursuant to Requirement R1, it has 12 full calendar months to
determine if each Element’s load-responsive protective relays meet the applicable PRC-026-1 –
Attachment B criteria, if the determination has not been performed in the last five calendar years.
Additionally, each Generator Owner and Transmission Owner, that becomes aware of a generator,
transformer, or transmission line BES Element that tripped in response to a stable or unstable
power swing due to the operation of its protective relays, must perform the same PRC-026-1 –
Attachment B criteria determination within 12 full calendar months.
Becoming Aware of an Element That Tripped in Response to a Power Swing
Part 2.2 in Requirement R2 is intended to initiate action by the Generator Owner and Transmission
Owner when there is a known stable or unstable power swing and it resulted in the entity’s Element
tripping. The criterion starts with becoming aware of the event (i.e., power swing) and then any
connection with the entity’s Element tripping. By doing so, the focus is removed from the entity
having to demonstrate that it performed a power swing analysis for every Element trip. The basis
for structuring the criterion in this manner is driven by the available ways that a Generator Owner
and Transmission Owner could become aware of an Element that tripped in response to a stable or
unstable power swing due to the operation of its protective relay(s).
Element trips caused by stable or unstable power swings, though infrequent, would be more
common in a larger event. The identification of power swings will be revealed during an analysis
of the event. Event analysis could include internal analysis conducted by the entity, the entity’s
Protection System review following a trip, or a larger scale analysis which includes involvement
by the entity’s Regional Entity and in some cases NERC.
Information Common to Both Generation and Transmission Elements
The PRC-026-1 – Attachment A lists the load-responsive protective relays that are subject to this
standard. Generator Owners and Transmission Owners may own load-responsive protective relays
(i.e., distance relays) that directly affect generation or transmission BES Elements and will require
analysis as a result of Elements being identified by the Planning Coordinator in Requirement R1
or the Generator Owner or Transmission Owner in Requirement R2. For example, distance relays
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owned by the Transmission Owner may be installed at the high-voltage side of the generator stepup (GSU) transformer (directional toward the generator) providing backup to generation
protection. Generator Owners may have distance relays applied to backup transmission protection
or backup protection to the GSU transformer. The Generator Owner may have relays installed at
the generator terminals or the high-voltage side of the GSU transformer.
Exclusion of Time Based Load-Responsive Protective Relays
The purpose of the standard is “[t]o ensure that load-responsive protective relays are expected to
not trip in response to stable power swings during non-Fault conditions.” Load-responsive, highspeed tripping protective relays pose the highest risk of operating during a power swing. Because
of this, high-speed tripping protective relays and relays with a time delay of less than 15 cycles are
included in the standard; whereas other relays (i.e., Zones 2 and 3) with a time a delay of 15 cycles
or greater are excluded. The time delay used for exclusion on some load-responsive protective
relays is recommended based on 1) the minimum time delay these relays are set in practice, and 2)
the maximum expected time that load-responsive protective relays would be exposed to a stable
power swing based on a swing rate.
In order to establish a time delay that distinguishes a high-risk load-responsive protective relay
from one that has a time delay for tripping (lower-risk), a sample of swing rates were calculated
based on a stable power swing entering and leaving the impedance characteristic as shown in Table
1. For a relay impedance characteristic that has the power swing entering and leaving beginning at
90 degrees with a termination at 120 degrees before exiting the zone, calculation of the timer must
be greater than the time the stable swing is inside the relay operate zone.
Eq. (1)
(120° − 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑜𝑜𝑜𝑜 𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒 𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖 𝑡𝑡ℎ𝑒𝑒 𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟 𝑐𝑐ℎ𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎) × 60
𝑍𝑍𝑍𝑍𝑍𝑍𝑍𝑍 𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 > 2 × �
�
(360 × 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅)
Table 1. Swing Rates
Zone Timer
Slip Rate
(Cycles)
(Hz)
10
1.00
15
0.67
20
0.50
30
0.33
With a minimum zone timer of 15 cycles, the corresponding slip of the system is 0.67 Hz. This
represents an approximation of a slow slip rate during a system Disturbance. Consequently, this
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value corresponds to the typical minimum time delay used for Zone 2 distance relays in
transmission line protection. Longer time delays allow for slower slip rates.
Application to Transmission Elements
Criteria A in PRC-026-1 – Attachment B describes an unstable power swing region that is formed
by the union of three shapes in the impedance (R-X) plane. The first shape is a lower loss of
synchronism circle based on a ratio of the sending-end to receiving-end voltages of 0.7 (i.e., E S /
E R = 0.7 / 1.0 = 0.7). The second shape is an upper loss of synchronism circle based on a ratio of
the receiving-end to sending-end voltages of 1.43 (i.e., E R / E S = 1.0 / 0.7 = 1.43). The third shape
is a lens that connects the endpoints of the total system impedance together by varying the sendingend and receiving-end system voltages from 0.0 to 1.0 per unit, while maintaining a constant
system separation angle across the total system impedance (with the parallel transfer impedance
removed—see Figures 1 through 5). The total system impedance is derived from a two-bus
equivalent network and is determined by summing the sending-end source impedance, the line
impedance (excluding the Thévenin equivalent transfer impedance), and the receiving-end source
impedance as shown in Figures 6 and 7. The goal in establishing the total system impedance is to
represent a conservative condition that will maximize the security of the relay against various
system conditions. The smallest total system impedance represents a condition where the size of
the lens characteristic in the R-X plane is smallest and is a conservative operating point from the
standpoint of ensuring a load-responsive protective relay is expected to not trip given a
predetermined angular displacement between the sending-end and receiving-end voltages. The
smallest total system impedance results when all generation is in service and all transmission BES
Elements are modeled in their “normal” system configuration (PRC-026-1 – Attachment B,
Criteria A). The parallel transfer impedance is removed to represent a likely condition where
parallel elements may be lost during the disturbance, and the loss of these elements magnifies the
sensitivity of the load-responsive relays on the parallel line by removing the “infeed effect” (i.e.,
the apparent impedance sensed by the relay is decreased as a result of the loss of the transfer
impedance, thus making the relay more likely to trip for a stable power swing—See Figures 13
and 14).
The sending-end and receiving-end source voltages are varied from 0.7 to 1.0 per unit to form the
lower and upper loss of synchronism circles. The ratio of these two voltages is used in the
calculation of the loss of synchronism circles, and result in a ratio range from 0.7 to 1.43.
Eq. (2)
𝐸𝐸𝑆𝑆 0.7
=
= 0.7
𝐸𝐸𝑅𝑅 1.0
Eq. (3):
𝐸𝐸𝑅𝑅 1.0
=
= 1.43
𝐸𝐸𝑆𝑆 0.7
The internal generator voltage during severe power swings or transmission system fault conditions
will be greater than zero, due to voltage regulator support. The voltage ratio of 0.7 to 1.43 is chosen
to be more conservative than the PRC-023 10 and PRC-025 11 NERC Reliability Standards, where
a lower bound voltage of 0.85 per unit voltage is used. A ±15% internal generator voltage range
10
Transmission Relay Loadability
11
Generator Relay Loadability
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was chosen as a conservative voltage range for calculation of the voltage ratio used to calculate
the loss of synchronism circles. For example, the voltage ratio using these voltages would result
in a ratio range from 0.739 to 1.353.
Eq. (4)
𝐸𝐸𝑆𝑆 0.85
=
= 0.739
𝐸𝐸𝑅𝑅 1.15
Eq. (5):
𝐸𝐸𝑅𝑅 1.15
=
= 1.353
𝐸𝐸𝑆𝑆 0.85
The lower ratio is rounded down to 0.7 to be more conservative, allowing a voltage range of 0.7
to 1.0 per unit to be used for the calculation of the loss of synchronism circles. 12
When the parallel transfer impedance is included in the model, the split in current through the
parallel transfer impedance path results in actual measured relay impedances that are larger than
those measured when the parallel transfer impedance is removed (i.e., infeed effect), which would
make it more likely for an impedance relay element to be completely contained within the unstable
power swing region in Figure 11. If the transfer impedance is included in the evaluation, a distance
relay element could be deemed as meeting PRC-026-1 – Attachment B and, in fact would be
secure, assuming all elements were in their normal state. In this case, the distance relay element
could trip for a stable power swing during an actual event if the system was weakened (i.e., a
higher transfer impedance) by the loss of a subset of lines that make up the parallel transfer
impedance. This could happen because the subset of lines that make up the parallel transfer
impedance tripped on unstable swings, contained the initiating fault, and/or were lost due to
operation of breaker failure or remote back-up protection schemes in Figure 10.
Table 10 shows the percent size increase of the lens shape as seen by the relay under evaluation
when the parallel transfer impedance is included. The parallel transfer impedance has minimal
effect on the apparent size of the lens shape as long as the parallel transfer impedance is at least
10 multiples of the parallel line impedance (less than 5% lens shape expansion), therefore, its
removal has minimal impact, but results in a slightly more conservative, smaller lens shape.
Transfer impedances of 5 multiples of the parallel line impedance or less result in an apparent lens
shape size of 10% or greater as seen by the relay. If two parallel lines and a parallel transfer
impedance tie the sending-end and receiving-end buses together, the total parallel transfer
impedance will be one or less multiples of the parallel line impedance, resulting in an apparent
lens shape size of 45% or greater. It is a realistic contingency that the parallel line could be outof-service, leaving the transfer impedance making up the rest of the system in parallel with the line
impedance. Since it is not known exactly which lines making up the parallel transfer impedance
that will be out of service during a major system disturbance, it is most conservative to assume
that all of them are out, leaving just the line under evaluation in service.
Either the saturated transient or sub-transient direct axis reactance values may be used for machines
in the evaluation because they are smaller than un-saturated reactance values. Since sub-transient
saturated generator reactances are smaller than the transient or synchronous reactance, they result
in a smaller source impedance and a smaller unstable power swing region in the graphical analysis
12
Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations,
April 2004, Section 6 (The Cascade Stage of the Blackout), p. 94 under “Why the Generators Tripped Off,” states,
“Some generator undervoltage relays were set to trip at or above 90% voltage. However, a motor stalls out at about
70% voltage and a motor starter contactor drops out around 75%, so if there is a compelling need to protect the
turbine from the system the under-voltage trigger point should be no higher than 80%.”
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as shown in Figures 8 and 9. Since power swings occur in a time frame where generator transient
reactances will be prevalent, it is acceptable to use saturated transient reactances instead of
saturated sub-transient reactance values. Some short-circuit models may not include transient
reactance values, so in this case, the use of sub-transient is acceptable because it also produces
more conservative results than transient reactances. For this reason, either value is acceptable when
determining the system source impedances (PRC-026-1 – Attachment B, Criteria A and B, No. 3).
Saturated reactance values are also the values used in short-circuit programs that produce the
system impedance mentioned above. Planning and stability software generally use the un-saturated
reactance values. Generator models used in transient stability analyses recognize that the extent of
the saturation effect depends upon both rotor (field) and stator currents. Accordingly, they derive
the effective saturated parameters of the machine at each instant by internal calculation from the
specified (constant) unsaturated values of machine reactances and the instantaneous internal flux
level. The specific assumptions regarding which inductances are affected by saturation, and the
relative effect of that saturation, are different for the various generator models used. Thus,
unsaturated values of all machine reactances are used in setting up planning and stability software
data, and the appropriate set of open-circuit magnetization curve data is provided for each machine.
Saturated reactance values are smaller than unsaturated reactance values and are used in shortcircuit programs owned by the Generator and Transmission Owners. Because of this, saturated
reactance values are to be used in the development of the system source impedances.
The source or system equivalent impedances can be obtained by a number of different methods
using commercially available short-circuit calculation tools. 13 Most short-circuit tools have a
network reduction feature that allows the user to select the local and remote terminal buses to
retain. The first method reduces the system to one that contains two buses, an equivalent generator
at each bus (representing the source impedance at the sending-end and receiving-ends), and two
parallel lines; one being the line impedance of the protected line with relays being analyzed, the
other being the transfer impedance representing all other combinations of lines that connect the
two buses together as shown in Figure 6. Another conservative method is to open both ends of the
line in question, and apply a three-phase bolted fault at each bus. The resulting source impedance
at each end will be less than or equal to the actual source impedance calculated by the network
reduction method. Either method can be used to develop the system source impedances at both
ends.
The two bullets of PRC-026-1 – Attachment B, Criteria A, No. 1, identify the system separation
angles to identify the size of the power swing stability boundary to be used to test load-responsive
protective relay impedance elements. Both bullets test impedance relay elements that are not
supervised by power swing blocking (PSB). The first bullet of PRC-026-1 – Attachment B, Criteria
A, No. 1 evaluates a system separation angle of at least 120 degrees that is held constant while
varying the sending-end and receiving-end source voltages from 0.7 to 1.0 per unit, thus creating
an unstable power swing region about the total system impedance in Figure 1. This unstable power
swing region is compared to the tripping portion of the distance relay characteristic; that is, the
portion that is not supervised by load encroachment, blinders, or some other form of supervision
as shown in Figure 12 that restricts the distance element from tripping for heavy, balanced load
13
Demetrios A. Tziouvaras and Daqing Hou, Appendix in Out-Of-Step Protection Fundamentals and
Advancements, April 17, 2014: https://www.selinc.com.
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conditions. If the tripping portion of the impedance characteristics are completely contained within
the unstable power swing region, the relay impedance element meets Criteria A in PRC-026-1 –
Attachment B. A system separation angle of 120 degrees was chosen for the evaluation where PSB
is not applied because it is generally accepted in the industry that recovery for a swing beyond this
angle is unlikely to occur. 14
The second bullet of PRC-026-1 – Attachment B, Criteria A, No. 1 evaluates impedance relay
elements at a system separation angle of less than 120 degrees, similar to the first bullet described
above. An angle less than 120 degrees may be used if a documented stability analysis demonstrates
that the power swing becomes unstable at a system separation angle of less than 120 degrees.
The exclusion of relay elements supervised by PSB in PRC-026-1 – Attachment A allows the
Generator Owner or Transmission Owner to exclude protective relay elements if they are blocked
from tripping by PSB relays. A PSB relay applied and set according to industry accepted practices
prevent supervised load-responsive protective relays from tripping in response to power swings.
Further, PSB relays are set to allow dependable tripping of supervised elements. The criteria in
PRC-026-1 – Attachment B specifically applies to unsupervised elements that could trip for stable
power swings. Therefore, load-responsive protective relay elements supervised by PSB can be
excluded from the Requirements of this standard.
14
“The critical angle for maintaining stability will vary depending on the contingency and the system condition at
the time the contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is
marginal and 120 degrees is generally accepted as an appropriate basis for setting out‐of‐step protection. Given the
importance of separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a
proper balance between dependable tripping for unstable power swings and secure operation for stable power
swings.” NERC System Protection and Control Subcommittee, Protection System Response to Power Swings,
August 2013: http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20
SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf), p. 28.
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Figure 1. An enlarged graphic illustrating the unstable power swing region formed by the union
of three shapes in the impedance (R-X) plane: Shape 1) Lower loss of synchronism circle, Shape
2) Upper loss of synchronism circle, and Shape 3) Lens. The mho element characteristic is
completely contained within the unstable power swing region (e.g., it does not intersect any
portion of the unstable power swing region), therefore it complies with PRC-026-1 – Attachment
B, Criteria A, No. 1.
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Figure 2. Full graphic of unstable power swing region formed by the union of three shapes in
the impedance (R-X) plane: Shape 1) Lower loss of synchronism circle, Shape 2) Upper loss of
synchronism circle, and Shape 3) Lens. The mho element characteristic is completely contained
within the unstable power swing region, therefore it meets PRC-26-1 – Attachment B, Criteria
A, No.1.
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Figure 3. System impedance as seen by relay R.
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Figure 4. The defining unstable power swing region points where the lens shape intersects the
lower and upper loss of synchronism circle shapes and where the lens intersects the equal EMF
(electromotive force) power swing.
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Figure 5. Full table of 31 detailed lens shape point calculations. The bold highlighted rows
correspond to the detailed calculations in Tables 2-7.
Table 2. Example Calculation (Lens Point 1)
This example is for calculating the impedance the first point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) leading
the receiving-end voltage (E R ) by 120 degrees. See Figures 3 and 4.
Eq. (6)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
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Table 2. Example Calculation (Lens Point 1)
Eq. (7)
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (8)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (9)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (10)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50 )Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,511∠71.3° 𝐴𝐴
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
Eq. (11)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴
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Table 2. Example Calculation (Lens Point 1)
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (12)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10) Ω × 4,511∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,757∠106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (13)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,757∠106.1° 𝑉𝑉
4,511∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 17.434 + 𝑗𝑗12.113 Ω
Table 3. Example Calculation (Lens Point 2)
This example is for calculating the impedance second point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) at 70% of
the receiving-end voltage (E R ) and leading the receiving-end voltage by 120 degrees. See
Figures 3 and 4.
Eq. (14)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (15)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
× 70%
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 92,953.7∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
× 0.70
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (16)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
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Table 3. Example Calculation (Lens Point 2)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (17)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (18)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
92,953.7∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠77° 𝐴𝐴
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (19)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿 = 3,854∠77° 𝐴𝐴 ×
𝐼𝐼𝐿𝐿 = 3,854∠77° 𝐴𝐴
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (20)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 92,953∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 )Ω × 3,854∠77° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 65,271∠99° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (21)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
65,271∠99° 𝑉𝑉
3,854∠77° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 15.676 + 𝑗𝑗6.41 Ω
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Table 4. Example Calculation (Lens Point 3)
This example is for calculating the impedance third point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (E R ) at 70%
of the sending-end voltage (E S ) and the sending-end voltage leading the receiving-end voltage
by 120 degrees. See Figures 3 and 4.
Eq. (22)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (23)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
× 70%
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 92,953.7∠0° 𝑉𝑉
× 0.70
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (24)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (25)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (26)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 92,953.7∠0° 𝑉𝑉
(10 + 𝑗𝑗50) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠65.5° 𝐴𝐴
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Table 4. Example Calculation (Lens Point 3)
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (27)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠65.5° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠65.5° 𝐴𝐴
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (28)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10) Ω × 3,854∠65.5° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 98,265∠110.6° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (29)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
98,265∠110.6° 𝑉𝑉
3,854∠65.5° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 18.005 + 𝑗𝑗18.054 Ω
Table 5. Example Calculation (Lens Point 4)
This example is for calculating the impedance fourth point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) leading
the receiving-end voltage (E R ) by 240 degrees. See Figures 3 and 4.
Eq. (30)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (31)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠240° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
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Table 5. Example Calculation (Lens Point 4)
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (32)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (33)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (34)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠240° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50 )Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,510∠131.3° 𝐴𝐴
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (35)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,510∠131.1° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,510∠131.1° 𝐴𝐴
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (36)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 ) Ω × 4,510∠131.1° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,756∠ − 106.1° 𝑉𝑉
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Table 5. Example Calculation (Lens Point 4)
The impedance seen by the relay on Z L .
Eq. (37)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,756∠ − 106.1° 𝑉𝑉
4,510∠131.1° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −11.434 + 𝑗𝑗17.887 Ω
Table 6. Example Calculation (Lens Point 5)
This example is for calculating the impedance fifth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) at 70% of
the receiving-end voltage (E R ) and leading the receiving-end voltage by 240 degrees. See
Figures 3 and 4.
Eq. (38)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (39)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
× 70%
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 92,953.7∠240° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
× 0.70
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (40)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (41)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
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Table 6. Example Calculation (Lens Point 5)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10 Ω) + (4 + 𝑗𝑗20 Ω) + (4 + 𝑗𝑗20 Ω)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (42)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
92,953.7∠240° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠125.5° 𝐴𝐴
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
Eq. (43)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠125.5° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠125.5° 𝐴𝐴
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (44)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 92,953.7∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 ) Ω × 3,854∠125.5° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 65,270.5∠ − 99.4° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (45)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
65,270.5∠ − 99.4° 𝑉𝑉
3,854∠125.5° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −12.005 + 𝑗𝑗11.946 Ω
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Table 7. Example Calculation (Lens Point 6)
This example is for calculating the impedance sixth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (E R ) at 70%
of the sending-end voltage (E S ) and the sending-end voltage leading the receiving-end voltage
by 240 degrees. See Figures 3 and 4.
Eq. (46)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠240° 𝑉𝑉
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
Eq. (47)
𝐸𝐸𝑅𝑅 =
× 70%
√3
230,000∠0° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
× 0.70
√3
𝐸𝐸𝑅𝑅 = 92,953.7∠0° 𝑉𝑉
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Given:
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
Total impedance between generators.
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
Eq. (48)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
Eq. (49)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
Eq. (50)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠240° 𝑉𝑉 − 92,953.7∠0° 𝑉𝑉
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠137.1° 𝐴𝐴
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Table 7. Example Calculation (Lens Point 6)
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
𝑍𝑍𝑇𝑇𝑇𝑇
Eq. (51)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠137.1° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠137.1° 𝐴𝐴
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (52)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 )Ω × 3,854∠137.1° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 98,265∠ − 110.6° 𝑉𝑉
The impedance seen by the relay on Z L .
𝑉𝑉𝑆𝑆
Eq. (53)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝐼𝐼𝐿𝐿
98,265∠ − 110.6° 𝑉𝑉
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
3,854∠137.1° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −9.676 + 𝑗𝑗23.59 Ω
Figure 6. Reduced two bus system with sending-end source impedance Z S , receiving-end
source impedance Z R , line impedance Z L , and transfer impedance Z TR .
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Figure 7. Reduced two bus system with sending-end source impedance Z S , receiving-end
source impedance Z R , line impedance Z L , and transfer impedance Z TR removed.
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Figure 8. A strong-source system with a line impedance of Z L = 20.4 ohms (i.e., the thicker red
line). This mho element characteristic (i.e., the blue circle) does not meet the PRC-026-1 –
Attachment B, Criteria A because it is not completely contained within the unstable power swing
region (i.e., the orange characteristic).
The figure above represents a heavy-loaded system using a maximum generation profile. The mho
element characteristic (set at 137% of Z L ) extends into the unstable power swing region (i.e., the
orange characteristic). Using the strongest source system is more conservative because it shrinks
the unstable power swing region, bringing it closer to the mho element characteristic. This figure
also graphically represents the effect of a system strengthening over time and this is the reason for
re-evaluation if the relay has not been evaluated in the last five calendar years. Figure 9 below
depicts a relay that meets the PRC-026-1 – Attachment B, Criteria A. Figure 8 depicts the same
relay with the same setting five years later, where each source has strengthened by about 10% and
now the same mho element characteristic does not meet Criteria A.
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Figure 9. A weak-source system with a line impedance of Z L = 20.4 ohms (i.e., the thicker red
line). This mho element characteristic (i.e., the blue circle) meets the PRC-026-1 – Attachment
B, Criteria A because it is completely contained within the unstable power swing region (i.e.,
the orange characteristic).
The figure above represents a lightly loaded system, using a minimum generation profile. The mho
element characteristic (set at 137% of Z L ) does not extend into the unstable power swing region
(i.e., the orange characteristic). Using a weaker source system expands the unstable power swing
region away from the mho element characteristic.
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PRC-026-1 – Application Guidelines
Figure 10. This is an example of an unstable power swing region (i.e., the orange characteristic)
with the transfer impedance removed. This relay mho element characteristic (i.e., the blue circle)
does not meet PRC-026-1 – Attachment B, Criteria A because it is not completely contained
within the unstable power swing region.
Table 8. Example Calculation (Transfer Impedance Removed)
Calculations for the point at 120 degrees with equal source impedances. The total system current
equals the line current. See Figure 10.
Eq. (54)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
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Table 8. Example Calculation (Transfer Impedance Removed)
Eq. (55)
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given impedance data.
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (56)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (57)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (58)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,511∠71.3° 𝐴𝐴
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
Eq. (59)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴 ×
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
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Table 8. Example Calculation (Transfer Impedance Removed)
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (60)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 Ω) × 4,511∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,757∠106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (61)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,757∠106.1° 𝑉𝑉
4,511∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 17.434 + 𝑗𝑗12.113 Ω
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Figure 11. This is an example of an unstable power swing region (i.e., the orange characteristic)
with the transfer impedance included. The mho element characteristic (i.e., the blue circle) meets
the PRC-026-1 – Attachment B, Criteria A because it is completely contained within the
unstable power swing region. However, including the transfer impedance in the calculation is
not compliant with PRC-026-1 – Attachment B Criteria A.
In the figure above, the transfer impedance is 5 times the line impedance. The unstable power
swing region has expanded out beyond the mho element characteristic due to the infeed effect from
the parallel current through the transfer impedance, thus allowing the mho element characteristic
to meet PRC-026-1 – Attachment B, Criteria A. However, including the transfer impedance in the
calculation is not compliant with PRC-026-1 – Attachment B Criteria A.
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Table 9. Example Calculation (Transfer Impedance Included)
Calculations for the point at 120 degrees with equal source impedances. The total system current
does not equal the line current. See Figure 11.
Eq. (62)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (63)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given impedance data.
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 5
𝑍𝑍𝑇𝑇𝑇𝑇 = (4 + 𝑗𝑗20) Ω × 5
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 20 + 𝑗𝑗100 Ω
Total impedance between generators.
Eq. (64)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
(4 + 𝑗𝑗20) Ω × (20 + 𝑗𝑗100) Ω
(4 + 𝑗𝑗20) Ω + (20 + 𝑗𝑗100) Ω
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 3.333 + 𝑗𝑗16.667 Ω
Total system impedance.
Eq. (65)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (3.333 + 𝑗𝑗16.667) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 9.333 + 𝑗𝑗46.667 Ω
Total system current from sending-end source.
Eq. (66)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
9.333 + 𝑗𝑗46.667 Ω
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Table 9. Example Calculation (Transfer Impedance Included)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,832∠71.3° 𝐴𝐴
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
Eq. (67)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿 = 4,832∠71.3° 𝐴𝐴 ×
𝐼𝐼𝐿𝐿 = 4,027.4∠71.3° 𝐴𝐴
(20 + 𝑗𝑗100) Ω
(9.333 + 𝑗𝑗46.667) Ω + (20 + 𝑗𝑗100) Ω
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (68)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 Ω) × 4,027∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 93,417∠104.7° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (69)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
93,417∠104.7° 𝑉𝑉
4,027∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 19.366 + 𝑗𝑗12.767 Ω
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Table 10. Percent Increase of a Lens Due To Parallel Transfer Impedance.
The following demonstrates the percent size increase of the lens characteristic for Z TR in
multiples of Z L with the transfer impedance included.
Z TR in multiples of Z L
Percent increase of lens with equal EMF
sources (Infinite source as reference)
Infinite
N/A
1000
0.05%
100
0.46%
10
4.63%
5
9.27%
2
23.26%
1
46.76%
0.5
94.14%
0.25
189.56%
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Figure 12. The tripping portion not blocked by load encroachment (i.e., the parallel green lines)
of the mho element characteristic (i.e., the blue circle) is completely contained within the
unstable power swing region (i.e., the orange characteristic). Therefore, the mho element
characteristic meets the PRC-026-1 – Attachment B, Criteria A.
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Figure 13: The infeed diagram shows the impedance in front of the relay R with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes Z L + Z R .
Table 11. Calculations (System Apparent Impedance in the forward direction)
The following equations are provided for calculating the apparent impedance back to the E R
source voltage as seen by relay R. Infeed equations from V S to source E R where E R = 0. See
Figure 13.
Eq. (70)
Eq. (71)
Eq. (72)
Eq. (73)
Eq. (74)
Eq. (75)
Eq. (76)
Eq. (77)
Eq. (78)
Eq. (79)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑆𝑆 − 𝑉𝑉𝑅𝑅
𝑍𝑍𝐿𝐿
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑅𝑅 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑅𝑅
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝐿𝐿 =
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅
𝑍𝑍𝑅𝑅
Since 𝐸𝐸𝑅𝑅 = 0
Rearranged:
𝑉𝑉𝑆𝑆 − 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑅𝑅
𝑍𝑍𝐿𝐿
𝑉𝑉𝑅𝑅 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑅𝑅
𝑉𝑉𝑆𝑆 − [(𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇 ) × 𝑍𝑍𝑅𝑅 ]
𝑍𝑍𝐿𝐿
𝑉𝑉𝑆𝑆 = (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝐿𝐿 ) + (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝑅𝑅 ) + (𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅 )
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅
𝐼𝐼𝑇𝑇𝑇𝑇
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 +
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
�
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝑇𝑇𝑇𝑇 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
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Table 11. Calculations (System Apparent Impedance in the forward direction)
Eq. (80)
𝐼𝐼𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
=
𝐼𝐼𝐿𝐿
𝑍𝑍𝑇𝑇𝑇𝑇
The infeed equations shows the impedance in front of the relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the forward direction becomes Z L + Z R .
Eq. (81)
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
Figure 14: The infeed diagram shows the impedance behind relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes Z S .
Table 12. Calculations (System Apparent Impedance in the reverse direction)
The following equations are provided for calculating the apparent impedance back to the E S
source voltage as seen by relay R. Infeed equations from V R back to source E S where E S = 0.
See Figure 14.
Eq. (82)
Eq. (83)
Eq. (84)
Eq. (85)
Eq. (86)
Eq. (87)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅 − 𝑉𝑉𝑆𝑆
𝑍𝑍𝐿𝐿
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑆𝑆 − 𝐸𝐸𝑆𝑆
𝑍𝑍𝑆𝑆
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝐿𝐿 =
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑆𝑆
𝑍𝑍𝑆𝑆
𝑉𝑉𝑅𝑅 − 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑆𝑆
𝑍𝑍𝐿𝐿
Since 𝐸𝐸𝑠𝑠 = 0
Rearranged:
𝑉𝑉𝑆𝑆 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑆𝑆
𝑉𝑉𝑅𝑅 − [(𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇 ) × 𝑍𝑍𝑆𝑆 ]
𝑍𝑍𝐿𝐿
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Table 12. Calculations (System Apparent Impedance in the reverse direction)
Eq. (88)
Eq. (89)
Eq. (90)
Eq. (91)
Eq. (92)
𝑉𝑉𝑅𝑅 = (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝐿𝐿 ) + (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝑆𝑆 ) + (𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅𝑅𝑅 )
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑅𝑅
𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑆𝑆
𝐼𝐼𝑇𝑇𝑇𝑇
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 +
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 × �1 +
�
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝑇𝑇𝑇𝑇 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
=
𝐼𝐼𝐿𝐿
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
The infeed equations shows the impedance behind relay R with the parallel transfer impedance
included. As the parallel transfer impedance approaches infinity, the impedances seen by the
relay R in the reverse direction becomes Z S .
Eq. (93)
Eq. (94)
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
As seen by relay R at the receiving-end of
the line.
Subtract Z L for relay R impedance as seen
at sending-end of the line.
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Figure 15. Out-of-step trip (OST) inner blinder (i.e., the parallel green lines) meets the PRC026-1 – Attachment B, Criteria A because the inner OST blinder initiates tripping either OnThe-Way-In or On-The-Way-Out. Since the inner blinder is completely contained within the
unstable power swing region (i.e., the orange characteristic), it meets the PRC-026-1 –
Attachment B, Criteria A.
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Table 13. Example Calculation (Voltage Ratios)
These calculations are based on the loss of synchronism characteristics for the cases of N < 1
and N > 1 as found in the Application of Out-of-Step Blocking and Tripping Relays, GER-3180,
p. 12, Figure 1. 15 The GE illustration shows the formulae used to calculate the radius and center
of the circles that make up the ends of the portion of the lens.
Voltage ratio equations, source impedance equation with infeed formulae applied, and circle
equations.
Given:
Eq. (95)
Eq. (96)
𝐸𝐸𝑆𝑆 = 0.7
𝑁𝑁𝑎𝑎 =
𝑁𝑁𝑏𝑏 =
𝐸𝐸𝑅𝑅 = 1.0
|𝐸𝐸𝑆𝑆 | 0.7
=
= 0.7
|𝐸𝐸𝑅𝑅 | 1.0
|𝐸𝐸𝑅𝑅 | 1.0
=
= 1.43
|𝐸𝐸𝑆𝑆 | 0.7
The total system impedance as seen by the relay with infeed formulae applied.
Given:
Given:
Eq. (97)
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = (4 + 𝑗𝑗20)10 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿
� + �𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
��
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
The calculated coordinates of the lower circle center.
Eq. (98)
𝑍𝑍𝐶𝐶1
𝑁𝑁𝑎𝑎2 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝑍𝑍𝐿𝐿
= − �𝑍𝑍𝑆𝑆 × �1 +
�� − �
�
𝑍𝑍𝑇𝑇𝑇𝑇
1 − 𝑁𝑁𝑎𝑎2
𝑍𝑍𝐶𝐶1 = − � (2 + 𝑗𝑗10) Ω × �1 +
𝑍𝑍𝐶𝐶1 = −11.608 − 𝑗𝑗58.039 Ω
(4 + 𝑗𝑗20) Ω
0.72 × (10 + 𝑗𝑗50) Ω
��
−
�
�
(4 + 𝑗𝑗20)10 Ω
1 − 0.72
The calculated radius of the lower circle.
Eq. (99)
𝑟𝑟𝑎𝑎 = �
𝑁𝑁𝑎𝑎 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
�
1 − 𝑁𝑁𝑎𝑎2
𝑟𝑟𝑎𝑎 = �
0.7 × (10 + 𝑗𝑗50) Ω
�
1 − 0.72
𝑟𝑟𝑎𝑎 = 69.987 Ω
15
http://store.gedigitalenergy.com/faq/Documents/Alps/GER-3180.pdf
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Table 13. Example Calculation (Voltage Ratios)
The calculated coordinates of the upper circle center.
Eq. (100)
𝑍𝑍𝐶𝐶2 = 𝑍𝑍𝐿𝐿 + �𝑍𝑍𝑅𝑅 × �1 +
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝑍𝑍𝐿𝐿
�� + � 2
�
𝑍𝑍𝑇𝑇𝑇𝑇
𝑁𝑁𝑏𝑏 − 1
𝑍𝑍𝐶𝐶2 = − � (4 + 𝑗𝑗20) Ω × �1 +
𝑍𝑍𝐶𝐶2 = 17.608 + 𝑗𝑗88.039 Ω
(4 + 𝑗𝑗20) Ω
(10 + 𝑗𝑗50) Ω
�� + �
�
10
(4 + 𝑗𝑗20) Ω
1.432 − 1
The calculated radius of the upper circle.
Eq. (101)
𝑟𝑟𝑏𝑏 = �
𝑟𝑟𝑏𝑏 = �
𝑁𝑁𝑏𝑏 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
�
𝑁𝑁𝑏𝑏2 − 1
1.43 × (10 + 𝑗𝑗50) Ω
�
1.432 − 1
𝑟𝑟𝑏𝑏 = 69.987 Ω
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Figure 15a: Lower circle loss of synchronism region showing the coordinates of the circle
center and the circle radius.
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Figure 15b: Lower circle loss of synchronism region showing the first steps to calculate the
coordinates of the points on the circle. 1) Identify the lower circle points that intersect the lens
shape where the sending-end to receiving-end voltage ratio is 0.7 (see lens shape calculations
in Tables 2-7). 2) Calculate the distance between the two lower circle points identified in Step
1. 3) Calculate the angle of arc that connects the two lower circle points identified in Step 1.
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Figure 15c: Lower circle loss of synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1)
Calculate the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4)
Calculate the angle step size for the desired number of points.
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Figure 15d: Lower circle loss of synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R–X coordinates.
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Figure 15e: Upper circle loss of synchronism region showing the coordinates of the circle
center and the circle radius.
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Figure 15f: Upper circle loss of synchronism region showing the first steps to calculate the
coordinates of the points on the circle. 1) Identify the upper circle points that intersect the lens
shape where the sending-end to receiving-end voltage ratio is 1.43 (see lens shape calculations
in Tables 2-7). 2) Calculate the distance between the two upper circle points identified in Step
1. 3) Calculate the angle of arc that connects the two upper circle points identified in Step 1.
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Figure 15g: Upper circle loss of synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1) Calculate
the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4) Calculate the angle
step size for the desired number of points.
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Figure 15h: Upper circle loss of synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R-X coordinates.
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Figure 15i: Full tables of calculated lower and upper loss of synchronism circle coordinates.
The highlighted row is the detailed calculated points in Figures 15d and 15h.
Application Specific to Criteria B
The PRC-026-1 – Attachment B, Criteria B evaluates overcurrent elements used for tripping. The
same criteria as PRC-026-1 – Attachment B, Criteria A is used except for an additional criteria
(No. 4) that calculates a current magnitude based upon generator terminal voltages of 1.05 per unit.
The formula used to calculate the current is as follows:
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Table 14. Example Calculation (Overcurrent)
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps secondary times a CT ratio of 160:1 that equals 8,000 amps, primary.
The following calculation is where V S equals the base line-to-ground sending-end generator
source voltage times 1.05 at an angle of 120 degrees, V R equals the base line-to-ground
receiving-end generator terminal voltage times 1.05 at an angle of 0 degrees, and Z sys equals the
sum of the sending-end, line, and receiving-end source impedances in ohms.
Here, the phase instantaneous setting of 8,000 amps is greater than the calculated system current
of 5,716 amps; therefore, it meets PRC-026-1 – Attachment B, Criteria B.
Eq. (102)
𝑉𝑉𝑆𝑆 =
𝑉𝑉𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
× 1.05
√3
230,000∠120° 𝑉𝑉
√3
𝑉𝑉𝑆𝑆 = 139,430∠120° 𝑉𝑉
× 1.05
Receiving-end generator terminal voltage.
Eq. (103)
𝑉𝑉𝑅𝑅 =
𝑉𝑉𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
× 1.05
√3
230,000∠0° 𝑉𝑉
√3
𝑉𝑉𝑅𝑅 = 139,430∠0° 𝑉𝑉
× 1.05
The total impedance of the system (Z sys ) equals the sum of the sending-end source impedance
(Z S ), the impedance of the line (Z L ), and receiving-end impedance (Z R ) in ohms.
Given:
Eq. (104)
𝑍𝑍𝑆𝑆 = 3 + 𝑗𝑗26 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝐿𝐿 = 1.3 + 𝑗𝑗8.7 Ω
𝑍𝑍𝑅𝑅 = 0.3 + 𝑗𝑗7.3 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (3 + 𝑗𝑗26) Ω + (1.3 + 𝑗𝑗8.7) Ω + (0.3 + 𝑗𝑗7.3) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 4.6 + 𝑗𝑗42 Ω
Total system current from sending-end source.
Eq. (105)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
(𝑉𝑉𝑆𝑆 − 𝑉𝑉𝑅𝑅 )
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
(139,430∠120° 𝑉𝑉 − 139,430∠0° 𝑉𝑉)
(4.6 + 𝑗𝑗42) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 5,715.82∠66.25° 𝐴𝐴
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Application Specific to Three-Terminal Lines
If a three-terminal line is identified as an Element that is susceptible to a power swing based on
Requirement R1, the load-responsive protective relays at each end of the three-terminal line must
be evaluated.
As shown in Figure 15j, the source impedances at each end of the line can be obtained from the
similar short circuit calculation as for the two-terminal line.
EA
A
B
ZSA
ZL2
ZL1
R
ZSB
EB
ZL3
C
ZSC
EC
Figure 15j. Three-terminal line. To evaluate the load-responsive protective relays on the threeterminal line at Terminal A, the circuit in Figure 15j is first reduced to the equivalent circuit
shown in Figure 15k. The evaluation process for the load-responsive protective relays on the
line at Terminal A will now be the same as that of the two-terminal line.
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Figure 15k. Three-terminal line reduced to a two-terminal line.
Application to Generation Elements
As with transmission BES Elements, the determination of the apparent impedance seen at an
Element located at, or near, a generation Facility is complex for power swings due to various
interdependent quantities. These variances in quantities are caused by changes in machine internal
voltage, speed governor action, voltage regulator action, the reaction of other local generators, and
the reaction of other interconnected transmission BES Elements as the event progresses through
the time domain. Though transient stability simulations may be used to determine the apparent
impedance for verifying load-responsive relay settings, 16,17 Requirement R2, PRC-026-1 –
Attachment B, Criteria A and B provides a simplified method for evaluating the load-responsive
protective relay’s susceptibility to tripping in response to a stable power swing without requiring
stability simulations.
In general, the electrical center will be in the transmission system for cases where the generator is
connected through a weak transmission system (high external impedance). Other cases where the
generator is connected through a strong Transmission system, the electrical center could be inside
the unit connected zone. 18 In either case, load-responsive protective relays connected at the
generator terminals or at the high-voltage side of the generator step-up (GSU) transformer may be
challenged by power swings as determined by the Planning Coordinator in Requirement R1 or
becoming aware of a generator, transformer, or transmission line BES Element that tripped 19 in
16
Donald Reimert, Protective Relaying for Power Generation Systems, Boca Raton, FL, CRC Press, 2006.
17
Prabha Kundur, Power System Stability and Control, EPRI, McGraw Hill, Inc., 1994.
18
Ibid, Kundur.
19
See Guidelines and Technical Basis section, “Becoming Aware of an Element That Tripped in Response to a
Power Swing,”
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response to stable or unstable power swing due to the operation of its protective relay(s) in
Requirement R2.
Load-responsive protective relays such as time over-current, voltage controlled time-overcurrent
or voltage-restrained time-overcurrent relays are excluded from this standard if they are set based
on equipment permissible overload capability. Their operating time is much greater than 15 cycles
for the current levels observed during a power swing.
Instantaneous overcurrent and definite-time overcurrent relays with a time delay of less than 15
cycles are applicable and are required to be evaluated for identified Elements.
The generator loss-of-field protective function is provided by impedance relay(s) connected at the
generator terminals. The settings are applied to protect the generator from a partial or complete
loss of excitation under all generator loading conditions and, at the same time, be immune to
tripping on stable power swings. It is more likely that the relay would operate during a power
swing when the automatic voltage regulator (AVR) is in manual mode rather than when in
automatic mode. 20 Figure 16 illustrates the loss-of-field relay in the R-X plot, which typically
includes up to three zones of protection.
Figure 16. An R-X graph of typical impedance settings for loss-of-field relays.
20
John Burdy, Loss-of-excitation Protection for Synchronous Generators GER-3183, General Electric Company.
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Loss-of-field characteristic 40-1 has a wider impedance characteristic (positive offset) than
characteristic 40-2 or characteristic 40-3 and provides additional generator protection for a partial
loss of field or a loss of field under low load (less than 10% of rated). The tripping logic of this
protection scheme is established by a directional contact, a voltage setpoint, and a time delay. The
voltage and time delay add security to the relay operation for stable power swings. Characteristic
40-3 is less sensitive to power swings than characteristic 40-2 and is set outside the generator
capability curve in the leading direction. Regardless of the relay impedance setting, PRC-01921
requires that the “in-service limiters operate before Protection Systems to avoid unnecessary trip”
and “in-service Protection System devices are set to isolate or de-energize equipment in order to
limit the extent of damage when operating conditions exceed equipment capabilities or stability
limits.” Time delays for tripping associated with loss-of-field relays 22,23 have a range from 15
cycles for characteristic 40-2 to 60 cycles for characteristic 40-1 to minimize tripping during stable
power swings. In the standard, 15 cycles establishes a threshold for applicability; however, it is
the responsibility of the Generator Owner to establish settings that provide security against stable
power swings and, at the same time, dependable protection for the generator.
The simple two-machine system circuit (method also used in the Application to Transmission
Elements section) is used to analyze the effect of a power swing at a generator facility for loadresponsive relays. In this section, the calculation method is used for calculating the impedance
seen by the relay connected at a point in the circuit. 24 The electrical quantities used to determine
the apparent impedance plot using this method are generator saturated transient reactance (X’ d ),
GSU transformer impedance (X GSU ), transmission line impedance (Z L ), and the system equivalent
(Z e ) at the point of interconnection. All impedance values are known to the Generator Owner
except for the system equivalent. The system equivalent is obtainable from the Transmission
Owner. The sending-end and receiving-end source voltages are varied from 0.0 to 1.0 per unit to
form the lens shape of the unstable power swing region. The voltage range of 0.7 to 1.0 results in
a ratio range from 0.7 to 1.43. This ratio range is used to form the lower and upper loss-ofsynchronism circle shapes of the unstable power swing region. A system separation angle of 120
degrees is used in accordance with PRC-026-1 – Attachment B criteria for each load-responsive
protective relay evaluation.
Table 15 below is an example calculation of the apparent impedance locus method based on
Figures 17 and 18. 25 In this example, the generator is connected to the 345 kV transmission system
through the GSU transformer and has the listed ratings. Note that the load-responsive protective
relays in this example may have ownership with the Generator Owner or the Transmission Owner.
21
Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection
22
Ibid, Burdy.
23
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
24
Edward Wilson Kimbark, Power System Stability, Volume II: Power Circuit Breakers and Protective Relays,
Published by John Wiley and Sons, 1950.
25
Ibid, Kimbark.
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Figure 17. Simple one-line diagram of the
system to be evaluated.
Figure 18. Simple system equivalent
impedance diagram to be evaluated. 26
Table15. Example Data (Generator)
Input Descriptions
Input Values
Synchronous Generator nameplate (MVA)
940 MVA
Sub-transient reactance (940MVA base)
Generator rated voltage (Line-to-Line)
Generator step-up (GSU) transformer rating
GSU transformer reactance (880 MVA base)
System Equivalent (100 MVA base)
𝑋𝑋𝑑𝑑′ = 0.3845 (per unit)
20 𝑘𝑘𝑘𝑘
880 𝑀𝑀𝑀𝑀𝑀𝑀
XGSU = 16.05%
𝑍𝑍𝑒𝑒 = 0.00723∠86° ohms
Generator Owner Load-Responsive Protective Relays
40-1
Positive Offset Impedance
Offset = 0.294 per unit ohms
Diameter = 0.294 per unit ohms
40-2
Negative Offset Impedance
Offset = 0.22 per unit ohms
Diameter = 2.24 per unit ohms
40-3
21-1
26
Negative Offset Impedance
Offset = 0.22 per unit ohms
Diameter = 1.00 per unit ohms
Diameter = 0.643 per unit ohms
MTA = 85°
Ibid, Kimbark.
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Table15. Example Data (Generator)
I (pickup) = 5.0 per unit
50
Transmission Owned Load-Responsive Protective Relays
Diameter = 0.55 per unit ohms
21-2
MTA = 85°
Calculations shown for a 120 degree angle and E S /E R = 1. The equation for calculating Z R is: 27
Eq. (106)
𝑍𝑍𝑅𝑅 = �
(1 − 𝑚𝑚)(𝐸𝐸𝑆𝑆 ∠𝛿𝛿) + (𝑚𝑚)(𝐸𝐸𝑅𝑅 )
� × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝐸𝐸𝑆𝑆 ∠𝛿𝛿 − 𝐸𝐸𝑅𝑅
Where m is the relay location as a function of the total impedance (real number less than 1)
E S and E R is the sending-end and receiving-end voltages
Z sys is the total system impedance
Z R is the complex impedance at the relay location and plotted on an R-X diagram
All of the above are constants (940 MVA base) while the angle δ is varied. Table 16 below contains
calculations for a generator using the data listed in Table 15.
Table16. Example Calculations (Generator)
Given:
Eq. (107)
𝑋𝑋𝑑𝑑′ = 𝑗𝑗0.3845 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑋𝑋𝑑𝑑′ + 𝑋𝑋𝐺𝐺𝐺𝐺𝐺𝐺 + 𝑍𝑍𝑒𝑒
𝑋𝑋𝐺𝐺𝐺𝐺𝐺𝐺 = 𝑗𝑗0.171 Ω
𝑍𝑍𝑒𝑒 = 0.06796 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑗𝑗0.3845 Ω + 𝑗𝑗0.171 Ω + 0.06796 Ω
Eq. (108)
Eq. (109)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 0.6239 ∠90° Ω
𝑚𝑚 =
𝑋𝑋𝑑𝑑′
0.3845
=
= 0.61633
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 0.6239
𝑍𝑍𝑅𝑅 = �
𝑍𝑍𝑅𝑅 = �
(1 − 𝑚𝑚)(𝐸𝐸𝑆𝑆 ∠𝛿𝛿) + (𝑚𝑚)(𝐸𝐸𝑅𝑅 )
� × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝐸𝐸𝑆𝑆 ∠𝛿𝛿 − 𝐸𝐸𝑅𝑅
(1 − 0.61633) × (1∠120°) + (0.61633)(1∠0°)
� × (0.6234∠90°) Ω
1∠120° − 1∠0°
0.4244 + 𝑗𝑗0.3323
Z𝑅𝑅 = �
� × (0.6234∠90°) Ω
−1.5 + 𝑗𝑗 0.866
Z𝑅𝑅 = (0.3112 ∠ − 111.94°) × (0.6234∠90°) Ω
27
Ibid, Kimbark.
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Table16. Example Calculations (Generator)
Z𝑅𝑅 = 0.194 ∠ − 21.94° Ω
Z𝑅𝑅 = −0.18 − 𝑗𝑗0.073 Ω
Table 17 lists the swing impedance values at other angles and at E S /E R = 1, 1.43, and 0.7. The
impedance values are plotted on an R-X graph with the center being at the generator terminals for
use in evaluating impedance relay settings.
Table 17: Sample calculations for a swing impedance chart for varying voltages at the
sending-end and receiving-end.
Angle (δ)
(Degrees)
E S /E R =1
E S /E R =1.43
E S /E R =0.7
ZR
ZR
ZR
Magnitude
(PU Ohms)
Angle
(Degrees)
Magnitude
(PU Ohms)
Angle
(Degrees)
Magnitude
(PU Ohms)
Angle
(Degrees)
90
0.320
-13.1
0.296
6.3
0.344
-31.5
120
0.194
-21.9
0.173
-0.4
0.227
-40.1
150
0.111
-41.0
0.082
-10.3
0.154
-58.4
210
0.111
-25.9
0.082
190.3
0.154
238.4
240
0.194
201.9
0.173
180.4
0.225
220.1
270
0.320
193.1
0.296
173.7
0.344
211.5
Requirement R2 Generator Examples
Distance Relay Application
Based on PRC-026-1 – Attachment B, Criteria A, the distance relay (21-1) (i.e., owned by the
Generation Owner) characteristic is in the region where a stable power swing would not occur as
shown in Figure 19. There is no further obligation to the owner in this standard for this loadresponsive protective relay.
The distance relay (21-2) (i.e., owned by the Transmission Owner) is connected at the high-voltage
side of the GSU transformer and its impedance characteristic is in the region where a stable power
swing could occur causing the relay to operate. In this example, if the intentional time delay of this
relay is less than 15 cycles, the PRC-026 – Attachment B, Criteria B cannot be met, thus the
Transmission Owner is required to create a CAP (Requirement R3). Some of the options include,
but are not limited to, changing the relay setting (i.e., impedance reach, angle, time delay), modify
the scheme (i.e., add PSB), or replace the Protection System. Note that the relay may be excluded
from this standard if it has an intentional time delay equal to or greater than 15 cycles.
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Figure 19. Swing impedance graph for impedance relays at a generating facility.
Loss-of-Field Relay Application
In Figure 20, the R-X diagram shows the loss-of-field relay (40-1 and 40-2) characteristics are in
the region where a stable power swing can cause a relay operation. Protective relay 40-1 would
be excluded if it has an intentional time delay equal to or greater than 15 cycles. Similarly, 40-2
would be excluded if its intentional time delay is equal to or greater than 15 cycles. For example,
if 40-1 has a time delay of 1 second and 40-2 has a time delay of 0.25 seconds, they are excluded
and there is no further obligation on the Generator Owner in this standard for these relays. The
loss-of-field relay characteristic 40-3 is outside the region where a stable power swing can cause
a relay operation. In this case, the owner may select high speed tripping on operation of the 40-3
impedance element.
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Figure 20: Stable power swing R-X graph for loss-of-field relays.
Instantaneous Overcurrent Relay
In similar fashion to the transmission line overcurrent example calculation in Table 14, the
instantaneous overcurrent relay minimum setting is established by PRC-026-1 – Attachment B,
Criteria B. The solution is found by:
Eq. (110)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍sys
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
(1.05∠120° − 1.05∠0°)
𝐴𝐴
0.6234∠90°
As stated in the relay settings in Table 15, the relay is installed on the high-voltage side of the GSU
transformer with a pickup of 5.0 per unit amps. The maximum allowable current is calculated
below.
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
1.775∠150° 𝑉𝑉
𝐴𝐴
0.6234∠90° Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 2.84 ∠60° 𝐴𝐴
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The phase instantaneous setting of 5.0 per unit amps is greater than the calculated system current
of 2.84 per unit amps; therefore, it meets the PRC-026-1 – Attachment B, Criteria B.
Out-of-Step Tripping for Generation Facilities
Out-of-step protection for the generator generally falls into three different schemes. The first
scheme is a distance relay connected at the high-voltage side of the GSU transformer with the
directional element looking toward the generator. Because this relay setting may be the same
setting used for generator backup protection (see Requirement R2 Generator Examples, Distance
Relay Application), it is susceptible to stable power swings and would require modification.
Because this scheme is susceptible to stable power swings and any modification to the mho
circle will jeopardize the overall protection of the out-of-step protection of the generator,
available technical literature does not recommend using this scheme specifically for generator
out-of-step protection. The second and third out-of-step Protection System schemes are
commonly referred to as single and double blinder schemes. These schemes are installed or
enabled for out-of-step protection using a combination of blinders, a mho element, and timers.
The combination of these protective relay functions provides out-of-step protection and
discrimination logic for stable and unstable power swings. Single blinder schemes use logic that
discriminate between stable and unstable power swings by issuing a trip command after the first
slip cycle. Double blinder schemes are more complex that the single blinder scheme and,
depending on the settings of the inner blinder, a trip for a stable power swing may occur. While
the logic discriminates between stable and unstable power swings in either scheme, it is
important that the trip initiating blinders be set at an angle greater than the stability limit of 120
degrees to remove the possibility of a trip for a stable power swing. Below is a discussion of the
double blinder scheme.
Double Blinder Scheme
The double blinder scheme is a method for measuring the rate of change of positive sequence
impedance for out-of-step swing detection. The scheme compares a timer setting to the actual
elapsed time required by the impedance locus to pass between two impedance characteristics. In
this case, the two impedance characteristics are simple blinders, each set to a specific resistive
reach on the R-X plane. Typically, the two blinders on the left half plane are the mirror images of
those on the right half plane. The scheme typically includes a mho characteristic which acts as a
starting element, but is not a tripping element.
The scheme detects the blinder crossings and time delays as represented on the R-X plane as
shown in Figure 21. The system impedance is composed of the generator transient (X d ’), GSU
transformer (X T) , and transmission system (X system ), impedances.
The scheme logic is initiated when the swing locus crosses the outer Blinder R1 (Figure 21), on
the right at separation angle α. The scheme only commits to take action when a swing crosses the
inner blinder. At this point the scheme logic seals in the out-of-step trip logic at separation angle
β. Tripping actually asserts as the impedance locus leaves the scheme characteristic at separation
angle δ.
The power swing may leave both inner and outer blinders in either direction and tripping will
assert. Therefore, the inner blinder must be set such that the separation angle β is large enough
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that the system cannot recover. This angle should be set at 120 degrees or more. Setting the angle
greater than 120 degrees satisfies the PRC-026-1 – Attachment B Criteria A (No. 1, 1st bullet)
since the tripping function is asserted by the blinder element. Transient stability studies are
usually required to determine an appropriate inner blinder setting. Such studies may indicate that
a smaller stability limit angle is acceptable under PRC-026-1 – Attachment B Criteria A (No. 1,
2nd bullet). In this respect, the double blinder scheme is similar to the double lens and triple lens
schemes, and many transmission application out-of-step schemes.
Figure 21: Double Blinder Scheme generic out of step characteristics.
Figure 22 illustrates a sample setting of the double blinder scheme for example 940 MVA
generator. The only setting requirement for this relay scheme is the right inner blinder, which
must be set greater than the separation angle of 120 degrees (or a lesser angle based on a
transient stability study) to ensure that the out-of-step protective function is expected to not trip
in response to a stable power swing during non-Fault conditions. Other settings such as the mho
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PRC-026-1 – Application Guidelines
characteristic, outer blinders, and timers are set according to transient stability studies and are not
a part of this standard.
Figure 22: Double Blinder Out-of-Step Scheme with unit impedance data and load-responsive
protective relay impedance characteristics for the example 940 MVA generator, scaled in relay
secondary ohms.
Requirement R3
To achieve the stated purpose of this standard, which is to ensure that relays are expected to not
trip in response to stable power swings during non-Fault conditions, this Requirement ensures
that the applicable entity develops a Corrective Action Plan (CAP) that reduces the risk of relays
tripping in response to a stable power swing during non-Fault conditions that may occur on any
applicable BES Element.
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Requirement R4
To achieve the stated purpose of this standard, which is to ensure that load-responsive protective
relays are expected to not trip in response to stable power swings during non-Fault conditions, the
applicable entity is required to implement any CAP developed pursuant to Requirement R3 such
that the Protection System will meet PRC-026-1 – Attachment B criteria or can be excluded under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay
functions are supervised by power swing blocking or using relay systems that are immune to power
swings), while maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the BES Element). Protection System owners are
required in the implementation of a CAP to update it when actions or timetable change, until all
actions are complete. Accomplishing this objective is intended to reduce the occurrence of
Protection System tripping during a stable power swing, thereby improving reliability and
minimizing risk to the BES.
The following are examples of actions taken to complete CAPs for a relay that did not meet PRC026-1 – Attachment B and could be at-risk of tripping in response to a stable power swing during
non-Fault conditions. A Protection System change was determined to be acceptable (without
diminishing the ability of the relay to protect for faults within its zone of protection).
Example R4a: Actions: Settings were issued on 6/02/2015 to reduce the Zone 2 reach of
the impedance relay used in the directional comparison unblocking (DCUB) scheme from
30 ohms to 25 ohms so that the relay characteristic is completely contained within the lens
characteristic identified by the criterion. The settings were applied to the relay on
6/25/2015. CAP was completed on 06/25/2015.
Example R4b: Actions: Settings were issued on 6/02/2015 to enable out-of-step blocking
on the existing microprocessor-based relay to prevent tripping in response to stable power
swings. The setting changes were applied to the relay on 6/25/2015. CAP was completed
on 06/25/2015.
The following is an example of actions taken to complete a CAP for a relay responding to a stable
power swing that required the addition of an electromechanical power swing blocking relay.
Example R4c: Actions: A project for the addition of an electromechanical power swing
blocking relay to supervise the Zone 2 impedance relay was initiated on 6/5/2015 to prevent
tripping in response to stable power swings. The relay installation was completed on
9/25/2015. CAP was completed on 9/25/2015.
The following is an example of actions taken to complete a CAP with a timetable that required
updating for the replacement of the relay.
Example R4d: Actions: A project for the replacement of the impedance relays at both
terminals of line X with line current differential relays was initiated on 6/5/2015 to prevent
tripping in response to stable power swings. The completion of the project was postponed
due to line outage rescheduling from 11/15/2015 to 3/15/2016. Following the timetable
change, the impedance relay replacement was completed on 3/18/2016. CAP was
completed on 3/18/2016.
The CAP is complete when all the documented actions to remedy the specific problem (i.e.,
unnecessary tripping during stable power swings) are completed.
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PRC-026-1 — Relay Performance During Stable Power Swings
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. Standards Authorization Request (SAR) posted for comment from August 19, 2010
through September 19, 2010.
2. Standards Committee (SC) authorized moving the SAR forward tointo standard
development on August 12, 2010.
3. SC authorized initial posting of draftDraft 1 on April 24, 2014.
4. Draft 1 of PRC-026-1 was posted for a 45-day formal comment period from April 25 –
June 9, 2014 and anwith a concurrent/parallel initial ballot in the last ten days of the
comment period from May 30 – June 9, 2014.
5. Draft 2 of PRC-026-1 was posted for an additional 45-day formal comment period from
August 22 – October 6, 2014 with a concurrent/parallel additional ballot in the last ten
days of the comment period from September 26 – October 6, 2014.
6. SC authorized a waiver of the Standards Process Manual on October 22, 2014 to reduce
the Draft 3 additional formal comment period of PRC-026-1 from 45 days to 21 days
with a concurrent/additional ballot period in the last ten days of the comment period.
Description of Current Draft
The Protection System Response to Power Swings Standard Drafting Team (PSRPS SDT) is
posting Draft 23 of PRC-026-1 – Relay Performance During Stable Power Swings for a 4521-day
additional comment period and concurrent/parallel additonaladditional ballot in the last ten days
of the comment period.
Anticipated Actions
Anticipated Date
45-day Formal Comment Period with Concurrent/Parallel Initial 10-day
Ballot
April 2014
45-day Formal Comment Period with Concurrent/Parallel Additional 10day Ballot
August 2014
Final Ballot21-day Formal Comment Period with Concurrent/Parallel
Additional 10-day Ballot (Standards Committee authorized a waiver of
the Standards Process Manual, October 22, 2014)
October 2014
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PRC-026-1 — Relay Performance During Stable Power Swings
Final Ballot
December 2014
NERC Board of Trustees Adoption
NovemberDecember
2014
Version History
Version
Date
1.0
TBD
Action
Effective Date
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Change
Tracking
New
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PRC-026-1 — Relay Performance During Stable Power Swings
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Glossary of Terms Used in Reliability Standards (Glossary) are not repeated
here. 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.
Term: None.
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PRC-026-1 — Relay Performance During Stable Power Swings
When this standard has received ballot approval, the rationale boxes will be moved to the
Application Guidelines Section of the Standardstandard.
A. Introduction
1. Title:
Relay Performance During Stable Power Swings
2. Number:
PRC-026-1
3. Purpose:
To ensure that load-responsive protective relays are expected to not trip in
response to stable power swings during non-Fault conditions.
4. Applicability:
4.1.
4.2.
Functional Entities:
4.1.1
Generator Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
4.1.2
Planning Coordinator.
4.1.3
Transmission Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
Facilities: The following Elements that are part of the Bulk Electric System
(BES) Elements:):
4.2.1
Generators.
4.2.2
Transformers.
4.2.3
Transmission lines.
5. Background:
This is the third phase of a three-phased standard development project that focused on
developing this new Reliability Standard to address protective relay operations due to
stable power swings. The March 18, 2010, Federal Energy Regulatory Commission
(FERC) Order No. 733, approved Reliability Standard PRC-023-1 – Transmission Relay
Loadability. In this Order, FERC directed NERC to address three areas of relay loadability
that include modifications to the approved PRC-023-1, development of a new Reliability
Standard to address generator protective relay loadability, and a new Reliability Standard
to address the operation of protective relays due to stable power swings. This project’s
SAR addresses these directives with a three-phased approach to standard development.
Phase 1 focused on making the specific modifications to PRC-023-1 and was completed in
the approved Reliability Standard PRC-023-2, which became mandatory on July 1, 2012.
Phase 2 focused on developing a new Reliability Standard, PRC-025-1 – Generator Relay
Loadability, to address generator protective relay loadability;. PRC-025-1 was approved
by FERCbecame mandatory on July 17October 1, 2014 along with PRC-023-3, which was
modified to harmonize PRC-023-2 with PRC-025-1.
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PRC-026-1 — Relay Performance During Stable Power Swings
This Phase 3 of the project establishes requirementsRequirements aimed at preventing
protective relays from tripping unnecessarily due to stable power swings by requiring the
identification of Elements on which a stable or unstable power swing may affect Protection
System operation, and to develop requirementsRequirements to assess the security of loadresponsive protective relays to tripping in response to only a stable power swing. Last, to
require entities to implement Corrective Action Plans, (CAP), where necessary, to improve
security of security of load-responsive protective relays for stable power swings so they
are expected to not trip in response to stable power swings during non-Fault conditions,
while maintaining dependable fault detection and dependable out-of-step tripping.
6. Effective DateDates:
Requirements R1-R3, R5, and R6
Requirement R1
First day of the first full calendar year that is 12 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 12 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
RequirementRequirements R2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 36 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
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B. Requirements and Measures
R1. Each Planning Coordinator shall, at least once each calendar year, identify provide
notification of each generator, transformer, and transmission line BES Element in its
area that meetsmeet one or more of the following criteria and provide notification , if
any, to the respective Generator Owner and Transmission Owner, if any: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
Criteria:
1. Generator(s) where an angular stability constraint exists that is addressed by an
operating limita System Operating Limit (SOL) or a Remedial Action Scheme
(RAS) and those Elements terminating at the transmission switchingTransmission
station associated with the generator(s).
2. An Element that is monitored as part of a System Operating Limit (SOL) that has
been established identified by the Planning Coordinator’s methodology 1 based on
an angular stability constraints identified in system planning or operating
studiesconstraint.
3. An Element that forms the boundary of an island due to angular instability
withinin the most recent underfrequency load shedding (UFLS) design assessment
based on application of the Planning Coordinator’s criteria for identifying islands,
where the island is formed by tripping the Element due to angular instability.
4. An Element identified in the most recent annual Planning Assessment where relay
tripping occurs due to a stable or unstable power swing during a simulated
disturbance.
5. An Element reported by the Generator Owner or Transmission Owner pursuant to
Requirement R2 or Requirement R3, unless the Planning Coordinator determines
the Element is no longer susceptible to power swings.
M1. Each Planning Coordinator shall have dated evidence that demonstrates identification
and the respective notification of the generator, transformer, and transmission line BES
Element(s), if any, which) that meet one or more of the criteria in Requirement R1, if
any, to the respective Generator Owner and Transmission Owner. Evidence may
include, but is not limited to, the following documentation: emails, facsimiles, records,
reports, transmittals, lists, or spreadsheets.
1
NERC Reliability Standard FAC-10 – System Operating Limits Methodology for the Planning Horizon
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Rationale for R1: The Planning Coordinator has a wide-area view and is in the position to
identify generator, transformer, and transmission line BES Elements which meet the criteria, if
any. The criterioncriteria-based approach is consistent with the NERC System Protection and
Control Subcommittee (SPCS) technical document Protection System Response to Power
Swings, August 2013 (“PSRPS Report”), 2 which recommends a focused approach to determine
an at-risk Element.BES Element. See the Guidelines and Technical Basis for a detailed
discussion of the criteria.
R1. Each Transmission Owner shall, within 30 calendar days of identifying an Element that
meets either of the following criteria, provide notification of the Element to its Planning
Coordinator: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
Criteria:
1. An Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load-responsive protective relays.
2. An Element that forms the boundary of an island during an actual system
Disturbance due to the operation of its load-responsive protective relays.
M2. Each Transmission Owner shall have dated evidence that demonstrates identification of the
Element(s), if any, which meet either of the criteria in Requirement R2. Evidence may
include, but is not limited to, the following documentation: emails, facsimiles, records,
reports, transmittals, lists, or spreadsheets.
Rationale for R2: The Transmission Owner is in the position to identify the load-responsive
protective relays that have tripped due to power swings, if any. The criteria is consistent with
the PSRPS Report. A time to complete a review of the relay tripping is not addressed here as
other NERC Reliability Standards address the review of Protection System operations.
R2. Each Generator Owner shall, within 30 calendar days of identifying an Element that meets
the following criterion, provide notification of the Element to its Planning Coordinator:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
Criterion:
1. An Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load-responsive protective relays.
2
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
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M3. Each Generator Owner shall have dated evidence that demonstrates identification of the
Element(s), if any, which the criterion in Requirement R3. Evidence may include, but is
not limited to, the following documentation: emails, facsimiles, records, reports,
transmittals, lists, or spreadsheets.
Rationale for R3: The Generator Owner is in the position to identify the load-responsive
protective relays that have tripped due to power swings, if any. The criterion is consistent with
the PSRPS Report. A requirement or time to complete a review of the relay tripping is not
addressed here as other NERC Reliability Standards address the review of Protection System
operations.
R2. Each Generator Owner and Transmission Owner shall, within determine: [Violation
Risk Factor: High] [Time Horizon: Operations Planning]
1.12.1
Within 12 full calendar months of receiving notification of ana BES
Element pursuant to Requirement R1 or within 12 full calendar months of
identifying an, determine whether its load-responsive protective relay(s) applied
to that BES Element pursuant to Requirement R2 or R3, evaluate each
identifiedmeets the criteria in PRC-026-1 – Attachment B where an evaluation of
that Element’s load-responsive protective relay(s) based on the PRC-026-1 –
Attachment B Criteria where the evaluationcriteria has not been performed in the
last threefive calendar years. [Violation Risk Factor: High] [Time Horizon:
Operations Planning]
2.2 Within 12 full calendar months of becoming aware of a generator, transformer, or
transmission line BES Element that tripped in response to a stable or unstable
power swing due to the operation of its protective relay(s), determine whether its
load-responsive protective relay(s) applied to that BES Element meets the criteria
in PRC-026-1 – Attachment B.
M4.M2.
Each Generator Owner and Transmission Owner shall have dated evidence
that demonstrates the evaluation was performed according to Requirement R4R2.
Evidence may include, but is not limited to, the following documentation: apparent
impedance characteristic plots, email, design drawings, facsimiles, R-X plots, software
output, records, reports, transmittals, lists, settings sheets, or spreadsheets.
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Rationale for R4: Performing the evaluation in Requirement R4 is the first step in ensuring that
the reliability goal of this standard will be met. The PRC-026-1 – Attachment B, Criteria
provides a basis for determining if the relays are expected to not trip for a stable power swing.
See the Guidelines and Technical Basis for a detailed explanation of the evaluation.Rationale
for R2: The Generator Owner and Transmission Owner are in a position to determine whether
its load-responsive protective relays meet the PRC-026-1 – Attachment B criteria. Generator,
transformer, and transmission line BES Elements are identified by the Planning Coordinator in
Requirement R1 and by the Generator Owner and Transmission Owner following an actual
event where the Generator Owner and Transmission Owner became aware (i.e., through an
event analysis or Protection System review) tripping was due to stable or unstable power swing.
A period of 12 calendar months allows sufficient time for protection staff to conduct the
evaluation.
R3. Each Generator Owner and Transmission Owner shall, within 60six full calendar
daysmonths of an evaluation that identifies determining a load-responsive protective
relays that dorelay does not meet the PRC-026-1 – Attachment B Criteria pursuant to
Requirement R4criteria, develop a Corrective Action Plan (CAP) to modifymeet one or
more of the following [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning]
•
The Protection System to meetmeets the PRC-026-1 – Attachment B
Criteriacriteria, while maintaining dependable fault detection and dependable outof-step tripping (if out-of-step tripping is applied at the terminal of the Element).
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning]BES
Element); or
•
The Protection System is excluded under the PRC-026-1 – Attachment A criteria
(e.g., modifying the Protection System so that relay functions are supervised by
power swing blocking or using relay systems that are immune to power swings),
while maintaining dependable fault detection and dependable out-of-step tripping
(if out-of-step tripping is applied at the terminal of the BES Element).
M5.M3.
The Generator Owner and Transmission Owner shall have dated evidence
that demonstrates the development of a CAP in accordance with Requirement R5R3.
Evidence may include, but is not limited to, the following documentation: corrective
action plans, maintenance records, settings sheets, project or work management
program records, or work orders.
Rationale for R5R3: To meet the reliability purpose of the standard, a CAP is necessary to
modifyensure the entity’s Protection System to meetmeets the PRC-026-1 – Attachment B
criteria so that protective relays are expected to not trip in response to stable power swings. The
phrase, ““…while maintaining dependable fault detection and dependable out-of-step
tripping”…” in Requirement R5R2 describes that the entity is to comply with this standard,
while achieving their desired protection goals. Refer to the Guidelines and Technical Basis,
Introduction, for more information.
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PRC-026-1 — Relay Performance During Stable Power Swings
R2.R4.
Each Generator Owner and Transmission Owner shall implement each CAP
developed pursuant to Requirement R5,R3 and update each CAP if actions or
timetables change until all actions are complete. [Violation Risk Factor:
Medium][Time Horizon: Long-Term Planning]
M6.M4.
The Generator Owner and Transmission Owner shall have dated evidence
that demonstrates implementation of each CAP according to Requirement R6R4,
including updates to the CAP when actions or timetables change. Evidence may
include, but is not limited to, the following documentation: corrective action plans,
maintenance records, settings sheets, project or work management program records, or
work orders.
Rationale for R6R4: Implementation of the CAP must accomplish all identified actions to be
complete to achieve the desired reliability goal. During the course of implementing a CAP,
updates may be necessary for a variety of reasons such as new information, scheduling conflicts,
or resource issues. Documenting CAP changes and completion of activities provides measurable
progress and confirmation of completion.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention
The following evidence retention periods 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 CEA may ask an entity to provide other evidence to show that it was
compliant for the full time period since the last audit.
The Generator Owner, Planning Coordinator, and Transmission Owner shall keep
data or evidence to show compliance as identified below unless directed by its CEA
to retain specific evidence for a longer period of time as part of an investigation.
•
The Planning Coordinator shall retain evidence of Requirement R1 for a
minimum of threeone calendar yearsyear following the completion of
eachthe Requirement.
•
The Transmission Owner shall retain evidence of Requirement R2 for a
minimum of three calendar years following the completion of each
Requirement.
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PRC-026-1 — Relay Performance During Stable Power Swings
•
The Generator Owner shall retain evidence of Requirement R3 for a
minimum of three calendar years following the completion of each
Requirement.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirement R4R2 evaluation for a minimum of 3612 calendar months
following completion of each evaluation where a CAP is not developed.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R5 and R6, including any supporting analysis per
Requirements R1, R2, R3, and R4, for a minimum of 12 calendar months
following completion of each CAP.
If a Generator Owner, Planning Coordinator, or Transmission Owner is found noncompliant, it shall keep information related to the non-compliance until mitigation
is complete and approved, or for the time specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3.
Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
As defined in the NERC Rules of Procedure; “Compliance Monitoring and
Assessment Processes” 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.
1.4.
Additional Compliance Information
None.
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PRC-026-1 — Relay Performance During Stable Power Swings
Table of Compliance Elements
R#
R1
Time
Horizon
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Planning
Coordinator identified
an Element and
provided notification
of the BES
Element(s) in
accordance with
Requirement R1, but
was less than or equal
to 30 calendar days
late.
Moderate VSL
High VSL
Severe VSL
The Planning
Coordinator identified
an Element and
provided notification
of the BES
Element(s) in
accordance with
Requirement R1, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Planning
Coordinator identified
an Element and
provided notification
of the BES
Element(s) in
accordance with
Requirement R1, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Planning
Coordinator identified
an Element and
provided notification
of the BES
Element(s) in
accordance with
Requirement R1, but
was more than 90
calendar days late.
OR
The Planning
Coordinator failed to
identify anprovide
notification of the
BES Element(s) in
accordance with
Requirement R1.
OR
The Planning
Coordinator failed to
provide notification in
accordance with
Requirement R1.
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R2
Time
Horizon
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Transmission
Owner identified an
Element and provided
notification in
accordance with
Requirement R2, but
was less than or equal
to 10 calendar days
late.
Moderate VSL
High VSL
Severe VSL
The Transmission
Owner identified an
Element and provided
notification in
accordance with
Requirement R2, but
was more than 10
calendar days and less
than or equal to 20
calendar days late.
The Transmission
Owner identified an
Element and provided
notification in
accordance with
Requirement R2, but
was more than 20
calendar days and less
than or equal to 30
calendar days late.
The Transmission
Owner identified an
Element and provided
notification in
accordance with
Requirement R2, but
was more than 30
calendar days late.
OR
The Transmission
Owner failed to
identify an Element in
accordance with
Requirement R2.
OR
The Transmission
Owner failed to
provide notification in
accordance with
Requirement R2.
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R3
Time
Horizon
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Generator Owner
identified an Element
and provided
notification in
accordance with
Requirement R3, but
was less than or equal
to 10 calendar days
late.
Moderate VSL
High VSL
Severe VSL
The Generator Owner
identified an Element
and provided
notification in
accordance with
Requirement R3, but
was more than 10
calendar days and less
than or equal to 20
calendar days late.
The Generator Owner
identified an Element
and provided
notification in
accordance with
Requirement R3, but
was more than 20
calendar days and less
than or equal to 30
calendar days late.
The Generator Owner
identified an Element
and provided
notification in
accordance with
Requirement R3, but
was more than 30
calendar days late.
OR
The Generator Owner
failed to identify an
Element in
accordance with
Requirement R3.
OR
The Generator Owner
failed to provide
notification in
accordance with
Requirement R3.
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R4R2
Time
Horizon
Operations
Planning
Violation Severity Levels
VRF
High
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner evaluated each
identified
Element’sits loadresponsive protective
relay(s) in accordance
with Requirement
R4R2, but was less
than or equal to 30
calendar days late.
The Generator Owner
or Transmission
Owner evaluated each
identified
Element’sits loadresponsive protective
relay(s) in accordance
with Requirement
R4R2, but was more
than 30 calendar days
and less than or equal
to 60 calendar days
late.
The Generator Owner
or Transmission
Owner evaluated each
identified
Element’sits loadresponsive protective
relay(s) in accordance
with Requirement
R4R2, but was more
than 60 calendar days
and less than or equal
to 90 calendar days
late.
The Generator Owner
or Transmission
Owner evaluated each
identified
Element’sits loadresponsive protective
relay(s) in accordance
with Requirement
R4R2, but was more
than 90 calendar days
late.
OR
The Generator Owner
or Transmission
Owner failed to
evaluate each
identified
Element’sits loadresponsive protective
relay(s) in accordance
with Requirement
R4R2.
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R5R3
R6R4
Time
Horizon
Long-term
Planning
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R5R3,
but in more than 60six
calendar daysmonths
and less than or equal
to 70seven calendar
daysmonths.
Medium The Generator Owner
or Transmission
Owner implemented,
a Corrective Action
Plan (CAP), but failed
to update a CAP,
when actions or
timetables changed, in
accordance with
Requirement R6R4.
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R5R3,
but in more than
70seven calendar
daysmonths and less
than or equal to
80eight calendar
daysmonths.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R5R3,
but in more than
80eight calendar
daysmonths and less
than or equal to
90nine calendar
daysmonths.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R5R3,
but in more than
90nine calendar
daysmonths.
N/A
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 223: November 4, 2014)
N/A
OR
The Generator Owner
or Transmission
Owner failed to
develop a CAP in
accordance with
Requirement R5R3.
The Generator Owner
or Transmission
Owner failed to
implement a
Corrective Action
Plan (CAP) in
accordance with
Requirement R6R4.
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PRC-026-1 — Relay Performance During Stable Power Swings
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
Burdy, John, Loss-of-excitation Protection for Synchronous Generators GER-3183, General
Electric Company.
IEEE Power System Relaying Committee WG D6, Power Swing and Out-of-Step
Considerations on Transmission Lines, July 2005: http://www.pes-psrc.org/Reports
/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission%20
Lines%20F..pdf.
Kimbark Edward Wilson, Power System Stability, Volume II: Power Circuit Breakers and
Protective Relays, Published by John Wiley and Sons, 1950.
KundarKundur, Prabha, Power System Stability and Control, 1994, Palo Alto: EPRI, McGraw
Hill, Inc.
NERC System Protection and Control Subcommittee, Protection System Response to Power
Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf.
Reimert, Donald, Protective Relaying for Power Generation Systems, 2006, Boca Raton: CRC
Press.
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment A
This standard includesapplies to any protective functions which could trip instantaneously or with
a time delay of less than 15 cycles, on load current (i.e., “load-responsive”) including, but not
limited to:
•
•
•
•
Phase distance
Phase overcurrent
Out-of-step tripping
Loss-of-field
The following protection functions are excluded from requirementsRequirements of this standard:
•
•
•
•
•
•
•
•
•
•
•
Relay elements supervised by power swing blocking
Relay elements that are only enabled when other relays or associated systems fail. For
example:
o Overcurrent elements that are only enabled during loss of potential conditions.
o ElementsRelay elements that are only enabled during a loss of communications
Thermal emulation relays which are used in conjunction with dynamic Facility Ratings
Relay elements associated with direct current (dc) lines
Relay elements associated with dc converter transformers
Phase fault detector relay elements employed to supervise other load-responsive phase
distance elements (e.g., in order to prevent false operation in the event of a loss of potential)
provided the distance element is set in accordance with the criteria outlined in the standard
Relay elements associated with switch-onto-fault schemes
Reverse power relay on the generator
Generator relay elements that are armed only when the generator is disconnected from the
system, (e.g., non-directional overcurrent elements used in conjunction with inadvertent
energization schemes, and open breaker flashover schemes)
Current differential relay, pilot wire relay, and phase comparison relay
Voltage-restrained or voltage-controlled overcurrent relays
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
Criteria A:
An impedance-based relay characteristic, used for tripping, that is expected to not trip for a
stable power swing, when the relay characteristic is completely contained within the portion
of the lens characteristicunstable power swing region. 3 The unstable power swing region is
formed by the union of three shapes in the impedance (R-X) plane; (1) a lower loss-ofsynchronism circle based on a ratio of the sending-end to receiving-end voltages of 0.7; (2) an
upper loss-of-synchronism circle based on a ratio of the receiving-end to sending-end voltages
of 1.43; (3) a lens that connects the endpoints of the total system impedance (with the parallel
transfer impedance removed) bounded by varying the sending-end and receiving-end voltages
from 0.70 to 1.0 per unit, while maintaining a constant system separation angle across the total
system impedance where:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
Rationale for Attachment B (Criteria A): The PRC-026-1, – Attachment B, Criteria A
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending-end and receiving-end
voltages varying from 0.7 to 1.0 per unit (See Guidelines and Technical Basis).
3
Guidelines and Technical Basis, Figures 1 and 2.
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
Criteria B:
The pickup of an overcurrent relay element used for tripping, that is above the calculated
current value (with the parallel transfer impedance removed) for the conditions below:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
4. Both the sending-end and receiving-end voltages at 1.05 per unit.
Rationale for Attachment B (Criteria B): The PRC-026-1, – Attachment B, Criteria B
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending-end and receiving-end
voltages at 1.05 per unit (See Guidelines and Technical Basis).
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PRC-026-1 — Relay Performance During Stable Power Swings
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PRC-026-1 – Application Guidelines
Guidelines and Technical Basis
Introduction
The NERC System Protection and Control Subcommittee technical document, Protection System
Response to Power Swings, August 2013 4 (“PSRPS Report” or “report”) was specifically prepared
to support the development of this NERC Reliability Standard. The report provided a historical
perspective on power swings as early as 1965 up through the approval of the report by the NERC
Planning Committee. The report also addresses reliability issues regarding trade-offs between
security and dependability of protection systemsProtection Systems, considerations for this NERC
Reliability Standard, and a collection of technical information about power swing characteristics
and varying issues with practical applications and approaches to power swings. Of these topics,
the report suggests an approach for this NERC Reliability Standard (“standard” or “PRC-026-1”)
which is consistent with addressing two of the three regulatory directives in the FERC Order No.
733. The first directive concerns the need for “…protective relay systems that differentiate
between faults and stable power swings and, when necessary, phases out protective relay systems
that cannot meet this requirement.” 5 Second, is “…to develop a Reliability Standard addressing
undesirable relay operation due to stable power swings.” 6 The third directive “…to consider
“islanding” strategies that achieve the fundamental performance for all islands in developing the
new Reliability Standard addressing stable power swings” 7 was considered during development
of the standard.
The development of this standard implements the majority of the approachapproaches suggested
by the report. However, it is noted that the Reliability Coordinator and Transmission Planner have
not been included in the standard’s Applicability section (as suggested by the PSRPS Report). This
is so that a single entity, the Planning Coordinator, may be the single source for identifying
Elements according to Requirement R1. A single source will insure that multiple entities will not
identify Elements in duplicate, nor will one entity fail to provide an Element because it believes
the Element is being provided by another entity. The Planning Coordinator has, or has access to,
the wide-area model and can correctly identify the Elements that may be susceptible to a stable
power swingor unstable power swing. Additionally, not including the Reliability Coordinator and
Transmission Planner is consistent with the applicability of other relay loadability NERC
Reliability Standards (e.g., PRC-023 and PRC-025). It is also consistent with the NERC Functional
Model.
The phrase, “while maintaining dependable fault detection and dependable out-of-step tripping”
in Requirement R1R2, describes that the Generator Owner and Transmission Owner is to comply
with this standard, while achieving its desired protection goals. Load-responsive protective relays,
4
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
5
Transmission Relay Loadability Reliability Standard, Order No. 733, P.150 FERC ¶ 61,221 (2010).
6
Ibid. P.153.
7
Ibid. P.162.
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PRC-026-1 – Application Guidelines
as addressed within this standard, may be intended to provide a variety of backup protection
functions, both within the generating unit or generating plant and on the Transmissiontransmission
system, and this standard is not intended to result in the loss of these protection functions. Instead,
it is suggested that the Generator Owner and Transmission Owner consider both the
requirementsRequirements within this standard and its desired protection goals, and perform
modifications to its protective relays or protection philosophies as necessary to achieve both.
Power Swings
The IEEE Power System Relaying Committee WG D6 developed a technical document called
Power Swing and Out-of-Step Considerations on Transmission Lines (July 2005) that provides
background on power swings. The following are general definitions from that document: 8
Power Swing: a variation in three phase power flow which occurs when the generator rotor
angles are advancing or retarding relative to each other in response to changes in load
magnitude and direction, line switching, loss of generation, faults, and other system
disturbances.
Pole Slip: a condition whereby a generator, or group of generators, terminal voltage angles
(or phases) go past 180 degrees with respect to the rest of the connected power system.
Stable Power Swing: a power swing is considered stable if the generators do not slip poles
and the system reaches a new state of equilibrium, i.e. an acceptable operating condition.
Unstable Power Swing: a power swing that will result in a generator or group of generators
experiencing pole slipping for which some corrective action must be taken.
Out-of-Step Condition: Same as an unstable power swing.
Electrical System Center or Voltage Zero: it is the point or points in the system where the
voltage becomes zero during an unstable power swing.
Burden to Entities
The PSRPS Report provides a technical basis and approach for focusing on Protection Systems,
which are susceptible to power swings, while achieving the reliability objective.purpose of the
standard. The approach reduces the number of relays thatto which the PRC-026-1 Requirements
would apply to by first identifying the Bulk Electric System (BES) Element(s) that need toon
which load-responsive protective relays must be evaluated. The first step uses criteria to identify
a BES Elementthe Elements on which a Protection System is expected to be challenged by power
swings. Of those BES Elements, the second step is to evaluate each load-responsive protective
relay that is applied on each identified Element. Rather than requiring the Planning Coordinator or
Transmission Planner to perform simulations to obtain information for each identified Element,
the Generator Owner and Transmission Owner will reduce the need for simulation by comparing
8
http://www.pes-psrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission
%20Lines%20F..pdf.
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PRC-026-1 – Application Guidelines
the load-responsive protective relay characteristic to specific criteria found in PRC-026-1 –
Attachment B.
Applicability
The standard is applicable to the Generator Owner, Planning Coordinator, and Transmission
Owner entities. More specifically, the Generator Owner and Transmission Owner entities are
applicable when applying load-responsive protective relays at the terminals of the applicable BES
Elements. All the entities have a responsibility to identify the Elements which meet specific
criteria. The standard is applicable to the following BES Elements: generators, transformers, and
transmission lines, and transformers. The Distribution Provider was considered for inclusion in the
standard; however, it is not subject to the standard because this entity, by functional registration,
would not own generators, transmission lines, or transformers other than load serving.
Load-responsive protective relays include any protective functions which could trip with or
without time delay, on load current.
Requirement R1
The Planning Coordinator has a wide-area view and is in the positon to identify what, if any,
Elements meet the criteria. The criterion-based approach is consistent with the NERC System
Protection and Control Subcommittee (SPCS) technical document Protection System Response to
Power Swings (August 2013), 9 which recommends a focused approach to determine an at-risk
Element. Identification of Elements comes from the annual Planning Assessments pursuant to the
transmission planning (i.e., “TPL”) and other NERC Reliability Standards, (e.g., PRC-006), and
the standard is not requiring any other assessments to be performed by the Planning Coordinator.
The required annual notification on a calendar year basis to the respective Generator Owner and
Transmission Owner is sufficient because it is expected that the Planning Coordinator will make
its notifications following the completion of its annual Planning Assessments. The Planning
Coordinator will continue to provide notification of Elements on a calendar year basis even if a
study is performed less frequently (e.g., PRC-006 – Automatic Underfrequency Load Shedding,
which is five years) and has not changed. It is possible that the Planning Coordinator provided
notification of Elements in two different calendar years using the same annual Planning
Assessment.
Criterion 1
The first criterion involves generator(s) where an angular stability constraint exists whichthat is
addressed by an operating limita System Operating Limit (SOL) or a Remedial Action Scheme
(RAS) and those Elements terminating at the transmission switchingTransmission station
associated with the generator(s). For example, a scheme to remove generation for specific
conditions is implemented for a four-unit generating plant (1,100 MW). Two of the units are 500
9
http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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PRC-026-1 – Application Guidelines
MW each; one is connected to the 345 kV system and one is connected to the 230 kV system. The
Transmission Owner has two 230 kV transmission lines and one 345 kV transmission line all
terminating at the generating facility as well as a 345/230 kV autotransformer. The remaining 100
MW consists of two 50 MW combustion turbine (CT) units connected to four 66 kV transmission
lines. The 66 kV transmission line is not electrically joined to the 345 kV and 230 kV transmission
lines at the plant site and is not a part of the operating limit or RAS. A stability constraint limits
the output of the portion of the plant affected by the RAS to 700 MW for an outage of the 345 kV
transmission line. The RAS trips one of the 500 MW units to maintain stability for a loss of the
345 kV transmission line when the total output from both 500 MW units is above 700 MW. For
this example, both 500 MW generating units and the associated generator step-up (GSU)
transformers would be identified as Elements meeting this criterion. The 345/230 kV
autotransformer, the 345 kV transmission line, and the two 230 kV transmission lines would also
be identified as Elements meeting this criterion. The 50 MW combustion turbines and 66 kV
transmission lines would not be identified pursuant to Criterion 1 because these Elements are not
subject to an operating limit or RAS and do not terminate at the transmission
switchingTransmission station associated with the generators that are subject to the operating limit
andSOL or RAS.
Criterion 2
The second criterion involves Elements that are monitored due toas a part of an established System
Operating Limit (SOL) based on an angular stability limit regardless of the outage conditions that
result in the enforcement of the SOL. For example, if two long parallel 500 kV transmission lines
have a combined SOL of 1,200 MW, and this limit is based on angular instability resulting from a
fault and subsequent loss of one of the two lines, then both lines would be identified as an Element
meeting the criterion.
Criterion 3
The third criterion involves the ElementElements that formsform the boundary of an island due to
angular instability within an underfrequency load shedding (UFLS) design assessment. While the
island may form due to various transmission lines tripping for a combination of reasons, such as
stable and unstable power swings, faults, and excessive loading, the The criterion requires that all
lines that tripped in simulation due to “angular instability” to form the island beapplies to islands
identified as meeting the based on application of the Planning Coordinator’s criteria for identifying
islands, where the island is formed by tripping the Elements based on angular instability. The
criterion applies if the angular instability is modeled in the UFLS design assessment, or if the
boundary is identified “off-line” (i.e., the Elements are selected based on angular instability
considerations, but the Elements are tripped in the UFLS design assessment without modeling the
initiating angular instability). In cases where an out-of-step condition is detected and tripping is
initiated at an alternate location, the criterion applies to the Element on which the power swing is
detected. The criterion does not apply to islands identified based on other considerations that do
not involve angular instability, such as excessive loading.
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Criterion 4
The fourth criterion involves Elements identified in the most recent annual Planning Assessment
where relay tripping occurs due to a stable or unstable power swing during a simulated disturbance.
The intent is for the Planning Coordinator to include any Element(s) where relay tripping was
observed during simulations performed for the most recent annual Planning Assessment associated
with the transmission planning TPL-001-4 Reliability Standard. Note that relay tripping must be
assessed within those annual Planning Assessments per TPL-001-4, R4, Part 4.3.1.3, which
indicates that analysis shall include the “Tripping of Transmission lines and transformers where
transient swings cause Protection System operation based on generic or actual relay models.”
Identifying such Elements according to criterionCriterion 4 and notifying the respective Generator
Owner and Transmission Owner will require that the owners of any load-responsive protective
relay applied at the terminals of the identified Element evaluate the relay’s susceptibility to
tripping in response a stable power swing.
Planning Coordinators have discretion to determine whether observed tripping for a power swing
in its Planning Assessments occurs for valid contingencies and system conditions. The Planning
Coordinator will address tripping that is observed in transient analyses on an individual basis;
therefore, the Planning Coordinator is responsible for identifying the Elements based only on
simulation results that are determined to be valid.
Due to the nature of how a Planning Assessment is performed, there may be cases where a
previously -identified Element is not identified in the most recent annual Planning Assessment. If
so, this is acceptable because the Generator Owner and Transmission Owner would have taken
action upon the initial notification of the previously identified Element. When an Element is not
identified in later Planning Assessments, the risk of load-responsive protective relays tripping in
response to a stable power swing during non-Fault conditions would have already been assessed
under Requirement R4R2 and mitigated according to Requirements R5R3 and R6 when
appropriate.R4 where the relays did not meet the PRC-026-1 – Attachment B criteria. According
to Requirement R4R2, the Generator Owner and Transmission Owner are only required to reevaluate each load-responsive protective relay for an identified Element where the evaluation has
not been performed in the last threefive calendar years.
Criterion 5
The fifth criterion involves Elements that have actually tripped due to a stable or unstable power
swing as reported by the Generator Owner and Transmission Owner. The Planning Coordinator
will continue to identify each reported Element until the Planning Coordinator determines that the
Element is expected to not trip in response to power swings due to BES configuration changes.
For example, eight lines interconnecting areas containing both generation and load to the rest of
the BES, and five of the lines terminate on a single straight bus as shown in Figure 1. A forced
outage of the straight bus in the past caused an island to form by tripping open the five lines
connecting to the straight bus, and subsequently causing the other three lines into the area to trip
on power swings. If the BES is reconfigured such that the five lines into the straight bus are now
divided between two different substations, the Planning Coordinator may determine that the
changes eliminated susceptibility to power swings as shown in Figure 2. If so, the Planning
Coordinator is no longer required to identify these Elements previously reported by either the
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Transmission Owner pursuant to Requirement R2 or Generator Owner pursuant to Requirement
R3.
Single Tie-line
Single Tie-line
Area
with generation
and load
Straight Bus
Single Tie-line
Single Tie-line
Single Tie-line
Area
with generation
and load
Straight Bus A
Single Tie-line
Straight Bus B
Figure 1. Criterion five example of an area Figure 2. Criterion five example of an area
with generation and load that experienced a with generation and load that was later
power swing.
reconfigured and determined to no longer be
susceptible to power swings.
Although Requirement R1 requires the Planning Coordinator to notify the respective Generator
Owner and Transmission Owner of any Elements meeting the one or more of the fivefour criteria,
it does not preclude the Planning Coordinator from providing additional information, such as
apparent impedance characteristics, in advance or upon request, that may be useful in evaluating
protective relays. Generator Owners and Transmission Owners are able to complete protective
relay evaluations and perform the required actions without additional information. The standard
does not includedinclude any requirement for the entities to provide information that is already
being shared or exchanged between entities for operating needs. While a requirementRequirement
has not been included for the exchange of information, entities mustshould recognize that relay
performance needs to be measured against the most current information.
Requirement R2
The approach of Requirement R2 requires the Transmission Owner to identify Elements that meet
the focused criteria. Only the Elements that meet the criteria and apply a load-responsive protective
relay at the terminal of the Element are in scope. Using the criteria focuses the reliability concern
on the Element that is at-risk to power swings.
The first criterion involves Elements that have tripped due to a power swing during an actual
system Disturbance, regardless of whether the power swing was stable or unstable. Elements that
have tripped by unstable power swings are included in this requirement because they were not
identified in Requirement R1 and this forms a basis for evaluating the load responsive relay
operation for stable power swings. After this standard becomes effective, if it is determined in an
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outage investigation that an Element tripped because of a power swing condition (either stable or
unstable), this standard will become applicable to the Element. An example of an identified
Element is an Element tripped by a distance relay element (i.e., a relay with a time delay of less
than 15 cycles) during a power swing condition. Another example that would identify an Element
is where out-of-step (OOS) tripping is applied on the Element, and if a legitimate OOS trip
occurred as expected during a power swing event.
The second criterion involves the formation of an island based on an actual system Disturbance.
While the island may form due to several transmission lines tripping for a combination of reasons,
such as power swings (stable or unstable), faults, or excessive loading, the criterion requires that
all Elements that tripped to form the island be identified as meeting this criterion. For example,
the Disturbance may have been initiated by one line faulting with a second line being out of service.
The outage of those two lines then initiated a swing condition between the “island” and the rest of
the system across the remaining ties causing the remaining ties to open. A second case might be
that the island could have formed by a fault on one of the other ties with a line out of service with
the swing going across the first and second lines mentioned above resulting in those lines opening
due to the swing. Therefore, the inclusion of all the Elements that formed the boundary of the
island are included as Elements to be reported to the Planning Coordinator.
The owner of the load-responsive protective relay that tripped for either criterion is required to
identify the Element and notify its Planning Coordinator. Notifying the Planning Coordinator of
the Element ensures that the planner is aware of an Element that is susceptible to a power swing
or formed an island. The Planning Coordinator will continue to notify the respective entities of the
identified Element under Requirement R1, Criterion 5 unless the Planning Coordinator determines
the Element is no longer susceptible to power swings.
Requirement R3
Requirement R3 is similar to Requirement R2, Criterion 1 and requires the Generator Owner to
identify any Element that trips due to a power swing condition (stable or unstable) in an actual
event. This standard does not focus on the review of Protection Systems because they are covered
by other NERC Reliability Standards. When a review of the Generator Owner’s Protection System
reveals that tripping occurred due to a power swing, it is required to identify the Element and to
notify its Planning Coordinator. Notifying the Planning Coordinator of the Element ensures that
the planner is aware of an Element that was susceptible to a power swing. The Planning
Coordinator will continue to notify entities of the identified Element under Requirement R1 unless
the Planning Coordinator determines the Element is no longer susceptible to power swings.
Requirement R4
Requirement R4Requirement R2 requires the Generator Owner and Transmission Owner to
evaluate its load-responsive protective relays applied at all of the terminals of an identified Element
to ensure that load-responsive protective relays they are expected to not trip in response to stable
power swings during non-Fault conditions. .
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The PRC-026-1 – Attachment A lists the applicable load-responsive relays that must be evaluated.
These relays include phase distance, phase overcurrent, out-of-step tripping, and loss-of-field.
Phase distance relays can include the following:
•
•
Mho element characteristics such as Zone 1, Zone 2, or Zone 3 with intentional time delays
of 15 cycles or less.
Mho element characteristics that overreach the remote line terminal used in high-speed,
communications assisted tripping schemes including:
Directional Comparison Blocking (DCB) schemes
Directional Comparison Un-Blocking (DCUB) schemes
Permissive Overreach Transfer Trip (POTT) schemes
A method is provided within the standard to support consistent evaluation by Generator Owners
and Transmission Owners based on specified conditions. Once a Generator Owner or Transmission
Owner is notified of Elements pursuant to Requirement R1, or once a Generator Owner or
Transmission Owner identifies an Element pursuant to Requirement R2 or R3, it has 12 full
calendar months to evaluatedetermine if each Element’s load-responsive protective relays based
onmeet the applicable PRC-026-1 – Attachment B, Criteria A and B criteria, if the evaluation
hasn’tdetermination has not been performed in the last threefive calendar years. Additionally, each
Generator Owner and Transmission Owner, that becomes aware of a generator, transformer, or
transmission line BES Element that tripped in response to a stable or unstable power swing due to
the operation of its protective relays, must perform the same PRC-026-1 – Attachment B criteria
determination within 12 full calendar months.
Becoming Aware of an Element That Tripped in Response to a Power Swing
Part 2.2 in Requirement R2 is intended to initiate action by the Generator Owner and Transmission
Owner when there is a known stable or unstable power swing and it resulted in the entity’s Element
tripping. The criterion starts with becoming aware of the event (i.e., power swing) and then any
connection with the entity’s Element tripping. By doing so, the focus is removed from the entity
having to demonstrate that it performed a power swing analysis for every Element trip. The basis
for structuring the criterion in this manner is driven by the available ways that a Generator Owner
and Transmission Owner could become aware of an Element that tripped in response to a stable or
unstable power swing due to the operation of its protective relay(s).
Element trips caused by stable or unstable power swings, though infrequent, would be more
common in a larger event. The identification of power swings will be revealed during an analysis
of the event. Event analysis could include internal analysis conducted by the entity, the entity’s
Protection System review following a trip, or a larger scale analysis which includes involvement
by the entity’s Regional Entity and in some cases NERC.
Information Common to Both Generation and Transmission Elements
The PRC-026-1 – Attachment A lists the load-responsive protective relays that are subject to this
standard. Generator Owners and Transmission Owners may own load–-responsive protective
relays (i.e.., distance relays) that directly affect generation or transmission BES Elements and will
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require analysis as a result of Elements being identified by Requirements R1, R2 or R3.the
Planning Coordinator in Requirement R1 or the Generator Owner or Transmission Owner in
Requirement R2. For example, distance relays owned by the Transmission Owner may be installed
at the high-voltage side of the generator step-up (GSU) transformer (directional toward the
generator) providing backup to generation protection. Generator Owners may have distance relays
applied for back-upto backup transmission protection or back-upbackup protection forto the GSU
transformer. The Generator Owner may have relays installed at the generator terminals or the highvoltage side of the GSU transformer.
Exclusion of Time Based Load-Responsive Protective Relays
The purpose of the standard is “To“[t]o ensure that load-responsive protective relays are expected
to not trip in response to stable power swings during non-Fault conditions.” Load-responsive
protective relays with , high-speed tripping protective relays pose the highest risk of operating
during a power swing. Because of this, high-speed tripping isprotective relays and relays with a
time delay of less than 15 cycles are included in the standard and others (Zone; whereas other
relays (i.e., Zones 2 and 3) with a time a delay of 15 cycles or greater are excluded. The time delay
used for exclusion on some load-responsive protective relays is recommended based on 1) the
minimum time delay these relays are set in practice, and 2) the maximum expected time that loadresponsive protective relays would be exposed to thea stable power swing based on a swing rate.
In order to establish a time delay that strikes a line betweendistinguishes a high-risk loadresponsive protective relay andfrom one that has a time delay for tripping, (lower-risk), a sample
of swing rates were calculated based on a stable power swing entering and leaving the impedance
characteristic as shown in Table 1. For a relay impedance characteristic that has the power swing
entering and leaving beginning at 90 degrees with a termination at 120 degrees before exiting the
zone, calculation of the timer must be greater than the time the stable swing is inside the relay
operate zone.
E
q.
(1
)
𝑍𝑍𝑍𝑍𝑍𝑍𝑍𝑍 𝑡𝑡𝑡𝑡𝑡𝑡𝑒𝑒
> 2
�
(120° − 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑜𝑜𝑜𝑜 𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒 𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖 𝑡𝑡ℎ𝑒𝑒 𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟 𝑐𝑐ℎ𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎) (120° − 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑜𝑜𝑜𝑜 𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒 𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖 𝑡𝑡
��
(360 × 𝑆𝑆
𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅
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Table 1. Swing Rates
Zone Timer
Slip Rate
(Cycles)
(Hz)
10
1.00
15
0.67
20
0.50
30
0.33
With a minimum zone timer of 15 cycles, the corresponding slip of the system is 0.67 Hz. This
represents an approximation of a slow slip rate during a system Disturbance. ThisConsequently,
this value corresponds to the typical minimum time delay used for zoneZone 2 distance relays in
transmission line protection. Longer time delays allow for slower slip rates.
Application to Transmission Elements
The criteriaCriteria A in PRC-026-1 – Attachment B describe a lens characteristicdescribes an
unstable power swing region that is formed by the union of three shapes in the impedance (R-X)
plane. The first shape is a lower loss of synchronism circle based on a ratio of the sending-end to
receiving-end voltages of 0.7 (i.e., E S / E R = 0.7 / 1.0 = 0.7). The second shape is an upper loss of
synchronism circle based on a ratio of the receiving-end to sending-end voltages of 1.43 (i.e., E R
/ E S = 1.0 / 0.7 = 1.43). The third shape is a lens that connects the endpoints of the total system
impedance together by varying the sending-end and receiving-end system voltages from 0.70 to
1.0 per unit, while maintaining a constant system separation angle across the total system
impedance (with the parallel transfer impedance removed—see Figures 31 through 5). The total
system impedance is derived from a two-bus equivalent network and is determined by summing
the sending-end source impedance, the line impedance (excluding the Thévenin equivalent transfer
impedance), and the receiving-end source impedance as shown in Figures 6 and 7. The goal in
establishing the total system impedance is to represent a conservative condition that will maximize
the security of the relay against various system conditions. The smallest total system impedance
represents a condition where the size of the lens characteristic in the R-X plane is smallest and is
a conservative operating point from the standpoint of ensuring a load -responsive protective relay
willis expected to not trip given a predetermined angular displacement between the sending-end
and receiving-end voltages. The smallest total system impedance results when all generation is in
service and all transmission elementsBES Elements are modeled in their “normal” system
configuration (PRC-026-1 – Attachment B, Criteria A). The parallel transfer impedance is
removed to represent a likely condition where parallel elements may be lost during the disturbance,
and the loss of these elements magnifies the sensitivity of the load-responsive relays on the parallel
line by removing the “infeed effect” (i.e., the apparent impedance sensed by the relay is decreased
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PRC-026-1 – Application Guidelines
as a result of the loss of the transfer impedance, thus making the relay more likely to trip for a
stable power swing—See Figures 13 and 14).
The sending-end and receiving-end source voltages are varied from 0.7 to 1.0 per unit to form a
portionthe lower and upper loss of a lens characteristic instead of varying the voltages from 0 to
1.0 per unit, which would form a full-lens characteristic.synchronism circles. The ratio of these
two voltages is used in the calculation of the portionloss of the lenssynchronism circles, and result
in a ratio range from 0.7 to 1.43.
Eq. (2)
𝐸𝐸𝑆𝑆 0.7
=
= 0.7
𝐸𝐸𝑅𝑅 1.0
Eq. (3):
𝐸𝐸𝑅𝑅 1.0
=
= 1.43
𝐸𝐸𝑆𝑆 0.7
The internal generator voltage during severe power swings or transmission system fault conditions
will be greater than zero, due to voltage regulator support. The voltage ratio of 0.7 to 1.43 is chosen
to be more conservative than the PRC-023 10 and PRC-025 11 NERC Reliability Standards, where
a lower bound voltage of 0.85 per unit voltage is used. A plus and minus ±15% internal generator
voltage range was chosen as a conservative voltage range for calculation of the voltage ratio that
would determineused to calculate the end pointsloss of the portion of the lenssynchronism circles.
For example, the voltage ratio using these voltages would result in a ratio range from 0.739 to
1.353.
Eq. (4)
𝐸𝐸𝑆𝑆 0.85
=
= 0.739
𝐸𝐸𝑅𝑅 1.15
Eq. (5):
𝐸𝐸𝑅𝑅 1.15
=
= 1.353
𝐸𝐸𝑆𝑆 0.85
The lower ratio is rounded down to 0.7 to be more conservative, allowing a voltage range of 0.7
to 1.0 per unit to be used for the calculation of the lens end pointsloss of synchronism circles. 12
When the parallel transfer impedance is included in the model, the split in current through the
parallel transfer impedance path results in actual measured relay impedances that are larger than
those measured when the parallel transfer impedance is removed (i.e., infeed effect), which would
make it more likely for an impedance relay element to be completely contained within the
applicable portion of the lens characteristicunstable power swing region in Figure 11. If the transfer
impedance is included in the lens evaluation, a distance relay element could be deemed as meeting
PRC-026-1 – Attachment B and, in fact would be secure, assuming all elements were in their
normal state. In this case, itthe distance relay element could trip for a stable power swing during
an actual event if the system was weakened (i.e., a higher transfer impedance) by the loss of a
subset of lines that make up the parallel transfer impedance. This could happen because thosethe
subset of lines that make up the parallel linestransfer impedance tripped on unstable swings,
10
Transmission Relay Loadability
11
Generator Relay Loadability
12
Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations,
April 2004, Section 6 (The Cascade Stage of the Blackout), p. 94 under “Why the Generators Tripped Off,” states,
“Some generator undervoltage relays were set to trip at or above 90% voltage. However, a motor stalls out at about
70% voltage and a motor starter contactor drops out around 75%, so if there is a compelling need to protect the
turbine from the system the under-voltage trigger point should be no higher than 80%.”
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contained the initiating fault, and/or were lost due to operation of breaker failure or remote backup protection schemes in Figure 10.
Table 10 shows the percent size increase of the lens shape as seen by the relay under evaluation
when the parallel transfer impedance is included. The parallel transfer impedance has minimal
effect on the apparent size of the lens shape as long as the parallel transfer impedance is at least
10 multiples of the parallel line impedance (less than 5% lens shape expansion), therefore, its
removal has minimal impact, but results in a slightly more conservative, smaller lens shape.
Transfer impedances of 5 multiples of the parallel line impedance or less result in an apparent lens
shape size of 10% or greater as seen by the relay. If two parallel lines and a parallel transfer
impedance tie the sending-end and receiving-end buses together, the total parallel transfer
impedance will be one or less multiples of the parallel line impedance, resulting in an apparent
lens shape size of 45% or greater. It is a realistic contingency that the parallel line could be outof-service, leaving the transfer impedance making up the rest of the system in parallel with the line
impedance. Since it is not known exactly which lines making up the parallel transfer impedance
that will be out of service during a major system disturbance, it is most conservative to assume
that all of them are out, leaving just the line under evaluation in service.
Either the saturated transient or sub-transient direct axis reactance values may be used for machines
in the evaluation because they are smaller than un-saturated reactance values. Since, sub-transient
saturated generator reactances are smaller than the transient or synchronous reactance, they result
in a smaller source impedance and a smaller lens characteristicunstable power swing region in the
graphical analysis as shown in Figures 8 and 9. Since power swings occur in a time frame where
generator transient reactances will be prevalent, it is acceptable to use saturated transient
reactances instead of saturated sub-transient reactance values. Some short-circuit models may not
include transient reactance values, so in this case, the use of sub-transient is acceptable because it
also produces more conservative results than transient reactances. For this reason, either value is
acceptable when determining the system source impedances (PRC-026-1 – Attachment B, Criteria
A and B, No. 3).
Saturated reactance values are also the values used in short-circuit programs that produce the
system impedance mentioned above. Planning and stability software generally use the un-saturated
reactance values. Generator models used in transient stability analyses recognize that the extent of
the saturation effect depends upon both rotor (field) and stator currents. Accordingly, they derive
the effective saturated parameters of the machine at each instant by internal calculation from the
specified (constant) unsaturated values of machine reactances and the instantaneous internal flux
level. The specific assumptions regarding which inductances are affected by saturation, and the
relative effect of that saturation, are different for the various generator models used. Thus,
unsaturated values of all machine reactances are used in setting up planning and stability software
data, and the appropriate set of open-circuit magnetization curve data is provided for each machine.
Saturated reactance values are smaller than unsaturated reactance values and are used in shortcircuit programs owned by the Generator and Transmission Owners. Because of this, saturated
reactance values are to be used in the development of the system source impedances.
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The source or system equivalent impedances can be obtained by a number of different methods
using commercially available short-circuit calculation tools. 13 Most short-circuit tools have a
network reduction feature that allows the user to select the local and remote terminal buses to
retain. The first method reduces the system to one that contains two buses, an equivalent generator
at each bus (representing the source impedance at the sending-end and receiving-ends), and two
parallel lines; one being the line impedance of the protected line with relays being analyzed, the
other being the transfer impedance representing all other combinations of lines that connect the
two buses together as shown in Figure 6. Another conservative method is to open both ends of the
line in question, and apply a three-phase bolted fault at each bus. The resulting source impedance
at each end will be less than or equal to the actual source impedance calculated by the network
reduction method. Either method can be used to develop the system source impedances at both
ends.
The two bullets of PRC-026-1 – Attachment B, Criteria A, No. 1, identify the system separation
angles to identify the size of the power swing stability boundary to be used to test load-responsive
protective relay impedance relay elements. Both bullets test impedance relay elements that are not
supervised by power swing blocking. (PSB). The first bullet of PRC-026-1 – Attachment B,
Criteria A, No. 1 evaluates a system separation angle of at least 120 degrees that is held constant
while varying the sending-end and receiving-end source voltages from 0.7 to 1.0 per unit, thus
creating aan unstable power swing stability boundary shaped like a portion of a lensregion about
the total system impedance in Figure 31. This portion of a lens characteristicunstable power swing
region is compared to the tripping portion of the distance relay characteristic,; that is, the portion
that is not supervised by load encroachment, blinders, or some other form of supervision as shown
in Figure 12 that restricts the distance element from tripping for heavy, balanced load conditions.
If the tripping portion of the impedance characteristics are completely contained within the portion
of a lens characteristicunstable power swing region, the Elementrelay impedance element meets
Criteria A in PRC-026-1 – Attachment B. A system separation angle of 120 degrees was chosen
for the evaluation where PSB is not applied because it is generally accepted in the industry that
recovery for a swing beyond this angle is unlikely to occur. 14
The second bullet of PRC-026-1 – Attachment B, Criteria A, No. 1 evaluates impedance relay
elements at a system separation angle of less than 120 degrees, similar to the first bullet described
above. An angle less than 120 degrees may be used if a documented stability analysis demonstrates
that the power swing becomes unstable at a system separation angle of less than 120 degrees.
The exclusion of relay elements supervised by PSB in PRC-026-1 – Attachment A allows the
Generator Owner or Transmission Owner to exclude protective relay elements if they are blocked
13
Demetrios A. Tziouvaras and Daqing Hou, Appendix in Out-Of-Step Protection Fundamentals and
Advancements, April 17, 2014: https://www.selinc.com.
14
“The critical angle for maintaining stability will vary depending on the contingency and the system condition at
the time the contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is
marginal and 120 degrees is generally accepted as an appropriate basis for setting out‐of‐step protection. Given the
importance of separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a
proper balance between dependable tripping for unstable power swings and secure operation for stable power
swings.” NERC System Protection and Control Subcommittee, Protection System Response to Power Swings,
August 2013: http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20
SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf), p. 28.
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from tripping by PSB relays. A PSB relay applied and set according to industry accepted practices
prevent supervised load-responsive protective relays from tripping in response to power swings.
Further, PSB relays are set to allow dependable tripping of supervised elements. The criteria in
PRC-026-1 – Attachment B specifically applies to unsupervised elements that could trip for stable
power swings. Therefore, load-responsive protective relay elements supervised by PSB can be
excluded from the Requirements of this standard.
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Figure 3. The portion of 1. An enlarged graphic illustrating the lens characteristic that isunstable
power swing region formed by the union of three shapes in the impedance (R-X) plane. The
pilot zone 2 relay : Shape 1) Lower loss of synchronism circle, Shape 2) Upper loss of
synchronism circle, and Shape 3) Lens. The mho element characteristic is completely contained
within the portion of the lensunstable power swing region (e.g., it does not intersect any portion
of the partial lensunstable power swing region), therefore it complies with PRC-026-1 –
Attachment B, Criteria A, No. 1.
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Figure 4. System impedance as seen by relay R.Figure 2. Full graphic of unstable power swing
region formed by the union of three shapes in the impedance (R-X) plane: Shape 1) Lower loss
of synchronism circle, Shape 2) Upper loss of synchronism circle, and Shape 3) Lens. The mho
element characteristic is completely contained within the unstable power swing region, therefore
it meets PRC-26-1 – Attachment B, Criteria A, No.1.
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Figure 5. Lens characteristic with the transfer3. System impedance included and contains
specific points identified for the calculationsas seen by relay R.
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Figure 4. The defining unstable power swing region points where the lens shape intersects the
lower and upper loss of synchronism circle shapes and where the lens intersects the equal EMF
(electromotive force) power swing.
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Figure 5. Full table of 31 detailed lens shape point calculations. The bold highlighted rows
correspond to the detailed calculations in Tables 2-7.
Table 2. Example Calculation (Lens Point 1)
This example is for calculating the impedance the first point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) leading
the receiving-end voltage (E R ) by 120 degrees. See Figures 43 and 54.
Eq. (6)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
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Table 2. Example Calculation (Lens Point 1)
Eq. (7)
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (8)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (9)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (10)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50 )Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,511∠71.3° 𝐴𝐴
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
Eq. (11)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴
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Table 2. Example Calculation (Lens Point 1)
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (12)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10) Ω × 4,511∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,757∠106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (13)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,757∠106.1° 𝑉𝑉
4,511∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 17.434 + 𝑗𝑗12.113 Ω
Table 3. Example Calculation (Lens Point 2)
This example is for calculating the impedance second point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) at 70% of
the receiving-end voltage (E R ) and leading the receiving-end voltage by 120 degrees. See
Figures 43 and 54.
Eq. (14)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (15)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
× 70%
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 92,953.7∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
× 0.70
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
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Table 3. Example Calculation (Lens Point 2)
Total impedance between generators.
Eq. (16)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (17)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (18)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
92,953.7∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠77° 𝐴𝐴
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (19)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠77° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠77° 𝐴𝐴
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (20)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 92,953∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 )Ω × 3,854∠77° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 65,271∠99° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (21)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
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Table 3. Example Calculation (Lens Point 2)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
65,271∠99° 𝑉𝑉
3,854∠77° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 15.676 + 𝑗𝑗6.41 Ω
Table 4. Example Calculation (Lens Point 3)
This example is for calculating the impedance third point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (E R ) at 70%
of the sending-end voltage (E S ) and the sending-end voltage leading the receiving-end voltage
by 120 degrees. See Figures 43 and 54.
Eq. (22)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (23)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
× 70%
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 92,953.7∠0° 𝑉𝑉
× 0.70
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (24)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (25)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
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Table 4. Example Calculation (Lens Point 3)
Total system current from sending-end source.
Eq. (26)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 92,953.7∠0° 𝑉𝑉
(10 + 𝑗𝑗50) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠65.5° 𝐴𝐴
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (27)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠65.5° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠65.5° 𝐴𝐴
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (28)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10) Ω × 3,854∠65.5° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 98,265∠110.6° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (29)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
98,265∠110.6° 𝑉𝑉
3,854∠65.5° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 18.005 + 𝑗𝑗18.054 Ω
Table 5. Example Calculation (Lens Point 4)
This example is for calculating the impedance fourth point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) leading
the receiving-end voltage (E R ) by 240 degrees. See Figures 43 and 54.
Eq. (30)
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
√3
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Table 5. Example Calculation (Lens Point 4)
𝐸𝐸𝑆𝑆 =
Eq. (31)
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠240° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (32)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (33)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (34)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠240° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50 )Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,510∠131.3° 𝐴𝐴
The current as measured by the relay on ZL is only the current flowing through that line as
determined by using the current divider equation.
Eq. (35)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
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Table 5. Example Calculation (Lens Point 4)
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,510∠131.1° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,510∠131.1° 𝐴𝐴
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (36)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 ) Ω × 4,510∠131.1° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,756∠ − 106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (37)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,756∠ − 106.1° 𝑉𝑉
4,510∠131.1° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −11.434 + 𝑗𝑗17.887 Ω
Table 6. Example Calculation (Lens Point 5)
This example is for calculating the impedance fifth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) at 70% of
the receiving-end voltage (E R ) and leading the receiving-end voltage by 240 degrees. See
Figures 43 and 54.
Eq. (38)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (39)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
× 70%
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 92,953.7∠240° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
× 0.70
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
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Table 6. Example Calculation (Lens Point 5)
Given:
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
Total impedance between generators.
Eq. (40)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (41)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10 Ω) + (4 + 𝑗𝑗20 Ω) + (4 + 𝑗𝑗20 Ω)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (42)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
92,953.7∠240° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠125.5° 𝐴𝐴
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
Eq. (43)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠125.5° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠125.5° 𝐴𝐴
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (44)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 92,953.7∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 ) Ω × 3,854∠125.5° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 65,270.5∠ − 99.4° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (45)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
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Table 6. Example Calculation (Lens Point 5)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
65,270.5∠ − 99.4° 𝑉𝑉
3,854∠125.5° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −12.005 + 𝑗𝑗11.946 Ω
Table 7. Example Calculation (Lens Point 6)
This example is for calculating the impedance sixth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (E R ) at 70%
of the sending-end voltage (E S ) and the sending-end voltage leading the receiving-end voltage
by 240 degrees. See Figures 43 and 54.
Eq. (46)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠240° 𝑉𝑉
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
Eq. (47)
𝐸𝐸𝑅𝑅 =
× 70%
√3
230,000∠0° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
× 0.70
√3
𝐸𝐸𝑅𝑅 = 92,953.7∠0° 𝑉𝑉
Given positive sequence impedance data (The transfer impedance Z TR is set to infinity).
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
10
Given:
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 10 Ω
Total impedance between generators.
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
Eq. (48)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
Eq. (49)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
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Table 7. Example Calculation (Lens Point 6)
Total system current from sending-end source.
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
Eq. (50)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠240° 𝑉𝑉 − 92,953.7∠0° 𝑉𝑉
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠137.1° 𝐴𝐴
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
𝑍𝑍𝑇𝑇𝑇𝑇
Eq. (51)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠137.1° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 3,854∠137.1° 𝐴𝐴
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (52)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 )Ω × 3,854∠137.1° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 98,265∠ − 110.6° 𝑉𝑉
The impedance seen by the relay on Z L .
𝑉𝑉𝑆𝑆
Eq. (53)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝐼𝐼𝐿𝐿
98,265∠ − 110.6° 𝑉𝑉
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
3,854∠137.1° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −9.676 + 𝑗𝑗23.59 Ω
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Figure 6. Reduced two bus system with sending-end source impedance Z S , receiving-end
source impedance Z R , line impedance Z L , and transfer impedance Z TR .
Figure 7. Reduced two bus system with sending-end source impedance Z S , receiving-end
source impedance Z R , line impedance Z L , and transfer impedance Z TR removed.
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Figure 8. A strong-source system with a line impedance of Z L = 20.4 ohms (i.e., the thicker red
line). This relaymho element characteristic (i.e., the blue circle) does not meet the PRC-026-1
– Attachment B, Criteria A because it is not completely contained within the unstable power
swing stability boundaryregion (i.e., the orange lens characteristic).
The figure above represents a heavily heavy-loaded system using a maximum generation profile.
The zone 2 mho circleelement characteristic (set at 137% of Z L ) extends into the unstable power
swing stability boundaryregion (i.e., the orange partial lens characteristic). Using the strongest
source system is more conservative because it shrinks the unstable power swing stability
boundaryregion, bringing it closer to the mho circleelement characteristic. This figure also
graphically represents the effect of a system strengthening over time and this is the reason for reevaluation if the relay has not been evaluated in the last threefive calendar years. Figure 9 below
depicts a relay that meets the, PRC-026-1 – Attachment B, Criteria A. Figure 8 depicts the same
relay with the same setting threefive years later, where each source has strengthened by about 10%
and now the same zone 2mho element characteristic does not meet Criteria A.
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Figure 9. A weak-source system with a line impedance of Z L = 20.4 ohms (i.e., the thicker red
line). This zone 2mho element characteristic (i.e., the blue circle) meets the PRC-026-1 –
Attachment B, Criteria A because it is completely contained within the unstable power swing
stability boundaryregion (i.e., the orange lens characteristic).
The figure above represents a lightly loaded system, using a minimum generation profile. The zone
2 mho circleelement characteristic (set at 137% of Z L ) does not extend into the unstable power
swing stability boundaryregion (i.e., the orange lens characteristic). Using a weaker source system
expands the unstable power swing stability boundaryregion away from the mho circleelement
characteristic.
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Figure 10. This is an example of aan unstable power swing stability boundaryregion (i.e., the
orange lens characteristic) with the transfer impedance removed. This relay zone 2mho element
characteristic (i.e., the blue circle) does not meet PRC-026-1 – Attachment B, Criteria A because
it is not completely contained within the unstable power swing stability boundaryregion.
Table 8. Example Calculation (Transfer Impedance Removed)
Calculations for the point at 120 degrees with equal source impedances. The total system current
equals the line current. See Figure 10.
Eq. (54)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
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Table 8. Example Calculation (Transfer Impedance Removed)
Eq. (55)
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given impedance data.
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between generators.
Eq. (56)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (57)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (58)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,511∠71.3° 𝐴𝐴
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
Eq. (59)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴
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Table 8. Example Calculation (Transfer Impedance Removed)
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (60)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 Ω) × 4,511∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,757∠106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (61)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,757∠106.1° 𝑉𝑉
4,511∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 17.434 + 𝑗𝑗12.113 Ω
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Figure 11. This is an example of aan unstable power swing stability boundaryregion (i.e., the
orange lens characteristic) with the transfer impedance included. The zone 2mho element
characteristic (i.e., the blue circle) meets the PRC-026-1 – Attachment B, Criteria A because it
is completely contained within the power swing stability boundary.unstable power swing region.
However, including the transfer impedance in the calculation is not compliant with PRC-026-1
– Attachment B Criteria A.
In the figure above, the transfer impedance is 5 times the line impedance. The lens
characteristicunstable power swing region has expanded out beyond the zone 2mho element
characteristic due to the infeed effect from the parallel current through the transfer impedance,
thus allowing the zone 2mho element characteristic to meet PRC-026-1 – Attachment B, Criteria
A. However, including the transfer impedance in the calculation is not compliant with PRC-0261 – Attachment B Criteria A.
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Table 9. Example Calculation (Transfer Impedance Included)
Calculations for the point at 120 degrees with equal source impedances. The total system current
does not equal the line current. See Figure 11.
Eq. (62)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (63)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given impedance data.
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 5
𝑍𝑍𝑇𝑇𝑇𝑇 = (4 + 𝑗𝑗20) Ω × 5
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 20 + 𝑗𝑗100 Ω
Total impedance between generators.
Eq. (64)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
(4 + 𝑗𝑗20) Ω × (20 + 𝑗𝑗100) Ω
(4 + 𝑗𝑗20) Ω + (20 + 𝑗𝑗100) Ω
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 3.333 + 𝑗𝑗16.667 Ω
Total system impedance.
Eq. (65)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (3.333 + 𝑗𝑗16.667) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 9.333 + 𝑗𝑗46.667 Ω
Total system current from sending-end source.
Eq. (66)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
9.333 + 𝑗𝑗46.667 Ω
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Table 9. Example Calculation (Transfer Impedance Included)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,832∠71.3° 𝐴𝐴
The current as measured by the relay on Z L is only the current flowing through that line as
determined by using the current divider equation.
Eq. (67)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿 = 4,832∠71.3° 𝐴𝐴 ×
𝐼𝐼𝐿𝐿 = 4,027.4∠71.3° 𝐴𝐴
(20 + 𝑗𝑗100) Ω
(9.333 + 𝑗𝑗46.667) Ω + (20 + 𝑗𝑗100) Ω
The voltage as measured by the relay on Z L is the voltage drop from the sending-end source
through the sending-end source impedance.
Eq. (68)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 Ω) × 4,027∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 93,417∠104.7° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (69)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
93,417∠104.7° 𝑉𝑉
4,027∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 19.366 + 𝑗𝑗12.767 Ω
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Table 10. Percent Increase of a Lens Due To Parallel Transfer Impedance.
The following demonstrates the percent size increase of the lens characteristic for Z TR in
multiples of Z L with the transfer impedance included.
Z TR in multiples of Z L
Percent increase of lens with equal EMF
sources (Infinite source as reference)
Infinite
N/A
1000
0.05%
100
0.46%
10
4.63%
5
9.27%
2
23.26%
1
46.76%
0.5
94.14%
0.25
189.56%
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Figure 12. The tripping portion not blocked by load encroachment (i.e., the parallel green lines)
of the pilot zone 2mho element characteristic (i.e., the blue circle) is completely contained
within the unstable power swing stability boundaryregion (i.e., the orange lens characteristic).
Therefore, the zone 2mho element characteristic meets the PRC-026-1 – Attachment B, Criteria
A.
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Figure 13: The infeed diagram shows the impedance in front of the relay R with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes Z L + Z R .
Table 11. Calculations (System Apparent Impedance in the forward direction)
The following equations are provided for calculating the apparent impedance back to the E R
source voltage as seen by relay R. Infeed equations from V S to source E R where E R = 0. See
Figure 13.
Eq. (70)
Eq. (71)
Eq. (72)
Eq. (73)
Eq. (74)
Eq. (75)
Eq. (76)
Eq. (77)
Eq. (78)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑆𝑆 − 𝑉𝑉𝑅𝑅
𝑍𝑍𝐿𝐿
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑅𝑅 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑅𝑅
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝐿𝐿 =
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅
𝑍𝑍𝑅𝑅
Since 𝐸𝐸𝑅𝑅 = 0
Rearranged:
𝑉𝑉𝑆𝑆 − 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑅𝑅
𝑍𝑍𝐿𝐿
𝑉𝑉𝑅𝑅 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑅𝑅
𝑉𝑉𝑆𝑆 − [(𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇 ) × 𝑍𝑍𝑅𝑅 ]
𝑍𝑍𝐿𝐿
𝑉𝑉𝑆𝑆 = (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝐿𝐿 ) + (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝑅𝑅 ) + (𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅 )
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅
𝐼𝐼𝑇𝑇𝑇𝑇
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 +
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
�
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝑇𝑇𝑇𝑇 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
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Table 11. Calculations (System Apparent Impedance in the forward direction)
Eq. (79)
Eq. (80)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
=
𝐼𝐼𝐿𝐿
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
The infeed equations shows the impedance in front of the relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the forward direction becomes Z L + Z R .
Eq. (81)
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
Figure 14: The infeed diagram shows the impedance behind relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes Z S .
Table 12. Calculations (System Apparent Impedance in the reverse direction)
The following equations are provided for calculating the apparent impedance back to the E S
source voltage as seen by relay R. Infeed equations from V R back to source E S where E S = 0.
See Figure 14.
Eq. (82)
Eq. (83)
Eq. (84)
Eq. (85)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅 − 𝑉𝑉𝑆𝑆
𝑍𝑍𝐿𝐿
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑆𝑆 − 𝐸𝐸𝑆𝑆
𝑍𝑍𝑆𝑆
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑆𝑆
𝑍𝑍𝑆𝑆
Since 𝐸𝐸𝑠𝑠 = 0
Rearranged:
𝑉𝑉𝑆𝑆 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑆𝑆
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Table 12. Calculations (System Apparent Impedance in the reverse direction)
Eq. (86)
Eq. (87)
Eq. (88)
Eq. (89)
Eq. (90)
Eq. (91)
Eq. (92)
𝐼𝐼𝐿𝐿 =
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅 − 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑆𝑆
𝑍𝑍𝐿𝐿
𝑉𝑉𝑅𝑅 − [(𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇 ) × 𝑍𝑍𝑆𝑆 ]
𝑍𝑍𝐿𝐿
𝑉𝑉𝑅𝑅 = (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝐿𝐿 ) + (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝑆𝑆 ) + (𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅𝑅𝑅 )
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑅𝑅
𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑆𝑆
𝐼𝐼𝑇𝑇𝑇𝑇
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 +
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 × �1 +
�
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝑇𝑇𝑇𝑇 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
=
𝐼𝐼𝐿𝐿
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
The infeed equations shows the impedance behind relay R with the parallel transfer impedance
included. As the parallel transfer impedance approaches infinity, the impedances seen by the
relay R in the reverse direction becomes Z S .
Eq. (93)
Eq. (94)
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
As seen by relay R at the receiving-end of
the line.
Subtract Z L for relay R impedance as seen
at sending-end of the line.
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Figure 15. Out-of-step trip (OST) inner blinder (i.e., the parallel green lines) meets the PRC026-1 – Attachment B, Criteria A because the inner OST blinder initiates tripping either OnThe-Way-In or On-The-Way-Out. Since the inner blinder is completely contained within the
portion of theunstable power swing stability boundaryregion (i.e., the orange lens
characteristic), the zone 2 element (i.e., the blue circle)it meets the PRC-026-1 – Attachment B,
Criteria A.
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Table 13. Example Calculation (Voltage Ratios)
These calculations are based on the loss of synchronism characteristics for the cases of N < 1
and N > 1 as found in the Application of Out-of-Step Blocking and Tripping Relays, GER-3180,
p. 12, Figure 31. 15 The GE illustration shows the formulae used to calculate the radius and center
of the circles that make up the ends of the portion of the lens.
Voltage ratio equations, source impedance equation with infeed formulae applied, and circle
equations.
Given:
Eq. (95)
Eq. (96)
𝐸𝐸𝑆𝑆 = 0.7
𝑁𝑁𝑎𝑎 =
𝑁𝑁𝑏𝑏 =
𝐸𝐸𝑅𝑅 = 1.0
|𝐸𝐸𝑆𝑆 | 0.7
=
= 0.7
|𝐸𝐸𝑅𝑅 | 1.0
|𝐸𝐸𝑅𝑅 | 1.0
=
= 1.43
|𝐸𝐸𝑆𝑆 | 0.7
The total system impedance as seen by the relay with infeed formulae applied.
Given:
Given:
Eq. (97)
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = (4 + 𝑗𝑗20)10 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿
� + �𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
��
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
The calculated coordinates of the lower circle center.
Eq. (98)
𝑍𝑍𝐶𝐶1
𝑁𝑁𝑎𝑎2 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝑍𝑍𝐿𝐿
= − �𝑍𝑍𝑆𝑆 × �1 +
�� − �
�
𝑍𝑍𝑇𝑇𝑇𝑇
1 − 𝑁𝑁𝑎𝑎2
𝑍𝑍𝐶𝐶1 = − � (2 + 𝑗𝑗10) Ω × �1 +
𝑍𝑍𝐶𝐶1 = −11.608 − 𝑗𝑗58.039 Ω
(4 + 𝑗𝑗20) Ω
0.72 × (10 + 𝑗𝑗50) Ω
��
−
�
�
(4 + 𝑗𝑗20)10 Ω
1 − 0.72
The calculated radius of the lower circle.
Eq. (99)
𝑟𝑟𝑎𝑎 = �
𝑁𝑁𝑎𝑎 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
�
1 − 𝑁𝑁𝑎𝑎2
𝑟𝑟𝑎𝑎 = �
0.7 × (10 + 𝑗𝑗50) Ω
�
1 − 0.72
𝑟𝑟𝑎𝑎 = 69.987 Ω
15
http://store.gedigitalenergy.com/faq/Documents/Alps/GER-3180.pdf
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Table 13. Example Calculation (Voltage Ratios)
The calculated coordinates of the upper circle center.
Eq. (100)
𝑍𝑍𝐶𝐶2 = 𝑍𝑍𝐿𝐿 + �𝑍𝑍𝑅𝑅 × �1 +
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝑍𝑍𝐿𝐿
�� + � 2
�
𝑍𝑍𝑇𝑇𝑇𝑇
𝑁𝑁𝑏𝑏 − 1
𝑍𝑍𝐶𝐶2 = − � (4 + 𝑗𝑗20) Ω × �1 +
𝑍𝑍𝐶𝐶2 = 17.608 + 𝑗𝑗88.039 Ω
(4 + 𝑗𝑗20) Ω
(10 + 𝑗𝑗50) Ω
�� + �
�
10
(4 + 𝑗𝑗20) Ω
1.432 − 1
The calculated radius of the upper circle.
Eq. (101)
𝑟𝑟𝑏𝑏 = �
𝑟𝑟𝑏𝑏 = �
𝑁𝑁𝑏𝑏 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
�
𝑁𝑁𝑏𝑏2 − 1
1.43 × (10 + 𝑗𝑗50) Ω
�
1.432 − 1
𝑟𝑟𝑏𝑏 = 69.987 Ω
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Figure 15a: Lower circle loss of synchronism region showing the coordinates of the circle
center and the circle radius.
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Figure 15b: Lower circle loss of synchronism region showing the first steps to calculate the
coordinates of the points on the circle. 1) Identify the lower circle points that intersect the lens
shape where the sending-end to receiving-end voltage ratio is 0.7 (see lens shape calculations
in Tables 2-7). 2) Calculate the distance between the two lower circle points identified in Step
1. 3) Calculate the angle of arc that connects the two lower circle points identified in Step 1.
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Figure 15c: Lower circle loss of synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1)
Calculate the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4)
Calculate the angle step size for the desired number of points.
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Figure 15d: Lower circle loss of synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R–X coordinates.
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Figure 15e: Upper circle loss of synchronism region showing the coordinates of the circle
center and the circle radius.
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Figure 15f: Upper circle loss of synchronism region showing the first steps to calculate the
coordinates of the points on the circle. 1) Identify the upper circle points that intersect the lens
shape where the sending-end to receiving-end voltage ratio is 1.43 (see lens shape calculations
in Tables 2-7). 2) Calculate the distance between the two upper circle points identified in Step
1. 3) Calculate the angle of arc that connects the two upper circle points identified in Step 1.
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Figure 15g: Upper circle loss of synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1) Calculate
the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4) Calculate the angle
step size for the desired number of points.
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Figure 15h: Upper circle loss of synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R-X coordinates.
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Figure 15i: Full tables of calculated lower and upper loss of synchronism circle coordinates.
The highlighted row is the detailed calculated points in Figures 15d and 15h.
Application Specific to Criteria B
The PRC-026-1 – Attachment B, Criteria B evaluates overcurrent elements used for tripping. The
same criteria as PRC-026-1 – Attachment B, Criteria A is used except for an additional criteria
(No. 4) that calculates a current magnitude based upon generator terminal voltages of 1.05 per unit.
The formula used to calculate the current is as follows:
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Table 14. Example Calculation (Overcurrent)
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps secondary times a CT ratio of 160:1 that equals 80008,000 amps on the,
primary. The following calculation is where V S equals the base line-to-ground sending-end
generator source voltage times 1.05 at an angle of 120 degrees, V R equals the base line-toground receiving-end generator terminal voltage times 1.05 at an angle of 0 degrees, and Z sys
equals the sum of the sending-end, line, and receiving-end source impedances in ohms.
Here, the phase instantaneous setting of 8,000 amps is greater than the calculated system current
of 5,716 amps; therefore, it meets PRC-026-1 – Attachment B, Criteria B.
Eq. (102)
𝑉𝑉𝑆𝑆 =
𝑉𝑉𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
× 1.05
√3
230,000∠120° 𝑉𝑉
√3
𝑉𝑉𝑆𝑆 = 139,430∠120° 𝑉𝑉
× 1.05
Receiving-end generator terminal voltage.
Eq. (103)
𝑉𝑉𝑅𝑅 =
𝑉𝑉𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
× 1.05
√3
230,000∠0° 𝑉𝑉
√3
𝑉𝑉𝑅𝑅 = 139,430∠0° 𝑉𝑉
× 1.05
The total impedance of the system (Z sys ) equals the sum of the sending-end source impedance
(Z S ), the impedance of the line (Z L ), and receiving-end impedance (Z R ) in ohms.
Given:
Eq. (104)
𝑍𝑍𝑆𝑆 = 3 + 𝑗𝑗26 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝐿𝐿 = 1.3 + 𝑗𝑗8.7 Ω
𝑍𝑍𝑅𝑅 = 0.3 + 𝑗𝑗7.3 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (3 + 𝑗𝑗26) Ω + (1.3 + 𝑗𝑗8.7) Ω + (0.3 + 𝑗𝑗7.3) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 4.6 + 𝑗𝑗42 Ω
Total system current from sending-end source.
Eq. (105)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
(𝑉𝑉𝑆𝑆 − 𝑉𝑉𝑅𝑅 )
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
(139,430∠120° 𝑉𝑉 − 139,430∠0° 𝑉𝑉)
(4.6 + 𝑗𝑗42) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 5,715.82∠66.25° 𝐴𝐴
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Application Specific to Three-Terminal Lines
If a three-terminal line is identified as an Element that is susceptible to a power swing based on
Requirement R1, the load-responsive protective relays at each end of the three-terminal line must
be evaluated.
As shown in Figure 15j, the source impedances at each end of the line can be obtained from the
similar short circuit calculation as for the two-terminal line.
EA
A
B
ZSA
ZL2
ZL1
R
ZSB
EB
ZL3
C
ZSC
EC
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps-secondary times a CT ratio of 160:1 that equals 8,000 amps-primary.
Here, the phase instantaneous setting of 8,000 amps is greater than the calculated system current
of 5,716 amps, therefore it is compliant with PRC-026-1 – Attachment B, Criteria B.Figure 15j.
Three-terminal line. To evaluate the load-responsive protective relays on the three-terminal line
at Terminal A, the circuit in Figure 15j is first reduced to the equivalent circuit shown in Figure
15k. The evaluation process for the load-responsive protective relays on the line at Terminal A
will now be the same as that of the two-terminal line.
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Figure 15k. Three-terminal line reduced to a two-terminal line.
Application to Generation Elements
As with Transmissiontransmission BES Elements, the determination of the apparent impedance
seen at an Element located at, or near, a generation Facility is complex for power swings due to
various interdependent quantities. These variances in quantities are caused by changes in machine
internal voltage, speed governor action, voltage regulator action, the reaction of other local
generators, and the reaction of other interconnected transmission BES Elements as the event
progresses through the time domain. Though transient stability simulations may be used to
determine the apparent impedance for verifying load-responsive relay settings, 16,17 Requirement
R4R2, PRC-026-1 – Attachment B, Criteria A and B provides a simplified method for evaluating
the load-responsive protective relay’s susceptibility to tripping in response to a stable power swing
without requiring stability simulations.
In general, the electrical center will be in the transmission system for cases where the generator is
connected through a weak transmission system (high external impedance). Other cases where the
generator is connected through a strong transmissionTransmission system, the electrical center
could be inside the unit connected zone. 18 In either case, load-responsive protective relays
connected at the generator terminals or at the high-voltage side of the generator step-up (GSU)
transformer may be challenged by power swings as determined by the Planning Coordinator in
Requirement R1 or becoming aware of a generator, transformer, or transmission line BES Element
16
Donald Reimert, Protective Relaying for Power Generation Systems, Boca Raton, FL, CRC Press, 2006.
17
Prabha KundarKundur, Power System Stability and Control, EPRI, McGraw Hill, Inc., 1994.
18
Ibid, KundarKundur.
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that tripped 19 in response to stable or unstable power swing event documented by an actual
Disturbancedue to the operation of its protective relay(s) in Requirement R2 and R3.
Load-responsive protective relays such as time over-current, voltage controlled time-overcurrent
or voltage-restrained time-overcurrent relays are excluded from this standard sinceif they are set
based on equipment permissible overload capability. Their operating time is much greater than 15
cycles for the current levels observed during a power swing.
Instantaneous overcurrent and definite-time overcurrent relays with a time delay of less than 15
cycles are includedapplicable and are required to be evaluated for identified Elements.
The generator loss-of-field protective function is provided by impedance relay(s) connected at the
generator terminals. The settings are applied to protect the generator from a partial or complete
loss of excitation under all generator loading conditions and, at the same time, be immune to
tripping on stable power swings. It is more likely that the relay would operate during a power
swing when the automatic voltage regulator (AVR) is in manual mode rather than when in
automatic mode. 20 Figure 16 illustrates in the R-X plot, the loss-of-field relaysrelay in the R-X
plot, which typically includeincludes up to three zones of protection.
19
See Guidelines and Technical Basis section, “Becoming Aware of an Element That Tripped in Response to a
Power Swing,”
20
John Burdy, Loss-of-excitation Protection for Synchronous Generators GER-3183, General Electric Company.
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Figure 16. An R-X graph of typical impedance settings for loss-of-field relays.
Loss-of-field characteristic 40-1 has a wider impedance characteristic (positive offset) than
characteristic 40-2 or characteristic 40-3 and provides additional generator protection for a partial
loss of field or a loss of field under low load (less than 10% of rated). The tripping logic of this
protection scheme is established by a directional contact, a voltage setpoint, and a time delay. The
voltage and time delay add security to the relay operation for stable power swings. Characteristic
40-3 is less sensitive to power swings than characteristic 40-2 and is set outside the generator
capability curve in the leading direction. Regardless of the relay impedance setting, PRC-01921
requires that the “in-service limiters operate before Protection Systems to avoid unnecessary trip”
and “in-service Protection System devices are set to isolate or de-energize equipment in order to
limit the extent of damage when operating conditions exceed equipment capabilities or stability
limits.” Time delays for tripping associated with loss-of-field relays 22,23 have a range from 15
cycles for characteristic 40-2 to 60 cycles for characteristic 40-1 to minimize tripping during stable
21
Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection
22
Ibid, Burdy.
23
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
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power swings. In the standard, 15 cycles establishes a threshold for applicability; however, it is
the responsibility of the Generator Owner to establish settings that provide security against stable
power swings and, at the same time, dependable protection for the generator.
The simple two-machine system circuit (method also used in the Application to Transmission
ElementElements section) is used to analyze the effect of a power swing at a generator facility for
load-responsive relays pursuant to Requirement R4.. In this section, the calculation method is used
for calculating the impedance seen by the relay connected at a point in the circuit. 24 The electrical
quantities used to determine the apparent impedance plot using this method are generator saturated
transient reactance (X’ d ), GSU transformer impedance (X GSU ), transmission line impedance (Z L ),
and the system equivalent (Z e ) at the point of interconnection. All impedance values are known to
the Generator Owner except for the system equivalent. The system equivalent is
availableobtainable from the Transmission Owner. The sending-end and receiving-end source
voltages are varied from 0.70 to 1.0 per unit to form a portion of a the lens characteristic instead
of varying the voltages from 0 to 1.0 per unit which would form a full lens characteristic.shape of
the unstable power swing region. The voltage range of 0.7 –to 1.0 results in a ratio range from 0.7
to 1.43. This ratio range is used in determining the portionto form the lower and upper loss-ofsynchronism circle shapes of the lens.unstable power swing region. A system separation angle of
120 degrees is also used inused in accordance with PRC-026-1 – Attachment B criteria for each
load-responsive protective relay evaluation.
BelowTable 15 below is an example calculation of the apparent impedance locus method based on
Figures 1817 and 1918. 25 In this example, the generator is connected to the 345 kV transmission
system through the GSU transformer and has the listed ratings listed. The . Note that the loadresponsive protective relay responsibilities below are divided betweenrelays in this example may
have ownership with the Generator Owner andor the Transmission Owner.
Figure 17. Simple one-line diagram of the
system to be evaluated.
Figure 18. Simple system equivalent
impedance diagram to be evaluated. 26
24
Edward Wilson Kimbark, Power System Stability, Volume II: Power Circuit Breakers and Protective Relays,
Published by John Wiley and Sons, 1950.
25
Ibid, Kimbark.
26
Ibid, Kimbark.
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Table15. Example Data (Generator)
Input Descriptions
Input Values
Synchronous Generator nameplate (MVA)
940 MVA
Sub-transient reactance (940MVA base – per unit)
Generator rated voltage (Line-to-Line)
Generator step-up (GSU) transformer rating
GSU transformer reactance (880 MVA base)
System Equivalent (100 MVA base)
X"d = 𝑋𝑋𝑑𝑑′ = 0.3845 (per unit)
20 𝑘𝑘𝑘𝑘
880 𝑀𝑀𝑀𝑀𝑀𝑀
XGSU = 16.05%
𝑍𝑍𝑒𝑒 = 0.00723∠86° ohms
Generator Owner Load-Responsive Protective Relays
Positive Offset Impedance
Offset = 0.294 per unit ohms
40-1
Diameter = 0.294 per unit ohms
Negative Offset Impedance
Offset = 0.22 per unit ohms
40-2
Diameter = 2.24 per unit ohms
Negative Offset Impedance
Offset = 0.22 per unit ohms
40-3
Diameter = 1.00 per unit ohms
Diameter = 0.643 per unit ohms
21-1
MTA = 85°
I (pickup) = 5.0 per unit
50
Transmission Owned Load-Responsive Protective Relays
Diameter = 0.55 per unit ohms
21-2
MTA = 85°
Calculations shown for a 120 degree angle and E S /E R = 1. The equation for calculating Z R is: 27
Eq. (106)
27
𝑍𝑍𝑅𝑅 = �
(1 − 𝑚𝑚)(𝐸𝐸𝑆𝑆 ∠𝛿𝛿) + (𝑚𝑚)(𝐸𝐸𝑅𝑅 )
� × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝐸𝐸𝑆𝑆 ∠𝛿𝛿 − 𝐸𝐸𝑅𝑅
Ibid, Kimbark.
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PRC-026-1 – Application Guidelines
Where m is the relay location as a function of the total impedance (real number less than 1)
E S and E R is the sending-end and receiving-end voltages
Z sys is the total system impedance
Z R is the complex impedance at the relay location and plotted on an R-X diagram
All of the above are constants (940 MVA base) while the angle δ is varied. Table 16 below contains
calculations for a generator using the data listed in Table 15.
Table16. Example Calculations (Generator)
Given:
Eq. (107)
𝑋𝑋𝑑𝑑" = 𝑋𝑋𝑑𝑑′ = 𝑗𝑗0.3845 Ω
𝑋𝑋𝐺𝐺𝐺𝐺𝐺𝐺 = 𝑗𝑗0.171 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑋𝑋𝑑𝑑" + 𝑋𝑋𝐺𝐺𝐺𝐺𝐺𝐺 𝑋𝑋𝑑𝑑′ + 𝑋𝑋𝐺𝐺𝐺𝐺𝐺𝐺 + 𝑍𝑍𝑒𝑒
𝑍𝑍𝑒𝑒 = 0.06796 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑗𝑗0.3845 Ω + 𝑗𝑗0.171 Ω + 0.06796 Ω
Eq. (108)
Eq. (109)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 0.6239 ∠90° Ω
𝑋𝑋𝑑𝑑" 𝑋𝑋𝑑𝑑′
0.3845
𝑚𝑚 =
=
= 0.61633
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 0.6239
𝑍𝑍𝑅𝑅 = �
𝑍𝑍𝑅𝑅 = �
(1 − 𝑚𝑚)(𝐸𝐸𝑆𝑆 ∠𝛿𝛿) + (𝑚𝑚)(𝐸𝐸𝑅𝑅 )
� × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝐸𝐸𝑆𝑆 ∠𝛿𝛿 − 𝐸𝐸𝑅𝑅
(1 − 0.61633) × (1∠120°) + (0.61633)(1∠0°)
� × (0.6234∠90°) Ω
1∠120° − 1∠0°
0.4244 + 𝑗𝑗0.3323
Z𝑅𝑅 = �
� × (0.6234∠90°) Ω
−1.5 + 𝑗𝑗 0.866
Z𝑅𝑅 = (0.3112 ∠ − 111.94°) × (0.6234∠90°) Ω
Z𝑅𝑅 = 0.194 ∠ − 21.94° Ω
Z𝑅𝑅 = −0.18 − 𝑗𝑗0.073 Ω
Table 17 lists the swing impedance values at other angles and at E S /E R = 1, 1.43, and 0.7. The
impedance values are plotted on an R-X graph with the center being at the generator terminals for
use in evaluating impedance relay settings.
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PRC-026-1 – Application Guidelines
Table 17: Sample calculations for a swing impedance chart for varying voltages at the
sending-end and receiving-end.
Angle (δ)
(Degrees)
E S /E R =1
E S /E R =1.43
E S /E R =0.7
ZR
ZR
ZR
Magnitude
(PU Ohms)
Angle
(Degrees)
Magnitude
(PU Ohms)
Angle
(Degrees)
Magnitude
(PU Ohms)
Angle
(Degrees)
90
0.320
-13.1
0.296
6.3
0.344
-31.5
120
0.194
-21.9
0.173
-0.4
0.227
-40.1
150
0.111
-41.0
0.082
-10.3
0.154
-58.4
210
0.111
-25.9
0.082
190.3
0.154
238.4
240
0.111194
221.0201.9
0.173
180.4
0.225
220.1
270
0.320
193.1
0.296
173.7
0.344
211.5
Requirement R4R2 Generator Examples
Distance Relay Application
Based on PRC-026-1 – Attachment B, Criteria A, the distance relay (21-1) (i.e., owned by the
generation entityGeneration Owner) characteristic is in the region where a stable power swing
would not occur as shown in Figure 19. There is no further obligation to the owner in this standard
for this load-responsive protective relay.
The distance relay (21-2) (i.e., owned by the transmission entityTransmission Owner) is connected
at the high-voltage side of the GSU transformer and its impedance characteristic is in the region
where a stable power swing could occur causing the relay to operate. In this example, if the
intentional time delay of this relay is less than 15 cycles, the PRC-026 – Attachment B, Criteria B
cannot be met, thus the Transmission Owner is required to create a CAP (Requirement R5) to meet
PRC-026 – Attachment B, Criteria B.R3). Some of the options include, but are not limited to,
changing the relay setting (i.e.., impedance reach, angle, time delay), modify the scheme (i.e.., add
power swing blockingPSB), or replace the Protection System. Note that the relay may be excluded
from this standard if it has an intentional time delay equal to or greater than 15 cycles.
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PRC-026-1 – Application Guidelines
Figure 19. Swing impedance graph for impedance relays at a generating facility.
Loss-of-Field Relay Application
In Figure 20, the R-X diagram shows the loss-of-field relay (40-1 and 40-2) characteristics are in
the region where a stable power swing can cause a relay operation. Protective relay 40-1 would
be excluded if it has an intentional time delay equal to or greater than 15 cycles. Similarly, 40-2
would be excluded if its intentional time delay is equal to or greater than 15 cycles. For example,
if 40-1 has a time delay of 1 second and 40-2 has a time delay of 0.25 seconds, they are excluded
and there is no further obligation toon the ownerGenerator Owner in this standard for these
relays. The loss-of-field relay characteristic 40-3 is outside the region where a stable power
swing can cause a relay operation. In this case, the owner may select high speed tripping on
operation of the 40-3 impedance element.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 223: November 4, 2014)
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PRC-026-1 – Application Guidelines
Figure 20: Stable power swing R-X graph for loss-of-field relays.
Instantaneous Overcurrent Relay
In similar fashion to the transmission line overcurrent example calculation in Table 14, the
instantaneous overcurrent relay minimum setting is established by PRC-026-1 – Attachment B,
Criteria B. The solution is found by:
Eq. (110)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍sys
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
(1.05∠120° − 1.05∠0°)
𝐴𝐴
0.6234∠90°
As stated in the relay settings in Table 15, the relay is installed on the high-voltage side of the GSU
transformer with a pickup of 5.0 per unit currentamps. The maximum allowable current is
calculated below.
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
1.775∠150° 𝑉𝑉
𝐴𝐴
0.6234∠90° Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 2.84 ∠60° 𝐴𝐴
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PRC-026-1 – Application Guidelines
The phase instantaneous setting of 5.0 per unit amps is greater than the calculated system current
of 2.84 per unit amps; therefore, it is compliant withmeets the PRC-026-1 – Attachment B, Criteria
B.
Out-of-Step Tripping for Generation Facilities
Out-of-step protection for the generator generally falls into three different schemes. The first
scheme is a distance relay connected at the high-voltage side of the GSU transformer with the
directional element looking toward the generator. Because this relay setting may be the same
setting used for generator backup protection (see Requirement R2 Generator Examples, Distance
Relay Application), it is susceptible to stable power swings and would require modification.
Because this scheme is susceptible to stable power swings and any modification to the mho
circle will jeopardize the overall protection of the out-of-step protection of the generator,
available technical literature does not recommend using this scheme specifically for generator
out-of-step protection. The second and third out-of-step Protection System schemes are
commonly referred to as single and double blinder schemes. These schemes are installed or
enabled for out-of-step protection using a combination of blinders, a mho element, and timers.
The combination of these protective relay functions provides out-of-step protection and
discrimination logic for stable and unstable power swings. Single blinder schemes use logic that
discriminate between stable and unstable power swings by issuing a trip command after the first
slip cycle. Double blinder schemes are more complex that the single blinder scheme and,
depending on the settings of the inner blinder, a trip for a stable power swing may occur. While
the logic discriminates between stable and unstable power swings in either scheme, it is
important that the trip initiating blinders be set at an angle greater than the stability limit of 120
degrees to remove the possibility of a trip for a stable power swing. Below is a discussion of the
double blinder scheme.
Double Blinder Scheme
The double blinder scheme is a method for measuring the rate of change of positive sequence
impedance for out-of-step swing detection. The scheme compares a timer setting to the actual
elapsed time required by the impedance locus to pass between two impedance characteristics. In
this case, the two impedance characteristics are simple blinders, each set to a specific resistive
reach on the R-X plane. Typically, the two blinders on the left half plane are the mirror images of
those on the right half plane. The scheme typically includes a mho characteristic which acts as a
starting element, but is not a tripping element.
The scheme detects the blinder crossings and time delays as represented on the R-X plane as
shown in Figure 21. The system impedance is composed of the generator transient (X d ’), GSU
transformer (X T) , and transmission system (X system ), impedances.
The scheme logic is initiated when the swing locus crosses the outer Blinder R1 (Figure 21), on
the right at separation angle α. The scheme only commits to take action when a swing crosses the
inner blinder. At this point the scheme logic seals in the out-of-step trip logic at separation angle
β. Tripping actually asserts as the impedance locus leaves the scheme characteristic at separation
angle δ.
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PRC-026-1 – Application Guidelines
The power swing may leave both inner and outer blinders in either direction and tripping will
assert. Therefore, the inner blinder must be set such that the separation angle β is large enough
that the system cannot recover. This angle should be set at 120 degrees or more. Setting the angle
greater than 120 degrees satisfies the PRC-026-1 – Attachment B Criteria A (No. 1, 1st bullet)
since the tripping function is asserted by the blinder element. Transient stability studies are
usually required to determine an appropriate inner blinder setting. Such studies may indicate that
a smaller stability limit angle is acceptable under PRC-026-1 – Attachment B Criteria A (No. 1,
2nd bullet). In this respect, the double blinder scheme is similar to the double lens and triple lens
schemes, and many transmission application out-of-step schemes.
Figure 21: Double Blinder Scheme generic out of step characteristics.
Figure 22 illustrates a sample setting of the double blinder scheme for example 940 MVA
generator. The only setting requirement for this relay scheme is the right inner blinder, which
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 223: November 4, 2014)
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PRC-026-1 – Application Guidelines
must be set greater than the separation angle of 120 degrees (or a lesser angle based on a
transient stability study) to ensure that the out-of-step protective function is expected to not trip
in response to a stable power swing during non-Fault conditions. Other settings such as the mho
characteristic, outer blinders, and timers are set according to transient stability studies and are not
a part of this standard.
Figure 22: Double Blinder Out-of-Step Scheme with unit impedance data and load-responsive
protective relay impedance characteristics for the example 940 MVA generator, scaled in relay
secondary ohms.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 223: November 4, 2014)
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PRC-026-1 – Application Guidelines
Requirement R3Requirement R5
This requirement ensures that all actions associated with any Corrective Action Plan (CAP)
developed in the previous requirement are completed. The requirement also permits the entity to
modify a CAP as necessary, while in the process of fulfilling the purpose of the standard.
To achieve the stated purpose of this standard, which is to ensure that relays are expected to not
trip in response to stable power swings during non-Fault conditions, this Requirement ensures
that the applicable entity is required to develop and completedevelops a Corrective Action Plan
(CAP) that reduces the risk of relays tripping during in response to a stable power swing during
non-Fault conditions that may occur on any applicable BES Element of the BES. Protection
System owners are required, during the implementation of a CAP, to update it when any action
or timetable changes until the CAP is completed. Accomplishing this objective is intended to
reduce the risk of the relays unnecessarily tripping during stable power swings, thereby
improving reliability and reducing risk to the BES.
Requirement R4
To achieve the stated purpose of this standard, which is to ensure that load-responsive protective
relays are expected to not trip in response to stable power swings during non-Fault conditions, the
applicable entity is required to implement any CAP developed pursuant to Requirement R3 such
that the Protection System will meet PRC-026-1 – Attachment B criteria or can be excluded under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay
functions are supervised by power swing blocking or using relay systems that are immune to power
swings), while maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the BES Element). Protection System owners are
required in the implementation of a CAP to update it when actions or timetable change, until all
actions are complete. Accomplishing this objective is intended to reduce the occurrence of
Protection System tripping during a stable power swing, thereby improving reliability and
minimizing risk to the BES.
The following are examples of actions taken to complete CAPs for a relay that did not meet PRC026-1 – Attachment B and could be exposedat-risk of tripping in response to a stable power swing
and a settingduring non-Fault conditions. A Protection System change was determined to be
acceptable (without diminishing the ability of the relay to protect for faults within its zone of
protection).
Example R5aR4a: Actions: Settings were issued on 6/02/2015 to reduce the zoneZone 2
reach of the impedance relay used in the permissive overreaching transfer trip
(POTTdirectional comparison unblocking (DCUB) scheme from 30 ohms to 25 ohms so
that the relay characteristic is completely contained within the lens characteristic identified
by the criterion. The settings were applied to the relay on 6/25/2015. CAP was completed
on 06/25/2015.
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PRC-026-1 – Application Guidelines
Example R5bR4b: Actions: Settings were issued on 6/02/2015 to enable out-of-step
blocking on the existing microprocessor-based relay to prevent tripping in response to
stable power swings. The setting changes were applied to the relay on 6/25/2015. CAP was
completed on 06/25/2015.
The following is an example of actions taken to complete a CAP for a relay responding to a stable
power swing that required the addition of an electromechanical power swing blocking relay.
Example R5cR4c: Actions: A project for the addition of an electromechanical power
swing blocking relay to supervise the zoneZone 2 impedance relay was initiated on
6/5/2015 to prevent tripping in response to stable power swings. The relay installation was
completed on 9/25/2015. CAP was completed on 9/25/2015.
The following is an example of actions taken to complete a CAP with a timetable that required
updating for the replacement of the relay.
Example R5dR4d: Actions: A project for the replacement of the impedance relays at both
terminals of line X with line current differential relays was initiated on 6/5/2015 to prevent
tripping in response to stable power swings. The completion of the project was postponed
due to line outage rescheduling from 11/15/2015 to 3/15/2016. Following the timetable
change, the impedance relay replacement was completed on 3/18/2016. CAP was
completed on 3/18/2016.
The CAP is complete when all the documented actions to resolveremedy the specific problem (i.e.,
unnecessary tripping during stable power swings) are completed.
Requirement R6
To achieve the stated purpose of this standard, which is to ensure that load-responsive protective
relays are expected to not trip in response to stable power swings during non-Fault conditions, the
applicable entity is required to fully implement any CAP developed pursuant to Requirement R5
that modifies the Protection System to meet PRC-026-1 – Attachment B, Criteria A and B.
Protection System owners are required in the implementation of a CAP to update it when actions
or timetable change, until all actions are complete. Accomplishing this objective is intended to
reduce the occurrence of Protection System tripping during a stable power swing, thereby
improving reliability and minimizing risk to the BES.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 2: August 223: November 4, 2014)
Page 98 of 98
Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power
Swings
Requested Approvals
PRC‐026‐1 – Relay Performance During Stable Power Swings
Requested Retirements
None.
Prerequisite Approvals
None.
General Considerations
There are a number of factors that influence the determination of an implementation period for the
new proposed standard. The following factors may be specific to one or more of the applicable entities
listed below.
1. The effort and resources for all applicable entities to develop or modify internal processes
and/or procedures.
2. The effort and resources for the Planning Coordinator to begin identifying Element(s) according
to the criteria in Requirement R1 based on existing information (e.g., the most recent Planning
Assessment).
3. The notification of Elements in Requirement R1 is based on the Planning Coordinator’s existing
studies (i.e., annual Planning Assessments) and there will be minimal additional effort to
identify Elements according to the criteria.
4. The need for the Generator Owner or Transmission Owner to plan for and secure resources
(e.g., availability of consultants, if needed) to address the initial influx of Elements from the
Planning Coordinator during the implementation period of Requirement R2.
Applicable Entities
Generator Owner
Planning Coordinator
Transmission Owner
Effective Dates
Requirement R1
First day of the first full calendar year that is 12 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 12 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Requirements R2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 36 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Notifications Prior to the Effective Date of R2
During the implementation of the standard, notifications are likely to occur prior to Requirement R2
becoming effective. Where notification of Elements under Requirement R1 or becoming aware of an
Element tripping due to a stable or unstable power swing prior to the Effective Date of Requirement
R2, the 12 month time period to evaluate if an Element’s load‐responsive protective relays meet the
criteria in PRC‐026‐1 – Attachment B in Requirement R2 will begin, as expected, from the Effective
Date of Requirement R2. Thereafter, entities will follow the 12 month time period in accordance with
Requirement R2. The intention of the additional time for R2 to become effective is to handle the initial
influx of notifications and identifications.
Justification
The implementation plan is based on the general considerations above and provides sufficient time for
the Generator Owner, Planning Coordinator, and Transmission Owner to begin becoming compliant
with the standard. The Effective date is constructed such that once the standard is adopted or
approved it would become effective on the first day of the first whole calendar year that is 12 months
for Requirement R1 and 36 months for Requirements R2, R3, and R4 after adoption or approval.
Requirement R1 – The Planning Coordinator will have at least one full calendar year to prepare
itself to identify any generator, transformer, and transmission line BES Elements that meet the
criteria and notify the respective Generator Owner and Transmission Owner of identified
Elements, if any, within the allotted timeframe.
Implementation Plan (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings| November 4, 2014
2
Requirement R2 – The Generator Owner and Transmission Owner will have 36 calendar months
to determine if its load‐responsive protective relays for an identified Element pursuant to
Requirement R1 meet the Attachment B criteria. Also, both entities are provided an
implementation that will allow the entity to conduct initial evaluations of its load‐responsive
protective relays for an identified Element during the first 36 calendar months of approval.
Requirement R3 – The implementation period for the development of a Corrective Action Plan
(CAP) is set to be consistent with Requirement R2 to begin during the fourth calendar year of
adoptions or approvals to address any load‐responsive protective relays determined in
Requirement R2 not to meet the Attachment B criteria.
Requirement R4 – The implementation period for this Requirement is set to be consistent with
Requirement R3, the development of a CAP.
Implementation Plan (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings| November 4, 2014
3
Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power
Swings
Requested Approvals
PRC‐026‐1 – Relay Performance During Stable Power Swings
Requested Retirements
None.
Prerequisite Approvals
None.
General Considerations
There are a number of factors that influence the determination of an implementation period for the
new proposed standard. The following factors may be specific to one or more of the applicable entities
listed below.
1. The effort and resources for all applicable entities to develop or modify internal processes
and/or procedures.
2. The effort and resources for the Planning Coordinator to identify thebegin identifying
Element(s) according to the criterioncriteria in Requirement R1. based on existing information
(e.g., the most recent Planning Assessment).
3. The notification of Elements in Requirement R1 is based on the Planning Coordinator’s existing
studies (i.e., annual Planning Assessments) and there will be minimal additional effort to
identify Elements according to the criteria.
3. The need for the Generator Owner or Transmission Owner to plan for and secure resources
(e.g., availability of consultants, if needed) to evaluate each load‐responsive protective relay’s
response to a stable power swing for identified Elements.
4. Theaddress the initial influx of Elements from the Planning Coordinator during the
implementation period of time for a Generator Owner or Transmission Owner to develop a
Corrective Action Plan to modify its Protection System.1Requirement R2.
The period of time that may be required for a Generator Owner or Transmission Owner to take an Element outage, if
necessary, to modify the Protection System is driven through the Corrective Action Plan (CAP) and is independent of the
standard’s implementation period. The CAP includes its own timetable which is at the discretion of the entity.
1
Applicable Entities
Generator Owner
Planning Coordinator
Transmission Owner
Effective DateDates
Requirement Requirements R1-R3, R5, and R6
R1
First day of the first full calendar year that is 12 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 12 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
RequirementRequirements R2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 36 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Notifications Prior to the Effective Date of R4R2
During the implementation of the standard, notifications are likely to occur prior to Requirement R4R2
becoming effective. Where notification under R1 or identificationof Elements under Requirement R2
R1 or becoming aware of an Element tripping due to a stable or R3 occursunstable power swing prior
to the Effective Date of Requirement R4R2, the 12 month time period to evaluate if an Element’s load‐
responsive protective relays meet the criteria in PRC‐026‐1 – Attachment B in Requirement R4R2 will
begin, as expected, from the Effective Date of Requirement R4R2. Thereafter, entities will follow the 12
month time period in R4.accordance with Requirement R2. The intention of the additional time for
R4R2 to become effective is to handle the initial influx of notifications and identifications.
Justification
The implementation plan is based on the general considerations above and provides sufficient time for
the Generator Owner, Planning Coordinator, and Transmission Owner to begin becoming compliant
with the standard. The Effective date is constructed such that once the standard is adopted or
approved it would become effective inon the first day of the first whole calendar year after approvals
that is 12 months for Requirements R1‐R3, R5, and R6,Requirement R1 and 36 months for
Requirement Requirements R2, R3, and R4 after adoption or approval.
Implementation Plan (Draft 23: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings| August 22November 4, 2014
2
Requirement R1 – The Planning Coordinator will have at least one full calendar year to prepare
itself to identify any generator, transformer, and transmission line BES Elements that meet the
criteria and notify the respective Generator Owner and Transmission Owner of any identified
Elements, if any, within the allotted timeframe.
Requirement R2 – The Transmission Owner will have at least one year to prepare itself with identifying
any Element that trips due to a stable or unstable power swing during an actual system Disturbance
due to the operation of its load‐responsive protective relays, or any Element that forms the boundary
of an island during an actual system Disturbance due to the operation of its protective relays. This
includes providing the applicable notifications to the Planning Coordinator within the allotted
timeframe.
Requirement R3 – The Generator Owner will have at least one year to prepare itself with
identifying any Element that trips due to a stable or unstable power swing during an actual
system Disturbance due to the operation of its load‐responsive protective relays. This includes
providing the applicable notifications to the Planning Coordinator within the allotted
timeframe.
Requirement R4 – The Generator Owner and Transmission Owner will have at least three years
to develop internal processes and procedures for evaluating36 calendar months to determine if
its load‐responsive protective relays for an identified Element pursuant to
RequirementsRequirement R1, R2, and R3 meet the Attachment B criteria. Also, both entities
are provided an implementation that will allow the entity to conduct initial evaluations of its
load‐responsive protective relays for an identified Element during the first 36 calendar months
of approval.
Requirement R5R3 – The Generator Owner and Transmission Owner will have at least one year
to develop internal processes and proceduresimplementation period for developingthe
development of a Corrective Action Plan (CAP) for addressingis set to be consistent with
Requirement R2 to begin during the fourth calendar year of adoptions or approvals to address
any Protection System for an identified Element that requires modificationload‐responsive
protective relays determined in Requirement R2 not to meet PRC‐206‐1 –the Attachment B,
Criteria A and B criteria.
Requirement R6R4 – The Generator Owner and Transmission Owner will have at least one year
to develop internal processes and proceduresimplementation period for implementing any
CAPs developed inthis Requirement R5is set to be consistent with Requirement R3, the
development of a CAP.
Implementation Plan (Draft 23: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings| August 22November 4, 2014
3
Unofficial Comment Form
Project 2010-13.3 – Relay Loadability: Stable Power Swings
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard. The electronic comment form must be completed by 8 p.m. Eastern,
Monday, November 24, 2014.
If you have questions please contact Scott Barfield-McGinnis, Standards Developer at
[email protected] or by telephone at 404-446-9689.
http://www.nerc.com/pa/Stand/Pages/Project2010133Phase3ofRelayLoadabilityStablePowerSwings.aspx
Background Information
This posting is soliciting formal comment.
This is Phase 3 of a three-phased standard development that is focused on developing a new Reliability
Standard, PRC-026-1 – Relay Performance During Stable Power Swings, to address protective relay
operations due to stable power swings. The March 18, 2010, the Federal Energy Regulatory Commission
(FERC) Order No. 733, approved Reliability Standard PRC-023-1 – Transmission Relay Loadability. In this
Order, FERC directed NERC to address three areas of relay loadability that include modifications to the
approved PRC-023-1, development of a new Reliability Standard to address generator protective relay
loadability, and a new Reliability Standard to address the operation of protective relays due to stable
power swings. This project’s SAR addresses these directives with a three-phased approach to standard
development.
Phase 1 focused on making the specific modifications to PRC-023-1 and was completed in the approved
Reliability Standard PRC-023-2, which became mandatory on July 1, 2012. Phase 2 focused on developing
a new Reliability Standard, PRC-025-1 – Generator Relay Loadability, to address generator protective relay
loadability. PRC-025-1 became mandatory on October 1, 2014 along with PRC-023-2, which was modified
to harmonize PRC-023-2 with PRC-025-1. This Phase 3 of the project focuses on developing a new
Reliability Standard, PRC-026-1 – Relay Performance During Stable Power Swings, to address protective
relay operations due to stable power swings. This Reliability Standard will establish requirements aimed at
preventing protective relays from tripping unnecessarily due to stable power swings by requiring the
Transmission Owners and Generator Owners to assess the security of protective relay systems that are
susceptible to operation during stable and unstable power swings, and take actions to improve security
for only stable power swings where such actions would not compromise dependable operation for faults
and unstable power swings.
Summary of Changes from Draft 2 to Draft 3
The following is a summary of the change made to the proposed PRC-026-1 NERC Reliability Standard.
Applicability
Section 4.2, Facilities was revised from “The following Bulk Electric System Elements” to “The following
Elements that are part of the Bulk Electric System (BES)” to clarify that the listed items are the items being
addressed in the Requirements as the “Elements.”
Requirement R1
The Elements from the Applicability 4.2 (i.e., generator, transformer, and transmission line BES Elements)
was added for clarity. Also, the Requirement was modified to specifically require “notification” rather
than “identify and provide notification.” Identification of Elements based on the criteria is implied and
necessary as a part of the Requirement.
Requirement R1, Criterion 1
The term “operating limit” was clarified to be “System Operating Limit (SOL)” to remove ambiguity
between the operating and planning time frame. Also, “transmission switching station” was revised to be
“Transmission station.” The word “switching” did not add any additional clarity and the capitalized term
“Transmission” references the Glossary of Terms Used in NERC Reliability Standards.
Requirement R1, Criterion 2
The phrase “constraints identified in system planning or operating studies” was modified to be “…a SOL
identified by the Planning Coordinator’s methodology.” This allows the Standard to draw a connection
between the FAC-010 standard applicable to the Planning Coordinator in the planning horizon.
Requirement R1, Criterion 3
This criterion originally identified Elements that formed the boundary of an island which in many cases
would include Elements that were selected as arbitrary separation points and are not intended to be
included within the scope of the Standard. Therefore, Criterion 3 was rewritten to reflect it is the Element
which tripped on angular stability thus forming the island. Also, the criterion was updated to reflect the
most recent “design assessment” by the Planning Coordinator (i.e., PRC-006) and when the Planning
Coordinator uses angular stability as a design criteria for identifying islands.
Requirement R1, Criterion 4
The term “annual” was added to provide clarity.
Requirement R1, Criterion 5
Criterion 5 was removed from Requirement R1 because Requirements R2 and R3 in Draft 2 were
eliminated. Those Requirements directed the Transmission Owner and Generator Owner to notify the
Planning Coordinator of Elements that actually tripped due to a stable or unstable power swing. Criterion
Unofficial Comment Form (Draft 3: PRC-026-1 | November 4, 2014)
Project 2010-13.3 – Relay Loadability: Stable Power Swings
2
5 created a loopback to the Generator Owner and Transmission Owner to ensure that load-responsive
protective relays on identified Elements were evaluated on a periodic basis. Actual tripping events are
now included in Requirement R2 (previously Requirement R4) and do not require periodic review, unless
the Element trips due to a stable or unstable power swing.
Measure M1
Measure M1 was updated to reflect changes to Requirement R1 and to clarify that the focus is on
notification and not identification of Elements.
Requirements R2 and R3
These Requirements were removed due to structural changes in Requirement R4 (now Requirement R2).
The evaluation Requirement (now R2) was restructured to have two conditions for performance; 1) upon
notification of an Element pursuant to Requirement R1, and 2) an actual event due to a stable or unstable
power swing.
Requirement R4
This Requirement became Requirement R2 due to the removal of Requirements R2 and R3. Most
significantly, the Requirement was restructured to incorporate the removal of Requirements R2 and R3. It
was determined that Elements that tripped due to a stable or unstable power swing (R2/R3) would be
infrequent and more than likely a significantly large event which the Planning Coordinator would be
aware of through an event analysis. The new structure of the Requirement causes an evaluation;
however, it would not be necessary for the Planning Coordinator to be notified and then to continue
notifying the Generator Owner and Transmission Owner. Elements that actually tripped due to stable or
unstable power swings are not typical and requiring the Generator Owner and Transmission Owner to do
a one-time analysis is sufficient to address the risk.
Requirements R5 and R6
These Requirements became Requirements R3 and R4 due to the removal of Requirements R2 and R3.
Requirement R3 to develop the Corrective Action Plan (CAP) was inflexible as it only allowed the
modification of a Protection System that did not meet the PRC-026-1 – Attachment B criteria. To correct
this issue, Requirement R3 was modified to meet the purpose of the standard which is to ensure that
load-responsive protective relays are expected to not trip in response to stable power swings during nonFault conditions. First, the Requirement was revised to include two conditions. The first condition requires
a CAP to be developed such that the Protection System will meet the PRC-026-1 – Attachment B criteria.
For example, this may include a Protection System modification or a system configuration change which
causes the Protection System to meet the criteria. Second, the CAP allows power swing block to be
applied such that the Protection System may be excluded from the Standard.
Unofficial Comment Form (Draft 3: PRC-026-1 | November 4, 2014)
Project 2010-13.3 – Relay Loadability: Stable Power Swings
3
Also, the development period of the CAP was extended from 90 calendar days to six calendar months due
to the complexities that might be involved with determining appropriate remediation of a Protection
System that did not meet PRC-026-1 – Attachment B criteria.
Compliance Section
Section C1.1.2 was modified to conform evidence retention to the Reliability Assurance Initiative (RAI).
Retention periods were set to 12 calendar months.
Violation Severity Levels
The Violation Severity Levels (VSL) were modified to align them with the revisions made to the
Requirements.
PRC-026-1 – Attachments A and B
Attachment A received editorial changes and Attachment B, Criteria A was rewritten to clarify that a relay
characteristic that is completely contained within the unstable power swing region meets the criteria. The
unstable power swing region is formed by the union of three shapes in the impedance (R-X) plane.
Guidelines and Technical Basis
This section was revised substantively in response to comments and due to the removal of Requirements
R2 and R3. Revisions are too numerous to list here effectively. Please see the Guidelines and Technical
Basis redline document for changes.
Implementation Plan
The period for implementing the standard did not change substantively. Based on comments, the
implementation time frame for Requirements R5 and R6 (now Requirements R3 and R4) were increased
from 12 calendar months to 36 calendar months to align them with Requirement R4 (now Requirement
R2).
Unofficial Comment Form (Draft 3: PRC-026-1 | November 4, 2014)
Project 2010-13.3 – Relay Loadability: Stable Power Swings
4
*Please use the electronic comment form to submit your final comments to NERC.
You do not have to answer all questions. Enter All Comments in Simple Text Format.
Please note that the official comment form does not retain formatting (even if it appears to transfer
formatting when you copy from the unofficial Word version of the form into the official electronic
comment form). If you enter extra carriage returns, bullets, automated numbering, symbols, bolding,
italics, or any other formatting, that formatting will not be retained when you submit your comments.
• Separate discrete comments by idea, e.g., preface with (1), (2), etc.
• Use brackets [] to call attention to suggested inserted or deleted text.
• Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
• Do not use formatting such as extra carriage returns, bullets, automated numbering, bolding, or
italics.
• Please do not repeat other entity’s comments. Select the appropriate item to support another
entity’s comments. An opportunity to enter additional or exception comments will be available.
• If supporting other’s comments, be sure the other party submits comments.
Question
1. The Protection System Response to Power Swings Standard Drafting Team believes it has
addressed industry comments in such a manner that industry consensus can be achieved. If there
are remaining unresolved issues in the proposed PRC-026-1 Reliability Standard, please provide
your comments here:
Comments:
Unofficial Comment Form (Draft 3: PRC-026-1 | November 4, 2014)
Project 2010-13.3 – Relay Loadability: Stable Power Swings
5
Violation Risk Factors and
Violation Severity Level Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
(PRC-026-1 – Relay Performance During Stable Power Swings)
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: PRC‐026‐1 – Relay
Performance During Stable Power Swings.
Each primary requirement is assigned a VRF and a set of one or more VSLs. 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 ERO
Sanction Guidelines.
The Protection System Response to Power Swings Standard Drafting Team applied the following
NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under
this project.
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric 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 electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
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 electric system, or the
ability to effectively monitor and control the bulk electric 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 electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
The standard drafting team (SDT) also considered consistency with the FERC Violation Risk Factor
Guidelines for setting VRFs:1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors 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: 2
• 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
Guideline (2) — Consistency within a Reliability Standard
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
2
Id. at footnote 15.
1
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
2
The Commission expects a rational connection between the sub‐Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk
Factor 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.
NERC Criteria - Violation Severity Levels
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.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets
the full intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
3
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the
following four guidelines for determining whether to approve 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
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: 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.
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 and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
4
VRF and VSL Justifications – PRC-026-1, R1
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to notify the respective Generator Owner or Transmission Owner of the Element(s) that meet the
Requirement R1 criteria prohibits further evaluation of any load‐responsive protective relay applied at the
terminal of the Element(s). A load‐responsive protective relay that goes without evaluation may not be
secure for a stable power swing and could in the planning time frame, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk
electric system.
Identifying an Element for notification that is expected to encounter stable power swings based on
Requirement R1 criteria is the first step in ensuring the reliable operation of the Bulk Electric System (BES)
and in preventing the future severity of disturbances from affecting a wider area.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two Bulk Power System (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Identification and
evaluation of BES Elements susceptible to power swings and the subsequent mitigation of load‐responsive
protective relays applied at the terminals of these BES Elements that do not meet the PRC‐026‐1 –
Attachment B criteria will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on the issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
5
VRF and VSL Justifications – PRC-026-1, R1
specific condition of concern, such as a fault, out‐of‐step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no sub‐
Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard FAC‐014‐2, R6 (“…Planning Authority shall
identify the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
A failure of the Planning Coordinator to notify the respective Generator Owner or Transmission Owner of
the BES Element(s) that meet the Requirement R1 criteria prohibits further evaluation of any load‐
responsive protective relay applied at the terminal of the Element. A load‐responsive protective relay that
goes without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
Identifying an Element for notification that is expected to encounter stable power swings based on the
Requirement R1 criteria is the first step in ensuring the reliable operation of the BES and in preventing the
future severity of disturbances from affecting a wider area.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This Requirement does not co‐mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
6
VRF and VSL Justifications – PRC-026-1, R1
Proposed VSL
Lower
Moderate
High
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was less
than or equal to 30 calendar
days late.
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The Planning Coordinator provided
notification of the BES Element(s)
in accordance with Requirement
R1, but was more than 60 calendar
days and less than or equal to 90
calendar days late.
Severe
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 90 calendar days late.
OR
The Planning Coordinator failed to
provide notification of the BES
Element(s) in accordance with
Requirement R1.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size‐neutral because performance is Element‐driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
7
VRF and VSL Justifications – PRC-026-1, R1
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
8
VRF and VSL Justifications – PRC-026-1, R2
Proposed VRF
High
NERC VRF Discussion
A Violation Risk Factor of High is consistent with the NERC VRF Guidelines:
A failure to evaluate the Protection System to determine that it is expected to not trip for a stable power
swing for a BES Element could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
A Protection System that does not meet the PRC‐026‐1 – Attachment B criteria is less secure during stable
power swings, which increases the risk of tripping should the Protection System be challenged by a power
swing.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Evaluation of load‐
responsive protective relays applied at the terminals of identified BES Elements will allow the Generator
Owner and Transmission Owner to determine whether the load‐responsive protective relays meet the
PRC‐026‐1 – Attachment B criteria.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out‐of‐step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
9
VRF and VSL Justifications – PRC-026-1, R2
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no sub‐
Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard PRC‐023‐3, R1 “…Each Transmission Owner,
Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per unit voltage and a
power factor angle of 30 degrees”) which has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
A failure of the Generator Owner or Transmission Owner to evaluate that the Protection System is
expected to not trip in response to a stable power swing during a non‐Fault condition for a BES Element
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to bulk electric system instability, separation, or a cascading sequence of failures, or
could place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures,
or could hinder restoration to a normal condition.
A Protection System that does not meet the PRC‐026‐1 – Attachment B criteria is less secure during stable
power swings, it increases the risk of tripping should the Protection System be challenged by a power
swing.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This Requirement does not co‐mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
10
VRF and VSL Justifications – PRC-026-1, R2
Proposed VSL
Lower
Moderate
High
The Generator Owner or
Transmission Owner evaluated
its load‐responsive protective
relay(s) in accordance with
Requirement R2, but was less
than or equal to 30 calendar
days late.
The Generator Owner or
Transmission Owner evaluated
its load‐responsive protective
relay(s) in accordance with
Requirement R2, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The Generator Owner or
Transmission Owner evaluated its
load‐responsive protective relay(s)
in accordance with Requirement
R2, but was more than 60 calendar
days and less than or equal to 90
calendar days late.
Severe
The Generator Owner or
Transmission Owner evaluated its
load‐responsive protective relay(s)
in accordance with Requirement
R2, but was more than 90 calendar
days late.
OR
The Generator Owner or
Transmission Owner failed to
evaluate its load‐responsive
protective relay(s) in accordance
with Requirement R2.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size‐neutral because performance is driven by exception. For example, each
identified Element must be evaluated.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
11
VRF and VSL Justifications – PRC-026-1, R2
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
12
VRF and VSL Justifications – PRC-004-3, R3
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
Failure to develop a Corrective Action Plan (CAP) such that the Protection System of a BES Element will
meet the PRC‐026‐1 – Attachment B criteria or to exclude the Protection System under the PRC‐026‐1 –
Attachment A criteria (e.g., modifying the Protection System so that relay functions are supervised by
power swing blocking or using relay systems that are immune to power swings) could in the planning time
frame, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
An unmitigated Protection System could affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Developing a CAP such
that the Protection System will meet the Attachment B criteria or to exclude the Protection System under
the PRC‐026‐1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) applied at
the terminals of BES Elements will reduce the likelihood of reoccurrence.
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
13
VRF and VSL Justifications – PRC-004-3, R3
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out‐of‐step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
This Requirement has a single reliability activity associated with the reliability objective and no sub‐
Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which requiring corrective actions
(e.g., Corrective Action Plans); PRC‐016‐0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC‐022‐1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC‐003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all three of which have a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to develop the Corrective Action Plan (CAP) such that the Protection System of a BES Element will
meet the Attachment B criteria or to exclude the Protection System under the PRC‐026‐1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings) could in the planning time frame, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system.
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
14
VRF and VSL Justifications – PRC-004-3, R3
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement does not co‐mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
Moderate
High
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R3, but in more
than six calendar months and
less than or equal to seven
calendar months.
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R3, but in more
than seven calendar months
and less than or equal to eight
calendar months.
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement R3,
but in more than eight calendar
months and less than or equal to
nine calendar months.
Severe
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement R3,
but in more than nine calendar
months.
OR
The Generator Owner or
Transmission Owner failed to
develop a CAP in accordance with
Requirement R3.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to develop the
Corrective Action Plan in a timely fashion and a binary aspect for a complete failure. The VSL is entity size‐
neutral because performance is driven by the need to mitigate the Protection System so that it is expected
to not trip on a stable power swing.
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
15
VRF and VSL Justifications – PRC-004-3, R3
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
This proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
This proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with this Requirement.
The VSL is based on a single violation and not cumulative violations.
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
16
VRF and VSL Justifications – PRC-004-3, R3
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-026-1, R4
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan (CAP) to meet the PRC‐026‐1 – Attachment B criteria or
to exclude the Protection System under the PRC‐026‐1 – Attachment A criteria (e.g., modifying the
Protection System so that relay functions are supervised by power swing blocking or using relay systems
that are immune to power swings) could in the planning time frame, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk
electric system.
An unmitigated Protection System could affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
17
VRF and VSL Justifications – PRC-026-1, R4
could negatively impact system reliability under different operating conditions. Implementing a CAP such
that the Protection System will meet the Attachment B criteria or to exclude the Protection System under
the PRC‐026‐1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) applied at
the terminals of these Elements will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out‐of‐step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no sub‐
Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which requiring corrective actions
(e.g., Corrective Action Plans): PRC‐016‐0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC‐022‐1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC‐003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all of which have a VRF of Medium.
FERC VRF G4 Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan such that the Protection System of a BES Element will
meet the Attachment B criteria or to exclude the Protection System under the PRC‐026‐1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings) could in the planning time frame, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
18
VRF and VSL Justifications – PRC-026-1, R4
affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This Requirement does not co‐mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
The responsible entity
implemented, but failed to
update a CAP, when actions or
timetables changed, in
accordance with Requirement
R4.
Moderate
N/A
High
N/A
Severe
The responsible entity failed to
implement a CAP in accordance
with Requirement R4.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to update the
Corrective Action Plan and a binary aspect for failure to implement. The VSL is entity size‐neutral because
performance is driven by the need to mitigate the Protection System so that it is expected to not trip on a
stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
19
VRF and VSL Justifications – PRC-026-1, R4
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
20
VRF and VSL Justifications – PRC-026-1, R4
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 3: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
21
Violation Risk Factors and
Violation Severity Level Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
(PRC-026-1 – Relay Performance During Stable Power Swings)
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: PRC‐026‐1 – Relay
Performance During Stable Power Swings.
Each primary requirement is assigned a VRF and a set of one or more VSLs. 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 ERO
Sanction Guidelines.
The Protection System Response to Power Swings Standard Drafting Team applied the following
NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under
this project.
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric 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 electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
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 electric system, or the
ability to effectively monitor and control the bulk electric 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 electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
The standard drafting team (SDT) also considered consistency with the FERC Violation Risk Factor
Guidelines for setting VRFs:1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors 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: 2
• 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
Guideline (2) — Consistency within a Reliability Standard
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
2
Id. at footnote 15.
1
VRF and VSL Justifications (Draft 23: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
2
The Commission expects a rational connection between the sub‐Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk
Factor 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.
NERC Criteria - Violation Severity Levels
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.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets
the full intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
VRF and VSL Justifications (Draft 23: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
3
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the
following four guidelines for determining whether to approve 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
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: 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.
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 and VSL Justifications (Draft 23: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
4
VRF and VSL Justifications – PRC-026-1, R1
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to identify annotify the respective Generator Owner or Transmission Owner of the Element
meeting(s) that meet the Requirement R1 criteria prohibits further evaluation of any load‐responsive
protective relay applied at the terminal of the Element.(s). A load‐responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
Identifying an Element for notification that is expected to encounter stable power swings based on
prescribedRequirement R1 criteria is the first step in ensuring the reliable operation of the Bulk Electric
System (BES) and in preventing the future severity of Disturbancesdisturbances from affecting a wider
area.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two Bulk Power System (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
protection systemProtection System operations on these lines did not contribute significantly to the
overall outcome of the August 14, 2003 system disturbance; however, protection systemProtection
System operation during stable powers swings could negatively impact system reliability under different
operating conditions. IdentifyingIdentification and evaluation of BES Elements pronesusceptible to power
swings and the subsequent mitigation of load‐responsive protective relays applied at the terminals of
these BES Elements that do not meet the PRC‐026‐1 – Attachment B criteria will reduce the likelihood of
reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on thisthe issue of Protection Systems tripping in response to stable power
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
5
VRF and VSL Justifications – PRC-026-1, R1
swings, the recommendation does note that “power system protection devices should be set to address
the specific condition of concern, such as a fault, out‐of‐step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no sub‐
Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability StandardsStandard FAC‐014‐2, R6 (“…Planning
Authority shall identify the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
A failure to identify an Element meeting theA failure of the Planning Coordinator to notify the respective
Generator Owner or Transmission Owner of the BES Element(s) that meet the Requirement R1 criteria
prohibits further evaluation of any load‐responsive protective relay applied at the terminal of the
Element. A load‐responsive protective relay that goes without evaluation may not be secure for a stable
power swing and could in the planning time frame, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly and adversely affect the electrical state or capability of the bulk
electric system, or the ability to effectively monitor, control, or restore the bulk electric system.
Identifying an Element for notification that is expected to encounter stable power swings based on
prescribedthe Requirement R1 criteria is the first step in ensuring the reliable operation of the BES and in
preventing the future severity of Disturbancesdisturbances from affecting a wider area.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This Requirement does not co‐mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
6
VRF and VSL Justifications – PRC-026-1, R1
Proposed VSL
Lower
Moderate
High
The Planning Coordinator
identified an Element and
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was less
than or equal to 30 calendar
days late.
The Planning Coordinator
identified an Element and
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The Planning Coordinator
identified an Element and
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 60 calendar days and less
than or equal to 90 calendar days
late.
Severe
The Planning Coordinator
identified an Element and
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 90 calendar days late.
OR
The Planning Coordinator failed to
identify anprovide notification of
the BES Element(s) in accordance
with Requirement R1.
OR
The Planning Coordinator failed to
provide notification in accordance
with Requirement R1.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size‐neutral because performance is Element‐driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
7
VRF and VSL Justifications – PRC-026-1, R1
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
8
VRF and VSL Justifications – PRC-026-1, R1
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-026-1, R2 and R3
Proposed VRF
HighMedium
NERC VRF Discussion
A Violation Risk Factor of MediumHigh is consistent with the NERC VRF Guidelines:
A failure to identify an Element meetingevaluate the criteria prohibits further evaluation of any load‐
responsive protective relay applied at the terminal of the Element. A load‐responsive protective
relayProtection System to determine that goes without evaluation mayit is expected to not be securetrip
for a stable power swing and for a BES Element could in the planning time frame, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical statecause or capability of thecontribute to bulk electric system instability, separation, or the
ability to effectively monitor, controla cascading sequence of failures, or restorecould place the bulk
electric system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Identifying an ElementA Protection System that is expected to encounterdoes not meet the PRC‐026‐1 –
Attachment B criteria is less secure during stable power swings based on prescribed criteria is the first
step in ensuring, which increases the reliable operationrisk of tripping should the BES and in preventing
the future severity of Disturbances from affectingProtection System be challenged by a wider areapower
swing.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
protection systemProtection System operations on these lines did not contribute significantly to the
overall outcome of the August 14, 2003 system disturbance; however, protection systemProtection
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
9
VRF and VSL Justifications – PRC-026-1, R2 and R3
System operation during stable powers swings could negatively impact system reliability under different
operating conditions. Identifying Elements prone to power swings and the subsequent
mitigationEvaluation of load‐responsive protective relays applied at the terminals of theseidentified BES
Elements will reduceallow the Generator Owner and Transmission Owner to determine whether the
likelihood of reoccurrence. load‐responsive protective relays meet the PRC‐026‐1 – Attachment B criteria.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out‐of‐step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no sub‐
Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
A failure to identify an Element meeting the criteria prohibits further evaluation of any load‐responsive
protective relay applied at the terminal of the Element. A load‐responsive protective relay that goes
without evaluation may not be secure for a stable power swing and could in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
Identifying an Element that is expected to encounter stable power swings based on prescribed criteria is
the first step in ensuring the reliable operation of the BES and in preventing the future severity of
Disturbances from affecting a wider area.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This Requirement does not co‐mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
10
VRF and VSL Justifications – PRC-026-1, R2 and R3
Proposed VSL
Lower
Moderate
High
Severe
The Transmission Owner
identified an Element and
provided notification in
accordance with Requirement
R2, but was less than or equal
to 10 calendar days late.
The Transmission Owner
identified an Element and
provided notification in
accordance with Requirement
R2, but was more than 10
calendar days and less than or
equal to 20 calendar days late.
The Transmission Owner identified
an Element and provided
notification in accordance with
Requirement R2, but was more
than 20 calendar days and less
than or equal to 30 calendar days
late.
The Transmission Owner identified
an Element and provided
notification in accordance with
Requirement R2, but was more
than 30 calendar days late.
OR
The Transmission Owner failed to
identify an Element in accordance
with Requirement R2.
OR
The Transmission Owner failed to
provide notification in accordance
with Requirement R2.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size‐neutral because performance is Element‐driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
The proposed VSL does not lower the current level of compliance because the Requirement is new.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
11
VRF and VSL Justifications – PRC-026-1, R2 and R3
FERC VSL G2
Violation Severity Level
Assignments 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
Guideline 2a:
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
12
VRF and VSL Justifications – PRC-026-1, R4
Proposed VRF
High
NERC VRF Discussion
A Violation Risk Factor of High is consistent with the NERC VRF Guidelines:
A failure to evaluate that the Protection System is expected to not trip for a stable power swing for an
identified Element could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
If a Protection System is less secure during stable power swings, it increases the risk of tripping should
the Protection System be challenged by a power swing.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two BPS transmission lines tripped
due to protective relay operation in response to stable power swings. The protection system operations
on these lines did not contribute significantly to the overall outcome of the August 14, 2003 system
disturbance. Identifying Elements prone to power swings and the subsequent mitigation of load‐
responsive protective relays applied at the terminals of these Elements will reduce the likelihood of
reoccurrence. This Requirement is consistent with the intent of Recommendation 8: Improve System
Protection to Slow or Limit the Spread of Future Cascading Outages. While the actions associated with
this recommendation did not focus specifically on this issue, the recommendation does note that “power
system protection devices should be set to address the specific condition of concern, such as a fault, out‐
of‐step condition, etc., and should not compromise a power system’s inherent physical capability to slow
down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no sub‐
Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
13
VRF and VSL Justifications – PRC-026-1, R4
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard PRC‐023‐3, R1 “…Each Transmission Owner,
Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per unit voltage and a
power factor angle of 30 degrees”) which has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
A failure of the Generator Owner or Transmission Owner to ensureevaluate that the Protection System
willis expected to not trip in response to a stable power swing during a non‐Fault condition for an
identifieda BES Element could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
If aA Protection System that does not meet the PRC‐026‐1 – Attachment B criteria is less secure during
stable power swings, it increases the risk of tripping should the Protection System be challenged by a
power swing.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This Requirement does not co‐mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
14
VRF and VSL Justifications – PRC-026-1, R4
Proposed VSL
Lower
Moderate
High
The Generator Owner
identified an Element and
provided notificationor
Transmission Owner evaluated
its load‐responsive protective
relay(s) in accordance with
Requirement R3R2, but was
less than or equal to 1030
calendar days late.
The Generator Owner
identified an Element and
provided notificationor
Transmission Owner evaluated
its load‐responsive protective
relay(s) in accordance with
Requirement R3R2, but was
more than 1030 calendar days
and less than or equal to 2060
calendar days late.
The Generator Owner identified
an Element and provided
notificationor Transmission Owner
evaluated its load‐responsive
protective relay(s) in accordance
with Requirement R3R2, but was
more than 2060 calendar days and
less than or equal to 3090
calendar days late.
Severe
The Generator Owner identified an
Element and provided
notificationor Transmission Owner
evaluated its load‐responsive
protective relay(s) in accordance
with Requirement R3R2, but was
more than 3090 calendar days late.
OR
The Generator Owner or
Transmission Owner failed to
identify an Elementevaluate its
load‐responsive protective relay(s)
in accordance with Requirement
R3.
OR
The Generator Owner failed to
provide notification in accordance
with Requirement R3R2.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size‐neutral because performance is driven by exception. For example, each
identified Element must be evaluated.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
15
VRF and VSL Justifications – PRC-026-1, R4
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
16
VRF and VSL Justifications – PRC-026-1, R4
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-004-3, R5R3
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
Failure to develop a Corrective Action Plan to modify a Protection System of an identified Element that
does not meet the criteria(CAP) such that the Protection System of a BES Element will meet the PRC‐026‐1
– Attachment B criteria or to exclude the Protection System under the PRC‐026‐1 – Attachment A criteria
(e.g., modifying the Protection System so that relay functions are supervised by power swing blocking or
using relay systems that are immune to power swings) could in the planning time frame, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system.
An unmitigated Protection System could affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
17
VRF and VSL Justifications – PRC-004-3, R5R3
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
protection systemProtection System operations on these lines did not contribute significantly to the
overall outcome of the August 14, 2003 system disturbance; however, protection systemProtection
System operation during stable powers swings could negatively impact system reliability under different
operating conditions. Identifying Elements proneDeveloping a CAP such that the Protection System will
meet the Attachment B criteria or to exclude the Protection System under the PRC‐026‐1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings and the subsequent mitigation of load‐
responsive protective relays) applied at the terminals of theseBES Elements will reduce the likelihood of
reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out‐of‐step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
This Requirement has a single reliability activity associated with the reliability objective and no sub‐
Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
18
VRF and VSL Justifications – PRC-004-3, R5R3
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which requiring corrective actions
or(e.g., Corrective Action Plans;); PRC‐016‐0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC‐022‐1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC‐003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all three of which have a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implementdevelop the Corrective Action Plan for a(CAP) such that the Protection System of an
identifieda BES Element will meet the Attachment B criteria or to exclude the Protection System under the
PRC‐026‐1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) could in the
planning time frame, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement does not co‐mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
19
VRF and VSL Justifications – PRC-004-3, R5R3
Proposed VSL
Lower
Moderate
High
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R5R3, but in more
than 60six calendar
daysmonths and less than or
equal to 70seven calendar
daysmonths.
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R5R3, but in more
than 70seven calendar
daysmonths and less than or
equal to 80eight calendar
daysmonths.
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement
R5R3, but in more than 80eight
calendar daysmonths and less than
or equal to 90nine calendar
daysmonths.
Severe
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement
R5R3, but in more than 90nine
calendar daysmonths.
OR
The Generator Owner or
Transmission Owner failed to
develop a CAP in accordance with
Requirement R5R3.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to develop the
Corrective Action Plan in a timely fashion and a binary aspect for a complete failure. The VSL is entity size‐
neutral because performance is driven by the need to mitigate the Protection System so that it is expected
to not trip on a stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
20
VRF and VSL Justifications – PRC-004-3, R5R3
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
This proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
This proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with this Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
21
VRF and VSL Justifications – PRC-026-1, R6R4
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for modifying a Protection System of an identified
Element(CAP) to meet the PRC‐026‐1 – Attachment B criteria or to exclude the Protection System under
the PRC‐026‐1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) could in the
planning time frame, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system.
An unmitigated Protection System could affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
protection systemProtection System operations on these lines did not contribute significantly to the
overall outcome of the August 14, 2003 system disturbance; however, protection systemProtection
System operation during stable powers swings could negatively impact system reliability under different
operating conditions. Identifying Elements proneImplementing a CAP such that the Protection System will
meet the Attachment B criteria or to exclude the Protection System under the PRC‐026‐1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings and the subsequent mitigation of load‐
responsive protective relays) applied at the terminals of these Elements will reduce the likelihood of
reoccurrence.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
22
VRF and VSL Justifications – PRC-026-1, R6R4
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out‐of‐step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no sub‐
Requirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which requiring corrective actions
or(e.g., Corrective Action Plans:): PRC‐016‐0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC‐022‐1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC‐003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all of which have a VRF of Medium.
FERC VRF G4 Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan for a Protection System of an identified Elementsuch
that the Protection System of a BES Element will meet the Attachment B criteria or to exclude the
Protection System under the PRC‐026‐1 – Attachment A criteria (e.g., modifying the Protection System so
that relay functions are supervised by power swing blocking or using relay systems that are immune to
power swings) could in the planning time frame, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly and adversely affect the electrical state or capability of the bulk
electric system, or the ability to effectively monitor, control, or restore the bulk electric system.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage.
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
23
VRF and VSL Justifications – PRC-026-1, R6R4
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This Requirement does not co‐mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
The responsible entity
implemented, but failed to
update a CAP, when actions or
timetables changed, in
accordance with Requirement
R4.
Moderate
N/A
High
N/A
Severe
The responsible entity failed to
implement a CAP in accordance
with Requirement R4.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to update the
Corrective Action Plan and a binary aspect for failure to implement. The VSL is entity size‐neutral because
performance is driven by the need to mitigate the Protection System so that it is expected to not trip on a
stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
24
VRF and VSL Justifications – PRC-026-1, R6R4
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 13: PRC‐026‐1)
Project 2010‐13.3 – Relay Loadability: Stable Power Swings | August 22November 4, 2014
25
Table of Issues and Directives
Project 2010-13.3 – Relay Loadability: Stable Power Swings
Table of Issues and Directives Associated with PRC-026-1
Source
FERC Order
733
1
Issue or Directive Language
(including Para. #)
150. We will not direct the ERO to
modify PRC‐023‐1 to address stable
power swings. However, because both
NERC and the Task Force have
identified undesirable relay operation
due to stable power swings as a
reliability issue, we direct the ERO to
develop a Reliability Standard that
requires the use of protective relay
systems that can differentiate between
faults and stable power swings and,
when necessary, phases out protective
relay systems that cannot meet this
requirement.
Section and/or
Requirement(s)
All requirements
Consideration of Issue or Directive
The PRC‐026‐1 standard is responsive to this
directive by using an equally effective and efficient
focused approach for the Planning Coordinator to
provide notification of BES Elements according to the
Requirement R1 criteria to the respective Generator
Owner and Transmission Owner. The criteria used to
identify a BES Element are based on the NERC
System Protection and Control Subcommittee
technical document, Protection System Response to
Power Swings (“PSRPS Report”).1 The specific criteria
are based on where power swings are expected to
challenge load‐responsive protective relays.
The criteria include 1) Generator(s) where an angular
stability constraint exists that is addressed by a
NERC System Protection and Control Subcommittee technical document, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
We also direct the ERO to file a report
no later than 120 days of this Final Rule
addressing the issue of protective relay
operation due to power swings. The
report should include an action plan
and timeline that explains how and
when the ERO intends to address this
issue through its Reliability Standards
development process.
AND
153. While we recognize that
addressing stable power swings is a
complex issue, we note that more than
six years have passed since the August
2003 blackout and there is still no
Reliability Standard that addresses
relays tripping due to stable power
swings. Additionally, NERC has long
identified undesirable relay operation
due to stable power swings as a
reliability issue. Consequently, pursuant
to section 215(d)(5) of the FPA, we find
Table of Issues and Directives (Draft 3: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
Consideration of Issue or Directive
System Operating Limit (SOL) or a Remedial Action
Scheme (RAS) and those Elements terminating at the
Transmission station associated with the
generator(s); 2) An Element that is monitored as part
of a SOL identified by the Planning Coordinator’s
methodology based on an angular stability
constraint; 3) An Element that forms the boundary
of an island in the most recent underfrequency load
shedding (UFLS) design assessment based on
application of the Planning Coordinator’s criteria for
identifying islands, where the island is formed by
tripping the Element based on angular instability; 4)
An Element identified in the most recent annual
Planning Assessment where relay tripping occurs due
to a stable or unstable power swing during a
simulated disturbance.
Requirement R2 requires the Generator Owner and
Transmission Owner to evaluate its load‐responsive
protective relays that are applied at all of the
terminals of each BES Element identified by the
Planning Coordinator in Requirement R1 or upon
becoming aware of a generator, transformer, or
2
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
that undesirable relay operation due to
stable power swings is a specific matter
that the ERO must address to carry out
the goals of section 215, and we direct
the ERO to develop a Reliability
Standard addressing undesirable relay
operation due to stable power swings.
Consideration of Issue or Directive
transmission line BES Element that tripped in
response to a stable or unstable power swing due to
the operation of its protective relay(s). The initial
evaluation allows the Generator Owner and
Tranmission Owner to determine whether its load‐
responsive protective relays applied at all of the
terminals of the BES Element meet the PRC‐026‐1 –
Attachment B criteria. Additionally, the Requirement
ensures that the Generator Owner and Transmission
Owner must re‐evaluate the Protection System on a
five year basis should the BES Element continue to
be identified by the Planning Coordinator in
Requirement R1.
Requirement R3 mandates the development of a
Corrective Action Plan (CAP) such that the Protection
System of a BES Element will meet the PRC‐026‐1 –
Attachment B criteria or to exclude the Protection
System under the PRC‐026‐1 – Attachment A criteria
(e.g., modifying the Protection System so that relay
functions are supervised by power swing blocking or
using relay systems that are immune to power
swings).
Table of Issues and Directives (Draft 3: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
3
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
Consideration of Issue or Directive
Requirement R4 mandates that the Generator
Owner and Transmission Owner implement each
developed CAP in Requirement R3 so that load‐
responsive protective relays are expected to not trip
in response to stable power swings during non‐Fault
conditions.
162. The PSEG Companies also assert
Requirement R1, Criterion 3
that the Commission’s approach to
and Requirement R2, Criterion
stable power swings should be inclusive 2.
and include “islanding” strategies in
conjunction with out‐of‐step blocking
or tripping requirements. We agree
with the PSEG Companies and direct
the ERO to consider “islanding”
strategies that achieve the fundamental
performance for all islands in
developing the new Reliability Standard
addressing stable power swings.
Islanding strategies were considered during the
development of the proposed standard. It was
determined that consideration of islanding strategies
does not comport with the purpose and approach of
the proposed standard. Islanding strategies are
developed to isolate the system from unstable
power swings, which is not prohibited under the
proposed standard. The proposed standard’s
purpose is to ensure that load‐responsive protective
relays are expected to not trip in response to stable
power swings during non‐Fault conditions, not to
determine where the BES Elements should form
island boundaries.
With respect to considering the islanding concern,
the proposed standard does require that a BES
Table of Issues and Directives (Draft 3: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
4
Table of Issues and Directives Associated with PRC-026-1
Source
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
Consideration of Issue or Directive
Element that forms the boundary of an island in the
most recent underfrequency load shedding (UFLS)
design assessment based on application of the
Planning Coordinator’s criteria for identifying islands,
where the island is formed by tripping the Element
based on angular instability.
Any identified BES Element(s) require the Generator
Owner and Transmission Owner to determine
whether its load‐responsive protective relays, if any,
applied at the terminals of such an Element are
susceptible to tripping in response to a stable power
swing. If so, the Generator Owner and Transmission
Owner are required to take specific action according
to the Requirements to reduce the risk that any load‐
responsive protective relay would trip in response to
stable power swings during non‐Fault conditions.
Table of Issues and Directives (Draft 3: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4, 2014
5
Standards Announcement Reminder
Project 2010-13.3 – Phase 3 of Relay Loadability: Stable
Power Swings
PRC-026-1
Additional Ballot and Non-Binding Poll Now Open through November 24, 2014
Now Available
An additional ballot for PRC-026-1 - Relay Performance During Stable Power Swing and a non-binding
poll of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) is open through 8
p.m. Eastern, Monday, November 24, 2014.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
standard and associated VRFs and VSLs by clicking here.
Note: If a member cast a vote in the initial ballot, that vote will not carry over to the additional
ballot. It is the responsibility of the registered voter in the ballot pool to cast a vote again in the
additional ballot. To ensure a quorum is reached, if you do not want to vote affirmative or negative,
please cast an abstention.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider
all comments received during the formal comment period and, if needed, make revisions to the
standard and post it for an additional ballot. If the comments do not show the need for significant
revisions, the standard will proceed to a final ballot.
For information on the Standards Development Process, please refer to the Standard Processes Manual.
For more information or assistance, please contact Standards Developer, Scott Barfield,
or by telephone at 404-446-9689.
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 2010-13.3 – Phase 3 of Relay Loadability: Stable
Power Swings
PRC-026-1
Formal Comment Period Now Open through November 24, 2014
Now Available
A 21-day formal comment period for PRC-026-1 - Relay Performance During Stable Power Swings is open
through 8 p.m. Eastern, Monday, November 24, 2014.
The Standards Committee (SC) authorized a waiver to shorten the comment period for PRC-026-1 from 45
days to 21 days, with an additional ballot and non-binding poll to be conducted during the last 10 days of
the comment period. The notice of waiver request presented to the SC for consideration is posted on
the project page.
Instructions for Commenting
Please use the electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Arielle Cunningham. An off-line, unofficial copy of the comment form is
posted on the project page.
Next Steps
An additional ballot for the standard and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted November 14-24, 2014.
Note: If a member cast a vote in the initial ballot, that vote will not carry over to the additional ballot. It
is the responsibility of the registered voter in the ballot pool to cast a vote again in the additional ballot.
To ensure a quorum is reached, please cast an abstention if you do not want to vote affirmative or
negative.
For information on the Standards Development Process, please refer to the Standard Processes Manual.
For more information or assistance, please contact Scott Barfield,
Standards Developer, or via telephone at 404-446-9689.
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 2010-13.3 – Phase 3 of Relay Loadability: Stable
Power Swings
PRC-026-1
Formal Comment Period Now Open through November 24, 2014
Now Available
A 21-day formal comment period for PRC-026-1 - Relay Performance During Stable Power Swings is open
through 8 p.m. Eastern, Monday, November 24, 2014.
The Standards Committee (SC) authorized a waiver to shorten the comment period for PRC-026-1 from 45
days to 21 days, with an additional ballot and non-binding poll to be conducted during the last 10 days of
the comment period. The notice of waiver request presented to the SC for consideration is posted on
the project page.
Instructions for Commenting
Please use the electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Arielle Cunningham. An off-line, unofficial copy of the comment form is
posted on the project page.
Next Steps
An additional ballot for the standard and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted November 14-24, 2014.
Note: If a member cast a vote in the initial ballot, that vote will not carry over to the additional ballot. It
is the responsibility of the registered voter in the ballot pool to cast a vote again in the additional ballot.
To ensure a quorum is reached, please cast an abstention if you do not want to vote affirmative or
negative.
For information on the Standards Development Process, please refer to the Standard Processes Manual.
For more information or assistance, please contact Scott Barfield,
Standards Developer, or via telephone at 404-446-9689.
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 2010-13.3 Phase 3 of Relay Loadability:
Stable Power Swings
PRC-026-1
Additional Ballot and Non-Binding Poll Results
Now Available
An additional ballot for PRC-026-1 – Relay Performance During Stable Power Swings and a non-binding
poll of the associated Violation Risk Factors and Violation Severity Levels concluded at 8 p.m. Eastern on
Monday, November 24, 2014.
The standard achieved a quorum and received sufficient affirmative votes for approval. Voting statistics
are listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Ballot
Non-Binding Poll
Quorum /Approval
Quorum/Supportive Opinions
79.83% / 67.39%
78.61% / 66.13%
Background information for this project can be found on the project page.
Next Steps
The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard and post it for an additional ballot. If the comments do not
show the need for significant revisions, the standard will proceed to a final ballot.
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Standards Developer, Scott Barfield,
or by telephone at 404-446-9689.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC Standards
Newsroom • Site Map • Contact NERC
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Ballot Results
Ballot Name:
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Home Page
Project 2010-13.3 Relay Loadability Stable Power Swings PRC-0261
Ballot Period: 11/14/2014 - 11/24/2014
Ballot Type: Additional
Total # Votes: 289
Total Ballot Pool: 362
Quorum: 79.83 % The Quorum has been reached
Weighted Segment
67.39 %
Vote:
Ballot Results: The Ballot has Closed
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
#
#
No
without a
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
1
2Segment
2
3Segment
3
4Segment
4
5Segment
5
6Segment
6
7Segment
7
8Segment
8
9Segment
104
1
38
0.594
26
0.406
1
16
23
9
0.8
6
0.6
2
0.2
0
0
1
76
1
34
0.68
16
0.32
0
11
15
25
1
10
0.556
8
0.444
0
4
3
79
1
33
0.611
21
0.389
0
8
17
52
1
22
0.611
14
0.389
0
5
11
2
0.1
0
0
1
0.1
0
0
1
4
0.4
3
0.3
1
0.1
0
0
0
2
0.2
2
0.2
0
0
0
0
0
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
NERC Standards
9
10 Segment
10
Totals
9
0.7
7
0.7
0
0
0
0
2
362
7.2
155
4.852
89
2.348
1
44
73
Individual Ballot Pool Results
Ballot
Segment
Organization
Member
1
1
1
1
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Eric Scott
Paul B Johnson
Andrew Z Pusztai
Robert Smith
1
Associated Electric Cooperative, Inc.
John Bussman
1
1
1
1
1
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
1
BC Hydro and Power Authority
Patricia Robertson
1
1
Black Hills Corp
Brazos Electric Power Cooperative, Inc.
Wes Wingen
Tony Kroskey
1
Bryan Texas Utilities
John C Fontenot
Negative
1
CenterPoint Energy Houston Electric, LLC
John Brockhan
Negative
1
Central Electric Power Cooperative
Michael B Bax
Negative
1
Central Iowa Power Cooperative
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Kevin J Lyons
Affirmative
Chang G Choi
Affirmative
Daniel S Langston
Jack Stamper
Abstain
Affirmative
1
1
1
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
Abstain
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Abstain
1
Colorado Springs Utilities
Shawna Speer
1
Consolidated Edison Co. of New York
Christopher L de Graffenried Affirmative
1
CPS Energy
Glenn Pressler
Negative
1
Dairyland Power Coop.
Robert W. Roddy
Negative
1
1
Deseret Power
Dominion Virginia Power
James Tucker
Larry Nash
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Luminant)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG) (Colorado
Springs
Utilities)
SUPPORTS
THIRD PARTY
COMMENTS (Luminant)
SUPPORTS
THIRD PARTY
COMMENTS (NSRF)
Abstain
Affirmative
1
Duke Energy Carolina
Doug E Hils
1
1
Empire District Electric Co.
Encari
Ralph F Meyer
Steven E Hamburg
1
Entergy Transmission
Oliver A Burke
Negative
1
1
1
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
William J Smith
Dennis Minton
Mike O'Neil
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
NERC
Notes
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Abstain
Affirmative
COMMENT
RECEIVED
NERC Standards
1
1
1
1
1
1
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Muhammed Ali
Martin Boisvert
Molly Devine
1
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates
1
JEA
Ted E Hobson
Negative
1
KAMO Electric Cooperative
Walter Kenyon
Negative
1
Kansas City Power & Light Co.
Daniel Gibson
Negative
1
Keys Energy Services
Stan T Rzad
Negative
1
1
1
1
1
1
Lakeland Electric
Lee County Electric Cooperative
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
Larry E Watt
John Chin
faranak sarbaz
Martyn Turner
Jo-Anne M Ross
Danny Dees
1
MidAmerican Energy Co.
Terry Harbour
Negative
1
Minnkota Power Coop. Inc.
Daniel L Inman
Negative
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
1
National Grid USA
NB Power Corporation
Michael Jones
Alan MacNaughton
1
Nebraska Public Power District
Jamison Cawley
1
New York Power Authority
Bruce Metruck
1
Northeast Missouri Electric Power
Cooperative
Kevin White
1
1
1
1
1
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
William Temple
Julaine Dyke
John Canavan
Scott R Cunningham
Terri Pyle
1
Omaha Public Power District
Doug Peterchuck
1
Oncor Electric Delivery
Jen Fiegel
1
Otter Tail Power Company
Daryl Hanson
1
1
1
1
1
Pacific Gas and Electric Company
Peak Reliability
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
Bangalore Vijayraghavan
Jared Shakespeare
John C. Collins
John T Walker
David Thorne
1
1
PPL Electric Utilities Corp.
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Negative
Jim D Cyrulewski
Abstain
Brenda L Truhe
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
NO COMMENT
RECEIVED
Abstain
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (See NSRF's
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Abstain
Negative
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Refer to
comments
submitted on
behalf of PPL
NERC Standards
NERC
Registered
Affiliates)
1
Public Service Company of New Mexico
Laurie Williams
1
Public Service Electric and Gas Co.
Kenneth D. Brown
1
1
1
1
1
1
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
SaskPower
Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Wayne Guttormson
Negative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
1
Seattle City Light
Pawel Krupa
Negative
1
Seminole Electric Cooperative, Inc.
Glenn Spurlock
Negative
1
1
1
1
1
1
1
1
1
1
1
1
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Southern California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State Generation & Transmission
Association, Inc.
Tucson Electric Power Co.
U.S. Bureau of Reclamation
United Illuminating Co.
Vermont Electric Power Company, Inc.
Denise Stevens
Long T Duong
Tom Hanzlik
Shawn T Abrams
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Steven Powell
1
1
1
1
1
Tracy Sliman
John Tolo
Richard T Jackson
Jonathan Appelbaum
Kim Moulton
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light Paul
Haase's
comment)
SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative
Comments
submitted by
Maryclaire
Yatsko)
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
1
Westar Energy
Allen Klassen
1
1
1
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Xcel Energy, Inc.
Lloyd A Linke
Michelle Clements
Gregory L Pieper
2
BC Hydro
Venkataramakrishnan
Vinnakota
Negative
2
California ISO
Rich Vine
Negative
2
2
2
2
2
2
2
3
3
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
MISO
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Cheryl Moseley
Leonard Kula
Matthew F Goldberg
Marie Knox
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
COMMENT
RECEIVED
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Patria
Robertson)
COMMENT
RECEIVED
NERC Standards
3
3
Ameren Corp.
APS
David J Jendras
Sarah Kist
Affirmative
3
Associated Electric Cooperative, Inc.
Todd Bennett
3
3
Atlantic City Electric Company
Avista Corp.
NICOLE BUCKMAN
Scott J Kinney
Abstain
3
BC Hydro and Power Authority
Pat G. Harrington
Negative
3
3
3
3
3
3
3
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Redding
City of Tallahassee
Adam M Weber
Andrew Gallo
Lynne Mila
Linda R Jacobson
Mark Schultz
Bill Hughes
Bill R Fowler
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
3
Colorado Springs Utilities
Jean Mueller
3
3
3
3
3
3
3
ComEd
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Dominion Resources, Inc.
John Bee
Peter T Yost
Gerald G Farringer
Russell A Noble
Jose Escamilla
Michael R. Mayer
Connie B Lowe
3
DTE Electric
Kent Kujala
3
3
3
3
FirstEnergy Corp.
Florida Keys Electric Cooperative
Florida Municipal Power Agency
Florida Power & Light Co.
Cindy E Stewart
Tom B Anthony
Joe McKinney
Summer C. Esquerre
3
Florida Power Corporation
Lee Schuster
3
3
3
3
Georgia System Operations Corporation
Great River Energy
Hydro One Networks, Inc.
JEA
Scott McGough
Brian Glover
Ayesha Sabouba
Garry Baker
3
Kansas City Power & Light Co.
Joshua D Bach
3
3
Lakeland Electric
Lee County Electric Cooperative
Mace D Hunter
David A Hadzima
3
Lincoln Electric System
Jason Fortik
3
Los Angeles Department of Water & Power
Mike Anctil
3
Louisville Gas and Electric Co.
Charles A. Freibert
3
3
Manitoba Hydro
MEAG Power
Greg C. Parent
Roger Brand
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (BC Hydro)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG) (Kaleb
Brimhall)
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Affirmative
Affirmative
3
MidAmerican Energy Co.
Thomas C. Mielnik
Negative
3
3
3
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Jack W Savage
John S Bos
Brian E Shanahan
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF
Comments)
Affirmative
SUPPORTS
THIRD PARTY
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
NERC Standards
3
Nebraska Public Power District
Tony Eddleman
3
3
3
3
3
New York Power Authority
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Ocala Utility Services
Oklahoma Gas and Electric Co.
David R Rivera
Ramon J Barany
David McDowell
Randy Hahn
Donald Hargrove
3
Omaha Public Power District
Blaine R. Dinwiddie
3
3
3
3
3
3
3
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Ballard K Mutters
Thomas T Lyons
John H Hagen
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
3
Public Service Electric and Gas Co.
Jeffrey Mueller
3
3
3
3
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Mariah R Kennedy
James Leigh-Kendall
John T. Underhill
James M Poston
Negative
Affirmative
Abstain
Affirmative
Negative
Negative
Dana Wheelock
Negative
3
Seminole Electric Cooperative, Inc.
James R Frauen
Negative
3
3
3
3
3
3
3
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Tacoma Power
Tampa Electric Co.
Tennessee Valley Authority
Tri-State Generation & Transmission
Association, Inc.
Jeff L Neas
Mark Oens
Hubert C Young
Lujuanna Medina
Marc Donaldson
Ronald L. Donahey
Ian S Grant
Abstain
Affirmative
Westar Energy
Bo Jones
Negative
3
Xcel Energy, Inc.
Michael Ibold
Negative
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
Negative
4
4
4
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Redding
Duane S Dahlquist
Reza Ebrahimian
Nicholas Zettel
Affirmative
Abstain
Affirmative
City Utilities of Springfield, Missouri
John Allen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light Paul
Haase's
comment)
SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative)
Affirmative
Affirmative
Affirmative
Affirmative
3
4
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
Affirmative
Affirmative
Affirmative
Abstain
Seattle City Light
Janelle Marriott
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF
comments)
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
3
3
COMMENTS (Nebraska
Public Power
District
comments.)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Xcel Energy)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS -
NERC Standards
(SPP
Standards
Review Group)
4
4
Consumers Energy Company
Cowlitz County PUD
Tracy Goble
Rick Syring
4
DTE Electric
Daniel Herring
4
4
4
4
Florida Municipal Power Agency
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Frank Gaffney
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
4
Indiana Municipal Power Agency
Jack Alvey
Negative
4
Madison Gas and Electric Co.
Joseph DePoorter
Negative
4
Modesto Irrigation District
Spencer Tacke
Negative
4
4
4
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Affirmative
Abstain
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Affirmative
4
4
4
Seattle City Light
Hao Li
Negative
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
Negative
4
4
4
5
5
5
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Amerenue
American Electric Power
Arizona Public Service Co.
Steve McElhaney
Keith Morisette
Brian Evans-Mongeon
Sam Dwyer
Thomas Foltz
Scott Takinen
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
Negative
5
BC Hydro and Power Authority
Clement Ma
Negative
5
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
Bonneville Power Administration
Francis J. Halpin
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
5
5
5
5
City
City
City
City
City
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
5
and County of San Francisco
of Austin dba Austin Energy
of Redding
of Tallahassee
Water, Light & Power of Springfield
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (comments
submitted by
Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light Paul
Haase's
comment)
SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative
Comments
submitted by
Maryclaire
Yatsko)
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Aeci)
SUPPORTS
THIRD PARTY
COMMENTS (BC Hydro)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Abstain
Affirmative
Abstain
SUPPORTS
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
NERC Standards
5
Cleco Power
Stephanie Huffman
5
Cogentrix Energy Power Management, LLC
Mike D Hirst
Negative
5
Colorado Springs Utilities
Kaleb Brimhall
Negative
5
5
5
Con Edison Company of New York
Consumers Energy Company
Cowlitz County PUD
Brian O'Boyle
David C Greyerbiehl
Bob Essex
5
Dairyland Power Coop.
Tommy Drea
Negative
5
Dominion Resources, Inc.
Mike Garton
Affirmative
DTE Electric
Mark Stefaniak
Negative
5
Duke Energy
Dale Q Goodwine
Negative
5
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
Entergy Services, Inc.
Exelon Nuclear
Dan Roethemeyer
Abstain
5
5
Tracey Stubbs
Mark F Draper
John Robertson
5
5
5
5
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
5
Ingleside Cogeneration LP
Michelle R DAntuono
Negative
5
JEA
John J Babik
Negative
5
Kansas City Power & Light Co.
Brett Holland
Negative
5
5
Kissimmee Utility Authority
Lakeland Electric
Mike Blough
James M Howard
Negative
Daniel Duff
Negative
5
Lincoln Electric System
Dennis Florom
Negative
5
5
5
5
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Muscatine Power & Water
Kenneth Silver
Dixie Wells
Rick Terrill
Chris Mazur
Abstain
Affirmative
David Gordon
Abstain
Steven Grego
Mike Avesing
Affirmative
Affirmative
Don Schmit
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Liberty Electric Power LLC
Nebraska Public Power District
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group (PSEG))
Affirmative
Affirmative
Affirmative
Affirmative
5
5
SUPPORTS
THIRD PARTY
COMMENTS (DTE Electric
and PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Affirmative
First Wind
5
5
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Dana Showalter
5
5
SUPPORTS
THIRD PARTY
COMMENTS (PSEG) (Colorado
Springs
Utilities)
Affirmative
Affirmative
5
5
THIRD PARTY
COMMENTS (See SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Nebraska
Public Power
NERC Standards
District)
5
5
5
5
5
5
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
Michael D Melvin
Bernard Johnson
Henry L Staples
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
5
Omaha Public Power District
Mahmood Z. Safi
Negative
5
5
5
Pacific Gas and Electric Company
Platte River Power Authority
Portland General Electric Co.
Alex Chua
Christopher R Wood
Matt E. Jastram
Affirmative
Affirmative
5
PPL Generation LLC
Annette M Bannon
Negative
5
PSEG Fossil LLC
Tim Kucey
Negative
5
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Steven Grega
5
5
5
5
5
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Affirmative
Affirmative
Affirmative
Abstain
Seattle City Light
Michael J. Haynes
Negative
5
5
5
5
5
5
5
5
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State Generation & Transmission
Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Mark Stein
Affirmative
5
5
Melissa Kurtz
Erika Doot
Westar Energy
Bryan Taggart
Negative
5
Xcel Energy, Inc.
Mark A Castagneri
Negative
6
6
6
AEP Marketing
Ameren Missouri
APS
Edward P. Cox
Robert Quinlivan
Randy A. Young
Affirmative
Affirmative
Affirmative
6
Associated Electric Cooperative, Inc.
Brian Ackermann
Negative
6
6
6
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Brenda S. Anderson
Lisa Martin
Marvin Briggs
Cleco Power LLC
SUPPORTS
THIRD PARTY
COMMENTS (Haase,
Seattle)
Abstain
5
6
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (PSEG (John
Seelke))
Michiko Sell
5
5
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Robert Hirchak
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Comments)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
SUPPORTS
THIRD PARTY
NERC Standards
6
Colorado Springs Utilities
Shannon Fair
6
6
6
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
David Balban
David J Carlson
Louis S. Slade
6
Duke Energy
Greg Cecil
6
6
6
6
6
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
6
Lakeland Electric
Paul Shipps
6
Lincoln Electric System
6
Lower Colorado River Authority
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
COMMENT
RECEIVED
Eric Ruskamp
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Michael Shaw
Affirmative
Luminant Energy
Brenda Hampton
6
6
6
6
6
6
Manitoba Hydro
Modesto Irrigation District
New York Power Authority
Northern Indiana Public Service Co.
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Blair Mukanik
James McFall
Shivaz Chopra
Joseph O'Brien
Donna Johnson
Jerry Nottnagel
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
6
Omaha Public Power District
Douglas Collins
Negative
6
PacifiCorp
Sandra L Shaffer
Negative
6
6
6
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Carol Ballantine
Shawn P Davis
Stephen C Knapp
Affirmative
Negative
6
Powerex Corp.
Gordon Dobson-Mack
Negative
6
PPL EnergyPlus LLC
Elizabeth Davis
Negative
6
PSEG Energy Resources & Trade LLC
Peter Dolan
Negative
6
6
6
6
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Hugh A. Owen
Diane Enderby
William Abraham
Michael Brown
Seattle City Light
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Affirmative
Affirmative
6
6
COMMENTS (Colorado
Springs
Utilities)
Dennis Sismaet
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (BC Hydro's
(Patricia
Robertson's))
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
Abstain
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase)
SUPPORTS
THIRD PARTY
COMMENTS -
NERC Standards
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
6
6
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Kenn Backholm
Joseph T Marone
Affirmative
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S Parsons
Grant L Wilkerson
Affirmative
6
6
6
6
6
6
6
Venona Greaff
7
8
8
8
Siemens Energy, Inc.
Massachusetts Attorney General
Frank R. McElvain
David L Kiguel
Roger C Zaklukiewicz
Frederick R Plett
9
10
10
10
10
10
10
10
10
10
Abstain
Peter Colussy
Occidental Chemical
9
Negative
Peter H Kinney
7
8
(comments
submitted by
Maryclaire
Yatsko on
behalf of
Seminole
Electric
Cooperative,
Inc.)
Volkmann Consulting, Inc.
Negative
Affirmative
Affirmative
Affirmative
Terry Volkmann
Commonwealth of Massachusetts
Department of Public Utilities
New York State Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Negative
Donald Nelson
Affirmative
Diane J Barney
Linda C Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Bob Reynolds
Karin Schweitzer
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Ingleside
Cogeneration,
LP)
Affirmative
Affirmative
Affirmative
Affirmative
Legal and Privacy : 404.446.2560 voice : 404.467.0474 fax : 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2014 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=b4d01291-eab1-4e34-9f62-af56edcaa172[12/1/2014 10:59:55 AM]
Non-Binding Poll Results
Project 2010-13.3 Phase 3 of Relay Loadability: Stable
Power Swings
PRC-026-1
Non-Binding Poll Results
Non-Binding Poll Name: Project 2010-13.3 Relay Loadability Stable Power Swings PRC-026-1
Poll Period: 11/14/2014 – 11/24/2014
Total # Opinions: 261
Total Ballot Pool: 332
78.61% of those who registered to participate provided an opinion or an
Summaray Results: abstention; 66.13% of those who provided an opinion indicated support for
the VRFs and VSLs.
Individual Ballot Pool Results
Segment
1
1
1
Organization
Ameren Services
American Electric Power
Arizona Public Service Co.
Member
Eric Scott
Paul B Johnson
Robert Smith
Opinions
Abstain
Affirmative
1
Associated Electric Cooperative, Inc. John Bussman
Negative
1
1
1
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern
California
BC Hydro and Power Authority
Abstain
Abstain
1
1
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Patricia Robertson
NERC Notes
Affirmative
Abstain
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
1
Brazos Electric Power Cooperative,
Inc.
Tony Kroskey
1
Bryan Texas Utilities
John C Fontenot
1
CenterPoint Energy Houston Electric,
John Brockhan
LLC
Negative
Abstain
1
Central Electric Power Cooperative
Michael B Bax
Negative
1
Central Iowa Power Cooperative
Kevin J Lyons
Negative
Chang G Choi
Affirmative
Daniel S Langston
Jack Stamper
Abstain
Affirmative
1
1
1
City of Tacoma, Department of
Public Utilities, Light Division, dba
Tacoma Power
City of Tallahassee
Clark Public Utilities
1
Colorado Springs Utilities
Shawna Speer
1
Consolidated Edison Co. of New York
Christopher L de
Graffenried
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
Affirmative
1
CPS Energy
Glenn Pressler
Negative
1
Dairyland Power Coop.
Robert W. Roddy
Negative
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
SUPPORTS
THIRD PARTY
COMMENTS (Luminant)
SUPPORTS
THIRD PARTY
COMMENTS (Luminant)
SUPPORTS
THIRD PARTY
COMMENTS (NSRF)
2
1
1
Deseret Power
Dominion Virginia Power
James Tucker
Larry Nash
Abstain
Abstain
1
Duke Energy Carolina
Doug E Hils
Negative
1
1
Empire District Electric Co.
Encari
Ralph F Meyer
Steven E Hamburg
Abstain
1
Entergy Transmission
Oliver A Burke
Negative
1
FirstEnergy Corp.
Florida Keys Electric Cooperative
Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
William J Smith
Affirmative
1
1
1
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Affirmative
Georgia Transmission Corporation
1
1
1
1
1
Great River Energy
Gordon Pietsch
Hydro One Networks, Inc.
Muhammed Ali
Hydro-Quebec TransEnergie
Martin Boisvert
Idaho Power Company
Molly Devine
International Transmission Company
Michael Moltane
Holdings Corp
JDRJC Associates
Jim D Cyrulewski
1
JEA
Ted E Hobson
Negative
1
KAMO Electric Cooperative
Walter Kenyon
Negative
1
Kansas City Power & Light Co.
Daniel Gibson
Negative
1
1
Lakeland Electric
Lee County Electric Cooperative
Larry E Watt
John Chin
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
COMMENT
RECEIVED
Dennis Minton
1
1
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
3
1
1
1
1
Los Angeles Department of Water &
Power
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
faranak sarbaz
Abstain
Martyn Turner
Jo-Anne M Ross
Danny Dees
Affirmative
Affirmative
Affirmative
1
MidAmerican Energy Co.
Terry Harbour
Negative
1
Minnkota Power Coop. Inc.
Daniel L Inman
Negative
1
N.W. Electric Power Cooperative,
Inc.
Mark Ramsey
Negative
1
1
1
1
National Grid USA
NB Power Corporation
Nebraska Public Power District
New York Power Authority
Michael Jones
Alan MacNaughton
Jamison Cawley
Bruce Metruck
1
Northeast Missouri Electric Power
Cooperative
Kevin White
1
1
1
1
1
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
William Temple
Julaine Dyke
John Canavan
Scott R Cunningham
Terri Pyle
1
Omaha Public Power District
Doug Peterchuck
1
Oncor Electric Delivery
Jen Fiegel
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (see NSRF's
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Abstain
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
4
1
Otter Tail Power Company
1
Pacific Gas and Electric Company
1
1
1
Peak Reliability
Platte River Power Authority
Portland General Electric Co.
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
PPL Electric Utilities Corp.
Daryl Hanson
Bangalore
Vijayraghavan
Jared Shakespeare
John C. Collins
John T Walker
Brenda L Truhe
Public Service Company of New
Laurie Williams
Mexico
Public Service Electric and Gas Co. Kenneth D. Brown
Public Utility District No. 1 of
Dale Dunckel
Okanogan County
Puget Sound Energy, Inc.
Denise M Lietz
Rochester Gas and Electric Corp.
John C. Allen
Sacramento Municipal Utility District Tim Kelley
Salt River Project
Robert Kondziolka
SaskPower
Wayne Guttormson
Seminole Electric Cooperative, Inc. Glenn Spurlock
Sho-Me Power Electric Cooperative Denise Stevens
Snohomish County PUD No. 1
Long T Duong
South Carolina Electric & Gas Co.
Tom Hanzlik
South Carolina Public Service
Shawn T Abrams
Authority
Southern California Edison Company Steven Mavis
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Refer to
comments
submitted on
behalf of PPL
NERC
Registered
Affiliates)
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
5
1
1
1
1
1
1
1
1
1
1
1
1
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission
Cooperative, Inc.
Sunflower Electric Power
Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State Generation & Transmission
Association, Inc.
Tucson Electric Power Co.
U.S. Bureau of Reclamation
United Illuminating Co.
Vermont Electric Power Company,
Inc.
Robert A. Schaffeld
William Hutchison
John Shaver
Beth Young
Howell D Scott
Steven Powell
Abstain
Affirmative
Tracy Sliman
Affirmative
John Tolo
Richard T Jackson
Jonathan Appelbaum
Affirmative
Kim Moulton
Westar Energy
1
1
Western Area Power Administration Lloyd A Linke
Wolverine Power Supply Coop., Inc. Michelle Clements
Venkataramakrishnan
BC Hydro
Vinnakota
2
2
2
2
2
California ISO
Electric Reliability Council of Texas,
Inc.
Independent Electricity System
Operator
ISO New England, Inc.
MISO
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Noman Lee Williams
1
2
Affirmative
Allen Klassen
Rich Vine
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
Abstain
Negative
Cheryl Moseley
Affirmative
Leonard Kula
Affirmative
Matthew F Goldberg
Marie Knox
Affirmative
Affirmative
COMMENT
RECEIVED
6
2
2
2
3
3
3
3
New York Independent System
Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Corp.
APS
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
David J Jendras
Sarah Kist
Affirmative
Abstain
Affirmative
Affirmative
Abstain
3
Associated Electric Cooperative, Inc. Todd Bennett
Negative
3
3
3
3
3
3
3
3
Avista Corp.
BC Hydro and Power Authority
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Tallahassee
Abstain
Abstain
Scott J Kinney
Pat G. Harrington
Adam M Weber
Andrew Gallo
Lynne Mila
Linda R Jacobson
Mark Schultz
Bill R Fowler
3
Colorado Springs Utilities
3
3
3
3
3
Consolidated Edison Co. of New York Peter T Yost
Consumers Energy Company
Gerald G Farringer
Cowlitz County PUD
Russell A Noble
CPS Energy
Jose Escamilla
Dominion Resources, Inc.
Connie B Lowe
3
DTE Electric
Kent Kujala
3
3
3
FirstEnergy Corp.
Florida Keys Electric Cooperative
Florida Municipal Power Agency
Cindy E Stewart
Tom B Anthony
Joe McKinney
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
Jean Mueller
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Kaleb
Brimhall)
Affirmative
Affirmative
Abstain
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
7
3
3
Florida Power & Light Co.
Florida Power Corporation
Summer C. Esquerre
Lee Schuster
3
3
3
Georgia System Operations
Corporation
Great River Energy
Hydro One Networks, Inc.
JEA
3
Kansas City Power & Light Co.
Joshua D Bach
3
3
3
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Ocala Utility Services
Oklahoma Gas and Electric Co.
Mace D Hunter
David A Hadzima
Jason Fortik
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Omaha Public Power District
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Scott McGough
Brian Glover
Ayesha Sabouba
Garry Baker
Mike Anctil
Charles A. Freibert
Greg C. Parent
Roger Brand
Thomas C. Mielnik
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Ramon J Barany
David McDowell
Randy Hahn
Donald Hargrove
Blaine R. Dinwiddie
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF
comments)
8
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Orlando Utilities Commission
Ballard K Mutters
Owensboro Municipal Utilities
Thomas T Lyons
Pacific Gas and Electric Company
John H Hagen
Platte River Power Authority
Terry L Baker
PNM Resources
Michael Mertz
Portland General Electric Co.
Thomas G Ward
Public Service Electric and Gas Co. Jeffrey Mueller
Puget Sound Energy, Inc.
Mariah R Kennedy
Sacramento Municipal Utility District James Leigh-Kendall
Salt River Project
John T. Underhill
Santee Cooper
James M Poston
Seminole Electric Cooperative, Inc. James R Frauen
Sho-Me Power Electric Cooperative Jeff L Neas
Snohomish County PUD No. 1
Mark Oens
South Carolina Electric & Gas Co.
Hubert C Young
Southern California Edison Company Lujuanna Medina
Tacoma Power
Marc Donaldson
Tampa Electric Co.
Ronald L. Donahey
Tennessee Valley Authority
Ian S Grant
Tri-State Generation & Transmission
Janelle Marriott
Association, Inc.
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
3
Westar Energy
Bo Jones
Negative
3
Xcel Energy, Inc.
Michael Ibold
Abstain
4
Alliant Energy Corp. Services, Inc.
4
4
4
Blue Ridge Power Agency
Duane S Dahlquist
City of Austin dba Austin Energy
Reza Ebrahimian
City Utilities of Springfield, Missouri John Allen
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
Kenneth Goldsmith
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Abstain
Abstain
9
4
4
Consumers Energy Company
Cowlitz County PUD
Tracy Goble
Rick Syring
4
DTE Electric
Daniel Herring
Negative
4
Florida Municipal Power Agency
Georgia System Operations
Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Frank Gaffney
Affirmative
Guy Andrews
Abstain
4
4
4
Herb Schrayshuen
Bob C. Thomas
4
Indiana Municipal Power Agency
4
4
4
Madison Gas and Electric Co.
Joseph DePoorter
Modesto Irrigation District
Spencer Tacke
Ohio Edison Company
Douglas Hohlbaugh
Public Utility District No. 1 of
John D Martinsen
Snohomish County
Sacramento Municipal Utility District Mike Ramirez
Seminole Electric Cooperative, Inc. Steven R Wallace
South Mississippi Electric Power
Steve McElhaney
Association
Tacoma Public Utilities
Keith Morisette
Utility Services, Inc.
Brian Evans-Mongeon
Amerenue
Sam Dwyer
American Electric Power
Thomas Foltz
Arizona Public Service Co.
Scott Takinen
4
4
4
4
4
4
5
5
5
5
BC Hydro and Power Authority
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
Jack Alvey
Clement Ma
Affirmative
COMMENT
RECEIVED
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (comments
submitted by
Public Service
Enterprise
Group)
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (BC Hydro)
10
5
5
5
5
5
5
5
Boise-Kuna Irrigation District/dba
Lucky peak power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative,
Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Tallahassee
City Water, Light & Power of
Springfield
Mike D Kukla
Francis J. Halpin
Affirmative
Shari Heino
Negative
Daniel Mason
Jeanie Doty
Karen Webb
Abstain
Abstain
Steve Rose
5
Cleco Power
Stephanie Huffman
5
Cogentrix Energy Power
Management, LLC
Mike D Hirst
5
Colorado Springs Utilities
Kaleb Brimhall
5
5
5
Con Edison Company of New York
Consumers Energy Company
Cowlitz County PUD
Brian O'Boyle
David C Greyerbiehl
Bob Essex
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
Affirmative
Affirmative
5
Dairyland Power Coop.
Tommy Drea
Negative
5
Dominion Resources, Inc.
Mike Garton
Abstain
5
DTE Electric
Mark Stefaniak
Negative
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS -
11
5
Duke Energy
Dale Q Goodwine
Negative
5
Dynegy Inc.
E.ON Climate & Renewables North
America, LLC
Entergy Services, Inc.
Dan Roethemeyer
Abstain
5
5
Dana Showalter
Tracey Stubbs
5
First Wind
John Robertson
Negative
5
5
5
5
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Affirmative
Affirmative
Affirmative
Affirmative
5
Ingleside Cogeneration LP
Michelle R DAntuono
Negative
5
JEA
John J Babik
Negative
5
Kansas City Power & Light Co.
Brett Holland
Negative
5
Kissimmee Utility Authority
Mike Blough
5
Liberty Electric Power LLC
Daniel Duff
Negative
5
Lincoln Electric System
Dennis Florom
Abstain
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
(DTE Electric
and PSEG)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
SUPPORTS
THIRD PARTY
COMMENTS (Public
Service
Enterprise
Group
(PSEG))
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Public
Service
Enterprise
Group)
12
5
5
5
5
5
5
5
5
5
5
5
5
Los Angeles Department of Water &
Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership
Corp.
Northern Indiana Public Service Co.
Kenneth Silver
Dixie Wells
Rick Terrill
Chris Mazur
David Gordon
Abstain
Affirmative
Affirmative
Abstain
Steven Grego
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Jeffrey S Brame
Affirmative
Michael D Melvin
5
Oglethorpe Power Corporation
Bernard Johnson
5
Oklahoma Gas and Electric Co.
Henry L Staples
5
Omaha Public Power District
Mahmood Z. Safi
5
5
5
Pacific Gas and Electric Company
Platte River Power Authority
Portland General Electric Co.
Alex Chua
Christopher R Wood
Matt E. Jastram
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC PCS)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Abstain
Affirmative
5
PPL Generation LLC
Annette M Bannon
Negative
5
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Tim Kucey
Abstain
5
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Steven Grega
13
5
5
5
5
5
Public Utility District No. 2 of Grant
Michiko Sell
County, Washington
Puget Sound Energy, Inc.
Lynda Kupfer
Sacramento Municipal Utility District Susan Gill-Zobitz
Salt River Project
William Alkema
Santee Cooper
Lewis P Pierce
Affirmative
Affirmative
Affirmative
Abstain
5
Seattle City Light
Michael J. Haynes
Negative
5
5
5
5
5
5
5
5
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
5
5
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State Generation & Transmission
Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
5
Xcel Energy, Inc.
Mark A Castagneri
Negative
6
6
6
AEP Marketing
Ameren Missouri
APS
Edward P. Cox
Robert Quinlivan
Randy A. Young
Affirmative
Abstain
Affirmative
5
Mark Stein
Abstain
Abstain
Melissa Kurtz
Erika Doot
6
Associated Electric Cooperative, Inc. Brian Ackermann
6
6
Bonneville Power Administration
City of Austin dba Austin Energy
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
SUPPORTS
THIRD PARTY
COMMENTS (Haase,
Seattle)
Brenda S. Anderson
Lisa Martin
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Abstain
14
6
Cleco Power LLC
Robert Hirchak
Negative
6
Colorado Springs Utilities
Shannon Fair
Negative
6
Con Edison Company of New York
David Balban
Affirmative
6
Duke Energy
Greg Cecil
6
FirstEnergy Solutions
Affirmative
6
Florida Municipal Power Agency
6
6
6
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kevin Querry
Richard L.
Montgomery
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
Negative
6
6
6
Lakeland Electric
Lincoln Electric System
Lower Colorado River Authority
Paul Shipps
Eric Ruskamp
Michael Shaw
6
Luminant Energy
Brenda Hampton
6
6
6
Manitoba Hydro
Modesto Irrigation District
New York Power Authority
Blair Mukanik
James McFall
Shivaz Chopra
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Affirmative
COMMENT
RECEIVED
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Luminant
Generation
Company,
LLC)
Affirmative
Affirmative
Affirmative
15
6
Northern Indiana Public Service Co. Joseph O'Brien
6
Oglethorpe Power Corporation
Donna Johnson
6
Oklahoma Gas and Electric Co.
Jerry Nottnagel
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (GTC)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
6
Omaha Public Power District
Douglas Collins
Negative
6
6
6
6
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Sandra L Shaffer
Carol Ballantine
Shawn P Davis
Stephen C Knapp
Abstain
Abstain
6
Powerex Corp.
Gordon Dobson-Mack
Negative
6
PPL EnergyPlus LLC
Elizabeth Davis
Negative
6
6
6
6
PSEG Energy Resources & Trade LLC Peter Dolan
Sacramento Municipal Utility District Diane Enderby
Salt River Project
William Abraham
Santee Cooper
Michael Brown
6
Seattle City Light
6
6
6
Seminole Electric Cooperative, Inc. Trudy S. Novak
Snohomish County PUD No. 1
Kenn Backholm
Southern California Edison Company Joseph T Marone
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
Dennis Sismaet
SUPPORTS
THIRD PARTY
COMMENTS (BC Hydro's)
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Abstain
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase)
Abstain
Affirmative
Affirmative
16
6
6
6
6
6
7
8
8
8
8
9
10
10
10
10
10
10
10
10
10
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Western Area Power Administration
- UGP Marketing
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S Parsons
Affirmative
Peter H Kinney
Occidental Chemical
Venona Greaff
Massachusetts Attorney General
David L Kiguel
Roger C Zaklukiewicz
Frederick R Plett
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
Florida Reliability Coordinating
Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating
Council
ReliabilityFirst
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating
Council
Non-Binding Poll Results
Project 2010-13.3 PRC-026-1 | November 2014
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Ingleside
Cogeneration,
LP)
Affirmative
Affirmative
Affirmative
Terry Volkmann
Negative
Donald Nelson
Affirmative
Linda C Campbell
Affirmative
Russel Mountjoy
Alan Adamson
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Bob Reynolds
Karin Schweitzer
Affirmative
Affirmative
Steven L. Rueckert
Abstain
Affirmative
17
Individual or group. (42 Responses)
Name (24 Responses)
Organization (24 Responses)
Group Name (18 Responses)
Lead Contact (18 Responses)
Question 1 (38 Responses)
Individual
Alshare Hughes
Luminant Generation Company, LLC
Luminant continues to believe that including unstable power swings in the draft standard goes
beyond FERC Order 733. Luminant understands that adding unstable power swings in the
Requirement only requires the Generator Owner to be compliant with the criteria in Requirement R3
(Attachment B) for any of the load-responsive relays in Attachment A. However, Requirement R1
(part 4) provides information to the Generator Owner that some units may be subject to an out-ofstep condition and action on their part may be necessary to enable generator out-of-step protection.
Luminant recommends that either “unstable” be removed from the standard in all requirements or
add language to Measure M1 for the Planning Coordinator to provide information (for example,
impedance plots) to the Generator Owner that describe the location of the electrical center for an
out-of-step condition.
Individual
Maryclaire Yatsko
Seminole Electric Cooperative, Inc.
Requirement R1 “Element” in R1 on page 6 of the redline was revised to “generator, transformer,
and transmission line BES Element.” It’s unclear whether “transmission line BES Element” includes
terminal equipment of the transmission line. It’s unclear whether a “generator BES Element”
includes a generator Facility, i.e., the generator itself or merely those Elements that make up the
generator. Seminole requests the drafting team add additional language as to what is actually
covered under R1. PRC-026-1 – Attachment B Under Criteria B on page 20 of the redline version, #2
states “All generation is in service and all transmission BES Elements are in their normal … .”
Seminole requests the drafting team explain how the “transmission BES Elements” listed here are
different than “Transmission BES Elements” (Transmission with a capital T)?
Individual
Reena Dhir
Manitoba Hydro
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
ATC accepts the SDT changes.
Group
MRO NERC Standards Review Forum
Joe DePoorter
The NSRF believes that the Industry concerns have not been adequately addressed. Request that
the drafting clarify its scope of applicability between NERC defined “Elements” and “Facilities” in
Section 4.2. Did the drafting team mean only BES generators, transmission lines, and transformers?
If so, please clarify this sub set is the only applicable items. The drafting team should eliminate or
revise criterion 3 under PRC-026-1 R1. UFLS islands are rare and UFLS islands mandated by PRC006 are likely best guess conditions. Therefore unless criterion 3 under R1 is modified to apply only
to known and designed stability power protection systems, the work performed would be a best
guess and of little practical value. At a minimum, criterion 3 could be further clarified by adding a
sentence such as the following, “Criterion 3 does not apply to other conditions such as excessive
loading.” FERC has defined that the requirements govern compliance (FERC O 693 sect. 253), unless
the words “non-fault power swings” are added to R2 similar to the PRC-026 purpose correctly
limiting the number of evaluations to non-fault conditions, a regulatory entity could determine an
entity was in non-compliance for not evaluating stable or unstable power swings for fault conditions
after an event for “impedance based relays identified in Attachment The use of “non-fault” in PRC026 R2 would clearly separate PRC-026 from PRC-004 which already governs analysis and corrective
actions for protection systems mis-operations usually with respect to fault conditions. This
separation will avoid a potential double jeopardy violation where PRC-026 and PRC-004 could be
interpreted to overlap for relay analysis of a misoperation. Concerns could exist for
electromechanical relays. Electromechanical relays do not provide appropriate data to verify
operation or misoperation due to a stable or unstable power swing. Electromechanical relays can
only provide target data. To verify correct operation due to a stable or unstable power swing, plots
of the system impedance characteristic need to be obtained. Suggest that requirement 2.3 be added
clearly identifying that limited data where it isn’t possible to verify if a relay tripped due to a power
swing, the entity can conclude it is unaware of the trip cause and a PRC-026 report isn’t required or
use of a foot note could be added.
Individual
David Jendras
Ameren
Individual
John Seelke
Public Service Enterprise Group
As explained below, we believe there are two unresolved issues. Background PRC-004-3 overlaps
PRC-026-1 in several areas. In PRC-004-3, GOs and TOs examine each operation its BES
interruption devices to identify Misoperations. Under R5, they must develop a Corrective Action Plan
(CAP) unless they “Explain in a declaration why corrective actions are beyond the entity’s control or
would not improve BES reliability, and that no further corrective actions will be taken.” In the
process of implementing PRC-004-3, “correct operations” are also identified (i.e., interrupting device
operations where a Misoperation DID NOT occur), but PRC-004-3 imposes no requirements on
correct operations. Misoperations A relay operation during a stable power swing under subpart 2.2 of
PRC-026-1 is a Misoperation reportable under PRC-004-3 and subject to a CAP under R5. This same
relay operation would be subject to a CAP under R3 of PRC-026-1. In addition, the CAP timelines are
different (60 days to develop a CAP in PRC-004-3 and six months to develop it in PRC-026-1). Two
standards should not contain requirements that apply to the same Misoperation. To avoid this, we
recommend that a new subpart 3.1 should be added in PRC-026-1 as follows: R3.1 The development
of a CAP pursuant to Requirement R3 shall supersede the requirements for a Generator Owner or
Transmission Owner to develop and implement a CAP for a Misoperation pursuant to NERC Reliability
Standard PRC-004. Correct operations Subpart 2.2 of PRC-026-1 also requires knowledge of correct
relay operations due to an unstable power swing. As explained above, this information is directly
derived from PRC-004-3, but performing a power swing analysis for each correct relay operation
would be very burdensome to meet subpart 2.2. The “becoming aware of” language in subpart 2.2 is
explained in the Application Guidelines on p. 22 of the standard. This explanation removes the onus
of an entity being required to examine each relay operation for the presence of a power swing. We
recommend the standard add a footnote to subpart 2.2 that states: “See p. 22 for an explanation of
implementing the “becoming aware” language in subpart 2.2.” Because a guideline is not
enforceable, such a footnote would tie this guideline language solidly to subpart 2.2.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
Ingleside Cogeneration L.P. (ICLP) has carefully read through the latest draft of PRC-026-1 and its
supporting documents, but still must deliver a “No” vote. We fully understand the regulatory need to
adhere to FERC’s December 31 deadline, but believe that the intent of the drafting team is not
captured in the enforceable parts of the standard itself. On a positive note, this means that we
believe that the technical aspects of PRC-026-1 are sound – which means that the most difficult
work has been performed. ICLP would like to compliment the project team on their ability to
construct a process that narrows the universe of load relays that may improperly react to stable
power swings, offsetting the arguments that the standard does not serve a reliability purpose.
However, several key logistical issues remain. In our view, if these remain uncorrected, we cannot
be sure that CEAs will administer the standard evenly across all eight Regions. Our specific
recommendations are as follows: 1) There must be clarity in the methods used to identify load relay
that react improperly to a stable or unstable power swing. The project team has articulated in their
Consideration of Comments that Events Analysis and/or a PRC-004 Misoperation study are the
triggers that they visualize. However, these concepts are not binding to CEAs – who we believe will
demand evidence that every load relay trip was investigated and proved to be not-applicable. In
addition, a TO or GO who does not properly identify a stable or unstable power swing will be held in
violation of PRC-026-1. This is not a capability or expertise that equipment owners possess, and
should not be held accountable for. The project team resolved a similar issue by adding a footnote
reference to FAC-010 in R1, and ICLP believes that the same could be done for R2. The footnote
would simply capture the fact that the potentially deficient load relay would be identified through the
Events Analysis process and/or a Misoperation study. 2) The project team has made it clear that a
trip in response to an unstable power swing is a screening factor – not a deficient condition.
However, no change has been made despite multiple requests to do so. Perhaps the project team
believes that there is already sufficient clarity in the requirements, but ICLP disagrees. As written,
we believe that some CEAs will demand corrective action in response to an unstable power swing –
an improper use of scarce resources better applied elsewhere. A modification to R2 to address the
screening intent of unstable power swings can be easily done in order to avoid this situation.
Individual
Kayleigh Wilkerson
Lincoln Electric System
Individual
Oliver Burke
Entergy Services, Inc.
Based on the information contained in the SPCS Power Swing Report Dated August 2013, there is
insufficient evidence contained in the historical study cases identified, to warrant implementation of
the proposed PRC-026-1 standard.”
Individual
John Merrell
Tacoma Power
In general, Tacoma Power agrees that the Power Swings Standard Drafting Team has addressed
industry comments in such a manner that industry consensus can be achieved. However, Tacoma
Power does have some other relatively minor suggestions. (In general, these comments were
identified by reviewing the draft with redlines.) 1. Consider modifying Requirement R3 as follows.
Change “...does not meet the PRC-026-1 – Attachment B criteria...” to “...does not meet the PRC026-1 – Attachment B criteria pursuant to Requirement R2...” This may be implied, but the language
in Requirement R3 does not tie back to Requirement R2. 2. In the Rationale for R3, it seems like the
reference to Requirement R2 should be a reference to Requirement R3. 3. The criteria headings in
Attachment B should read as Criterion A and Criterion B. 4. Under Attachment B, Criterion B,
Condition 2, all transmission BES Elements cannot be in their normal operating state if the parallel
transfer impedance has been removed. It is understood that all transmission BES Elements would be
in their normal operating state with the exception that the parallel transfer impedance should be
removed.
Group
Northeast Power Coordinating Council
Guy Zito
With respect to Requirement 1, stability addressed by RAS (Criterion 1), or relay trips observed in
Planning Assessments (Criterion 4) often involves remote or local generators and the instability or
relay trip does not impact the Bulk Electric System outside the local area. In NPCC, the majority of
RAS are classified as Type III SPS, meaning that their failure (and resulting instability) does not
adversely impact the Bulk Electric System outside the local area. As in PRC‐010‐1 that recognizes
local issues and "provides latitude for the Planning Coordinator or Transmission Planner to determine
if UVLS falls under the defined term based on the impact on the reliability of the BES", it is
suggested that PRC‐026‐1 also provide latitude to the PC to exclude some of the BES Elements
identified by Criteria 1 and 4 if the instability or relay trip does not impact the Bulk Electric System
outside the local area. The page numbers refer to the pages in the clean copy of PRC-026-1. Page
14--from “The following protection functions are excluded from Requirements of this standard:”,
Why are voltage-restrained relays excluded? Wouldn't the voltage dip during a power swing enable
these relays to misoperate on load current? Page 18--in the “Pole Slip:” item it should read “a
generator’s, or group of generator’s, terminal…”. Page 18--the “Out-of-step Condition:” should read
“Same as an Unstable Power Swing.” (Capitalization change). Page 20--line 5 should reads
“…identified as BES Elements meeting…”. Page 30--the caption for Figure 3 should read: “System
impedances as seen by Relay R. (voltage connections for relay not shown.)” Page 33-- The first blue
box for Table 2 should read: “Positive sequence impedance data (with transfer impedance ZTR set to
a very large value).” Page 33--In equation (8), ZTR was given as = ZL x 10^10, which equals (4 +
j20) x 10^10, not (4 + j20)^10 as used in the equations. Page 34--In Table 3, the second blue box
should read: “Positive sequence impedance data (with transfer impedance ZTR set to a very large
value). Page 36--same comment for Equation (16) as for Equation (8) above. Page 36--for Table 4
and Equation (24), the same comment as for Equation (8) above. Pages 38-42--for Tables 5, 6, and
7 the same comment as for Equation (8) above. Page 53--For Figure 12 the caption should be
rephrased to: “The tripping portion of the mho element characteristic not blocked by load
encroachment (i.e., …) is completely contained within…”. Page 69--The last blue box in Table 14
should read “Total system current”. Current direction is irrelevant. Page 72--the Drafting Team
should consider adding the word “Stable” in the lower right region of the Figure 16 graph, and the
word “Unstable”: under the words “Capability Curve” to the right of SSSL. Page 74--in Table 15, X”d
was changed to X’d, but “sub-transient” was not corrected to read “saturated transient reactance”.
Page 75--regarding Table 16, define the Base that the values of Table 15 have been converted to
(e.g. “Table 16. Example calculations (Generator) on 941 MVA base”). Pages 74-75--there are two
different values for Ze and both are in ohms, not per unit. Page 75--in Equation (107) j0.3845 +
j0.171 + 0.06796 does is not equal to 0.6239 ∠90°. Page 75-- Zsys is defined as 0.6239 ∠90° Ω in
Equation (107) of Table 16, but defined as 0.6234∠90° Ω in Equation (109) of Table 16 and in
Equation (110) of the Instantaneous Overcurrent Relay section. Page 78--in Figure 20 add “hashing”
to the area between the SSSL (black) curve and the 40-1 (blue) curve with an arrow and note
saying “Stable and can trip” or similar wording. There are inconsistencies in the use of “per unit” in
the tables of the Applications Guidelines. In some instances per unit is used, and in other instances
the ohmic value is given. There should be consistency in the Applications Guidelines and standard.
Individual
Jamison Cawley
Nebraska Public Power District
It is clear the drafting team has put a great amount of effort into this standard which is quite
complex. This effort is appreciated. Comments for consideration: R2.2 states: Within 12 full calendar
months of becoming aware of a generator, transformer, or transmission line BES Element that
tripped in response to a stable or unstable power swing due to the operation of its protective
relay(s), determine whether its load-responsive protective relay(s) applied to that BES Element
meets the criteria in PRC-026-1 – Attachment B. R2.2 hinges on “becoming aware” which seems will
be difficult to prove or audit. The drafting team felt that it is not needed to prove how an entity
addresses “becoming aware” but the RSAW indicates that an auditor should “(R2) Interview an
entity representative to understand the entity’s process for identifying applicable load-responsive
protective relays applied on the terminals of the BES Elements identified pursuant to Requirement
R2, Parts 2.1 and 2.2”. R2.2 seems to be a very vague and unpredictable part to R2. The standard
would be much cleaner without 2.2. A trip on a stable power swing will most likely be a misoperation
and will be addressed per other NERC standards (e.g. PRC-004, PRC-016). A trip on an unstable
power swing may or may not be a misoperation depending on if the relaying was set to trip for OOS
or not. It seems the only benefit to 2.2 then is to identify correct trips for unstable swings and this
does not seem to add significant reliability compared to the burden and audit risks. Consider
removal of 2.2. During the 11-13-2014 webinar some concerns were noted regarding the guidelines
and technical basis equations and calculations. Since a significant portion of this document is
devoted to calculations it is beneficial these be as accurate as possible since it will be a part of
compliance. Any reevaluations and rechecks of these calculations are greatly appreciated. There is
concern with voting yes until the final checks can be made. In addition to these comments, we also
support the comments submitted by SPP.
Individual
Brett Holland
Kansas City Power and Light
Attachment A The following protection functions should also be excluded from the Requirement of
this standard: Phase distance relay elements that do not reach beyond the next bus. Loss-of-field
relay elements that do not reach beyond the generator impedance.
Individual
Thomas Foltz
American Electric Power
Applicability, Section 4.2 (Facilities): Despite the changes proposed in this most recent draft, our
interpretation is the same as it was for the previous version. That being the case, we’re not certain
the proposed changes are serving their intended purpose. Could the team provide some insight into
what they were trying to clarify or correct with their most recent changes to this section? R2 and
R2.1: Collectively, these requirements read awkwardly due to multiple uses of the word “determine”.
We suggest eliminating the first “determine”, so that R2 instead reads ”Each Generator Owner and
Transmission Owner shall:”.
Group
PacifiCorp
Sandra Shaffer
The drafting team should eliminate or revise criterion 3 under PRC-026-1 R1. PRC-006 studies are
performed to help ensure sufficient load is available to be shed during extreme events to help arrest
frequency decline within an island. Since there are a large number of potential but very low
probability extreme events that could result in island formation, UFLS programs applied to small
loads dispersed throughout the interconnected system in order to increase the likelihood that
potential islands include load that can be shed. Since many of these potential islands and the
elements that open to form them are highly speculative, R1 Criteria 3, if it is kept, should be
modified to limit its application to elements associated with actual events or specifically designed
island boundaries. The Planning Coordinator should not be required to develop a criteria for
identifying islands.
Individual
Sonya Green-Sumpter
South carolina Electric & Gas
1) Please make R1, Criterion 3 clearer by replacing ‘where’ with ‘only if’. It then reads “ An Element
that forms the boundary of an island in the most recent underfrequency load shedding UFLS) design
assessment based on application of the Planning Coordinator’s criteria for identifying islands, only if
the island is formed by tripping the Element due to angular instability.” 2) Please expand Application
Guidelines p20 explanation of Criterion 3 by adding, ‘PC area boundary tie lines, or BA boundary tie
lines’ at the end of the last sentence so that it reads “The criterion does not apply to islands
identified based on other considerations that do not involve angular instability, such as excessive
loading, PC area boundary tie lines, or BA boundary tie lines.” 3) R1 Criteria 3 and 4, and R2 2.2
identify BES Elements tripped for instability. The Standard’s Purpose is ‘To ensure that loadresponsive protective relays are expected to not trip in response to stable power swings during nonFault conditions.’ (Why do relays that trip on instability need to be evaluated and required to meet
this standard?) Please explain that these BES Elements are included because they could be more
likely to be challenged by power swings. Their inclusion does not mean that the relays tripping these
Elements were necessarily inappropriate. Such an explanation could fit well on page 18 just after
“The first step uses criteria to identify the Elements on which a Protection System is expected to be
challenged by power swings.”
Individual
Amy Casuscelli
Xcel Energy
Although the latest draft of PRC-026 is an improvement, Xcel Energy feels that there are additional
opportunities for improvement. We respectfully submit the following comments for the drafting
team’s consideration. A new Requirement should be added requiring the PC to provide the system
separation angle as part of the notification in order to ensure proper calculation of relay settings.
Suggested wording: [Each Planning Coordinator shall provide notification of the system separation
angle of each identified BES Element(s) in its area that met any of the Criteria in R1, if any, to the
respective Generator Owner and Transmission Owner.] Additionally, the 1.05 V Pu voltage is
subjective and not based on a study, and contradicts what the GTB says about the AVR: “it is more
likely that the relay would operate during a power swing when the automatic voltage regulator
(AVR) is in manual mode rather than when in automatic mode.” The statement would lead one to
believe that 1- The GO is operating in manual mode in contrast to the VAR standards. 2 – That
operating in manual mode would keep the unit voltage at 1.05 pu, which is inherently false.
Therefore, the calculations in GTB are hypothetical and should not be in a standard, as they provide
no reliability assurance.
Individual
Michael Moltane
ITC
Edit R2.2 to include, “…due to the operation of its protective [functions described in Attachment A],
determine…” Modern relays which enable power swing blocking functions result in time-delayed
clearing for subsequent 3 phase faults. E.g. SEL-411L manual states “Three-phase faults will be
detected with a minimum and maximum time delay of two and five cycles, respectively.” More
conventional power swing blocking functions result in time delays much longer than 5 cycles,
possibly exceeding 1 second. Does the SDT believe this is “dependable fault detection”? Does the
SDT believe this contributes to the reliability of the BES? Edit page 79, “Double blinder schemes are
more complex [than] the single…” R1 Criteria 3 remains unclear. PRC-006 does not seem to require
the level of detail required for PCs to meet this requirement. Our concerns are that PCs will commit
much more resources to developing this level of detail or absent that level of detail will identify all or
none of the boundary elements as meeting this criteria.
Group
ISO RTO Council Standards Review Committee
Greg Campoli
The IRC SRC appreciates the drafting team’s efforts in addressing industry concerns, especially
those we submitted in the prior posting. We believe our concerns have been addressed, but
respectfully suggest the following small clarification regarding Requirement R3: Each Generator
Owner and Transmission Owner shall, within six full calendar months of determining, pursuant to R2,
that a load-responsive protective relay does not meet the PRC-026-1 – Attachment B criteria,
develop a Corrective Action Plan (CAP) to meet one or more of the following…. Thank you for the
additional comment opportunity.
Individual
Steve
Rueckert
I don't have any concerns with the standard as drafted. However, you may wish to make a
gramatical review of the language of R2. the word "determine" is included in the language of R2
(last word) as well as in Parts 2.1 and 2.2. It seems like it is not needed both times.
Group
SERC Protection and Controls Subcommittee
David Greene
1) Please make R1, Criterion 3 clearer by replacing ‘where’ with ‘only if’. It then reads “ An Element
that forms the boundary of an island in the most recent underfrequency load shedding (UFLS)
design assessment based on application of the Planning Coordinator’s criteria for identifying islands,
only if the island is formed by tripping the Element due to angular instability.” 2) Please expand
Application Guidelines p20 explanation of Criterion 3 by adding, ‘PC area boundary tie lines, or BA
boundary tie lines’ at the end of the last sentence so that it reads “The criterion does not apply to
islands identified based on other considerations that do not involve angular instability, such as
excessive loading, PC area boundary tie lines, or BA boundary tie lines.” 3) R1 Criteria 3 and 4, and
R2 2.2 identify BES Elements tripped for instability. The Standard’s Purpose is ‘To ensure that loadresponsive protective relays are expected to not trip in response to stable power swings during nonFault conditions.’ (Why do relays that trip on instability need to be evaluated and required to meet
this standard?) Please explain that these BES Elements are included because they could be more
likely to be challenged by power swings. Their inclusion does not mean that the relays tripping these
Elements were necessarily inappropriate. Such an explanation could fit well on page 18 just after
“The first step uses criteria to identify the Elements on which a Protection System is expected to be
challenged by power swings.” The comments expressed herein represent a consensus of the views of
the above-named members of the SERC EC Protection and Control Subcommittee only and should
not be construed as the position of SERC Reliability Corporation, its board, or its officers.
Individual
Sergio Banuelos
Tri-State Generation and Transmission Association, Inc.
Tri-State believes that Requirement R3 should continue to refer to the Requirement to assess the
load-responsive protective relays against the criteria of PRC-026-1 - Attachment B. We recommend
adding “pursuant to Requirement R2,” between “PRC-026-1 - Attachment B criteria,” and “develop a
Corrective Action Plan (CAP)” in Requirement R3. Without the clarifying clause, the requirement
could be referring to any load-responsive protective relay that the entity happens to recognize that
does not meet the criteria in the attachment.
Group
Dominion
Connie Lowe
As mentioned in the Webinar, the upper loss of synchronism circle is based on the ratio of sendingend to receiving-end voltage of 1.43. Looking at the REDLINE copy of PRC-026-1 draft 3, this should
be revised in several places, Revisions Page 19 of 98: “ […] (2) an upper loss-of-synchronism circle
based on a ratio of the sending-end to receiving-end voltages of 1.43” Page 31 of 98: “The second
shape is an upper loss of synchronism circle based on a ratio of the sending-end to receiving-end
voltage of 1.43 (i.e., ES / ER = 1.0 / 0.7 = 1.43).” Page 32 of 98: “Eq. (3): E_S/E_R
=1.0/0.7=1.43” Page 37 of 98: “Shape 2 – Upper Loss of Synchronism Circle With Sending to
Receiving Voltage Ratio of 1.43” Page 72 of 98: Table 13 should have an example calculation where
ES < ER for the lower loss of synchronism circle and an example calculation where ES > ER for the
upper loss of synchronism circle. As discussed with Kevin Jones at Xcel Energy, a revision of Figure
5, on page 41 of 98, changing “Voltage (p.u.)” to the voltage ratio of “ES/ER”, where the ratio
extends from 0.7 to 1.43, would align nicely with the edits above.
Group
SPP Standards Review Group
Shannon Mickens
We have a concern about the significance of Attachment A in the documentation and ask the drafting
team to provide more clarity on this documentation. In Requirement R3, the drafting team mentions
that the Generator Owner and Transmission Owner has six full calendar months after determining
that load-responsive protection relays don’t meet Attachment B criteria and a Correction Action Plan
(CAP) needs to be developed. Additionally in the second bullet of the same requirement, the drafting
team mentions ‘The Protection System is excluded under the PRC-026-1 – Attachment A criteria’.
However in the Rationale Box of R3, the drafting team provides detailed information on the necessity
of the CAP and its association with Attachment B. As for Attachment A, there is no explanation of
how it impacts the Generator Owner and Transmission Owner or what role it plays in this process.
Please provide more detailed information in the Rationale Box of R3 in reference to Attachment A.
Group
Duke Energy
Michael Lowman
“Duke Energy would like to reiterate that we do not believe adequate technical justification has been
identified for this project to become a standard. Based on the SPCS recommendation, the SDT and
NERC should consider moving this project to a Guideline document until such time as a standard is
warranted.”
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
These comments are submitted on behalf of the following PPL NERC Registered Affiliates: LG&E and
KU Energy, LLC; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; PPL Generation, LLC; PPL
Susquehanna, LLC; and PPL Montana, LLC. The PPL NERC Registered Affiliates are registered in six
regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more of the following NERC functions:
BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP. Comments: We agree that SDT has
largely addressed industry comments on this standard and believe that STD’s work on this standard
sets a model for future collaborative effort. We have only one remaining concern. Although the
Application Guideline has language that satisfactorily explains the intent of the “becoming aware of”
language in subpart 2.2, we are concerned that a guideline is not enforceable. We recommend
adding a footnote in subpart 2.2 that solidly ties the guideline language to this subpart. If this single
change were made to this version of the standard, PPL would vote affirmatively
Individual
Muhammed Ali
Hydro One
Group
JEA
Thomas McElhinney
We are concerned that this standard may have unintended consequences and hurt the reliability of
the BES.
Group
ACES Standards Collaborators
Jason Marshall
(1) The drafting team has continued improving this standard and we thank you for the
improvements. (2) We question the need for this standard. In its “Protection System Response to
Power Swings” (on page 5) document dated August 2013, the NERC System Protection and Control
Subcommittee (SPCS) concluded ”that a NERC Reliability Standard to address relay performance
during stable power swings is NOT needed, and could result in unintended adverse impacts to the
Bulk-Power System reliability” [emphasis added]. (3) The footnote in criterion 2 for Requirement R1
is technically inaccurate and should be modified. An Element would be identified through the
application of the PC’s SOL methodology which is required in FAC-014-2 not FAC-010. The
methodology must be developed in FAC-010 but application is required in FAC-014-2 R3 and R4. (3)
Why is the word “full” added to “six full calendar months”? We think it only adds confusion in other
areas where it is not included. The words six calendar months imply the inclusion of a “full” calendar
month. (4) Requirement R4 should be modified to avoid a registered entity being in technical
violation for simply updating their Corrective Action Plan (CAP). As it is written, the applicable entity
must both implement the CAP and update the CAP. The problem is that they may be updating the
CAP because implementation on the original timeline is not possible. As R4 is written with an “and”
condition, this is not possible without a technical violation of the requirement. We suggest changing
the second “and” to “or” to address this concern. (5) Criterion 4 of Requirement R1 requires further
explanation. In response to our previous comment questioning the inclusion of unstable power
swings in criterion 4 of Requirement R1, the drafting team stated that “this standard does not
require that entities assess Protection System performance during unstable swings.” If this is the
case, this would support removing “unstable power swings” from criterion 4. What reliability purpose
does the PC notifying the GO and TO of Elements susceptible to unstable power swings serve, if the
GO and TO are not required to do anything with the information. (6) Any VRFs that are greater than
Lower would seem to be inconsistent with the recommendation of the SPCS (see our point two for
the recommendation) that a standard is not needed. Especially, assigning Requirement R2 a VRF of
High would seem to a complete rejection of this recommendation. Is this what is intended by the
drafting team? (7) Should Requirement R3 allow selection of “one or more of the following” or
should it be limited to selecting one option? In other words, can a Protection System meet both
Criteria A and B simultaneously? If not, then “one or more of the following” should be changed to
“either of the following.” (8) We do not understand why unstable power swings are included in Part
2.2. Per the purpose statement of the standard and the drafting’s prior response to comments (see
our bullet 5), the purpose is to prevent tripping of protective relays in response to stable power
swings. It is not intended to prevent tripping due to unstable power swings. Thus, why would Part
2.2 compel an evaluation of load-responsive relays for actual tripping due to unstable power swings?
(8) Thank you for the opportunity to comment.
Group
DTE Electric Co.
Kathleen Black
Agree with PSEG comments. The current draft does provide more detailed evaluation basis and
examples, however, not all variations in protection schemes are addressed which could result in
misapplication of the evaluation criteria.
Group
Tennessee Valley AUthority
Dennis Chastain
Based on the proposed implementation plan, it seems that the applicable GO and TO will not be
required to perform an initial R2.1 evaluation until the second annual notification is received from
the PC. Suggest making the “12 months” in the R1 implementation statement “24 months” unless a
practice year was intended for the PC requirement. Consider making the implementation date for R3
and R4 lag the implementation date of R2 by six months. The R3 requirement allows for six months
to develop a CAP following completion of work associated with R2. To align with the change made to
requirement R2 regarding evaluations performed in the last five calendar years, consider making the
effective date of R2 the “First day of the first full calendar year that is 60 months after the date….”
Page number references in the following comments apply to the redline posting. Page 19: Within the
“Rationale for Attachment B (Criteria A)” box shaded blue, should “… varying from 0.7 to 1.0 per
unit…” be changed to “varying from 0.0 to 1.0 per unit…” to match the change made in the
preceding Criteria A section? Page 24: In the Requirement R1 section, recommend replacing the last
sentence with “It is possible that a Planning Coordinator will utilize prior year studies in determining
their requirement R1 Elements list each year.” Page 25: In the Requirement R1, Criterion 1 section,
suggest changing “The 66 kV transmission line is not electrically joined to the 345 kV and 230 kV
transmission lines at the plant site and is not a part of the operating limit or RAS.” to “The 66 kV
transmission lines are not electrically joined to the 345 kV and 230 kV transmission lines at the plant
site and are not a part of the operating limit or RAS.” since there is more than one 66 kV line in the
example. Page 25: In the Requirement R1, Criterion 2 section, since the acronym SOL is now spelled
out in the Criterion 1 section, the acronym can be used in the Criterion 2 section without spelling it
out.
Individual
Anthony Jablonski
ReliabilityFirst
ReliabilityFirst votes in the Affirmative and believes the PRC-026-1 standard enhances reliability and
ensures that load-responsive protective relays are expected to not trip in response to stable power
swings during non-Fault conditions. ReliabilityFirst offers the following comments for consideration:
1. Requirement R2 – the language regarding who determines whether or not a stable or unstable
power swing has occurred is vague. The associated application notes state that the SDT purposefully
avoided making the GO or TO responsible for that determination and allude that possibly the GO or
TO, the RE or NERC during an event analysis could be the source. Unfortunately, this wording sets
up a lot of finger pointing as to who was responsible to launch the analysis of the compliance of
PRC-026 with the event. ReliabilityFirst recommends including language clearly identifying the
source of who determines whether or not a stable or unstable power swing has occurred as
referenced in Requirement R2.
Individual
Richard Vine
California ISO
The California ISO does not agree with the change to remove the Transmission Planner in the
Applicability section and in Requirement R1. The California ISO supports continuing to include the
Transmission Planner in Requirement R1 as suggested by the PSRPS Report.
Individual
Spencer Tacke
Modesto Irrigation District
The standard should be applicable to more than just BES elements. I think it is critical that the
following phrase be included in Part 4.2 of the Applicability Section: "Any system element,
regardless of size or connected voltage, that has been shown to be material to the reliability of the
BES". The “bright line” of 100 kV is fine in general, but when it is known that an element connected
at less than 100 kV is material to the reliability of the BES, it should be included as an applicable
facility for this standard. This is because WECC members have learned over the years to recognize
the significant role that smaller size elements play in system response and stability. Also, past WECC
studies of major outages have shown that elements connected at less than 100 kV, have played a
major role in the impact of outages. In fact, the most accurate duplication of the 1996 major system
wide outage and more recent outages that the WECC MVWG has simulated, have shown that the
accuracy of the simulated results of actual system outages is highly affected by the accuracy of the
modeled system below 100 KV.
Individual
Scott Berry
Indiana Municipal Power Agency
Individual
John Brockhan
CenterPoint Energy Houston Electric, LLC
(1) CenterPoint Energy still feels strongly that there is redundancy between PRC-004 and PRC-026
regarding Corrective Action Plans (CAPs) and must again vote negative. Redundancy is included in
the NERC Paragraph 81 (P.81) project as item “B7. Redundant”. Item “B7. Redundant” states the
following: “The Reliability Standard requirement is redundant with: (i) another FERC-approved
Reliability Standard requirement(s); (ii) the ERO compliance and monitoring program or (iii) a
governmental regulation (e.g., Open Access Transmission Tariff, North American Energy Standards
Board (“NAESB”), etc.). This criterion is designed to identify requirements that are redundant with
other requirements and are, therefore, unnecessary. Unlike the other criteria listed in Criterion B, in
the case of redundancy, the task or activity itself may contribute to a reliable BES, but it is not
necessary to have two duplicative requirements on the same or similar task or activity. Such
requirements can be removed with little or no effect on reliability and removal will result in an
increase in efficiency of the ERO compliance program.” Based on our understanding, from responses
to comments and also from the recent Q&A webinar, the SDT believes that PRC-026 is more
stringent than PRC-004; therefore, PRC-026 requirements for a CAP would supersede those in PRC004. Mainly, PRC-026 will require a CAP, whereas PRC-004 does not require a CAP if explained “in a
declaration why corrective actions are beyond the entity’s control or would not improve BES
reliability, and that no further corrective actions will be taken.” We believe such duplicative
requirements could send mixed signals where a CAP does not appear to be required (PRC-004)
when, in fact, one is required (PRC-026). Should standard PRC-026 be approved as currently
written, CenterPoint Energy recommends, due to redundancy, that NERC initiate a project to remove
the requirement for a CAP for Protection System operations from power swings in standard PRC-004.
(2) CenterPoint Energy technically disagrees with the SDT’s response that operator-initiated
switching to reconnect islands, to restore load during Black Start activities, or to synchronize a
generating unit to the system should be applicable to PRC-026. We believe that any Element that
tripped in response to a stable or unstable power swing involving restoration and black‐starting
would be addressed in after-action reviews of those events. We expect that entities will need to
coordinate with their Regional Entities to address such circumstances.
Group
BC Hydro
Patricia Robertson
BC hydro does not agree with the proposed new reliability standard PRC-026-1. In the past 15 years
with approximately 1000 faults per year on the transmission system, there has not been a single
undesired protection operation on a stable power swing. There have been some protection
operations on power swings, but they were desirable, and separated systems that were about to go
out of step. BC Hydro has a very large portion of its transmission system that is subject to stability
constraints. Therefore, even the focussed approach proposed in the new standard will present a
significant amount of engineering resources to perform the stability checks and protection response
checks to determine whether setting modifications or addition of power swing blocking relays or
whether exemptions are required. BC Hydro recommends that the new standard not be
implemented, or if it is implemented, that the WECC region be exempted in view of the fact that the
transmission network is sparse, with many stability constraints. The work required to meet this
standard will be excessive, even with the focussed approach proposed.
Group
Seattle City Light
Paul Haase
Seattle City Light appreciates the efforts of the Standards Drafting Team to respond to comments
and clarify the proposed draft. Seattle, however, continues to believe that the proposed Standard is
not warranted by the history of major electrical outages. Seattle further finds the proposed Standard
to be based on theoretical concepts rather than practical experience, and as such, proposes a largely
untried process to become a rigid federal regulation having continental reach. Recent industry
experience suggests the difficulty of such an approach. Consider industry experience with another
new concept, that of the NERC “Order 754” effort. Considerable back-and-forth exchange and
flexibility was required of this effort before well-meaning entities across the continent--each having
different configurations, equipment, and characteristics--were able apply a new, untried process to
reach a desired and consistent result. Furthermore, as the drafting team will recall, the Order 754
request required some three years to complete, and first year was spent almost entirely in
clarifications and modifications. The clarifications and modifications were necessary to address the
differing equipment and configurations of diverse entities, configurations and equipment that had
not been considered by the team that framed the request. Matters came up as fundamental as “what
is meant by the term ‘bus’ in the request?” (in the end, ‘bus’ was defined to mean one thing for one
part of the request and defined as something else for another part). Given the diversity of entities in
North America, how could any team, no matter how strong, be expected to conceive of all possible
arrangements with no application experience to guide them? Consider now that the proposed
Standard is just as untried as the Order 754 request and is rather more complex. Moreover, as a
mandatory reliability Standard it would lack the implementation flexibility that allowed successful
completion of the Order 754 request. Consequently Seattle is deeply concerned about the
effectiveness of the proposed approach in improving the reliability of the bulk electric system in the
near term. Rather it appears more likely to drive a bow-wave of compliance violations as numerous
entities struggle to apply new theoretical processes that do not fit their situation and circumstances,
and regulators struggle to figure out how to audit a misfit Standard. As such, Seattle votes Negative
on this ballot and expects to do so in future ballots as well. Seattle would consider an Affirmative
position if the draft Standard was put on hold and a 1-2 year pilot program run in its place. Such a
pilot program could be structured as a mandatory reporting exercise somewhat like the Order 754
effort: reporting would be required but results would not be audited for compliance (rather used for
learning). Alternatively, a pilot program might be structured to focus on a small number of entities
such as the recent CIP v5 pilot program (with the difference that no PRC-026-1 Standard would be
adopted, until after the pilot when lessons learned could be incorporated into it). Once experience
had been acquired with the real-world application of the proposed PRC-026-1 requirements, and the
Standard revised to accommodate these lessons, then Seattle would consider an Affirmative vote.
Should a pilot program be implemented, Seattle would be willing to serve a test entity.
Group
Bonneville Power Administration
Andrea Jessup
BPA has no unresolved issues.
Group
Associated Electric Cooperative, Inc.
Phil Hart
AECI believes that the term unstable power swing should be removed from this standard. Reliability
risks associated with unstable swings are already handled with relay protection (PRC) and system
study standards (TPL). FERC ordered this drafting team to address issues associated with stable
power swings, and the addition of unstable swings in the language is unwarranted. In the previous
round of commenting the SDT responded by stating this inclusion was inherent in statements made
in the PSRPS report. I would encourage the SDT to also read the following statement from page 19
of that same report, “over‐emphasizing secure operation for stable powers swings could be
detrimental to Bulk‐Power System reliability.” By including unstable power swings within the
screening process of R1 more events will qualify for testing and the SDT will have done the very
thing the SPCS warned against. An unwarranted emphasis on stable power swings is created when
you use unrelated events like unstable swings to define your testing criteria for stable swings. AECI
would respectfully request the drafting team removed “unstable” from PRC-026 and keep stable and
unstable power swing standards as completely separate as possible, or provide the reliability based
risk that exists without the inclusion of this term within the standard.
Group
Bureau of Reclamation
Erika Doot
The Bureau of Reclamation (Reclamation) supports the proposed PRC-026-1. Reclamation
appreciates the drafting team’s efforts revising the Applicability, Requirements, and Measures to
clarify which entities will be required to complete stable power swing analysis for which qualifying
facilities and elements.
Additional Comments:
Xcel Energy
Amy Casuscelli
The reference to FAC-10 in R1 Criterion 2 does not appear to be consistent with its intent since
the Planning Coordinator’s methodology per se does not identify/establish the SOLs… instead,
they are determined based on applying the methodology, which is required in FAC-014-2.
Therefore, assuming there is value in retaining a reference in Criterion 2, it should probably be
changed to R3 of FAC-014 that requires SOLs to be established by the Planning Coordinator. Or
the reference could be changed to R6 of FAC-014, which specifically pertains to identifying the
stability limit SOLs. However, it may be sufficient to have no reference in Criterion 2 as follows:
“Monitored elements that are part of (angular) stability limit SOLs determined by the Planning
Coordinator.”
END OF REPORT
Consideration of Comments
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swings
The Project 2010-13.3 Drafting Team thanks all commenters who submitted comments on the
standard. These standards were posted for a 21-day public comment period from November 4, 2014
through November 24, 2014. Stakeholders were asked to provide feedback on the standards and
associated documents through a special electronic comment form. There were 42 sets of comments,
including comments from approximately 142 different people from approximately 88 companies
representing all 10 Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please 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,
you can contact the Director of Standards, Valerie Agnew, at 404-446-2566 or
at [email protected] . In addition, there is a NERC Reliability Standards Appeals Process. 1
Summary of Changes to the Standard
The following is a summary of the revisions to Draft 4 that were made to the proposed PRC-026-1 NERC
Reliability Standard in order to provide additional clarity of the Standard. Revisions were based on
industry stakeholder comments from Draft 3 of the Standard.
Applicability
•
No change
Background
•
The Background section was updated for clarity
Effective Dates
•
No change
Requirement R1
•
•
1
Minor editorial revisions based upon comments
Footnote added to draw attention to new detail provided in the Guidelines and Technical Basis
concerning the inclusion of “unstable” in Criterion 4
The appeals process is in the Standard Processes Manual: http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf
Requirements R2
•
•
•
•
The word “determine” was removed from the main requirement body based on comments as it
is duplicative of Parts 2.1 and 2.2
Footnote added to draw attention to examples provided in the Guidelines and Technical Basis
of how an entity would “become aware” of a stable or unstable power swing
Footnote added to draw attention to new detail provided in the Guidelines and Technical Basis
concerning the inclusion of “unstable” in Part 2.2
The rationale box text was updated for clarity
Requirement R3
•
•
•
The phrase “pursuant to Requirement R2” was inserted based on comments to provide a
referential link to the previous requirement which triggers performance under Requirement R3
The clause “or more” was deleted based on comments to remove confusion about whether
either or both of the Corrective Action Plan options were required. Although an entity may
perform both under certain circumstances, the standard drafting team concluded that
performing one of the two bulleted items would achieve the reliability goal of the standard
The rationale box text was updated for clarity
Requirement R4
•
No change
Measures M1-M4
•
No change
Compliance Section
•
No change
Violation Severity Levels
•
No change
PRC-026-1 – Attachment A
•
The phrase “provided the distance element is set in accordance with the criteria outlined in the
standard” has been removed from a bullet in the PRC-026-1 – Attachment A (protection system
functions that are excluded from the standard) pertaining to phase fault detector relay
elements that supervise other load-responsive phase distance elements. The removal of the
phrase does not change any performance under requirements of the standard, however, it does
eliminate any inadvertent confusion that may be introduced by this phrase. Phase distance
elements are on the PRC-026-1 – Attachment A inclusion list and must be set in accordance with
PRC-026-1 – Attachment B, Criterion A if the protected Element (i.e., transmission line,
Consideration of Comments: Project 2010-13.3 – Phase 3 of Relay Loadability: Stable Power Swings
Posted: December 5, 2014
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transformer, or generator BES Element) is determined to be applicable to the standard pursuant
to Requirement R1 and/or Requirement R2. Given that:
1. the pickup of the phase fault detector relay element cannot cause a trip without the pickup
of the supervised phase distance element, and
2. the phase distance relay element must be set in accordance with PRC-026-1 – Attachment B,
Criterion A, the deleted phrase is irrelevant and unnecessary
PRC-026-1 – Attachment B
•
•
The uses of “Criteria” were replaced by “Criterion” for correctness
The order of “sending-end” to “receiving-end” voltages were reversed and swapped for
correctness
Guidelines and Technical Basis
•
•
•
•
•
•
The Guidelines and Technical Basis received a number of varying revisions to provide additional
clarity. Some of the most notable enhancements include:
Several Figures were corrected due to errors reported through the comments
Several calculations in the Tables were corrected due to errors reported through the comments,
Table 13 in particular
Several revisions were due to inconsistencies within the document on how information is
presented
The format of the document was updated for consistency with the NERC style guide
The section, “Justification for Including Unstable Power Swings in the Requirements” was
appended to provide an understanding of why “unstable” power swings are relevant to the
performance of the Standard.
Implementation Plan
•
Clarification to the section, “Notifications Prior to the Effective Date of Requirement R2” was
made to clarify an entity’s obligations during the implementation plan period
VRF and VSL Justifications
•
•
Several paragraphs that were redundant with other information were removed
Minor corrections made in the text
Consideration of Comments: Project 2010-13.3 – Phase 3 of Relay Loadability: Stable Power Swings
Posted: December 5, 2014
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1.
The Protection System Response to Power Swings Standard Drafting Team believes it
has addressed industry comments in such a manner that industry consensus can be
achieved. If there are remaining unresolved issues in the proposed PRC-026-1
Reliability Standard, please provide your comments here: .............................13
Consideration of Comments: Project 2010-13.3 – Phase 3 of Relay Loadability: Stable Power Swings
Posted: December 5, 2014
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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
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Joe DePoorter
Additional Organization
MRO NERC Standards Review Forum
2
X
3
X
4
X
5
X
6
7
8
9
X
Region Segment Selection
1. Amy Casucelli
Xcel Energy
MRO
1, 3, 5, 6
2. Chuck Wicklund
Otter Tail Power
MRO
1, 3, 5
3. Dan Inman
Minnkota Power Cooperative
MRO
1, 3, 5, 6
4. Dave Rudolph
Basin Electric Power Coop
MRO
1, 3, 5, 6
5. Kayleigh Wilkerson Lincoln Electric System
MRO
1, 3, 5, 6
6. Jodi Jensen
WAPA
MRO
1, 6
7. Ken Goldsmith
Alliant Energy
MRO
4
8. Mahmood Safi
Omaha Public Power District
MRO
1, 3, 5, 6
9. Marie Knox
MISO
MRO
2
10. Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
11. Randi Nyholm
Minnesota Power
MRO
1, 5
12. Scott Nickels
Rochester Public Utilities
MRO
4
13. Terry Harbour
MidAmerican Energy
MRO
1, 3, 5, 6
14. Tom Breene
Wisconsin Public Service
MRO
3, 4, 5, 6
Consideration of Comments: Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power Swing
Posted: December 5, 2014
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10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
15. Tony Eddleman
Nebraska Public Power District MRO
2.
Guy Zito
Group
Additional Member
4
5
6
7
8
9
Northeast Power Coordinating Council
Additional Organization
New York State Reliability Council, LLC
NPCC
10
Orange and Rockland Utilities Inc.
NPCC
3
3. Greg Campoli
New York Independent System Operator
NPCC
2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5. Kelly Dash
Consolidated Edison Co. of New York Inc. NPCC
1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
7. Milke Garton
Dominion Resources Services, Inc.
NPCC
5
8. Kathleen Goodman
ISO - New England
NPCC
2
9. Ben Wu
Orange and Rockland Utilities Inc.
NPCC
1
10. Mark Kenny
Northeast Utilities
NPCC
1
11. Helen Lainis
Independent Electricity System Operator
NPCC
2
12. Alan MacNaughton
New Brunswick Power Corporation
NPCC
9
13. Bruce Metruck
New York Power Authority
NPCC
6
14. Silvia Parada Mitchell NextEra Energy, LLC
NPCC
5
15. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
16. Robert Pellegrini
The United Illuminating Company
NPCC
1
17. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
18. David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
19. Brian Robinson
Utility Services
NPCC
8
20. Ayesha Sabouba
Hydro One Networks Inc.
NPCC
1
21. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC
3
22. Wayne Sipperly
New York Power Authority
5
3.
Group
Sandra Shaffer
PacifiCorp
Group
Greg Campoli
ISO RTO Council Standards Review
Committee
NPCC
X
X
Additional Member Additional Organization Region Segment Selection
1. Charles Yeung
SPP
SPP
10
X
Region Segment Selection
2. David Burke
4.
3
1, 3, 5
1. Alan Adamson
N/A
2
2
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Posted: December 5, 2014
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Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2. Ben Li
IESO
NPCC
2
3. Matt Goldberg
ISONE
NPCC
2
4. Lori Spence
MISO
MRO
2
5. Cheryl Moseley
ERCOT
ERCOT 2
6. Mark Holman
PJM
RFC
5.
Group
Additional Organization
1. Paul Nauert
Ameran
2. Russ Evans
SCE&G
3. Phil Winston
Southern Company Services
4. David Greene
SERC
6.
Group
Additional Organization
Dominion
NERC Compliance Policy
SERC
1, 3, 5, 6
NERC Compliance Policy
RFC
5, 6
3. Mike Garton
NERC Compliance Policy
NPCC 5
4. Larry Nash
Electric Transmission Compliance SERC
1, 3
5. Larry Bateman
Electric Transmission Compliance SERC
1, 3
6. Christopher Mertz
Electric Transmission
1, 3
Additional Member
Shannon Mickens
Additional Organization
6
7
8
9
X
X
X
Region Segment Selection
2. Louis Slade
Group
5
2
1. Randi Heise
7.
4
Region Segment Selection
Connie Lowe
Additional Member
3
SERC Protection and Controls
Subcommittee
David Greene
Additional Member
2
SERC
SPP Standards Review Group
X
Region Segment Selection
1. Karl Diekevers
Nebraska Public Power District MRO
1, 3, 5
2. Joe Fultz
Grand River Dam Authority
SPP
1
3. Louis Guidry
Cleco Power
SPP
1, 3, 5, 6
4. Greg Hill
Nebraska Public Power District MRO
1, 3, 5
5. Stephanie Johnson Westar Energy
SPP
1, 3, 5, 6
6. Bo Jones
Westar Energy
SPP
1, 3, 5, 6
7. Mike Kidwell
Empire District Electric
SPP
1, 3, 5
8. Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
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Posted: December 5, 2014
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10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9. James Nail
City of Independence, MO
SPP
3, 5
10. Robert Rhodes
Southwest Power Pool
SPP
2
11. Lynn Schroeder
Westar Energy
SPP
1, 3, 5, 6
12. Jason Smith
Southwest Power Pool
SPP
2
8.
Michael Lowman
Duke Energy
Group
2
3
4
5
6
X
X
X
X
X
X
X
X
7
8
9
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
RFC
1
2. Lee Schuster
FRCC
3
3. Dale Goodwine
SERC
5
4. Greg Cecil
RFC
6
9.
Group
Additional Member
Brent Ingebrigtson
PPL NERC Registered Affiliates
Additional Organization
Region Segment Selection
1. Charlie Freibert
LG&E and KU Energy, LLC
2. Brenda Truhe
PPL Electric Utilities Corporation RFC
SERC
3
1
3. Annette Bannon
PPL Generation, LLC
RFC
5
4.
PPL Susquehanna, LLC
RFC
5
5.
PPL Montana, LLC
WECC 5
6. Elizabeth Davis
PPL EnergyPlus, LLC
MRO
6
7.
NPCC 6
8.
RFC
6
9.
SERC
6
10.
SPP
6
11.
WECC 6
10.
Group
Thomas McElhinney
JEA
Additional Member Additional Organization Region Segment Selection
1. Ted Hobson
FRCC
1
2. Garry Baker
FRCC
3
3. John Babik
FRCC
5
11.
Group
Jason Marshall
ACES Standards Collaborators
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Posted: December 5, 2014
X
8 of 50
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Additional
Member
Additional Organization
Region
Central Iowa Power Cooperative
MRO
1
2. Ellen Watkins
Sunflower Electric Power Corporation
SPP
1
3. John Shaver
Arizona Electric Power Cooperative/ Southwest Transmission
Cooperative, Inc.
WECC 1, 4, 5
4. Shari Heino
Brazos Electric Power Cooperative, Inc.
ERCOT 1, 5
5. Ryan Strom
Buckeye Power, Inc.
RFC
3, 4, 5
6. Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
7. Scott Brame
North Carolina Electric Membership Corporation
RFC
3, 4, 5
8. Mark Ringhausen
Old Dominion Electric Cooperative
RFC
3, 4
9. Ginger Mercier
Prairie Power, Inc.
SERC
3
10. Bob Solomon
Hoosier Energy Rural Electric Cooperative, Inc.
RFC
1
Group
Kathleen Black
Additional Member
DTE Electric Co.
Additional Organization
X
NERC Compliance
RFC
3
2. Daniel Herring
NERC Training & Standards Development RFC
4
3. Mark Stefaniak
Merchant Operations
5
Group
Dennis Chastain
4
5
6
7
8
9
X
X
Region Segment Selection
1. Kent Kujala
13.
3
Segment
Selection
1. Kevin Lyons
12.
2
RFC
Tennessee Valley AUthority
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. DeWayne Scott
Tennessee Valley Authority SERC
1
2. Ian Grant
Tennessee Valley Authority SERC
3
3. Brandy Spraker
Tennessee Valley Authority SERC
5
4. Marjorie Parsons
Tennessee Valley Authority SERC
6
14.
Group
Patricia Robertson
Additional Member
BC Hydro
1. Venkataramakrishnan Vinnakota BC Hydro
WECC 2
2. Pat G. Harrington
BC Hydro
WECC 3
3. Clement Ma
BC Hydro
WECC 5
15.
Group
X
Additional Organization Region Segment Selection
Paul Haase
Seattle City Light
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10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
Additional Member Additional Organization Region Segment Selection
1. Pawel Krupa
Seattle City Light
WECC 1
2. Dana Wheelock
Seattle City Light
WECC 3
3. Hao Li
Seattle City Light
WECC 4
4. Mike Haynes
Seattle City Light
WECC 5
5. Dennis Sismaet
Seattle City Light
WECC 6
16.
Group
Andrea Jessup
Additional Member
Bonneville Power Administration
Additional Organization
System Control Engineering WECC 1
2. Jim Gronquist
Transmission Planning
WECC 1
3. Chuck Matthews
Transmission Planning
WECC 1
Group
Phil Hart
Additional Member
X
X
X
X
X
Region Segment Selection
1. Dean Bender
17.
X
Associated Electric Cooperative, Inc.
Additional Organization Region Segment Selection
1. Central Electric Power Cooperative
SERC
1, 3
2. KAMO Electric Cooperative
SERC
1, 3
3. M & A Electric Power Cooperative
SERC
1, 3
4. Northeast Missouri Electric Power Cooperative
SERC
1, 3
5. N.W. Electric Power Cooperative, Inc.
SERC
1, 3
6. Sho-Me Power Electric Cooperative
SERC
1, 3
Group
Erika Doot
Bureau of Reclamation
X
19.
Individual
Alshare Hughes
Luminant Generation Company, LLC
X
X
20.
Individual
Maryclaire Yatsko
Seminole Electric Cooperative, Inc.
X
X
21.
Individual
Reena Dhir
Manitoba Hydro
X
X
X
22.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
23.
Individual
David Jendras
Ameren
X
X
X
24.
Individual
John Seelke
Public Service Enterprise Group
X
X
X
25.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
26.
Individual
Kayleigh Wilkerson
Lincoln Electric System
18.
N/A
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Posted: December 5, 2014
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X
X
X
X
X
X
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10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
27.
Individual
2
3
4
5
6
Oliver Burke
Entergy Services, Inc.
Individual
29. Individual
John Merrell
Jamison Cawley
Tacoma Power
Nebraska Public Power District
X
X
X
30.
Individual
Brett Holland
Kansas City Power and Light
X
31.
Individual
Thomas Foltz
American Electric Power
X
X
X
X
32.
Individual
Sonya Green-Sumpter
South carolina Electric & Gas
X
X
X
33.
Individual
Amy Casuscelli
Xcel Energy
X
X
X
34.
Individual
Michael Moltane
ITC
35.
Individual
Steve Rueckert
Individual
Sergio Banuelos
Western Electricity Coordinating Council
Tri-State Generation and Transmission
Association, Inc.
37.
Individual
Muhammed Ali
Hydro One
38.
Individual
Anthony Jablonski
ReliabilityFirst
39.
Individual
Richard Vine
California ISO
40.
Individual
Spencer Tacke
Modesto Irrigation District
41.
Individual
Scott Berry
Indiana Municipal Power Agency
42.
Individual
John Brockhan
CenterPoint Energy Houston Electric, LLC
28.
36.
Consideration of Comments: Project 2010-13.3 – Phase 3 of Relay Loadability: Stable Power Swings
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X
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8
9
10
X
X
X
X
X
X
X
X
X
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X
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If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
Summary Consideration: The drafting team appreciates entities for supporting the comments of other entities rather than duplicating
the same or similar comments. Having single sets of comments with documented support greatly improves the efficiency of the
standard drafting team. This format also ensures the drafting team has a clearer picture of the number of industry stakeholders
supporting the same concerns or suggestions as the case may be. Please see the responses to the entity’s comments that are being
supported here.
Organization
Agree
Supporting Comments of “Entity Name”
Ameren
Agree
Ameren adopts the SERC PCS comments for PRC026-1
Lincoln Electric System
Agree
MRO NERC Standards Review Forum (NSRF)
Hydro One
Agree
NPCC - RSC
Indiana Municipal Power
Agency
Agree
Comments submitted by Public Service Enterprise
Group.
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1. The Protection System Response to Power Swings Standard Drafting Team believes it has addressed industry comments in such a
manner that industry consensus can be achieved. If there are remaining unresolved issues in the proposed PRC-026-1 Reliability
Standard, please provide your comments here:
Summary Consideration: The following summary discusses the most significant concerns by industry stakeholders. There were several
comments that resulted in the standard drafting team making clarifying revisions. There were a number comments that did not result
in revisions, in part, because the commenters were asking for feedback on a particular question.
The following summarizes the clarifying revisions made to the Standard beginning with the most notable first. Four comments
supported by 30 individuals reported various errors, inconsistencies, or requested clarifying enhancements. The standard drafting team
was able to address the vast majority of these observations resulting in a much improved Standard. Four comments supported by 19
industry stakeholder raised concerns about the phrase “become aware” in Requirement R2, Part 2.2. Concerns ranged from who would
initiate a review to find out whether or not a stable or unstable power swing was present, how auditors would interpret the phrase,
and how this phrase impacts Elements that trip when the entity reviews its Protection System operations. To address this, the standard
drafting team appended a footnote to reference the Guidelines and Technical Basis which provide examples that answer stakeholder
concerns. The phrase “become aware” was initially inserted into Requirement R2, Part 2.2 during draft 3 to make it clear that an entity
is not having to analyze every Protection System operation for a stable or unstable power swing. It is only when an entity “becomes
aware” of a power swing on an Element and that Element tripped in response to a stable or unstable power swing would the entity be
obligated to evaluate its load-responsive protective relays applied on that Element.
Five comments supported by 26 individuals continue to be concerned about the use of “unstable” in the Requirements. Some believe
the use of “unstable” over-reaches the Federal Energy Regulatory Commission (FERC) Order No. 733. Others believe it is unnecessary to
evaluate load-responsive protective relays for unstable power swing while others believe that the Standard is mandating that entities
set relays properly for unstable power swings. Because of these few remaining concerns, the standard drafting team appended a
justification to the end of the Guidelines and Technical Basis to illustrate the importance of having “unstable” as a criterion in the
Standard. The Requirements are constructed in a manner that the “unstable” power swing condition only determines that an Element
is susceptible along with stable power swings. An Element that trips on an unstable power swing is most likely subjected to numerous
stable power swings that may challenge the Protection System. By identifying these Elements, an entity can then evaluate its loadresponsive protective relays applied on these Elements and develop a Corrective Action Plan (CAP) when those relays are determined
not to meet the PRC-026-1 – Attachment B criteria. The use of “unstable” is not over-reaching the FERC Order No. 733 because the
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Requirements only mandate that an entity ensure their load-responsive protective relays are expected to not trip in response to a
“stable” power swing during non-Fault conditions.
Four comments supported by 20 stakeholders questioned the use of “one or more” in Requirement R3 regarding the two bulleted
items for developing a CAP. The standard drafting team notes that it is possible that both options may be performed to meet the
obligations for correcting any load-responsive protective relays that do not meet the PRC-026-1 – Attachment B criteria. After further
consideration, the standard drafting team concluded that it is acceptable to limit performance to one of the two available options to
achieve the reliability objective of the Standard; therefore, the “or more” phrase was eliminated to avoid confusion that only one bullet
had to be performed to be meet the Requirement.
Four comments supported by 19 individuals questioned the potential redundancy with the PRC-004-3 standard that addresses
Misoperation identification and correction of Protection Systems. The standard drafting team considered the connection between PRC004-3 and PRC-026-1 with regard to the Corrective Action Plan (CAP) at great length over the development of the Standard. In the case
where an Element trip occurs due to a stable power swing and the trip is identified as a Misoperation (under PRC-004-3) a single CAP is
permitted to satisfy both PRC-004 and PRC-026-1. However, in the broader sense, the CAP for PRC-026-1 is specifically intended to
ensure that load-responsive protective relays are expected to not trip in response to stable power swings during non-Fault conditions
and PRC-004 is intended to identify and correct the causes of Misoperations. In most cases, the action required under each standard
will remain separate and distinct whether included in one CAP or separate CAPs. The standard drafting team believes that entities are
able to administratively work around, from a compliance standpoint, any special nuances that arise for CAPs that address an identified
Misoperation whether due to a stable or unstable power swing and CAPs to meet the PRC-026-1 – Attachment B criteria.
Two comments by 12 individuals believed that FAC-014 is more appropriate for referencing established System Operating Limits (SOL)
by the Planning Coordinator than the FAC-010 Standard. The standard drafting team agreed with the comment that FAC-014 more
effectively represented the intent; therefore, updated the footnote to point to FAC-014, R3 that is specific to the Planning Coordinator
establishing SOLs.
Two comments supported by six stakeholders requested for Requirement R1, Criterion 3 that the word “where” be replaced with “only
if.” The standard drafting team agreed that it was clearer and did not change the intent of the Criterion. One comment by five
individuals reported various grammatical issues with text in the body of the standard, including the Guidelines and Technical Basis. The
standard drafting team agreed with many of the observations and made the corresponding corrections. Two individuals noted that the
use of “determine” in the main body of Requirement R2 was redundant with its use in Parts 2.1 and 2.2. The standard drafting team
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agreed that the use of “determine” in the main body of Requirement R2 could be eliminated without changing the intent. Single
comments that did result in a revision to the Standard are not summarized here and are responded to individually below.
The following summarizes comments made by stakeholders where the standard drafting team did not make any changes to the
Standard. Four comments supported by 21 individuals believe a standard is not necessary. The standard drafting team provided a
detailed explanation in the Consideration of Comments2 to Draft 1 of the Standard in the introductory remarks regarding the need for a
standard to meet regulatory directives. Two comments supported by 17 stakeholders do not believe the Requirement R1, Criterion 3
concerning islanding should be included. The standard drafting team noted that Requirement R1, Criterion 3 does not require the
Planning Coordinator to develop criteria for identifying islands. If the Planning Coordinator has criteria (i.e., as determined under PRC006) where the island is formed by tripping the Element due to angular instability, then the Planning Coordinator must notify the
respective Generator Owner and Transmission Owner. Further, the standard drafting team included this criterion to remain consistent
with the PSRPS Report 3 recommendation for facilities to consider.
Two individuals commented that the Planning Coordinator should provide information (e.g., impedance plots) for identified Elements
to the respective Generator Owner and Transmission Owner. The standard drafting team did not include any such requirement
because this information is not essential for an entity to determine whether its load-responsive protective relays meet the PRC-026-1 –
Attachment B criteria. Also, adding a Requirement for the exchange of information does not comport with the results-based standard
(RBS) structure. Moreover, a goal during standard development was to keep the burden low on all entities. This included not requiring
the Planning Coordinator to develop additional assessments or simulations. For the Generator Owner and Transmission Owner, to only
have to evaluate the set of Elements identified by the Planning Coordinator and any Elements that actually trip in response to a stable
or unstable power swing. Single comments that did not result in a revision are not summarized here and are responded to individually
below.
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NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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Organization
SERC Protection and
Controls
Subcommittee
Question 1 Comment
1) Please make R1, Criterion 3 clearer by replacing ‘where’ with ‘only if’. It then reads
“An Element that forms the boundary of an island in the most recent underfrequency load shedding
(UFLS) design assessment based on application of the Planning Coordinator’s criteria for identifying
islands, only if the island is formed by tripping the Element due to angular instability.”
Response: Change made.
2) Please expand Application Guidelines p20 explanation of Criterion 3 by adding, ‘PC area boundary tie
lines, or BA boundary tie lines’ at the end of the last sentence so that it reads “The criterion does not apply
to islands identified based on other considerations that do not involve angular instability, such as excessive
loading, PC area boundary tie lines, or BA boundary tie lines.”
Response: Change made.
3) R1 Criteria 3 and 4, and R2 2.2 identify BES Elements tripped for instability. The Standard’s Purpose is ‘To
ensure that load-responsive protective relays are expected to not trip in response to stable power swings
during non-Fault conditions.’ (Why do relays that trip on instability need to be evaluated and required to
meet this standard?) Please explain that these BES Elements are included because they could be more
likely to be challenged by power swings. Their inclusion does not mean that the relays tripping these
Elements were necessarily inappropriate. Such an explanation could fit well on page 18 just after “The first
step uses criteria to identify the Elements on which a Protection System is expected to be challenged by
power swings.”
Response: The standard drafting team has provided additional clarification in the Standard in the
Guidelines and Technical Basis section, “Justification for Including Unstable Power Swings in the
Requirements” why “unstable” is included.
The comments expressed herein represent a consensus of the views of the above-named members of the
SERC EC Protection and Control Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.
CenterPoint Energy
Houston Electric, LLC
(1) CenterPoint Energy still feels strongly that there is redundancy between PRC-004 and PRC-026
regarding Corrective Action Plans (CAPs) and must again vote negative. Redundancy is included in the
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Organization
Question 1 Comment
NERC Paragraph 81 (P.81) project as item “B7. Redundant”. Item “B7. Redundant” states the following:
“The Reliability Standard requirement is redundant with: (i) another FERC-approved Reliability Standard
requirement(s); (ii) the ERO compliance and monitoring program or (iii) a governmental regulation (e.g.,
Open Access Transmission Tariff, North American Energy Standards Board (“NAESB”), etc.). This criterion is
designed to identify requirements that are redundant with other requirements and are, therefore,
unnecessary. Unlike the other criteria listed in Criterion B, in the case of redundancy, the task or activity
itself may contribute to a reliable BES, but it is not necessary to have two duplicative requirements on the
same or similar task or activity. Such requirements can be removed with little or no effect on reliability and
removal will result in an increase in efficiency of the ERO compliance program.” Based on our
understanding, from responses to comments and also from the recent Q&A webinar, the SDT believes that
PRC-026 is more stringent than PRC-004; therefore, PRC-026 requirements for a CAP would supersede
those in PRC-004. Mainly, PRC-026 will require a CAP, whereas PRC-004 does not require a CAP if explained
“in a declaration why corrective actions are beyond the entity’s control or would not improve BES
reliability, and that no further corrective actions will be taken.” We believe such duplicative requirements
could send mixed signals where a CAP does not appear to be required (PRC-004) when, in fact, one is
required (PRC-026). Should standard PRC-026 be approved as currently written, CenterPoint Energy
recommends, due to redundancy, that NERC initiate a project to remove the requirement for a CAP for
Protection System operations from power swings in standard PRC-004.
Response: The standard drafting team considered the connection between PRC-004 and PRC-026 with
regard to the Corrective Action Plan (CAP) being redundant at great length over the development of the
standard. The standard drafting team notes that in the case where an Element trip occurs due to a stable
power swing and is identified as a Misoperation (under PRC-004-3) a single CAP is permitted to be
developed to satisfy both PRC-004 and PRC-026. However, in the broader sense, the CAP for PRC-026-1 is
specifically intended to ensure that load-responsive protective relays are expected to not trip in response to
stable power swings during non-Fault conditions and PRC-004 is to identify and correct the causes of
Misoperations of Protection Systems for Bulk Electric System (BES) Elements. In most cases, the action
required for each standard will remain separate and distinct whether included in one CAP or separate CAPs.
(2) CenterPoint Energy technically disagrees with the SDT’s response that operator-initiated switching to
reconnect islands, to restore load during Black Start activities, or to synchronize a generating unit to the
system should be applicable to PRC-026. We believe that any Element that tripped in response to a stable
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Question 1 Comment
or unstable power swing involving restoration and black-starting would be addressed in after-action
reviews of those events. We expect that entities will need to coordinate with their Regional Entities to
address such circumstances.
Response: The standard drafting team concluded exclusions for system restoration or black‐starting should
not be provided because it could be detrimental to reliability. Any Element that tripped in response to a
stable or unstable power swing must be addressed, especially involving restoration and black‐starting
because those are conditions where power swings would be expected and it is critical that load‐responsive
protective relays are secure for stable power swings. No change made.
ACES Standards
Collaborators
(1) The drafting team has continued improving this standard and we thank you for the improvements.
Response: The standard drafting team thanks you for your comment.
(2) We question the need for this standard. In its “Protection System Response to Power Swings” (on page
5) document dated August 2013, the NERC System Protection and Control Subcommittee (SPCS) concluded
“that a NERC Reliability Standard to address relay performance during stable power swings is NOT needed,
and could result in unintended adverse impacts to the Bulk-Power System reliability” [emphasis added].
Response: The standard drafting team thanks you for your comment and provided a detailed explanation
in the Consideration of Comments 4 to Draft 1 of the Standard in the introductory remarks regarding the
need for a standard to meet regulatory directives.
(3) The footnote in criterion 2 for Requirement R1 is technically inaccurate and should be modified. An
Element would be identified through the application of the PC’s SOL methodology which is required in FAC014-2 not FAC-010. The methodology must be developed in FAC-010 but application is required in FAC-0142 R3 and R4.
Response: The standard drafting team agrees that using “FAC-014-2, Requirement R3” more clearly
describes the Planning Coordinator establishing a System Operating Limit or SOL. Clarification made.
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Organization
Question 1 Comment
(3) Why is the word “full” added to “six full calendar months”? We think it only adds confusion in other
areas where it is not included. The words six calendar months imply the inclusion of a “full” calendar
month.
Response: The standard drafting team added the clarifier “full” based on previous comments received in
early postings of the standard to be clear that partial months are not counted. For example, if the starting
point is in the middle of a calendar month, the entity will have until the end of the last month of the stated
period. No change made.
(4) Requirement R4 should be modified to avoid a registered entity being in technical violation for simply
updating their Corrective Action Plan (CAP). As it is written, the applicable entity must both implement the
CAP and update the CAP. The problem is that they may be updating the CAP because implementation on
the original timeline is not possible. As R4 is written with an “and” condition, this is not possible without a
technical violation of the requirement. We suggest changing the second “and” to “or” to address this
concern.
Response: The standard drafting team contends that the primary action in Requirement R4 is to implement
the Corrective Action Plan (CAP). The clause after the “and” is conditional based on the entity changing
actions or timetables. No change made.
(5) Criterion 4 of Requirement R1 requires further explanation. In response to our previous comment
questioning the inclusion of unstable power swings in criterion 4 of Requirement R1, the drafting team
stated that “this standard does not require that entities assess Protection System performance during
unstable swings.” If this is the case, this would support removing “unstable power swings” from criterion 4.
What reliability purpose does the PC notifying the GO and TO of Elements susceptible to unstable power
swings serve, if the GO and TO are not required to do anything with the information.
Response: The standard drafting team has provided additional clarification in the Standard in the
Guidelines and Technical Basis section, “Justification for Including Unstable Power Swings in the
Requirements” why “unstable” is included.
(6) Any VRFs that are greater than Lower would seem to be inconsistent with the recommendation of the
SPCS (see our point two for the recommendation) that a standard is not needed. Especially, assigning
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Question 1 Comment
Requirement R2 a VRF of High would seem to a complete rejection of this recommendation. Is this what is
intended by the drafting team?
Response: The standard drafting team assigned a VRF of High to Requirement R2 because the standard is
narrowly focusing performance of a sub-set of BES Elements and not all load-responsive protective relays.
The failure to evaluate that the Protection System is expected to not trip in response to a stable power
swing during a non‐Fault condition for a BES Element could contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable
risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Therefore, Requirement R2 meets a VRF assignment of High and NERC guidance on determining VRFs. Also,
other standards that address similar forms of evaluations for Generator Owners and Transmission Owners
have VRFs assignments of High. No change made.
(7) Should Requirement R3 allow selection of “one or more of the following” or should it be limited to
selecting one option? In other words, can a Protection System meet both Criteria A and B simultaneously?
If not, then “one or more of the following” should be changed to “either of the following.”
Response: The standard drafting team notes that in certain cases an entity may perform either or both to
meet the Requirement. The Requirement was revised to state “one of the following.” Clarification made.
(8) We do not understand why unstable power swings are included in Part 2.2. Per the purpose statement
of the standard and the drafting’s prior response to comments (see our bullet 5), the purpose is to prevent
tripping of protective relays in response to stable power swings. It is not intended to prevent tripping due
to unstable power swings. Thus, why would Part 2.2 compel an evaluation of load-responsive relays for
actual tripping due to unstable power swings?
Response: The standard drafting team has provided additional clarification in the Standard in the
Guidelines and Technical Basis section, “Justification for Including Unstable Power Swings in the
Requirements” why “unstable” is included.
(8) Thank you for the opportunity to comment.
South carolina Electric
& Gas
1) Please make R1, Criterion 3 clearer by replacing ‘where’ with ‘only if’. It then reads
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Organization
Question 1 Comment
“An Element that forms the boundary of an island in the most recent underfrequency load shedding
UFLS) design assessment based on application of the Planning Coordinator’s criteria for identifying
islands, only if the island is formed by tripping the Element due to angular instability.”
Response: Change made.
2) Please expand Application Guidelines p20 explanation of Criterion 3 by adding, ‘PC area boundary tie
lines, or BA boundary tie lines’ at the end of the last sentence so that it reads “The criterion does not apply
to islands identified based on other considerations that do not involve angular instability, such as excessive
loading, PC area boundary tie lines, or BA boundary tie lines.”
Response: Change made
3) R1 Criteria 3 and 4, and R2 2.2 identify BES Elements tripped for instability. The Standard’s Purpose is ‘To
ensure that load-responsive protective relays are expected to not trip in response to stable power swings
during non-Fault conditions.’ (Why do relays that trip on instability need to be evaluated and required to
meet this standard?) Please explain that these BES Elements are included because they could be more
likely to be challenged by power swings. Their inclusion does not mean that the relays tripping these
Elements were necessarily inappropriate. Such an explanation could fit well on page 18 just after “The first
step uses criteria to identify the Elements on which a Protection System is expected to be challenged by
power swings.”
Response: The standard drafting team has provided additional clarification in the Standard in the
Guidelines and Technical Basis section, “Justification for Including Unstable Power Swings in the
Requirements” why “unstable” is included.
Duke Energy
“Duke Energy would like to reiterate that we do not believe adequate technical justification has been
identified for this project to become a standard. Based on the SPCS recommendation, the SDT and NERC
should consider moving this project to a Guideline document until such time as a standard is warranted.”
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Organization
Question 1 Comment
Response: The standard drafting team thanks you for your comment and provided a detailed explanation
in the Consideration of Comments 5 to Draft 1 of the standard in the introductory remarks regarding the
need for a standard to meet regulatory directives.
Associated Electric
Cooperative, Inc.
AECI believes that the term unstable power swing should be removed from this standard. Reliability risks
associated with unstable swings are already handled with relay protection (PRC) and system study
standards (TPL). FERC ordered this drafting team to address issues associated with stable power swings,
and the addition of unstable swings in the language is unwarranted. In the previous round of commenting
the SDT responded by stating this inclusion was inherent in statements made in the PSRPS report. I would
encourage the SDT to also read the following statement from page 19 of that same report, “overemphasizing secure operation for stable powers swings could be detrimental to Bulk-Power System
reliability.” By including unstable power swings within the screening process of R1 more events will qualify
for testing and the SDT will have done the very thing the SPCS warned against. An unwarranted emphasis
on stable power swings is created when you use unrelated events like unstable swings to define your
testing criteria for stable swings. AECI would respectfully request the drafting team removed “unstable”
from PRC-026 and keep stable and unstable power swing standards as completely separate as possible, or
provide the reliability based risk that exists without the inclusion of this term within the standard.
Response: The standard drafting team has provided additional clarification in the Standard in the
Guidelines and Technical Basis section, “Justification for Including Unstable Power Swings in the
Requirements” why “unstable” is included.
DTE Electric Co.
Agree with PSEG comments. The current draft does provide more detailed evaluation basis and examples,
however, not all variations in protection schemes are addressed which could result in misapplication of the
evaluation criteria.
Response: Please see our response to PSEG. The standard drafting team believes that it has provided
sufficient examples to understand the application of the evaluation criteria. It is not possible to provide an
example for every permutation of a protection system.
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Xcel Energy
Question 1 Comment
Although the latest draft of PRC-026 is an improvement, Xcel Energy feels that there are additional
opportunities for improvement. We respectfully submit the following comments for the drafting team’s
consideration. A new Requirement should be added requiring the PC to provide the system separation
angle as part of the notification in order to ensure proper calculation of relay settings. Suggested wording:
[Each Planning Coordinator shall provide notification of the system separation angle of each
identified BES Element(s) in its area that met any of the Criteria in R1, if any, to the respective
Generator Owner and Transmission Owner.]
Response: The standard drafting team chose to use the industry accepted 120 degree separation angle as a
screening criterion in order to avoid creating an undue burden on the Planning Coordinator by having to do
dynamic studies for every element identified in Requirement R1. Note that PRC-026-1 – Attachment B allows
“an angle less than 120 degrees where a documented transient stability analysis demonstrates that the
expected maximum stable separation angle is less than 120 degrees.” This analysis could be performed by
an entity other than the Planning Coordinator. No change made.
Additionally, the 1.05 V Pu voltage is subjective and not based on a study, and contradicts what the GTB
says about the AVR:
“it is more likely that the relay would operate during a power swing when the automatic voltage
regulator (AVR) is in manual mode rather than when in automatic mode.”
The statement would lead one to believe that
1- The GO is operating in manual mode in contrast to the VAR standards.
2 - That operating in manual mode would keep the unit voltage at 1.05 pu, which is inherently false.
Therefore, the calculations in GTB are hypothetical and should not be in a standard, as they provide
no reliability assurance.
Response: The standard drafting team notes that the AVR may be operated in the manual mode under
specific circumstances stated in VAR 002-3 (Requirement R1 and R3). Although operating the AVR in manual
mode is not a desired state, VAR 002-3 allows for operation of the AVR in manual mode as directed by the
Transmission Operator, during AVR testing, or during unit shutdown. It is also possible that the AVR could be
operated in manual mode due to equipment failure (AVR controller failure, generator voltage transformer
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fuse failure, etc.). It is under these AVR operating scenarios that operating under manual mode with a
system perturbation will be most likely to cause a loss of field relay trip during a stable power swing.
The reference to 1.05 per unit generator voltage is used to establish a minimum pickup current value for
overcurrent relays that are set at or below 15 cycles. The sending and receiving end voltages are established
at 1.05 per unit at 120 degree separation. The reference from the Guidelines and Technical Basis is an
excerpt from an explanation of the loss-of-field relays and not the overcurrent relays. The generating unit
AVR may be operating in "auto" and at this upper voltage level.
The reference to FAC-10 in R1 Criterion 2 does not appear to be consistent with its intent since the
Planning Coordinator’s methodology per se does not identify/establish the SOLs… instead, they are
determined based on applying the methodology, which is required in FAC-014-2.
Therefore, assuming there is value in retaining a reference in Criterion 2, it should probably be changed to
R3 of FAC-014 that requires SOLs to be established by the Planning Coordinator. Or the reference could be
changed to R6 of FAC-014, which specifically pertains to identifying the stability limit SOLs. However, it may
be sufficient to have no reference in Criterion 2 as follows:
“Monitored elements that are part of (angular) stability limit SOLs determined by the Planning
Coordinator.”
Response: The standard drafting team agrees that using “FAC-014-2, Requirement R3” more clearly
describes the Planning Coordinator establishing a System Operating Limit or SOL. Clarification made.
American Electric
Power
Applicability, Section 4.2 (Facilities):
Despite the changes proposed in this most recent draft, our interpretation is the same as it was for the
previous version. That being the case, we’re not certain the proposed changes are serving their intended
purpose. Could the team provide some insight into what they were trying to clarify or correct with their
most recent changes to this section?
Response: The standard drafting team revised this phrase in response to comments in quality review to use
phrasing that is consistent with other Reliability Standard applicability sections. There is no change to the
intent or meaning of Section 4.2.
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Question 1 Comment
R2 and R2.1: Collectively, these requirements read awkwardly due to multiple uses of the word
“determine”. We suggest eliminating the first “determine”, so that R2 instead reads “Each Generator
Owner and Transmission Owner shall:”.
Response: The standard drafting team agreed with the suggestion and that removing the first occurrence
of “determine” does not substantively change the intent of the requirement as it pertains to Requirement
R2, Parts 2.1 and 2.2.
Public Service
Enterprise Group
As explained below, we believe there are two unresolved issues.
Background
PRC-004-3 overlaps PRC-026-1 in several areas. In PRC-004-3, GOs and TOs examine each operation its BES
interruption devices to identify Misoperations. Under R5, they must develop a Corrective Action Plan (CAP)
unless they “Explain in a declaration why corrective actions are beyond the entity’s control or would not
improve BES reliability, and that no further corrective actions will be taken.” In the process of
implementing PRC-004-3, “correct operations” are also identified (i.e., interrupting device operations
where a Misoperation DID NOT occur), but PRC-004-3 imposes no requirements on correct operations.
Misoperations
A relay operation during a stable power swing under subpart 2.2 of PRC-026-1 is a Misoperation reportable
under PRC-004-3 and subject to a CAP under R5. This same relay operation would be subject to a CAP
under R3 of PRC-026-1. In addition, the CAP timelines are different (60 days to develop a CAP in PRC-004-3
and six months to develop it in PRC-026-1). Two standards should not contain requirements that apply to
the same Misoperation. To avoid this, we recommend that a new subpart 3.1 should be added in PRC-0261 as follows:
R3.1 The development of a CAP pursuant to Requirement R3 shall supersede the requirements for a
Generator Owner or Transmission Owner to develop and implement a CAP for a Misoperation
pursuant to NERC Reliability Standard PRC-004.
Response: The standard drafting team considered the connection between PRC-004 and PRC-026 with
regard to the Corrective Action Plan (CAP) being redundant at great length over the development of the
standard. The standard drafting team notes that in the case where an Element trip occurs due to a stable
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power swing and is identified as a Misoperation (under PRC-004-3) a single CAP is permitted to be
developed to satisfy both PRC-004 and PRC-026. However, in the broader sense, the CAP for PRC-026-1 is
specifically intended to ensure that load-responsive protective relays are expected to not trip in response
to stable power swings during non-Fault conditions and PRC-004 is to identify and correct the causes of
Misoperations of Protection Systems for Bulk Electric System (BES) Elements. In most cases, the action
required for each standard will remain separate and distinct whether included in one CAP or separate
CAPs.
Correct operations
Subpart 2.2 of PRC-026-1 also requires knowledge of correct relay operations due to an unstable power
swing. As explained above, this information is directly derived from PRC-004-3, but performing a power
swing analysis for each correct relay operation would be very burdensome to meet subpart 2.2. The
“becoming aware of” language in subpart 2.2 is explained in the Application Guidelines on p. 22 of the
standard. This explanation removes the onus of an entity being required to examine each relay operation
for the presence of a power swing. We recommend the standard add a footnote to subpart 2.2 that states:
“See p. 22 for an explanation of implementing the “becoming aware” language in subpart 2.2.” Because a
guideline is not enforceable, such a footnote would tie this guideline language solidly to subpart 2.2.
Response: The standard drafting team agrees that placing a cross reference in a footnote to the guidelines
will provide increased awareness of where examples can be found. A reference to the Guidelines and
Technical Basis concerning “becoming aware” footnote has been appended to Requirement R2, Part 2.2.
However, the addition of the footnote only serves to increase the visibility of where an entity can find
examples. It does not make the information in the guideline part of the enforceable requirement.
Dominion
As mentioned in the Webinar, the upper loss of synchronism circle is based on the ratio of sending-end to
receiving-end voltage of 1.43. Looking at the REDLINE copy of PRC-026-1 draft 3, this should be revised in
several places,
Revisions
Page 19 of 98: “ [...] (2) an upper loss-of-synchronism circle based on a ratio of the sending-end to
receiving-end voltages of 1.43”
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Page 31 of 98: “The second shape is an upper loss of synchronism circle based on a ratio of the sending-end
to receiving-end voltage of 1.43 (i.e., ES / ER = 1.0 / 0.7 = 1.43).”
Page 32 of 98: “Eq. (3): E_S/E_R =1.0/0.7=1.43”
Page 37 of 98: “Shape 2 - Upper Loss of Synchronism Circle With Sending to Receiving Voltage Ratio of
1.43”
Page 72 of 98: Table 13 should have an example calculation where ES < ER for the lower loss of
synchronism circle and an example calculation where ES > ER for the upper loss of synchronism circle. As
discussed with Kevin Jones at Xcel Energy, a revision of Figure 5, on page 41 of 98, changing “Voltage (p.u.)”
to the voltage ratio of “ES/ER”, where the ratio extends from 0.7 to 1.43, would align nicely with the edits
above.
Response: Excellent catches on the errors. The standard drafting team has made the above corrections.
American
Transmission
Company, LLC
ATC accepts the SDT changes.
Kansas City Power and
Light
Attachment A
Response: The standard drafting team thanks you for your comment.
The following protection functions should also be excluded from the Requirement of this standard:
Phase distance relay elements that do not reach beyond the next bus.
Loss-of-field relay elements that do not reach beyond the generator impedance.
Response: The standard drafting team contends that all impedance elements with a time delay of less than
15 cycles must be evaluated against the PRC-026-1 – Attachment B criteria. For example, a long
transmission line with strong sources at each end could result in a Zone 1 relay tripping on a stable power
swing, if the relay is not set according to the PRC-026-1 – Attachment B criteria. Even a relay that does not
reach beyond the next bus could have a characteristic that is outside the unstable power swing region. No
change made.
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Entergy Services, Inc.
Question 1 Comment
Based on the information contained in the SPCS Power Swing Report Dated August 2013, there is
insufficient evidence contained in the historical study cases identified, to warrant implementation of the
proposed PRC-026-1 standard.”
Response: The standard drafting team thanks you for your comment and provided a detailed explanation
in the Consideration of Comments 6 to Draft 1 of the standard in the introductory remarks regarding the
need for a standard to meet regulatory directives.
Tennessee Valley
Authority
Based on the proposed implementation plan, it seems that the applicable GO and TO will not be required
to perform an initial R2.1 evaluation until the second annual notification is received from the PC. Suggest
making the “12 months” in the R1 implementation statement “24 months” unless a practice year was
intended for the PC requirement.
Response: The implementation plan is designed such that the Planning Coordinator will begin notifying the
respective Generator Owners and Transmission Owners of any Elements in Requirement R1 based on the
effective date language. The 36 months for the Generator Owner and Transmission Owner in Requirement
R2 (and Requirements R3 and R4) to become compliant is intended to allow the entity an opportunity to
address the initial influx of identified Elements in Requirement R1. There is no obligation on the Generator
Owner or Transmission Owner to perform Requirement R2, R3, or R4 until the effective date of these
Requirements. Although there is no compliance obligation during the 36 month implementation period, an
entity will have the full obligation of Requirements R2, R3, and R4 following the 36 month period. The 36
month implementation period also allows an opportunity for the entity to establish the evaluation of loadresponsive protective relays pursuant to Requirement R2 which will provide the point in time that the five
year re-evaluation of such relays will occur. “No change made.
Consider making the implementation date for R3 and R4 lag the implementation date of R2 by six months.
The R3 requirement allows for six months to develop a CAP following completion of work associated with
R2.
6
http://www.nerc.com/pa/Stand/Project%202010133%20Phase%203%20of%20Relay%20Loadability%20stabl/Project_2010_13.3_Consideration_of_Comments_
2014_08_22_to_Draft_1.pdf.
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Response: The standard drafting team notes that in order to begin measuring the six months required as
part of the performance in Requirement R3, the requirement itself must be “active.” Because there is six
months built into the performance of the requirement, the implementation plan would not reflect this
timing aspect since the implementation timing has to do with when the requirement becomes effective
(i.e., active). The dates have been aligned to accomplish this and entities still have the full six months lag in
the requirement before performance would be due. Adding this to the implementation timing would only
serve to misalign the timing needed. Requirement R4 begins upon development of the Corrective Action
Plan in Requirement R3; therefore, Requirement R4 must become “active” at the same time as
Requirement R3. No change made.
To align with the change made to requirement R2 regarding evaluations performed in the last five calendar
years, consider making the effective date of R2 the “First day of the first full calendar year that is 60
months after the date....”Page number references in the following comments apply to the redline posting.
Response: The additional time for Requirement R2 to become effective in the implementation plan is
provided to handle the initial influx of notifications and identifications of Elements by the Planning
Coordinator. The five-year interval is based on the anticipated amount of time before system changes
would require re-evaluation of protective relays. The standard drafting team concluded that a five year
implementation period was too long and that three years provides adequate time to evaluate the initial
influx of notifications and identifications of Elements by the Planning Coordinator. The team considered the
60 months requested and determined that three years is sufficient time to handle the influx of
notifications. No change made.
Page 19: Within the “Rationale for Attachment B (Criteria A)” box shaded blue, should “... varying from 0.7
to 1.0 per unit...” be changed to “varying from 0.0 to 1.0 per unit...” to match the change made in the
preceding Criteria A section?
Response: The standard drafting team notes that the union of the lens with the two circles limits the
voltage range of the unstable power swing region’s boundary from 0.7 to 1.0. No change made.
Page 24: In the Requirement R1 section, recommend replacing the last sentence with “It is possible that a
Planning Coordinator will utilize prior year studies in determining their requirement R1 Elements list each
year.”
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Response: Change made.
Page 25: In the Requirement R1, Criterion 1 section, suggest changing
“The 66 kV transmission line is not electrically joined to the 345 kV and 230 kV transmission lines at
the plant site and is not a part of the operating limit or RAS.”
to
“The 66 kV transmission lines are not electrically joined to the 345 kV and 230 kV transmission lines
at the plant site and are not a part of the operating limit or RAS.” since there is more than one 66 kV
line in the example.
Response: Change made.
Page 25: In the Requirement R1, Criterion 2 section, since the acronym SOL is now spelled out in the
Criterion 1 section, the acronym can be used in the Criterion 2 section without spelling it out.
Response: The standard drafting team notes that because a reader may go directly to Criterion 2 without
reading the preceding section and may not know what is meant by the acronym SOL, the full phrase is
used. No change made.
BC Hydro
BC hydro does not agree with the proposed new reliability standard PRC-026-1. In the past 15 years with
approximately 1000 faults per year on the transmission system, there has not been a single undesired
protection operation on a stable power swing. There have been some protection operations on power
swings, but they were desirable, and separated systems that were about to go out of step. BC Hydro has a
very large portion of its transmission system that is subject to stability constraints. Therefore, even the
focussed approach proposed in the new standard will present a significant amount of engineering
resources to perform the stability checks and protection response checks to determine whether setting
modifications or addition of power swing blocking relays or whether exemptions are required. BC Hydro
recommends that the new standard not be implemented, or if it is implemented, that the WECC region be
exempted in view of the fact that the transmission network is sparse, with many stability constraints. The
work required to meet this standard will be excessive, even with the focussed approach proposed.
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Response: The standard drafting team is addressing Federal Energy Regulatory Commission (FERC) Order
No. 733 directives to address stable power swings. The standard is using an equally effective and efficient
approach in addressing the directive by implementing the narrow focus recommended by the NERC System
Protection and Control Subcommittee technical report on a continent-wide basis. The standard drafting
team recognizes that there will be cases where Reliability Standards impact one entity more significantly
that others when addressing certain risks. No change made.
Bonneville Power
Administration
BPA has no unresolved issues.
ITC
Edit R2.2 to include, “...due to the operation of its protective [functions described in Attachment A],
determine...”
Response: The standard drafting team thanks you for your comment.
Response: The standard drafting team contends that “due to the operation of its protective relay(s)” is the
proper phrase. Any relay trip in response to a power swing is an indication that the Element has
experienced a power swing significant enough to warrant evaluation of the Element’s load responsive
relays. No change made.
Modern relays which enable power swing blocking functions result in time-delayed clearing for subsequent
3 phase faults. E.g. SEL-411L manual states “Three-phase faults will be detected with a minimum and
maximum time delay of two and five cycles, respectively.” More conventional power swing blocking
functions result in time delays much longer than 5 cycles, possibly exceeding 1 second. Does the SDT
believe this is “dependable fault detection”?
Response: The standard drafting team notes that the Guidelines and Technical Basis provides information
on this phrase. The determination of “dependable fault detection” and acceptable tripping delay is outside
the scope of this standard and should be governed by other existing reliability standards and industry
practices. No change made.
Does the SDT believe this contributes to the reliability of the BES?
Response: The standard drafting team contends that installing out of step blocking normally promotes
reliability of the BES. If the application of power swing blocking using a particular type of protection
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scheme can be shown to degrade reliability for a given location, other alternatives should be considered to
meet the requirements of this standard. No change made.
Edit page 79, “Double blinder schemes are more complex [than] the single...”
Response: The standard drafting team corrected the error.
R1 Criteria 3 remains unclear. PRC-006 does not seem to require the level of detail required for PCs to meet
this requirement. Our concerns are that PCs will commit much more resources to developing this level of
detail or absent that level of detail will identify all or none of the boundary elements as meeting this
criteria.
Response: The standard drafting team contends that it is up to the discretion of the Planning Coordinator
as to whether it addresses angular stability under PRC-006-1 – Automatic Underfrequency Load Shedding.
No change made.
Western Electricity
Coordinating Council
I don't have any concerns with the standard as drafted. However, you may wish to make a gramatical
review of the language of R2. the word "determine" is included in the language of R2 (last word) as well as
in Parts 2.1 and 2.2. It seems like it is not needed both times.
Response: The standard drafting team agreed with the suggestion and that removing the first occurrence
of “determine” does not substantively change the intent of the Requirement as it pertains to Requirement
R2, Parts 2.1 and 2.2.
Tacoma Power
In general, Tacoma Power agrees that the Power Swings Standard Drafting Team has addressed industry
comments in such a manner that industry consensus can be achieved. However, Tacoma Power does have
some other relatively minor suggestions. (In general, these comments were identified by reviewing the
draft with redlines.)
1. Consider modifying Requirement R3 as follows. Change “...does not meet the PRC-026-1 - Attachment B
criteria...” to “...does not meet the PRC-026-1 - Attachment B criteria pursuant to Requirement R2...” This
may be implied, but the language in Requirement R3 does not tie back to Requirement R2.
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Question 1 Comment
Response: The standard drafting team agrees with the suggestion that it adds clarity that Requirement R3
is contingent upon Requirement R2. Clarification made.
2. In the Rationale for R3, it seems like the reference to Requirement R2 should be a reference to
Requirement R3.
Response: The standard drafting team agrees and has corrected the reference.
3. The criteria headings in Attachment B should read as Criterion A and Criterion B.
Response: Change made.
4. Under Attachment B, Criterion B, Condition 2, all transmission BES Elements cannot be in their normal
operating state if the parallel transfer impedance has been removed. It is understood that all transmission
BES Elements would be in their normal operating state with the exception that the parallel transfer
impedance should be removed.
Response: The standard drafting team notes that “…all transmission BES Elements are in their normal
operating state…” when calculating the system impedances (i.e., sending-end, receiving-end, and parallel
transfer impedance). The parallel transfer impedance is then removed when evaluating the Element
pursuant to the criteria.
Ingleside
Cogeneration LP
Ingleside Cogeneration L.P. (ICLP) has carefully read through the latest draft of PRC-026-1 and its
supporting documents, but still must deliver a “No” vote. We fully understand the regulatory need to
adhere to FERC’s December 31 deadline, but believe that the intent of the drafting team is not captured in
the enforceable parts of the standard itself.
On a positive note, this means that we believe that the technical aspects of PRC-026-1 are sound - which
means that the most difficult work has been performed. ICLP would like to compliment the project team on
their ability to construct a process that narrows the universe of load relays that may improperly react to
stable power swings, offsetting the arguments that the standard does not serve a reliability purpose.
However, several key logistical issues remain. In our view, if these remain uncorrected, we cannot be sure
that CEAs will administer the standard evenly across all eight Regions.
Our specific recommendations are as follows:
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1) There must be clarity in the methods used to identify load relay that react improperly to a stable or
unstable power swing. The project team has articulated in their Consideration of Comments that Events
Analysis and/or a PRC-004 Misoperation study are the triggers that they visualize. However, these concepts
are not binding to CEAs - who we believe will demand evidence that every load relay trip was investigated
and proved to be not-applicable. In addition, a TO or GO who does not properly identify a stable or
unstable power swing will be held in violation of PRC-026-1. This is not a capability or expertise that
equipment owners possess, and should not be held accountable for.
The project team resolved a similar issue by adding a footnote reference to FAC-010 in R1, and ICLP
believes that the same could be done for R2. The footnote would simply capture the fact that the
potentially deficient load relay would be identified through the Events Analysis process and/or a
Misoperation study.
Response: The standard drafting team notes although it cannot address the consistency in auditing across
the regions; however, the drafting team appended a footnote to Requirement R2, Part 2.2 to reference the
Guidelines and Technical Basis concerning “becoming aware.” This will serve to increase the reader’s
awareness of the intent of this phrase. Requirement R2, Part 2.2 is structured where the stable or unstable
power swing must be identified that is connected with the entity’s Element tripping to avoid the need to
address all Element trips. The explanation and examples in the Guideline referenced through the footnote
remain explanatory only and are not part of the mandatory requirement. The NERC standard developer will
also share this comment with the RSAW development team for further consideration of clarifying notes in
the RSAW. Clarification made.
2) The project team has made it clear that a trip in response to an unstable power swing is a screening
factor - not a deficient condition. However, no change has been made despite multiple requests to do so.
Perhaps the project team believes that there is already sufficient clarity in the requirements, but ICLP
disagrees. As written, we believe that some CEAs will demand corrective action in response to an unstable
power swing - an improper use of scarce resources better applied elsewhere. A modification to R2 to
address the screening intent of unstable power swings can be easily done in order to avoid this situation.
Response: The standard drafting team notes that Requirement R2 drives the evaluation of load-responsive
protective relays for BES Elements that have been identified by Requirement R2, Parts 2.1 and 2.2 (stable
or unstable power swings). Requirement R3 requires the entity to meet the performance where the load-
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responsive protective relay is expected to not trip in response to a stable power swing by meeting PRC-0261 – Attachment B criteria (i.e., stable power swings only). If the criteria is not met, the entity must develop
a Corrective Action Plan (CAP) that meets the conditions in Requirement R3. No change made.
Nebraska Public
Power District
It is clear the drafting team has put a great amount of effort into this standard which is quite complex. This
effort is appreciated. Comments for consideration:
R2.2 states: Within 12 full calendar months of becoming aware of a generator, transformer, or transmission
line BES Element that tripped in response to a stable or unstable power swing due to the operation of its
protective relay(s), determine whether its load-responsive protective relay(s) applied to that BES Element
meets the criteria in PRC-026-1 - Attachment B. R2.2 hinges on “becoming aware” which seems will be
difficult to prove or audit. The drafting team felt that it is not needed to prove how an entity addresses
“becoming aware” but the RSAW indicates that an auditor should “(R2) Interview an entity representative
to understand the entity’s process for identifying applicable load-responsive protective relays applied on
the terminals of the BES Elements identified pursuant to Requirement R2, Parts 2.1 and 2.2”. R2.2 seems to
be a very vague and unpredictable part to R2. The standard would be much cleaner without 2.2.
Response: The standard drafting team agrees that placing a cross reference in a footnote to the guidelines
will provide increased awareness of where examples can be found. A reference to the Guidelines and
Technical Basis concerning “becoming aware” footnote has been appended to Requirement R2, Part 2.2.
However, the addition of the footnote only serves to increase the visibility of where an entity can find
examples. It does not make the information in the guideline part of the enforceable requirement.
Requirement R2, Part 2.2 is important to reliability because it addresses actual events. This part is also
consistent with the PRSRP Report 7 recommendation.
A trip on a stable power swing will most likely be a misoperation and will be addressed per other NERC
standards (e.g. PRC-004, PRC-016). A trip on an unstable power swing may or may not be a misoperation
depending on if the relaying was set to trip for OOS or not. It seems the only benefit to 2.2 then is to
7
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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identify correct trips for unstable swings and this does not seem to add significant reliability compared to
the burden and audit risks. Consider removal of 2.2.
Response: The standard drafting team has provided additional clarification in the Standard in the Guidelines
and Technical Basis section, “Justification for Including Unstable Power Swings in the Requirements” why
“unstable” is included.
The standard drafting team considered how the determination of Misoperations interacts with the PRC026-1 standard. PRC-004 addresses the identification and correction of Misoperations and PRC-026-1
addresses Elements that have tripped in response to stable or unstable power swings, and if so, evaluate
load-responsive protective relays to ensure these relays are expected to not trip in response to stable
power swings according to the PRC-026-1 – Attachment B criteria. The action required for each standard
will remain separate and distinct whether included in one CAP or separate CAPs.
Requirement R2, Part 2.2 is important to reliability because it addresses actual events. This part is also
consistent with the PRSRP Report 8 recommendation.
During the 11-13-2014 webinar some concerns were noted regarding the guidelines and technical basis
equations and calculations. Since a significant portion of this document is devoted to calculations it is
beneficial these be as accurate as possible since it will be a part of compliance. Any reevaluations and
rechecks of these calculations are greatly appreciated. There is concern with voting yes until the final
checks can be made.
Response: The standard drafting team notes that comments from Dominion, herein, provide comments on
the errors discussed during the November 13, 2014 Questions and Answers session held by the standard
drafting team. These errors were addressed with the help of Dominion staff.
In addition to these comments, we also support the comments submitted by SPP.
Response: The standard drafting team thanks you for supporting the comments of others. Please see the
responses to the SPP Standards Review Group.
8
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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Luminant Generation
Company, LLC
Question 1 Comment
Luminant continues to believe that including unstable power swings in the draft standard goes beyond
FERC Order 733. Luminant understands that adding unstable power swings in the Requirement only
requires the Generator Owner to be compliant with the criteria in Requirement R3 (Attachment B) for any
of the load-responsive relays in Attachment A. However, Requirement R1 (part 4) provides information to
the Generator Owner that some units may be subject to an out-of-step condition and action on their part
may be necessary to enable generator out-of-step protection. Luminant recommends that either
“unstable” be removed from the standard in all requirements or add language to Measure M1 for the
Planning Coordinator to provide information (for example, impedance plots) to the Generator Owner that
describe the location of the electrical center for an out-of-step condition.
Response: It is important to note that this standard does not require that entities assess Protection System
performance during unstable swings and does not require entities to prevent tripping in response to
unstable swings. Such requirements would exceed the directive stated in the Federal Energy Regulatory
Commission (FERC) Order No. 733. This standard focuses on the identification of Elements by the Planning
Coordinator (Requirement R1) and Elements where the Generator Owner or Transmission Owner becomes
aware of an Element that tripped in response to a stable or unstable power swing (Draft 3, Requirement R2,
2nd bullet). Requirements R1 and R2 (2nd bullet) is a screen to identify Elements that are subject to the
Requirements of the standard.
The standard drafting team has provided additional clarification in the Standard in the Guidelines and
Technical Basis section, “Justification for Including Unstable Power Swings in the Requirements” why
“unstable” is included.
The standard drafting team chose not to include communication requirements between the Generator
Owner and Transmission Owner for the exchange of impedance plot information at a given transmission
interconnection point. A communication Requirement for the exchange of information would be
administrative in nature, and would create additional compliance tracking burdens for both entities.
ReliabilityFirst
ReliabilityFirst votes in the Affirmative and believes the PRC-026-1 standard enhances reliability and
ensures that load-responsive protective relays are expected to not trip in response to stable power swings
during non-Fault conditions. ReliabilityFirst offers the following comments for consideration:
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1. Requirement R2 - the language regarding who determines whether or not a stable or unstable power
swing has occurred is vague. The associated application notes state that the SDT purposefully avoided
making the GO or TO responsible for that determination and allude that possibly the GO or TO, the RE or
NERC during an event analysis could be the source. Unfortunately, this wording sets up a lot of finger
pointing as to who was responsible to launch the analysis of the compliance of PRC-026 with the event.
ReliabilityFirst recommends including language clearly identifying the source of who determines whether
or not a stable or unstable power swing has occurred as referenced in Requirement R2.
Response: The standard drafting team agrees that placing a cross reference in a footnote to the guidelines
will provide increased awareness of where examples can be found. A reference to the Guidelines and
Technical Basis concerning “becoming aware” footnote has been appended to Requirement R2, Part 2.2.
However, the addition of the footnote only serves to increase the visibility of where an entity can find
examples. It does not make the information in the guideline part of the enforceable requirement.
Also, Requirement R2, Part 2.2 does not require re-evaluation on a periodic basis and is only triggered by
actual events. The standard drafting team concluded that in those rare cases where an event included
tripping in response to stable or unstable power swings, that the Generator Owner and Transmission
Owner must evaluate its load-responsive protective relays due to the event; however, subsequent review
would not be necessary on an ongoing basis. Clarification made.
Seminole Electric
Cooperative, Inc.
Requirement R1”Element” in R1 on page 6 of the redline was revised to “generator, transformer, and
transmission line BES Element.” It’s unclear whether “transmission line BES Element” includes terminal
equipment of the transmission line.
Response: The standard drafting team modified the language in the Applicability section and Requirements
in the previous Draft 3 to more clearly note that Requirement R1 is applicable to three types of BES
Elements (i.e., “generator, transformer, and transmission line”). By definition of “Element” the terminal
equipment may be included as a part of the Element. No change made.
It’s unclear whether a “generator BES Element” includes a generator Facility, i.e., the generator itself or
merely those Elements that make up the generator. Seminole requests the drafting team add additional
language as to what is actually covered under R1.
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Response: The standard drafting team notes that the term “generator,” as used in Requirement R1, is
specific to the generating unit and not other elements that make up a generator facility.
PRC-026-1 - Attachment B
Under Criteria B on page 20 of the redline version, #2 states “All generation is in service and all
transmission BES Elements are in their normal ... .” Seminole requests the drafting team explain how the
“transmission BES Elements” listed here are different than “Transmission BES Elements” (Transmission with
a capital T)?
Response: The standard drafting team revised the use of the capitalized version of “Transmission system”
to lower case. The occurrences of “Transmission station” appropriately reflect the standard drafting team’s
intent to reference the term “Transmission” as defined in the Glossary of Terms Used in NERC Reliability
Standards (NERC Glossary). Occurrences of the phrase “…generation is in service and all transmission BES
Elements...” does not refer to the NERC Glossary and is intended to be used in the normal understanding of
“generation” and “transmission.”
Seattle City Light
Seattle City Light appreciates the efforts of the Standards Drafting Team to respond to comments and
clarify the proposed draft. Seattle, however, continues to believe that the proposed Standard is not
warranted by the history of major electrical outages. Seattle further finds the proposed Standard to be
based on theoretical concepts rather than practical experience, and as such, proposes a largely untried
process to become a rigid federal regulation having continental reach. Recent industry experience suggests
the difficulty of such an approach. Consider industry experience with another new concept, that of the
NERC “Order 754” effort. Considerable back-and-forth exchange and flexibility was required of this effort
before well-meaning entities across the continent--each having different configurations, equipment, and
characteristics--were able apply a new, untried process to reach a desired and consistent result.
Furthermore, as the drafting team will recall, the Order 754 request required some three years to
complete, and first year was spent almost entirely in clarifications and modifications. The clarifications and
modifications were necessary to address the differing equipment and configurations of diverse entities,
configurations and equipment that had not been considered by the team that framed the request. Matters
came up as fundamental as “what is meant by the term ‘bus’ in the request?” (in the end, ‘bus’ was defined
to mean one thing for one part of the request and defined as something else for another part). Given the
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diversity of entities in North America, how could any team, no matter how strong, be expected to conceive
of all possible arrangements with no application experience to guide them? Consider now that the
proposed Standard is just as untried as the Order 754 request and is rather more complex. Moreover, as a
mandatory reliability Standard it would lack the implementation flexibility that allowed successful
completion of the Order 754 request. Consequently Seattle is deeply concerned about the effectiveness of
the proposed approach in improving the reliability of the bulk electric system in the near term. Rather it
appears more likely to drive a bow-wave of compliance violations as numerous entities struggle to apply
new theoretical processes that do not fit their situation and circumstances, and regulators struggle to
figure out how to audit a misfit Standard. As such, Seattle votes Negative on this ballot and expects to do
so in future ballots as well. Seattle would consider an Affirmative position if the draft Standard was put on
hold and a 1-2 year pilot program run in its place. Such a pilot program could be structured as a mandatory
reporting exercise somewhat like the Order 754 effort: reporting would be required but results would not
be audited for compliance (rather used for learning). Alternatively, a pilot program might be structured to
focus on a small number of entities such as the recent CIP v5 pilot program (with the difference that no
PRC-026-1 Standard would be adopted, until after the pilot when lessons learned could be incorporated
into it). Once experience had been acquired with the real-world application of the proposed PRC-026-1
requirements, and the Standard revised to accommodate these lessons, then Seattle would consider an
Affirmative vote. Should a pilot program be implemented, Seattle would be willing to serve a test entity.
Response: The standard drafting team thanks you for your comments. The ideas presented concerning a
field trial will be referred to NERC staff for further consideration.
Bureau of
Reclamation
The Bureau of Reclamation (Reclamation) supports the proposed PRC-026-1. Reclamation appreciates the
drafting team’s efforts revising the Applicability, Requirements, and Measures to clarify which entities will
be required to complete stable power swing analysis for which qualifying facilities and elements.
Response: The standard drafting team thanks you for your comments.
California ISO
The California ISO does not agree with the change to remove the Transmission Planner in the Applicability
section and in Requirement R1. The California ISO supports continuing to include the Transmission Planner
in Requirement R1 as suggested by the PSRPS Report.
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Response: The standard drafting team removed the Transmission Planner (and Reliability Coordinator) as
applicable entities in Draft 2 of the proposed standard in response to comments on Draft 1 to address
concerns about overlap and potential gaps when identifying Elements in Requirement R1. Although the
PSRPS Report 9 suggested entities for applicability, the standard drafting team agreed with industry
comments received on Draft 1 that the Planning Coordinator is in the best position to identify the BES
Elements for notification to avoid duplication and potential gaps. No change made
PacifiCorp
The drafting team should eliminate or revise criterion 3 under PRC-026-1 R1. PRC-006 studies are
performed to help ensure sufficient load is available to be shed during extreme events to help arrest
frequency decline within an island. Since there are a large number of potential but very low probability
extreme events that could result in island formation, UFLS programs applied to small loads dispersed
throughout the interconnected system in order to increase the likelihood that potential islands include load
that can be shed. Since many of these potential islands and the elements that open to form them are highly
speculative, R1 Criteria 3, if it is kept, should be modified to limit its application to elements associated
with actual events or specifically designed island boundaries. The Planning Coordinator should not be
required to develop a criteria for identifying islands.
Response: The standard drafting team notes that Requirement R1, Criterion 3 does not require the
Planning Coordinator to develop criteria for identifying islands. If the Planning Coordinator has criteria (i.e.,
as determined under PRC-006) where the island is formed by tripping the Element due to angular
instability, then the Planning Coordinator must notify the respective Generator Owner and Transmission
Owner. Further, the standard drafting team included this criterion to remain consistent with the PSRPS
Report 10 recommendation for facilities to consider. No change made.
ISO RTO Council
Standards Review
Committee
The IRC SRC appreciates the drafting team’s efforts in addressing industry concerns, especially those we
submitted in the prior posting. We believe our concerns have been addressed, but respectfully suggest the
following small clarification regarding Requirement R3:
9
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
10
Ibid, page 21 of 61, 4th bullet.
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Question 1 Comment
Each Generator Owner and Transmission Owner shall, within six full calendar months of determining,
pursuant to R2, that a load-responsive protective relay does not meet the PRC-026-1 - Attachment B
criteria, develop a Corrective Action Plan (CAP) to meet one or more of the following....
Thank you for the additional comment opportunity.
Response: The standard drafting team agrees with the suggestion that it adds clarity that Requirement R3
is contingent upon Requirement R2. Clarification made.
MRO NERC Standards
Review Forum
The NSRF believes that the Industry concerns have not been adequately addressed.
Request that the drafting clarify its scope of applicability between NERC defined “Elements” and “Facilities”
in Section 4.2. Did the drafting team mean only BES generators, transmission lines, and transformers? If so,
please clarify this sub set is the only applicable items.
Response: The standard drafting team modified the language in the Applicability section and Requirements
in the previous Draft 3 to more clearly note the standard is applicable to three types of BES Elements (i.e.,
“generator, transformer, and transmission line”). By definition of “Element” the terminal equipment may
be included as a part of the Element.
The drafting team should eliminate or revise criterion 3 under PRC-026-1 R1. UFLS islands are rare and UFLS
islands mandated by PRC-006 are likely best guess conditions. Therefore unless criterion 3 under R1 is
modified to apply only to known and designed stability power protection systems, the work performed
would be a best guess and of little practical value. At a minimum, criterion 3 could be further clarified by
adding a sentence such as the following, “Criterion 3 does not apply to other conditions such as excessive
loading.”
Response: The standard drafting team notes that Requirement R1, Criterion 3 does not require the
Planning Coordinator to develop criteria for identifying islands. If the Planning Coordinator has criteria (i.e.,
as determined under PRC-006) where the island is formed by tripping the Element due to angular
instability, then the Planning Coordinator must notify the respective Generator Owner and Transmission
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Owner. Further, the standard drafting team included this criterion to remain consistent with the PSRPS
Report 11 recommendation for facilities to consider. No change made.
FERC has defined that the requirements govern compliance (FERC O 693 sect. 253), unless the words “nonfault power swings” are added to R2 similar to the PRC-026 purpose correctly limiting the number of
evaluations to non-fault conditions, a regulatory entity could determine an entity was in non-compliance
for not evaluating stable or unstable power swings for fault conditions after an event for “impedance based
relays identified in Attachment
Response: The standard drafting team contends that the use of “non-Fault” in the Purpose describes the
standard’s intent to “…ensure that load-responsive protective relays are expected to not trip in response to
stable power swings during non-Fault conditions...” where the non-Fault condition applies to the
Element(s) the relays are protecting. The evaluation, in the case of Requirement R2 for actual events,
comes into scope upon becoming aware of a generator, transformer, or transmission line BES Element that
tripped in response to a stable or unstable power swing due to the operation of its protective relay(s) for a
non-Fault condition on the protected Element.
The use of “non-fault” in PRC-026 R2 would clearly separate PRC-026 from PRC-004 which already governs
analysis and corrective actions for protection systems mis-operations usually with respect to fault
conditions. This separation will avoid a potential double jeopardy violation where PRC-026 and PRC-004
could be interpreted to overlap for relay analysis of a misoperation.
Response: The standard drafting team discussed the relationship between the proposed PRC-026-1 and
PRC-004-3 (recently NERC Board adopted). The use of “non-Fault” does not separate PRC-026-1 from PRC004-3 because PRC-004-3 addresses the categories of “Other Than Fault” with regard to identifying
Misoperations.
The standard drafting team considered the connection between PRC-004 and PRC-026 with regard to the
Corrective Action Plan (CAP) being redundant at great length over the development of the standard. The
standard drafting team notes that in the case where an Element trip occurs due to a stable power swing
and is identified as a Misoperation (under PRC-004-3) a single CAP is permitted to be developed to satisfy
11
Ibid, page 21 of 61, 4th bullet.
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Question 1 Comment
both PRC-004 and PRC-026. However, in the broader sense, the CAP for PRC-026-1 is specifically intended
to ensure that load-responsive protective relays are expected to not trip in response to stable power
swings during non-Fault conditions and PRC-004 is to identify and correct the causes of Misoperations of
Protection Systems for Bulk Electric System (BES) Elements. In most cases, action required for each
standard will remain separate and distinct whether included in one CAP or separate CAPs.
Concerns could exist for electromechanical relays. Electromechanical relays do not provide appropriate
data to verify operation or misoperation due to a stable or unstable power swing. Electromechanical relays
can only provide target data. To verify correct operation due to a stable or unstable power swing, plots of
the system impedance characteristic need to be obtained. Suggest that requirement 2.3 be added clearly
identifying that limited data where it isn’t possible to verify if a relay tripped due to a power swing, the
entity can conclude it is unaware of the trip cause and a PRC-026 report isn’t required or use of a foot note
could be added.
Response: Issues concerning the ability of an entity being capable of identifying power swings is addressed
by the “becoming aware” language in Requirement R2, Part 2.2. See the Guidelines and Technical Basis as
footnoted in the revised standard for “becoming aware.” Performance under Requirement R2, Part 2.2
starts with becoming aware of the event (i.e., power swing) and then any connection with the entity’s
Element tripping. No change made.
Modesto Irrigation
District
The standard should be applicable to more than just BES elements.
I think it is critical that the following phrase be included in Part 4.2 of the Applicability Section: "Any system
element, regardless of size or connected voltage, that has been shown to be material to the reliability of
the BES". The “bright line” of 100 kV is fine in general, but when it is known that an element connected at
less than 100 kV is material to the reliability of the BES, it should be included as an applicable facility for
this standard.
This is because WECC members have learned over the years to recognize the significant role that smaller
size elements play in system response and stability. Also, past WECC studies of major outages have shown
that elements connected at less than 100 kV, have played a major role in the impact of outages. In fact, the
most accurate duplication of the 1996 major system wide outage and more recent outages that the WECC
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MVWG has simulated, have shown that the accuracy of the simulated results of actual system outages is
highly affected by the accuracy of the modeled system below 100 KV.
Response: The standard drafting team thanks you for your comment. The standard addresses concerns
raised in the Federal Energy Regulatory Order No. 733 using an equally effective and efficient approach
based on the PSRPS Report. 12 The standard uses the PSRPS Report’s narrow focus for the applicability to
the subset of BES Elements that are at an increased risk for power swings. By identifying these specific BES
Elements, the Generator Owner and Transmission Owner can ensure that load-responsive protective relays
are expected to not trip in response to stable power swings during non-Fault conditions. Entities are not
precluded from applying the principles to other BES and non-BES Elements. No change made.
PPL NERC Registered
Affiliates
These comments are submitted on behalf of the following PPL NERC Registered Affiliates: LG&E and KU
Energy, LLC; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; PPL Generation, LLC; PPL Susquehanna,
LLC; and PPL Montana, LLC. The PPL NERC Registered Affiliates are registered in six regions (MRO, NPCC,
RFC, SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA,
PSE, RP, TO, TOP, TP, and TSP.
Comments: We agree that SDT has largely addressed industry comments on this standard and believe that
STD’s work on this standard sets a model for future collaborative effort. We have only one remaining
concern. Although the Application Guideline has language that satisfactorily explains the intent of the
“becoming aware of” language in subpart 2.2, we are concerned that a guideline is not enforceable. We
recommend adding a footnote in subpart 2.2 that solidly ties the guideline language to this subpart. If this
single change were made to this version of the standard, PPL would vote affirmatively.
Response: The standard drafting team agrees that placing a cross reference in a footnote to the guidelines
will provide increased awareness of where examples can be found. A reference to the Guidelines and
Technical Basis concerning “becoming aware” footnote has been appended to Requirement R2, Part 2.2.
However, the addition of the footnote only serves to increase the visibility of where an entity can find
examples. It does not make the information in the guideline part of the enforceable requirement.
12
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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Tri-State Generation
and Transmission
Association, Inc.
Question 1 Comment
Tri-State believes that Requirement R3 should continue to refer to the Requirement to assess the loadresponsive protective relays against the criteria of PRC-026-1 - Attachment B. We recommend adding
“pursuant to Requirement R2,” between “PRC-026-1 - Attachment B criteria,” and “develop a Corrective
Action Plan (CAP)” in Requirement R3. Without the clarifying clause, the requirement could be referring to
any load-responsive protective relay that the entity happens to recognize that does not meet the criteria in
the attachment.
Response: The standard drafting team agrees with the suggestion that it adds clarity that Requirement R3
in contingent upon Requirement R2. Clarification made.
JEA
We are concerned that this standard may have unintended consequences and hurt the reliability of the
BES.
Response: The standard drafting team thanks you for your comment.
SPP Standards Review
Group
We have a concern about the significance of Attachment A in the documentation and ask the drafting team
to provide more clarity on this documentation.
In Requirement R3, the drafting team mentions that the Generator Owner and Transmission Owner has six
full calendar months after determining that load-responsive protection relays don’t meet Attachment B
criteria and a Correction Action Plan (CAP) needs to be developed. Additionally in the second bullet of the
same requirement, the drafting team mentions ‘The Protection System is excluded under the PRC-026-1 Attachment A criteria’. However in the Rationale Box of R3, the drafting team provides detailed
information on the necessity of the CAP and its association with Attachment B. As for Attachment A, there
is no explanation of how it impacts the Generator Owner and Transmission Owner or what role it plays in
this process. Please provide more detailed information in the Rationale Box of R3 in reference to
Attachment A.
Response: The standard drafting team notes that the rationale box incorrectly referenced Requirement R2
and should have been Requirement R3. The rationale box was revised to provide information about PRC026-1 – Attachment A. For a load-responsive protective relay that did not meet the PRC-026-1 –
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Attachment B criteria, the entity must develop a Corrective Action Plan (CAP) meets one of the following
(the following is paraphrased for clarity):
1. Modify the Protection System to meet PRC-026-1 – Attachment B criteria or make some other
modification (e.g., a system configuration change) such that the Protection System will meet PRC-026-1
– Attachment B criteria (because the system impedance changed), or
2. Modify the Protection System in a manner as to exclude it from the applicability of the standard (by
using the list of exclusions in PRC-026-1 – Attachment A). For example, applying power swing blocking
supervision to the load-responsive protective relay would be an acceptable CAP and way to meet the
objectives of the Standard.
Northeast Power
Coordinating Council
With respect to Requirement 1, stability addressed by RAS (Criterion 1), or relay trips observed in Planning
Assessments (Criterion 4) often involves remote or local generators and the instability or relay trip does not
impact the Bulk Electric System outside the local area. In NPCC, the majority of RAS are classified as Type III
SPS, meaning that their failure (and resulting instability) does not adversely impact the Bulk Electric System
outside the local area. As in PRC-010-1 that recognizes local issues and "provides latitude for the Planning
Coordinator or Transmission Planner to determine if UVLS falls under the defined term based on the impact
on the reliability of the BES", it is suggested that PRC-026-1 also provide latitude to the PC to exclude some
of the BES Elements identified by Criteria 1 and 4 if the instability or relay trip does not impact the Bulk
Electric System outside the local area.
Response: The standard drafting team has developed the standard consistent with applicability provided in
the PSRPS Report. 13 All of the BES Elements that are identified through the Requirements must meet the
standard regardless of whether the condition is a local issue or a more widespread problem. No change
made.
The page numbers refer to the pages in the clean copy of PRC-026-1.
13
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/System%20
Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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Page 14--from “The following protection functions are excluded from Requirements of this standard:”, Why
are voltage-restrained relays excluded? Wouldn't the voltage dip during a power swing enable these relays
to misoperate on load current?
Response: Voltage controlled time-overcurrent or voltage-restrained time-overcurrent relays are excluded
from this standard. When set based on equipment permissible overload capability, a voltage-restrained
time-overcurrent operating time is much greater than 15 cycles for the current levels observed during a
power swing.
Page 18--in the “Pole Slip:” item it should read “a generator’s, or group of generator’s, terminal...”. Page
18--the “Out-of-step Condition:” should read “Same as an Unstable Power Swing.” (Capitalization
change).Page 20--line 5 should reads “...identified as BES Elements meeting...”.
Response: These descriptions are taken directly from the referenced IEEE Power System Relaying
Committee WG D6 developed a technical document called Power Swing and Out-of-Step Considerations on
Transmission Lines (July 2005) technical document. No change made.
Page 30--the caption for Figure 3 should read: “System impedances as seen by Relay R. (voltage
connections for relay not shown.)”
Response: Correction made as suggested.
Page 33-- The first blue box for Table 2 should read: “Positive sequence impedance data (with transfer
impedance ZTR set to a very large value).”
Response: Clarification made.
Page 33--In equation (8), ZTR was given as = ZL x 10^10, which equals (4 + j20) x 10^10, not (4 + j20)^10 as
used in the equations.
Response: Correction made to all related equations.
Page 34--In Table 3, the second blue box should read: “Positive sequence impedance data (with transfer
impedance ZTR set to a very large value).
Response: Clarification made.
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Question 1 Comment
Page 36--same comment for Equation (16) as for Equation (8) above.
Response: Correction made to all related equations.
Page 36--for Table 4 and Equation (24), the same comment as for Equation (8) above.
Response: Correction made to all related equations.
Pages 38-42--for Tables 5, 6, and 7 the same comment as for Equation (8) above.
Response: Correction made to all related equations.
Page 53--For Figure 12 the caption should be rephrased to: “The tripping portion of the mho element
characteristic not blocked by load encroachment (i.e., ...) is completely contained within...”.
Response: Clarification made.
Page 69--The last blue box in Table 14 should read “Total system current”. Current direction is irrelevant.
Response: The phrase “from sending-end source” was deleted.
Page 72--the Drafting Team should consider adding the word “Stable” in the lower right region of the
Figure 16 graph, and the word “Unstable”: under the words “Capability Curve” to the right of SSSL.
Response: Figure 16 illustrates a typical SSSL curve and is not intended to reference the stable and unstable
regions as noted in other figures.
Page 74--in Table 15, X”d was changed to X’d, but “sub-transient” was not corrected to read “saturated
transient reactance”.
Response: Correction made.
Page 75--regarding Table 16, define the Base that the values of Table 15 have been converted to (e.g.
“Table 16. Example calculations (Generator) on 941 MVA base”).
Response: The MVA base was added to Table 16.
Pages 74-75--there are two different values for Ze and both are in ohms, not per unit.
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Response: Values were updated to reference per unit and Z e was corrected from 86 degrees to 90 degrees
to be consistent.
Page 75--in Equation (107) j0.3845 + j0.171 + 0.06796 does is not equal to 0.6239∠90Ω.
Response: Correction made.
Page 75-- Zsys is defined as 0.6239∠90Ω in Equation (107) of Table 16, but defined as 0.6234∠90Ω in
Equation (109) of Table 16 and in Equation (110) of the Instantaneous Overcurrent Relay section.
Response: Correction made to Equation 107 and Equations 109 and 110 are now correct.
Page 78--in Figure 20 add “hashing” to the area between the SSSL (black) curve and the 40-1 (blue) curve
with an arrow and note saying “Stable and can trip” or similar wording.
Response: Figure 20 title was revised to remove the reference to “stable power swing” and to note the
figure is a typical loss-of-field R-X plot. Hashing relative to the SSSL curve was not added because the figure
is illustrating a test against the unstable power swing region represented by the solid red lines.
There are inconsistencies in the use of “per unit” in the tables of the Applications Guidelines. In some
instances per unit is used, and in other instances the ohmic value is given. There should be consistency in
the Applications Guidelines and standard.
Response: The standard drafting team revised the calculations so that per unit and ohm values are
consistent within each table.
END OF REPORT
Consideration of Comments: Project 2010-13.3 – Phase 3 of Relay Loadability: Stable Power Swings
Posted: December 5, 2014
50 of 50
PRC-026-1 — Relay Performance During Stable Power Swings
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. Standards Authorization Request (SAR) posted for comment from August 19, 2010,
through September 19, 2010.
2. Standards Committee (SC) authorized moving the SAR forward into standard
development on August 12, 2010.
3. SC authorized initial posting of Draft 1 on April 24, 2014.
4. Draft 1 of PRC-026-1 was posted for a 45-day formal comment period from April 25 –
June 9, 2014, with a concurrent/parallel initial ballot in the last ten days of the comment
period from May 30 – June 9, 2014.
5. Draft 2 of PRC-026-1 was posted for an additional 45-day formal comment period from
August 22 – October 6, 2014 with a concurrent/parallel additional ballot in the last ten
days of the comment period from September 26 – October 6, 2014.
6. SC authorized a waiver of the Standards Process Manual on October 22, 2014 to reduce
the Draft 3 additional formal comment period of PRC-026-1 from 45 days to 21 days
with a concurrent/additional ballot period in the last ten days of the comment period.
7. Draft 3 of PRC-026-1 was posted for an additional 21-day formal comment period from
November 4 – November 24, 2014 with a concurrent/parallel additional ballot in the last
ten days of the comment period from November 14 – November 24, 2014
Description of Current Draft
The Protection System Response to Power Swings Standard Drafting Team (PSRPS SDT) is
posting Draft 4 of PRC-026-1 – Relay Performance During Stable Power Swings for a 10-day final
ballot.
Anticipated Actions
Anticipated Date
45-day Formal Comment Period with Concurrent/Parallel Initial 10-day
Ballot
April 2014
45-day Formal Comment Period with Concurrent/Parallel Additional 10day Ballot
August 2014
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
Anticipated Actions
Anticipated Date
21-day Formal Comment Period with Concurrent/Parallel Additional 10day Ballot (Standards Committee authorized a waiver of the Standards
Process Manual, October 22, 2014)
November 2014
Final Ballot
December 2014
NERC Board of Trustees Adoption
December 2014
Version History
Version
Date
1.0
TBD
Action
Effective Date
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
Change
Tracking
New
Page 2 of 87
PRC-026-1 — Relay Performance During Stable Power Swings
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Glossary of Terms Used in Reliability Standards (Glossary) are not repeated
here. 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.
Term: None.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
When this standard has received ballot approval, the rationale boxes will be moved to the
Application Guidelines Section of the standard.
A. Introduction
1. Title:
Relay Performance During Stable Power Swings
2. Number:
PRC-026-1
3. Purpose:
To ensure that load-responsive protective relays are expected to not trip in
response to stable power swings during non-Fault conditions.
4. Applicability:
4.1.
4.2.
Functional Entities:
4.1.1
Generator Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
4.1.2
Planning Coordinator.
4.1.3
Transmission Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
Facilities: The following Elements that are part of the Bulk Electric System
(BES):
4.2.1
Generators.
4.2.2
Transformers.
4.2.3
Transmission lines.
5. Background:
This is the third phase of a three-phased standard development project that focused on
developing this new Reliability Standard to address protective relay operations due to
stable power swings. The March 18, 2010, Federal Energy Regulatory Commission
(FERC) Order No. 733 approved Reliability Standard PRC-023-1 – Transmission Relay
Loadability. In that Order, FERC directed NERC to address three areas of relay loadability
that include modifications to the approved PRC-023-1, development of a new Reliability
Standard to address generator protective relay loadability, and a new Reliability Standard
to address the operation of protective relays due to stable power swings. This project’s
SAR addresses these directives with a three-phased approach to standard development.
Phase 1 focused on making the specific modifications from FERC Order No. 733 to PRC023-1. Reliability Standard PRC-023-2, which incorporated these modifications, became
mandatory on July 1, 2012.
Phase 2 focused on developing a new Reliability Standard, PRC-025-1 – Generator Relay
Loadability, to address generator protective relay loadability. PRC-025-1 became
mandatory on October 1, 2014, along with PRC-023-3, which was modified to harmonize
PRC-023-2 with PRC-025-1.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
Phase 3 focuses on preventing protective relays from tripping unnecessarily due to stable
power swings by requiring identification of Elements on which a stable or unstable power
swing may affect Protection System operation, assessment of the security of loadresponsive protective relays to tripping in response to only a stable power swing, and
implementation of Corrective Action Plans (CAP), where necessary. Phase 3 improves
security of load-responsive protective relays for stable power swings so they are expected
to not trip in response to stable power swings during non-Fault conditions while
maintaining dependable fault detection and dependable out-of-step tripping.
6. Effective Dates:
Requirement R1
First day of the first full calendar year that is 12 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 12 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
Requirements R2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 36 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
B. Requirements and Measures
R1. Each Planning Coordinator shall, at least once each calendar year, provide notification
of each generator, transformer, and transmission line BES Element in its area that
meets one or more of the following criteria, if any, to the respective Generator Owner
and Transmission Owner: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
Criteria:
1. Generator(s) where an angular stability constraint exists that is addressed by a
System Operating Limit (SOL) or a Remedial Action Scheme (RAS) and those
Elements terminating at the Transmission station associated with the generator(s).
2. An Element that is monitored as part of an SOL identified by the Planning
Coordinator’s methodology 1 based on an angular stability constraint.
3. An Element that forms the boundary of an island in the most recent
underfrequency load shedding (UFLS) design assessment based on application of
the Planning Coordinator’s criteria for identifying islands, only if the island is
formed by tripping the Element due to angular instability.
4. An Element identified in the most recent annual Planning Assessment where relay
tripping occurs due to a stable or unstable 2 power swing during a simulated
disturbance.
M1. Each Planning Coordinator shall have dated evidence that demonstrates notification of
the generator, transformer, and transmission line BES Element(s) that meet one or
more of the criteria in Requirement R1, if any, to the respective Generator Owner and
Transmission Owner. Evidence may include, but is not limited to, the following
documentation: emails, facsimiles, records, reports, transmittals, lists, or spreadsheets.
Rationale for R1: The Planning Coordinator has a wide-area view and is in the position to
identify generator, transformer, and transmission line BES Elements which meet the criteria, if
any. The criteria-based approach is consistent with the NERC System Protection and Control
Subcommittee (SPCS) technical document Protection System Response to Power Swings,
August 2013 (“PSRPS Report”), 3 which recommends a focused approach to determine an atrisk BES Element. See the Guidelines and Technical Basis for a detailed discussion of the
criteria.
1
NERC Reliability Standard FAC-014-2 – Establish and Communicate System Operating Limits, Requirement R3.
2
An example of an unstable power swing is provided in the Guidelines and Technical Basis section, “Justification
for Including Unstable Power Swings in the Requirements section of the Guidelines and Technical Basis.”
3
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R2. Each Generator Owner and Transmission Owner shall: [Violation Risk Factor: High]
[Time Horizon: Operations Planning]
2.1 Within 12 full calendar months of notification of a BES Element pursuant to
Requirement R1, determine whether its load-responsive protective relay(s)
applied to that BES Element meets the criteria in PRC-026-1 – Attachment B
where an evaluation of that Element’s load-responsive protective relay(s) based
on PRC-026-1 – Attachment B criteria has not been performed in the last five
calendar years.
2.2 Within 12 full calendar months of becoming aware 4 of a generator, transformer,
or transmission line BES Element that tripped in response to a stable or unstable 5
power swing due to the operation of its protective relay(s), determine whether its
load-responsive protective relay(s) applied to that BES Element meets the criteria
in PRC-026-1 – Attachment B.
M2. Each Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the evaluation was performed according to Requirement R2. Evidence
may include, but is not limited to, the following documentation: apparent impedance
characteristic plots, email, design drawings, facsimiles, R-X plots, software output,
records, reports, transmittals, lists, settings sheets, or spreadsheets.
Rationale for R2: The Generator Owner and Transmission Owner are in a position to determine
whether their load-responsive protective relays meet the PRC-026-1 – Attachment B criteria.
Generator, transformer, and transmission line BES Elements are identified by the Planning
Coordinator in Requirement R1 and by the Generator Owner and Transmission Owner
following an actual event where the Generator Owner and Transmission Owner became aware
(i.e., through an event analysis or Protection System review) tripping was due to a stable or
unstable power swing. A period of 12 calendar months allows sufficient time for the entity to
conduct the evaluation.
4
Some examples of the ways an entity may become aware of a power swing are provided in the Guidelines and
Technical Basis section, “Becoming Aware of an Element That Tripped in Response to a Power Swing.”
5
An example of an unstable power swing is provided in the Guidelines and Technical Basis section, “Justification
for Including Unstable Power Swings in the Requirements section of the Guidelines and Technical Basis.”
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R3. Each Generator Owner and Transmission Owner shall, within six full calendar months
of determining a load-responsive protective relay does not meet the PRC-026-1 –
Attachment B criteria pursuant to Requirement R2, develop a Corrective Action Plan
(CAP) to meet one of the following: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
•
The Protection System meets the PRC-026-1 – Attachment B criteria, while
maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the BES Element); or
•
The Protection System is excluded under the PRC-026-1 – Attachment A criteria
(e.g., modifying the Protection System so that relay functions are supervised by
power swing blocking or using relay systems that are immune to power swings),
while maintaining dependable fault detection and dependable out-of-step tripping
(if out-of-step tripping is applied at the terminal of the BES Element).
M3. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the development of a CAP in accordance with Requirement R3. Evidence
may include, but is not limited to, the following documentation: corrective action
plans, maintenance records, settings sheets, project or work management program
records, or work orders.
Rationale for R3: To meet the reliability purpose of the standard, a CAP is necessary to ensure
the entity’s Protection System meets the PRC-026-1 – Attachment B criteria (1st bullet) so that
protective relays are expected to not trip in response to stable power swings. A CAP may also
be developed to modify the Protection System for exclusion under PRC-026-1 – Attachment A
(2nd bullet). Such an exclusion will allow the Protection System to be exempt from the
Requirement for future events. The phrase, “…while maintaining dependable fault detection
and dependable out-of-step tripping…” in Requirement R3 describes that the entity is to comply
with this standard, while achieving their desired protection goals. Refer to the Guidelines and
Technical Basis, Introduction, for more information.
R4. Each Generator Owner and Transmission Owner shall implement each CAP developed
pursuant to Requirement R3 and update each CAP if actions or timetables change until
all actions are complete. [Violation Risk Factor: Medium][Time Horizon: Long-Term
Planning]
M4. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates implementation of each CAP according to Requirement R4, including
updates to the CAP when actions or timetables change. Evidence may include, but is
not limited to, the following documentation: corrective action plans, maintenance
records, settings sheets, project or work management program records, or work orders.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
Rationale for R4: Implementation of the CAP must accomplish all identified actions to be
complete to achieve the desired reliability goal. During the course of implementing a CAP,
updates may be necessary for a variety of reasons such as new information, scheduling conflicts,
or resource issues. Documenting CAP changes and completion of activities provides measurable
progress and confirmation of completion.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention
The following evidence retention periods 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 CEA may ask an entity to provide other evidence to show that it was
compliant for the full time period since the last audit.
The Generator Owner, Planning Coordinator, and Transmission Owner shall keep
data or evidence to show compliance as identified below unless directed by its CEA
to retain specific evidence for a longer period of time as part of an investigation.
•
The Planning Coordinator shall retain evidence of Requirement R1 for a
minimum of one calendar year following the completion of the
Requirement.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirement R2 evaluation for a minimum of 12 calendar months following
completion of each evaluation where a CAP is not developed.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R2, R3, and R4 for a minimum of 12 calendar months
following completion of each CAP.
If a Generator Owner, Planning Coordinator, or Transmission Owner is found noncompliant, it shall keep information related to the non-compliance until mitigation
is complete and approved, or for the time specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
1.3.
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure; “Compliance Monitoring and
Assessment Processes” 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.
1.4.
Additional Compliance Information
None.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
Table of Compliance Elements
R#
R1
Time
Horizon
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was less than or equal
to 30 calendar days
late.
Moderate VSL
High VSL
Severe VSL
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 90
calendar days late.
OR
The Planning
Coordinator failed to
provide notification
of the BES
Element(s) in
accordance with
Requirement R1.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R2
Time
Horizon
Operations
Planning
Violation Severity Levels
VRF
High
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was less than or equal
to 30 calendar days
late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 90
calendar days late.
OR
The Generator Owner
or Transmission
Owner failed to
evaluate its loadresponsive protective
relay(s) in accordance
with Requirement R2.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R3
R4
Time
Horizon
Long-term
Planning
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than six
calendar months and
less than or equal to
seven calendar
months.
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than seven
calendar months and
less than or equal to
eight calendar
months.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than eight
calendar months and
less than or equal to
nine calendar months.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than nine
calendar months.
Medium The Generator Owner
or Transmission
Owner implemented a
Corrective Action
Plan (CAP), but failed
to update a CAP when
actions or timetables
changed, in
accordance with
Requirement R4.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
N/A
OR
The Generator Owner
or Transmission
Owner failed to
develop a CAP in
accordance with
Requirement R3.
N/A
The Generator Owner
or Transmission
Owner failed to
implement a
Corrective Action
Plan (CAP) in
accordance with
Requirement R4.
Page 13 of 87
PRC-026-1 — Relay Performance During Stable Power Swings
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
Burdy, John, Loss-of-excitation Protection for Synchronous Generators GER-3183, General
Electric Company.
IEEE Power System Relaying Committee WG D6, Power Swing and Out-of-Step
Considerations on Transmission Lines, July 2005: http://www.pes-psrc.org/Reports
/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission%20
Lines%20F..pdf.
Kimbark Edward Wilson, Power System Stability, Volume II: Power Circuit Breakers and
Protective Relays, Published by John Wiley and Sons, 1950.
Kundur, Prabha, Power System Stability and Control, 1994, Palo Alto: EPRI, McGraw Hill,
Inc.
NERC System Protection and Control Subcommittee, Protection System Response to Power
Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf.
Reimert, Donald, Protective Relaying for Power Generation Systems, 2006, Boca Raton: CRC
Press.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
Page 14 of 87
PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment A
This standard applies to any protective functions which could trip instantaneously or with a time
delay of less than 15 cycles on load current (i.e., “load-responsive”) including, but not limited to:
•
•
•
•
Phase distance
Phase overcurrent
Out-of-step tripping
Loss-of-field
The following protection functions are excluded from Requirements of this standard:
•
•
•
•
•
•
•
•
•
•
•
Relay elements supervised by power swing blocking
Relay elements that are only enabled when other relays or associated systems fail. For
example:
o Overcurrent elements that are only enabled during loss of potential conditions.
o Relay elements that are only enabled during a loss of communications
Thermal emulation relays which are used in conjunction with dynamic Facility Ratings
Relay elements associated with direct current (dc) lines
Relay elements associated with dc converter transformers
Phase fault detector relay elements employed to supervise other load-responsive phase
distance elements (i.e., in order to prevent false operation in the event of a loss of potential)
Relay elements associated with switch-onto-fault schemes
Reverse power relay on the generator
Generator relay elements that are armed only when the generator is disconnected from the
system, (e.g., non-directional overcurrent elements used in conjunction with inadvertent
energization schemes, and open breaker flashover schemes)
Current differential relay, pilot wire relay, and phase comparison relay
Voltage-restrained or voltage-controlled overcurrent relays
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
Criterion A:
An impedance-based relay used for tripping is expected to not trip for a stable power swing,
when the relay characteristic is completely contained within the unstable power swing region. 6
The unstable power swing region is formed by the union of three shapes in the impedance (RX) plane; (1) a lower loss-of-synchronism circle based on a ratio of the sending-end to
receiving-end voltages of 0.7; (2) an upper loss-of-synchronism circle based on a ratio of the
sending-end to receiving-end voltages of 1.43; (3) a lens that connects the endpoints of the
total system impedance (with the parallel transfer impedance removed) bounded by varying
the sending-end and receiving-end voltages from 0.0 to 1.0 per unit, while maintaining a
constant system separation angle across the total system impedance where:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
Rationale for Attachment B (Criterion A): The PRC-026-1 – Attachment B, Criterion A
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending-end and receiving-end
voltages varying from 0.7 to 1.0 per unit (See Guidelines and Technical Basis).
6
Guidelines and Technical Basis, Figures 1 and 2.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
Criterion B:
The pickup of an overcurrent relay element used for tripping, that is above the calculated
current value (with the parallel transfer impedance removed) for the conditions below:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
4. Both the sending-end and receiving-end voltages at 1.05 per unit.
Rationale for Attachment B (Criterion B): The PRC-026-1 – Attachment B, Criterion B
provides a basis for determining if the relays are expected to not trip for a stable power swing
having a system separation angle of up to 120 degrees with the sending-end and receiving-end
voltages at 1.05 per unit (See Guidelines and Technical Basis).
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
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PRC-026-1 – Application Guidelines
Guidelines and Technical Basis
Introduction
The NERC System Protection and Control Subcommittee technical document, Protection System
Response to Power Swings, August 2013, 7 (“PSRPS Report” or “report”) was specifically prepared
to support the development of this NERC Reliability Standard. The report provided a historical
perspective on power swings as early as 1965 up through the approval of the report by the NERC
Planning Committee. The report also addresses reliability issues regarding trade-offs between
security and dependability of Protection Systems, considerations for this NERC Reliability
Standard, and a collection of technical information about power swing characteristics and varying
issues with practical applications and approaches to power swings. Of these topics, the report
suggests an approach for this NERC Reliability Standard (“standard” or “PRC-026-1”) which is
consistent with addressing three regulatory directives in the FERC Order No. 733. The first
directive concerns the need for “…protective relay systems that differentiate between faults and
stable power swings and, when necessary, phases out protective relay systems that cannot meet
this requirement.” 8 Second, is “…to develop a Reliability Standard addressing undesirable relay
operation due to stable power swings.” 9 The third directive “…to consider “islanding” strategies
that achieve the fundamental performance for all islands in developing the new Reliability
Standard addressing stable power swings” 10 was considered during development of the standard.
The development of this standard implements the majority of the approaches suggested by the
report. However, it is noted that the Reliability Coordinator and Transmission Planner have not
been included in the standard’s Applicability section (as suggested by the PSRPS Report). This is
so that a single entity, the Planning Coordinator, may be the single source for identifying Elements
according to Requirement R1. A single source will insure that multiple entities will not identify
Elements in duplicate, nor will one entity fail to provide an Element because it believes the
Element is being provided by another entity. The Planning Coordinator has, or has access to, the
wide-area model and can correctly identify the Elements that may be susceptible to a stable or
unstable power swing. Additionally, not including the Reliability Coordinator and Transmission
Planner is consistent with the applicability of other relay loadability NERC Reliability Standards
(e.g., PRC-023 and PRC-025). It is also consistent with the NERC Functional Model.
The phrase, “while maintaining dependable fault detection and dependable out-of-step tripping”
in Requirement R3, describes that the Generator Owner and Transmission Owner are to comply
with this standard while achieving its desired protection goals. Load-responsive protective relays,
as addressed within this standard, may be intended to provide a variety of backup protection
functions, both within the generating unit or generating plant and on the transmission system, and
7
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
8
Transmission Relay Loadability Reliability Standard, Order No. 733, P.150 FERC ¶ 61,221 (2010).
9
Ibid. P.153.
10
Ibid. P.162.
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this standard is not intended to result in the loss of these protection functions. Instead, the
Generator Owner and Transmission Owner must consider both the Requirements within this
standard and its desired protection goals and perform modifications to its protective relays or
protection philosophies as necessary to achieve both.
Power Swings
The IEEE Power System Relaying Committee WG D6 developed a technical document called
Power Swing and Out-of-Step Considerations on Transmission Lines (July 2005) that provides
background on power swings. The following are general definitions from that document: 11
Power Swing: a variation in three phase power flow which occurs when the generator rotor
angles are advancing or retarding relative to each other in response to changes in load
magnitude and direction, line switching, loss of generation, faults, and other system
disturbances.
Pole Slip: a condition whereby a generator, or group of generators, terminal voltage angles
(or phases) go past 180 degrees with respect to the rest of the connected power system.
Stable Power Swing: a power swing is considered stable if the generators do not slip poles
and the system reaches a new state of equilibrium, i.e. an acceptable operating condition.
Unstable Power Swing: a power swing that will result in a generator or group of generators
experiencing pole slipping for which some corrective action must be taken.
Out-of-Step Condition: Same as an unstable power swing.
Electrical System Center or Voltage Zero: it is the point or points in the system where the
voltage becomes zero during an unstable power swing.
Burden to Entities
The PSRPS Report provides a technical basis and approach for focusing on Protection Systems,
which are susceptible to power swings, while achieving the purpose of the standard. The approach
reduces the number of relays to which the PRC-026-1 Requirements would apply by first
identifying the BES Element(s) on which load-responsive protective relays must be evaluated. The
first step uses criteria to identify the Elements on which a Protection System is expected to be
challenged by power swings. Of those Elements, the second step is to evaluate each loadresponsive protective relay that is applied on each identified Element. Rather than requiring the
Planning Coordinator or Transmission Planner to perform simulations to obtain information for
each identified Element, the Generator Owner and Transmission Owner will reduce the need for
simulation by comparing the load-responsive protective relay characteristic to specific criteria in
PRC-026-1 – Attachment B.
11
http://www.pes-psrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission
%20Lines%20F..pdf.
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Applicability
The standard is applicable to the Generator Owner, Planning Coordinator, and Transmission
Owner entities. More specifically, the Generator Owner and Transmission Owner entities are
applicable when applying load-responsive protective relays at the terminals of the applicable BES
Elements. The standard is applicable to the following BES Elements: generators, transformers, and
transmission lines. The Distribution Provider was considered for inclusion in the standard;
however, it is not subject to the standard because this entity, by functional registration, would not
own generators, transmission lines, or transformers other than load serving.
Load-responsive protective relays include any protective functions which could trip with or
without time delay, on load current.
Requirement R1
The Planning Coordinator has a wide-area view and is in the position to identify what, if any,
Elements meet the criteria. The criterion-based approach is consistent with the NERC System
Protection and Control Subcommittee (SPCS) technical document, Protection System Response to
Power Swings (August 2013), 12 which recommends a focused approach to determine an at-risk
Element. Identification of Elements comes from the annual Planning Assessments pursuant to the
transmission planning (i.e., “TPL”) and other NERC Reliability Standards (e.g., PRC-006), and
the standard is not requiring any other assessments to be performed by the Planning Coordinator.
The required notification on a calendar year basis to the respective Generator Owner and
Transmission Owner is sufficient because it is expected that the Planning Coordinator will make
its notifications following the completion of its annual Planning Assessments. The Planning
Coordinator will continue to provide notification of Elements on a calendar year basis even if a
study is performed less frequently (e.g., PRC-006 – Automatic Underfrequency Load Shedding,
which is five years) and has not changed. It is possible that a Planning Coordinator could utilize
studies from a prior year in determining the necessary notifications pursuant to Requirement R1.
Criterion 1
The first criterion involves generator(s) where an angular stability constraint exists that is
addressed by a System Operating Limit (SOL) or a Remedial Action Scheme (RAS) and those
Elements terminating at the Transmission station associated with the generator(s). For example, a
scheme to remove generation for specific conditions is implemented for a four-unit generating
plant (1,100 MW). Two of the units are 500 MW each; one is connected to the 345 kV system and
one is connected to the 230 kV system. The Transmission Owner has two 230 kV transmission
lines and one 345 kV transmission line all terminating at the generating facility as well as a 345/230
kV autotransformer. The remaining 100 MW consists of two 50 MW combustion turbine (CT)
units connected to four 66 kV transmission lines. The 66 kV transmission lines are not electrically
joined to the 345 kV and 230 kV transmission lines at the plant site and are not subject to the
operating limit or RAS. A stability constraint limits the output of the portion of the plant affected
12
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%20
20/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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by the RAS to 700 MW for an outage of the 345 kV transmission line. The RAS trips one of the
500 MW units to maintain stability for a loss of the 345 kV transmission line when the total output
from both 500 MW units is above 700 MW. For this example, both 500 MW generating units and
the associated generator step-up (GSU) transformers would be identified as Elements meeting this
criterion. The 345/230 kV autotransformer, the 345 kV transmission line, and the two 230 kV
transmission lines would also be identified as Elements meeting this criterion. The 50 MW
combustion turbines and 66 kV transmission lines would not be identified pursuant to Criterion 1
because these Elements are not subject to an operating limit or RAS and do not terminate at the
Transmission station associated with the generators that are subject to the SOL or RAS.
Criterion 2
The second criterion involves Elements that are monitored as a part of an established System
Operating Limit (SOL) based on an angular stability limit regardless of the outage conditions that
result in the enforcement of the SOL. For example, if two long parallel 500 kV transmission lines
have a combined SOL of 1,200 MW, and this limit is based on angular instability resulting from a
fault and subsequent loss of one of the two lines, then both lines would be identified as Elements
meeting the criterion.
Criterion 3
The third criterion involves Elements that form the boundary of an island within an underfrequency
load shedding (UFLS) design assessment. The criterion applies to islands identified based on
application of the Planning Coordinator’s criteria for identifying islands, where the island is
formed by tripping the Elements based on angular instability. The criterion applies if the angular
instability is modeled in the UFLS design assessment, or if the boundary is identified “off-line”
(i.e., the Elements are selected based on angular instability considerations, but the Elements are
tripped in the UFLS design assessment without modeling the initiating angular instability). In cases
where an out-of-step condition is detected and tripping is initiated at an alternate location, the
criterion applies to the Element on which the power swing is detected. The criterion does not apply
to islands identified based on other considerations that do not involve angular instability, such as
excessive loading, Planning Coordinator area boundary tie lines, or Balancing Authority boundary
tie lines.
Criterion 4
The fourth criterion involves Elements identified in the most recent annual Planning Assessment
where relay tripping occurs due to a stable or unstable 13 power swing during a simulated
disturbance. The intent is for the Planning Coordinator to include any Element(s) where relay
tripping was observed during simulations performed for the most recent annual Planning
Assessment associated with the transmission planning TPL-001-4 Reliability Standard. Note that
relay tripping must be assessed within those annual Planning Assessments per TPL-001-4, R4,
13
Refer to the “Justification for Including Unstable Power Swings in the Requirements” section.
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Part 4.3.1.3, which indicates that analysis shall include the “Tripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic or actual
relay models.” Identifying such Elements according to Criterion 4 and notifying the respective
Generator Owner and Transmission Owner will require that the owners of any load-responsive
protective relay applied at the terminals of the identified Element evaluate the relay’s susceptibility
to tripping in response to a stable power swing.
Planning Coordinators have the discretion to determine whether the observed tripping for a power
swing in its Planning Assessments occurs for valid contingencies and system conditions. The
Planning Coordinator will address tripping that is observed in transient analyses on an individual
basis; therefore, the Planning Coordinator is responsible for identifying the Elements based only
on simulation results that are determined to be valid.
Due to the nature of how a Planning Assessment is performed, there may be cases where a
previously-identified Element is not identified in the most recent annual Planning Assessment. If
so, this is acceptable because the Generator Owner and Transmission Owner would have taken
action upon the initial notification of the previously identified Element. When an Element is not
identified in later Planning Assessments, the risk of load-responsive protective relays tripping in
response to a stable power swing during non-Fault conditions would have already been assessed
under Requirement R2 and mitigated according to Requirements R3 and R4 where the relays did
not meet the PRC-026-1 – Attachment B criteria. According to Requirement R2, the Generator
Owner and Transmission Owner are only required to re-evaluate each load-responsive protective
relay for an identified Element where the evaluation has not been performed in the last five
calendar years.
Although Requirement R1 requires the Planning Coordinator to notify the respective Generator
Owner and Transmission Owner of any Elements meeting one or more of the four criteria, it does
not preclude the Planning Coordinator from providing additional information, such as apparent
impedance characteristics, in advance or upon request, that may be useful in evaluating protective
relays. Generator Owners and Transmission Owners are able to complete protective relay
evaluations and perform the required actions without additional information. The standard does
not include any requirement for the entities to provide information that is already being shared or
exchanged between entities for operating needs. While a Requirement has not been included for
the exchange of information, entities should recognize that relay performance needs to be
measured against the most current information.
Requirement R2
Requirement R2 requires the Generator Owner and Transmission Owner to evaluate its loadresponsive protective relays to ensure that they are expected to not trip in response to stable power
swings.
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The PRC-026-1 – Attachment A lists the applicable load-responsive relays that must be evaluated
which include phase distance, phase overcurrent, out-of-step tripping, and loss-of-field relay
functions. Phase distance relays could include, but are not limited to, the following:
•
•
Zone elements with instantaneous tripping or intentional time delays of less than 15 cycles
Phase distance elements used in high-speed communication-aided tripping schemes
including:
Directional Comparison Blocking (DCB) schemes
Directional Comparison Un-Blocking (DCUB) schemes
Permissive Overreach Transfer Trip (POTT) schemes
Permissive Underreach Transfer Trip (PUTT) schemes
A method is provided within the standard to support consistent evaluation by Generator Owners
and Transmission Owners based on specified conditions. Once a Generator Owner or Transmission
Owner is notified of Elements pursuant to Requirement R1, it has 12 full calendar months to
determine if each Element’s load-responsive protective relays meet the PRC-026-1 – Attachment
B criteria, if the determination has not been performed in the last five calendar years. Additionally,
each Generator Owner and Transmission Owner, that becomes aware of a generator, transformer,
or transmission line BES Element that tripped in response to a stable or unstable power swing due
to the operation of its protective relays pursuant to Requirement R2, Part 2.2, must perform the
same PRC-026-1 – Attachment B criteria determination within 12 full calendar months.
Becoming Aware of an Element That Tripped in Response to a Power Swing
Part 2.2 in Requirement R2 is intended to initiate action by the Generator Owner and Transmission
Owner when there is a known stable or unstable power swing and it resulted in the entity’s Element
tripping. The criterion starts with becoming aware of the event (i.e., power swing) and then any
connection with the entity’s Element tripping. By doing so, the focus is removed from the entity
having to demonstrate that it made a determination whether a power swing was present for every
Element trip. The basis for structuring the criterion in this manner is driven by the available ways
that a Generator Owner and Transmission Owner could become aware of an Element that tripped
in response to a stable or unstable power swing due to the operation of its protective relay(s).
Element trips caused by stable or unstable power swings, though infrequent, would be more
common in a larger event. The identification of power swings will be revealed during an analysis
of the event. Event analysis where an entity may become aware of a stable or unstable power swing
could include internal analysis conducted by the entity, the entity’s Protection System review
following a trip, or a larger scale analysis by other entities. Event analysis could include
involvement by the entity’s Regional Entity, and in some cases NERC.
Information Common to Both Generation and Transmission Elements
The PRC-026-1 – Attachment A lists the load-responsive protective relays that are subject to this
standard. Generator Owners and Transmission Owners may own load-responsive protective relays
(e.g., distance relays) that directly affect generation or transmission BES Elements and will require
analysis as a result of Elements being identified by the Planning Coordinator in Requirement R1
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PRC-026-1 – Application Guidelines
or the Generator Owner or Transmission Owner in Requirement R2. For example, distance relays
owned by the Transmission Owner may be installed at the high-voltage side of the generator stepup (GSU) transformer (directional toward the generator) providing backup to generation
protection. Generator Owners may have distance relays applied to backup transmission protection
or backup protection to the GSU transformer. The Generator Owner may have relays installed at
the generator terminals or the high-voltage side of the GSU transformer.
Exclusion of Time Based Load-Responsive Protective Relays
The purpose of the standard is “[t]o ensure that load-responsive protective relays are expected to
not trip in response to stable power swings during non-Fault conditions.” Load-responsive, highspeed tripping protective relays pose the highest risk of operating during a power swing. Because
of this, high-speed tripping protective relays and relays with a time delay of less than 15 cycles are
included in the standard; whereas other relays (i.e., Zones 2 and 3) with a time delay of 15 cycles
or greater are excluded. The time delay used for exclusion on some load-responsive protective
relays is based on the maximum expected time that load-responsive protective relays would be
exposed to a stable power swing with a slow slip rate frequency.
In order to establish a time delay that distinguishes a high-risk load-responsive protective relay
from one that has a time delay for tripping (lower-risk), a sample of swing rates were calculated
based on a stable power swing entering and leaving the impedance characteristic as shown in Table
1. For a relay impedance characteristic that has a power swing entering and leaving, beginning at
90 degrees with a termination at 120 degrees before exiting the zone, the zone timer must be greater
than the calculated time the stable power swing is inside the relay’s operating zone to not trip in
response to the stable power swing.
Eq. (1)
(120° − 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑜𝑜𝑜𝑜 𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒 𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖 𝑡𝑡ℎ𝑒𝑒 𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟 𝑐𝑐ℎ𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎) × 60
𝑍𝑍𝑍𝑍𝑍𝑍𝑍𝑍 𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 > 2 × �
�
(360 × 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅)
Table 1: Swing Rates
Zone Timer
(Cycles)
Slip Rate
(Hz)
10
1.00
15
0.67
20
0.50
30
0.33
With a minimum zone timer of 15 cycles, the corresponding slip rate of the system is 0.67 Hz.
This represents an approximation of a slow slip rate during a system Disturbance. Longer time
delays allow for slower slip rates.
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Application to Transmission Elements
Criterion A in PRC-026-1 – Attachment B describes an unstable power swing region that is formed
by the union of three shapes in the impedance (R-X) plane. The first shape is a lower loss-ofsynchronism circle based on a ratio of the sending-end to receiving-end voltages of 0.7 (i.e., E S /
E R = 0.7 / 1.0 = 0.7). The second shape is an upper loss-of-synchronism circle based on a ratio of
the sending-end to receiving-end voltages of 1.43 (i.e., E S / E R = 1.0 / 0.7 = 1.43). The third shape
is a lens that connects the endpoints of the total system impedance together by varying the sendingend and receiving-end system voltages from 0.0 to 1.0 per unit, while maintaining a constant
system separation angle across the total system impedance (with the parallel transfer impedance
removed—see Figures 1 through 5). The total system impedance is derived from a two-bus
equivalent network and is determined by summing the sending-end source impedance, the line
impedance (excluding the Thévenin equivalent transfer impedance), and the receiving-end source
impedance as shown in Figures 6 and 7. Establishing the total system impedance provides a
conservative condition that will maximize the security of the relay against various system
conditions. The smallest total system impedance represents a condition where the size of the lens
characteristic in the R-X plane is smallest and is a conservative operating point from the standpoint
of ensuring a load-responsive protective relay is expected to not trip given a predetermined angular
displacement between the sending-end and receiving-end voltages. The smallest total system
impedance results when all generation is in service and all transmission BES Elements are modeled
in their “normal” system configuration (PRC-026-1 – Attachment B, Criterion A). The parallel
transfer impedance is removed to represent a likely condition where parallel Elements may be lost
during the disturbance, and the loss of these Elements magnifies the sensitivity of the loadresponsive relays on the parallel line by removing the “infeed effect” (i.e., the apparent impedance
sensed by the relay is decreased as a result of the loss of the transfer impedance, thus making the
relay more likely to trip for a stable power swing—See Figures 13 and 14).
The sending-end and receiving-end source voltages are varied from 0.7 to 1.0 per unit to form the
lower and upper loss-of-synchronism circles. The ratio of these two voltages is used in the
calculation of the loss-of-synchronism circles, and result in a ratio range from 0.7 to 1.43.
Eq. (2)
𝐸𝐸𝑆𝑆 0.7
=
= 0.7
𝐸𝐸𝑅𝑅 1.0
Eq. (3):
𝐸𝐸𝑆𝑆 1.0
=
= 1.43
𝐸𝐸𝑅𝑅 0.7
The internal generator voltage during severe power swings or transmission system fault conditions
will be greater than zero due to voltage regulator support. The voltage ratio of 0.7 to 1.43 is chosen
to be more conservative than the PRC-023 14 and PRC-025 15 NERC Reliability Standards where a
lower bound voltage of 0.85 per unit voltage is used. A ±15% internal generator voltage range was
chosen as a conservative voltage range for calculation of the voltage ratio used to calculate the
loss-of-synchronism circles. For example, the voltage ratio using these voltages would result in a
ratio range from 0.739 to 1.353.
14
Transmission Relay Loadability
15
Generator Relay Loadability
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Eq. (4)
𝐸𝐸𝑆𝑆 0.85
=
= 0.739
𝐸𝐸𝑅𝑅 1.15
Eq. (5):
𝐸𝐸𝑆𝑆 1.15
=
= 1.353
𝐸𝐸𝑅𝑅 0.85
The lower ratio is rounded down to 0.7 to be more conservative, allowing a voltage range of 0.7
to 1.0 per unit to be used for the calculation of the loss-of-synchronism circles. 16
When the parallel transfer impedance is included in the model, the division of current through the
parallel transfer impedance path results in actual measured relay impedances that are larger than
those measured when the parallel transfer impedance is removed (i.e., infeed effect), which would
make it more likely for an impedance relay element to be completely contained within the unstable
power swing region as shown in Figure 11. If the transfer impedance is included in the evaluation,
a distance relay element could be deemed as meeting PRC-026-1 – Attachment B criteria and, in
fact would be secure, assuming all Elements were in their normal state. In this case, the distance
relay element could trip in response to a stable power swing during an actual event if the system
was weakened (i.e., a higher transfer impedance) by the loss of a subset of lines that make up the
parallel transfer impedance as shown in Figure 10. This could happen because the subset of lines
that make up the parallel transfer impedance tripped on unstable swings, contained the initiating
fault, and/or were lost due to operation of breaker failure or remote back-up protection schemes.
Table 10 shows the percent size increase of the lens shape as seen by the relay under evaluation
when the parallel transfer impedance is included. The parallel transfer impedance has minimal
effect on the apparent size of the lens shape as long as the parallel transfer impedance is at least
10 multiples of the parallel line impedance (less than 5% lens shape expansion), therefore, its
removal has minimal impact, but results in a slightly more conservative, smaller lens shape.
Parallel transfer impedances of 5 multiples of the parallel line impedance or less result in an
apparent lens shape size of 10% or greater as seen by the relay. If two parallel lines and a parallel
transfer impedance tie the sending-end and receiving-end buses together, the total parallel transfer
impedance will be one or less multiples of the parallel line impedance, resulting in an apparent
lens shape size of 45% or greater. It is a realistic contingency that the parallel line could be outof-service, leaving the parallel transfer impedance making up the rest of the system in parallel with
the line impedance. Since it is not known exactly which lines making up the parallel transfer
impedance will be out of service during a major system disturbance, it is most conservative to
assume that all of them are out, leaving just the line under evaluation in service.
Either the saturated transient or sub-transient direct axis reactance may be used for machines in
the evaluation because they are smaller than the un-saturated reactances. Since saturated subtransient generator reactances are smaller than the transient or synchronous reactances, the use of
sub-transient reactances will result in a smaller source impedance and a smaller unstable power
swing region in the graphical analysis as shown in Figures 8 and 9. Because power swings occur
in a time frame where generator transient reactances will be prevalent, it is acceptable to use
saturated transient reactances instead of saturated sub-transient reactances. Because some short-
16
Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations,
April 2004, Section 6 (The Cascade Stage of the Blackout), p. 94 under “Why the Generators Tripped Off,” states,
“Some generator undervoltage relays were set to trip at or above 90% voltage. However, a motor stalls out at about
70% voltage and a motor starter contactor drops out around 75%, so if there is a compelling need to protect the
turbine from the system the under-voltage trigger point should be no higher than 80%.”
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circuit models may not include transient reactances, the use of sub-transient reactances is also
acceptable because it produces more conservative results. For this reason, either value is acceptable
when determining the system source impedances (PRC-026-1 – Attachment B, Criterion A and B,
No. 3).
Saturated reactances are used in short-circuit programs that produce the system impedance
mentioned above. Planning and stability software generally use un-saturated reactances. Generator
models used in transient stability analyses recognize that the extent of the saturation effect depends
upon both rotor (field) and stator currents. Accordingly, they derive the effective saturated
parameters of the machine at each instant by internal calculation from the specified (constant)
unsaturated values of machine reactances and the instantaneous internal flux level. The specific
assumptions regarding which inductances are affected by saturation, and the relative effect of that
saturation, are different for the various generator models used. Thus, unsaturated values of all
machine reactances are used in setting up planning and stability software data, and the appropriate
set of open-circuit magnetization curve data is provided for each machine.
Saturated reactance values are smaller than unsaturated reactance values and are used in shortcircuit programs owned by the Generator and Transmission Owners. Because of this, saturated
reactance values are to be used in the development of the system source impedances.
The source or system equivalent impedances can be obtained by a number of different methods
using commercially available short-circuit calculation tools. 17 Most short-circuit tools have a
network reduction feature that allows the user to select the local and remote terminal buses to
retain. The first method reduces the system to one that contains two buses, an equivalent generator
at each bus (representing the source impedances at the sending-end and receiving-end), and two
parallel lines; one being the line impedance of the protected line with relays being analyzed, the
other being the parallel transfer impedance representing all other combinations of lines that
connect the two buses together as shown in Figure 6. Another conservative method is to open both
ends of the line being evaluated, and apply a three-phase bolted fault at each bus to determine the
Thévenin equivalent impedance at each bus. The source impedances are set equal to the Thévenin
equivalent impedances and will be less than or equal to the actual source impedances calculated
by the network reduction method. Either method can be used to develop the system source
impedances at both ends.
The two bullets of PRC-026-1 – Attachment B, Criterion A, No. 1, identify the system separation
angles used to identify the size of the power swing stability boundary for evaluating loadresponsive protective relay impedance elements. The first bullet of PRC-026-1 – Attachment B,
Criterion A, No. 1 evaluates a system separation angle of at least 120 degrees that is held constant
while varying the sending-end and receiving-end source voltages from 0.7 to 1.0 per unit, thus
creating an unstable power swing region about the total system impedance in Figure 1. This
unstable power swing region is compared to the tripping portion of the distance relay
characteristic; that is, the portion that is not supervised by load encroachment, blinders, or some
other form of supervision as shown in Figure 12 that restricts the distance element from tripping
17
Demetrios A. Tziouvaras and Daqing Hou, Appendix in Out-Of-Step Protection Fundamentals and
Advancements, April 17, 2014: https://www.selinc.com.
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for heavy, balanced load conditions. If the tripping portion of the impedance characteristics are
completely contained within the unstable power swing region, the relay impedance element meets
Criterion A in PRC-026-1 – Attachment B. A system separation angle of 120 degrees was chosen
for the evaluation because it is generally accepted in the industry that recovery for a swing beyond
this angle is unlikely to occur. 18
The second bullet of PRC-026-1 – Attachment B, Criterion A, No. 1 evaluates impedance relay
elements at a system separation angle of less than 120 degrees, similar to the first bullet described
above. An angle less than 120 degrees may be used if a documented stability analysis demonstrates
that the power swing becomes unstable at a system separation angle of less than 120 degrees.
The exclusion of relay elements supervised by Power Swing Blocking (PSB) in PRC-026-1 –
Attachment A allows the Generator Owner or Transmission Owner to exclude protective relay
elements if they are blocked from tripping by PSB relays. A PSB relay applied and set according
to industry accepted practices prevent supervised load-responsive protective relays from tripping
in response to power swings. Further, PSB relays are set to allow dependable tripping of supervised
elements. The criteria in PRC-026-1 – Attachment B specifically applies to unsupervised elements
that could trip for stable power swings. Therefore, load-responsive protective relay elements
supervised by PSB can be excluded from the Requirements of this standard.
18
“The critical angle for maintaining stability will vary depending on the contingency and the system condition at
the time the contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is
marginal and 120 degrees is generally accepted as an appropriate basis for setting out‐of‐step protection. Given the
importance of separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a
proper balance between dependable tripping for unstable power swings and secure operation for stable power
swings.” NERC System Protection and Control Subcommittee, Protection System Response to Power Swings,
August 2013: http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20
SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf), p. 28.
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Figure 1: An enlarged graphic illustrating the unstable power swing region formed by the union
of three shapes in the impedance (R-X) plane: Shape 1) Lower loss-of-synchronism circle,
Shape 2) Upper loss-of-synchronism circle, and Shape 3) Lens. The mho element characteristic
is completely contained within the unstable power swing region (i.e., it does not intersect any
portion of the unstable power swing region), therefore it meets PRC-026-1 – Attachment B,
Criterion A, No. 1.
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PRC-026-1 – Application Guidelines
Figure 2: Full graphic of the unstable power swing region formed by the union of the three
shapes in the impedance (R-X) plane: Shape 1) Lower loss-of-synchronism circle, Shape 2)
Upper loss-of-synchronism circle, and Shape 3) Lens. The mho element characteristic is
completely contained within the unstable power swing region, therefore it meets PRC-26-1 –
Attachment B, Criterion A, No.1.
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PRC-026-1 – Application Guidelines
Figure 3: System impedances as seen by Relay R (voltage connections are not shown).
Figure 4: The defining unstable power swing region points where the lens shape intersects the
lower and upper loss-of-synchronism circle shapes and where the lens intersects the equal EMF
(electromotive force) power swing.
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PRC-026-1 – Application Guidelines
Figure 5: Full table of 31 detailed lens shape point calculations. The bold highlighted rows
correspond to the detailed calculations in Tables 2-7.
Table 2: Example Calculation (Lens Point 1)
This example is for calculating the impedance the first point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) leading
the receiving-end voltage (E R ) by 120 degrees. See Figures 3 and 4.
Eq. (6)
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
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Table 2: Example Calculation (Lens Point 1)
𝐸𝐸𝑆𝑆 =
Eq. (7)
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Positive sequence impedance data (with transfer impedance Z TR set to a large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (8)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (9)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (10)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50 )Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,511∠71.3° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (11)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
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Table 2: Example Calculation (Lens Point 1)
(4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (12)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10) Ω × 4,511∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,757∠106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (13)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,757∠106.1° 𝑉𝑉
4,511∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 17.434 + 𝑗𝑗12.113 Ω
Table 3: Example Calculation (Lens Point 2)
This example is for calculating the impedance second point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) at 70% of
the receiving-end voltage (E R ) and leading the receiving-end voltage by 120 degrees. See
Figures 3 and 4.
Eq. (14)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (15)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
× 70%
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 92,953.7∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
× 0.70
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Positive sequence impedance data (with transfer impedance Z TR set to a large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
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𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
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Table 3: Example Calculation (Lens Point 2)
Total impedance between the generators.
Eq. (16)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (17)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (18)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
92,953.7∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠77° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (19)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠77° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠77° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (20)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 92,953∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 )Ω × 3,854∠77° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 65,271∠99° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (21)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
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Table 3: Example Calculation (Lens Point 2)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
65,271∠99° 𝑉𝑉
3,854∠77° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 15.676 + 𝑗𝑗6.41 Ω
Table 4: Example Calculation (Lens Point 3)
This example is for calculating the impedance third point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (E R ) at 70%
of the sending-end voltage (E S ) and the sending-end voltage leading the receiving-end voltage
by 120 degrees. See Figures 3 and 4.
Eq. (22)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (23)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
× 70%
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 92,953.7∠0° 𝑉𝑉
× 0.70
Positive sequence impedance data (with transfer impedance Z TR set to a large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (24)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (25)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
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Table 4: Example Calculation (Lens Point 3)
Total system current from sending-end source.
Eq. (26)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 92,953.7∠0° 𝑉𝑉
(10 + 𝑗𝑗50) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠65.5° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (27)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠65.5° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠65.5° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (28)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10) Ω × 3,854∠65.5° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 98,265∠110.6° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (29)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
98,265∠110.6° 𝑉𝑉
3,854∠65.5° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 18.005 + 𝑗𝑗18.054 Ω
Table 5: Example Calculation (Lens Point 4)
This example is for calculating the impedance fourth point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) leading
the receiving-end voltage (E R ) by 240 degrees. See Figures 3 and 4.
Eq. (30)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
√3
230,000∠240° 𝑉𝑉
√3
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Table 5: Example Calculation (Lens Point 4)
Eq. (31)
𝐸𝐸𝑆𝑆 = 132,791∠240° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Positive sequence impedance data (with transfer impedance Z TR set to a large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (32)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (33)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (34)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠240° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50 )Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,511∠131.3° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (35)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 4,511∠131.1° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 4,511∠131.1° 𝐴𝐴
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Table 5: Example Calculation (Lens Point 4)
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (36)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 ) Ω × 4,511∠131.1° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,756∠ − 106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (37)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,756∠ − 106.1° 𝑉𝑉
4,511∠131.1° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −11.434 + 𝑗𝑗17.887 Ω
Table 6: Example Calculation (Lens Point 5)
This example is for calculating the impedance fifth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) at 70% of
the receiving-end voltage (E R ) and leading the receiving-end voltage by 240 degrees. See
Figures 3 and 4.
Eq. (38)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (39)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
× 70%
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 92,953.7∠240° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
× 0.70
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Positive sequence impedance data (with transfer impedance Z TR set to a large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (40)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
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Table 6: Example Calculation (Lens Point 5)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (41)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10 Ω) + (4 + 𝑗𝑗20 Ω) + (4 + 𝑗𝑗20 Ω)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (42)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
92,953.7∠240° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠125.5° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (43)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿 = 3,854∠125.5° 𝐴𝐴 ×
𝐼𝐼𝐿𝐿 = 3,854∠125.5° 𝐴𝐴
(4 + 𝑗𝑗20) × 1010 Ω
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (44)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 92,953.7∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 ) Ω × 3,854∠125.5° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 65,270.5∠ − 99.4° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (45)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
65,270.5∠ − 99.4° 𝑉𝑉
3,854∠125.5° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −12.005 + 𝑗𝑗11.946 Ω
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Table 7: Example Calculation (Lens Point 6)
This example is for calculating the impedance sixth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (E R ) at 70%
of the sending-end voltage (E S ) and the sending-end voltage leading the receiving-end voltage
by 240 degrees. See Figures 3 and 4.
Eq. (46)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠240° 𝑉𝑉
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
Eq. (47)
𝐸𝐸𝑅𝑅 =
× 70%
√3
230,000∠0° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
× 0.70
√3
𝐸𝐸𝑅𝑅 = 92,953.7∠0° 𝑉𝑉
Positive sequence impedance data (with transfer impedance Z TR set to a large value).
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Given:
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
Total impedance between the generators.
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
Eq. (48)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
Eq. (49)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
Eq. (50)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠240° 𝑉𝑉 − 92,953.7∠0° 𝑉𝑉
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠137.1° 𝐴𝐴
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Table 7: Example Calculation (Lens Point 6)
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
𝑍𝑍𝑇𝑇𝑇𝑇
Eq. (51)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
(4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠137.1° 𝐴𝐴 ×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠137.1° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (52)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 ) Ω × 3,854∠137.1° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 98,265∠ − 110.6° 𝑉𝑉
The impedance seen by the relay on Z L .
𝑉𝑉𝑆𝑆
Eq. (53)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝐼𝐼𝐿𝐿
98,265∠ − 110.6° 𝑉𝑉
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
3,854∠137.1° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −9.676 + 𝑗𝑗23.59 Ω
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Figure 6: Reduced two bus system with sending-end source impedance Z S , receiving-end
source impedance Z R , line impedance Z L , and parallel transfer impedance Z TR .
Figure 7: Reduced two bus system with sending-end source impedance Z S , receiving-end
source impedance Z R , and line impedance Z L with the parallel transfer impedance Z TR removed.
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Figure 8: A strong-source system with a line impedance of Z L = 20.4 ohms (i.e., the thicker red
line). This mho element characteristic (i.e., the blue circle) does not meet the PRC-026-1 –
Attachment B, Criterion A because it is not completely contained within the unstable power
swing region (i.e., the orange characteristic).
Figure 8 above represents a heavily-loaded system with all generation in service and all
transmission BES Elements in their normal operating state. The mho element characteristic (set at
137% of Z L ) extends into the unstable power swing region (i.e., the orange characteristic). Using
the strongest source system is more conservative because it shrinks the unstable power swing
region, bringing it closer to the mho element characteristic. This figure also graphically represents
the effect of a system strengthening over time and this is the reason for re-evaluation if the relay
has not been evaluated in the last five calendar years. Figure 9 below depicts a relay that meets the
PRC-026-1 – Attachment B, Criterion A. Figure 8 depicts the same relay with the same setting
five years later, where each source has strengthened by about 10% and now the same mho element
characteristic does not meet Criterion A.
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Figure 9: A weak-source system with a line impedance of Z L = 20.4 ohms (i.e., the thicker red
line). This mho element characteristic (i.e., the blue circle) meets the PRC-026-1 – Attachment
B, Criterion A because it is completely contained within the unstable power swing region (i.e.,
the orange characteristic).
Figure 9 above represents a lightly-loaded system, using a minimum generation profile. The mho
element characteristic (set at 137% of Z L ) does not extend into the unstable power swing region
(i.e., the orange characteristic). Using a weaker source system expands the unstable power swing
region away from the mho element characteristic.
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Figure 10: This is an example of an unstable power swing region (i.e., the orange characteristic)
with the parallel transfer impedance removed. This relay mho element characteristic (i.e., the
blue circle) does not meet PRC-026-1 – Attachment B, Criterion A because it is not completely
contained within the unstable power swing region.
Table 8: Example Calculation (Parallel Transfer Impedance Removed)
Calculations for the point at 120 degrees with equal source impedances. The total system current
equals the line current. See Figure 10.
Eq. (54)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
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Table 8: Example Calculation (Parallel Transfer Impedance Removed)
Eq. (55)
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given impedance data.
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (56)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (57)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (58)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,511∠71.3° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (59)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴 ×
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴
(4 + 𝑗𝑗20) × 1010 Ω
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
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Table 8: Example Calculation (Parallel Transfer Impedance Removed)
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (60)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 Ω) × 4,511∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,757∠106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (61)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,757∠106.1° 𝑉𝑉
4,511∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 17.434 + 𝑗𝑗12.113 Ω
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Figure 11: This is an example of an unstable power swing region (i.e., the orange characteristic)
with the parallel transfer impedance included causing the mho element characteristic (i.e., the
blue circle) to appear to meet the PRC-026-1 – Attachment B, Criterion A because it is
completely contained within the unstable power swing region. Including the parallel transfer
impedance in the calculation is not allowed by the PRC-026-1 – Attachment B, Criterion A.
In Figure 11 above, the parallel transfer impedance is 5 times the line impedance. The unstable
power swing region has expanded out beyond the mho element characteristic due to the infeed
effect from the parallel current through the parallel transfer impedance, thus allowing the mho
element characteristic to appear to meet the PRC-026-1 – Attachment B, Criterion A. Including
the parallel transfer impedance in the calculation is not allowed by the PRC-026-1 – Attachment
B, Criterion A.
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Table 9: Example Calculation (Parallel Transfer Impedance Included)
Calculations for the point at 120 degrees with equal source impedances. The total system current
does not equal the line current. See Figure 11.
Eq. (62)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (63)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given impedance data.
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 5
𝑍𝑍𝑇𝑇𝑇𝑇 = (4 + 𝑗𝑗20) Ω × 5
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 20 + 𝑗𝑗100 Ω
Total impedance between the generators.
Eq. (64)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
(4 + 𝑗𝑗20) Ω × (20 + 𝑗𝑗100) Ω
(4 + 𝑗𝑗20) Ω + (20 + 𝑗𝑗100) Ω
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 3.333 + 𝑗𝑗16.667 Ω
Total system impedance.
Eq. (65)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (3.333 + 𝑗𝑗16.667) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 9.333 + 𝑗𝑗46.667 Ω
Total system current from sending-end source.
Eq. (66)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
9.333 + 𝑗𝑗46.667 Ω
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Table 9: Example Calculation (Parallel Transfer Impedance Included)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,833∠71.3° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (67)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿 = 4,833∠71.3° 𝐴𝐴 ×
𝐼𝐼𝐿𝐿 = 4,027.4∠71.3° 𝐴𝐴
(20 + 𝑗𝑗100) Ω
(4 + 𝑗𝑗20) Ω + (20 + 𝑗𝑗100) Ω
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (68)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 Ω) × 4,833∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 93,417∠104.7° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (69)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
93,417∠104.7° 𝑉𝑉
4,027∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 19.366 + 𝑗𝑗12.767 Ω
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Table 10: Percent Increase of a Lens Due To Parallel Transfer Impedance.
The following demonstrates the percent size increase of the lens characteristic for Z TR in
multiples of Z L with the parallel transfer impedance included.
Z TR in multiples of Z L
Percent increase of lens with equal EMF
sources (Infinite source as reference)
Infinite
N/A
1000
0.05%
100
0.46%
10
4.63%
5
9.27%
2
23.26%
1
46.76%
0.5
94.14%
0.25
189.56%
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Figure 12: The tripping portion of the mho element characteristic (i.e., the blue circle) not
blocked by load encroachment (i.e., the parallel green lines) is completely contained within the
unstable power swing region (i.e., the orange characteristic). Therefore, the mho element
characteristic meets the PRC-026-1 – Attachment B, Criterion A.
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Figure 13: The infeed diagram shows the impedance in front of the relay R with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes Z L + Z R .
Table 11: Calculations (System Apparent Impedance in the forward direction)
The following equations are provided for calculating the apparent impedance back to the E R
source voltage as seen by relay R. Infeed equations from V S to source E R where E R = 0. See
Figure 13.
Eq. (70)
Eq. (71)
Eq. (72)
Eq. (73)
Eq. (74)
Eq. (75)
Eq. (76)
Eq. (77)
Eq. (78)
Eq. (79)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑆𝑆 − 𝑉𝑉𝑅𝑅
𝑍𝑍𝐿𝐿
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑅𝑅 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑅𝑅
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝐿𝐿 =
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅
𝑍𝑍𝑅𝑅
Since 𝐸𝐸𝑅𝑅 = 0
Rearranged:
𝑉𝑉𝑆𝑆 − 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑅𝑅
𝑍𝑍𝐿𝐿
𝑉𝑉𝑅𝑅 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑅𝑅
𝑉𝑉𝑆𝑆 − [(𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇 ) × 𝑍𝑍𝑅𝑅 ]
𝑍𝑍𝐿𝐿
𝑉𝑉𝑆𝑆 = (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝐿𝐿 ) + (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝑅𝑅 ) + (𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅 )
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅
𝐼𝐼𝑇𝑇𝑇𝑇
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 +
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
�
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝑇𝑇𝑇𝑇 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
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Table 11: Calculations (System Apparent Impedance in the forward direction)
Eq. (80)
𝐼𝐼𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
=
𝐼𝐼𝐿𝐿
𝑍𝑍𝑇𝑇𝑇𝑇
The infeed equations shows the impedance in front of the relay R (Figure 13) with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes Z L + Z R .
Eq. (81)
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
Figure 14: The infeed diagram shows the impedance behind relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes Z S .
Table 12: Calculations (System Apparent Impedance in the Reverse Direction)
The following equations are provided for calculating the apparent impedance back to the E S
source voltage as seen by relay R. Infeed equations from V R back to source E S where E S = 0.
See Figure 14.
Eq. (82)
Eq. (83)
Eq. (84)
Eq. (85)
Eq. (86)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅 − 𝑉𝑉𝑆𝑆
𝑍𝑍𝐿𝐿
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑆𝑆 − 𝐸𝐸𝑆𝑆
𝑍𝑍𝑆𝑆
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑆𝑆
𝑍𝑍𝑆𝑆
𝑉𝑉𝑅𝑅 − 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑆𝑆
𝑍𝑍𝐿𝐿
Since 𝐸𝐸𝑠𝑠 = 0
Rearranged:
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 4: December 5, 2014)
𝑉𝑉𝑆𝑆 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑆𝑆
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Table 12: Calculations (System Apparent Impedance in the Reverse Direction)
Eq. (87)
Eq. (88)
Eq. (89)
Eq. (90)
Eq. (91)
Eq. (92)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅 − [(𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇 ) × 𝑍𝑍𝑆𝑆 ]
𝑍𝑍𝐿𝐿
𝑉𝑉𝑅𝑅 = (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝐿𝐿 ) + (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝑆𝑆 ) + (𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅𝑅𝑅 )
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑅𝑅
𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑆𝑆
𝐼𝐼𝑇𝑇𝑇𝑇
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 +
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 × �1 +
�
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝑇𝑇𝑇𝑇 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
=
𝐼𝐼𝐿𝐿
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
The infeed equations shows the impedance behind relay R (Figure 14) with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes Z S .
Eq. (93)
Eq. (94)
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
As seen by relay R at the receiving-end of
the line.
Subtract Z L for relay R impedance as seen
at sending-end of the line.
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Figure 15: Out-of-step trip (OST) inner blinder (i.e., the parallel green lines) meets the PRC026-1 – Attachment B, Criterion A because the inner OST blinder initiates tripping either OnThe-Way-In or On-The-Way-Out. Since the inner blinder is completely contained within the
unstable power swing region (i.e., the orange characteristic), it meets the PRC-026-1 –
Attachment B, Criterion A.
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Table 13: Example Calculation (Voltage Ratios)
These calculations are based on the loss-of-synchronism characteristics for the cases of N < 1
and N > 1 as found in the Application of Out-of-Step Blocking and Tripping Relays, GER-3180,
p. 12, Figure 3. 19 The GE illustration shows the formulae used to calculate the radius and center
of the circles that make up the ends of the portion of the lens.
Voltage ratio equations, source impedance equation with infeed formulae applied, and circle
equations.
Given:
Eq. (95)
𝐸𝐸𝑆𝑆 = 0.7
𝑁𝑁 =
|𝐸𝐸𝑆𝑆 | 0.7
=
= 0.7
|𝐸𝐸𝑅𝑅 | 1.0
𝐸𝐸𝑅𝑅 = 1.0
The total system impedance as seen by the relay with infeed formulae applied.
Given:
Given:
Eq. (96)
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = (4 + 𝑗𝑗20) × 1010 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿
� + �𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
��
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
The calculated coordinates of the lower loss-of-synchronism circle center.
Eq. (97)
𝑍𝑍𝐶𝐶1 = − �𝑍𝑍𝑆𝑆 × �1 +
𝑁𝑁 2 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝑍𝑍𝐿𝐿
�� − �
�
𝑍𝑍𝑇𝑇𝑇𝑇
1 − 𝑁𝑁 2
𝑍𝑍𝐶𝐶1 = − � (2 + 𝑗𝑗10) Ω × �1 +
(4 + 𝑗𝑗20) Ω
0.72 × (10 + 𝑗𝑗50) Ω
−
�
�
��
(4 + 𝑗𝑗20) × 1010 Ω
1 − 0.72
𝑍𝑍𝐶𝐶1 = −11.608 − 𝑗𝑗58.039 Ω
The calculated radius of the lower loss-of-synchronism circle.
Eq. (98)
𝑁𝑁 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
�
1 − 𝑁𝑁 2
0.7 × (10 + 𝑗𝑗50) Ω
𝑟𝑟𝑎𝑎 = �
�
1 − 0.72
𝑟𝑟𝑎𝑎 = �
𝑟𝑟𝑎𝑎 = 69.987 Ω
The calculated coordinates of the upper loss-of-synchronism circle center.
Given:
19
𝐸𝐸𝑆𝑆 = 1.0
𝐸𝐸𝑅𝑅 = 0.7
http://store.gedigitalenergy.com/faq/Documents/Alps/GER-3180.pdf
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Table 13: Example Calculation (Voltage Ratios)
Eq. (99)
Eq. (100)
𝑁𝑁 =
|𝐸𝐸𝑆𝑆 | 1.0
=
= 1.43
|𝐸𝐸𝑅𝑅 | 0.7
𝑍𝑍𝐶𝐶2 = 𝑍𝑍𝐿𝐿 + �𝑍𝑍𝑅𝑅 × �1 +
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝑍𝑍𝐿𝐿
�� + � 2
�
𝑍𝑍𝑇𝑇𝑇𝑇
𝑁𝑁 − 1
𝑍𝑍𝐶𝐶2 = 4 + 𝑗𝑗20 Ω + � (4 + 𝑗𝑗20) Ω × �1 +
𝑍𝑍𝐶𝐶2 = 17.608 + 𝑗𝑗88.039 Ω
(4 + 𝑗𝑗20) Ω
(10 + 𝑗𝑗50) Ω
�
�� + �
10
(4 + 𝑗𝑗20) × 10 Ω
1.432 − 1
The calculated radius of the upper loss-of-synchronism circle.
Eq. (101)
𝑁𝑁 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
�
𝑁𝑁 2 − 1
1.43 × (10 + 𝑗𝑗50) Ω
𝑟𝑟𝑏𝑏 = �
�
1.432 − 1
𝑟𝑟𝑏𝑏 = �
𝑟𝑟𝑏𝑏 = 69.987 Ω
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Figure 15a: Lower circle loss-of-synchronism region showing the coordinates of the circle
center and the circle radius.
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Figure 15b: Lower circle loss-of-synchronism region showing the first three steps to calculate
the coordinates of the points on the circle. 1) Identify the lower circle loss-of-synchronism
points that intersect the lens shape where the sending-end to receiving-end voltage ratio is 0.7
(see lens shape calculations in Tables 2-7). 2) Calculate the distance between the two lower
circle loss-of-synchronism points identified in Step 1. 3) Calculate the angle of arc that
connects the two lower circle loss-of-synchronism points identified in Step 1.
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Figure 15c: Lower circle loss-of-synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1)
Calculate the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4)
Calculate the angle step size for the desired number of points.
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Figure 15d: Lower circle loss-of-synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R–X coordinates.
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Figure 15e: Upper circle loss-of-synchronism region showing the coordinates of the circle
center and the circle radius.
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Figure 15f: Upper circle loss-of-synchronism region showing the first three steps to calculate
the coordinates of the points on the circle. 1) Identify the upper circle points that intersect the
lens shape where the sending-end to receiving-end voltage ratio is 1.43 (see lens shape
calculations in Tables 2-7). 2) Calculate the distance between the two upper circle points
identified in Step 1. 3) Calculate the angle of arc that connects the two upper circle points
identified in Step 1.
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Figure 15g: Upper circle loss-of-synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1) Calculate
the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4) Calculate the angle
step size for the desired number of points.
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Figure 15h: Upper circle loss-of-synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R-X coordinates.
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Figure 15i: Full tables of calculated lower and upper loss-of-synchronism circle coordinates.
The highlighted row is the detailed calculated points in Figures 15d and 15h.
Application Specific to Criterion B
The PRC-026-1 – Attachment B, Criterion B evaluates overcurrent elements used for tripping. The
same criteria as PRC-026-1 – Attachment B, Criterion A is used except for an additional criterion
(No. 4) that calculates a current magnitude based upon generator internal voltage of 1.05 per unit.
A value of 1.05 per unit generator voltage is used to establish a minimum pickup current value for
overcurrent relays that have a time delay less than 15 cycles. The sending-end and receiving-end
voltages are established at 1.05 per unit at 120 degree system separation angle. The 1.05 per unit
is the typical upper end of the operating voltage, which is also consistent with the maximum power
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transfer calculation using actual system source impedances in the PRC-023 NERC Reliability
Standard. The formulas used to calculate the current are in Table 14 below.
Table 14: Example Calculation (Overcurrent)
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps secondary times a CT ratio of 160:1 that equals 8,000 amps, primary.
The following calculation is where V S equals the base line-to-ground sending-end generator
source voltage times 1.05 at an angle of 120 degrees, V R equals the base line-to-ground
receiving-end generator internal voltage times 1.05 at an angle of 0 degrees, and Z sys equals the
sum of the sending-end source, line, and receiving-end source impedances in ohms.
Here, the instantaneous phase setting of 8,000 amps is greater than the calculated system current
of 5,716 amps; therefore, it meets PRC-026-1 – Attachment B, Criterion B.
Eq. (102)
𝑉𝑉𝑆𝑆 =
𝑉𝑉𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
× 1.05
√3
230,000∠120° 𝑉𝑉
√3
𝑉𝑉𝑆𝑆 = 139,430∠120° 𝑉𝑉
× 1.05
Receiving-end generator terminal voltage.
Eq. (103)
𝑉𝑉𝑅𝑅 =
𝑉𝑉𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
× 1.05
√3
230,000∠0° 𝑉𝑉
√3
𝑉𝑉𝑅𝑅 = 139,430∠0° 𝑉𝑉
× 1.05
The total impedance of the system (Z sys ) equals the sum of the sending-end source impedance
(Z S ), the impedance of the line (Z L ), and receiving-end impedance (Z R ) in ohms.
Given:
Eq. (104)
𝑍𝑍𝑆𝑆 = 3 + 𝑗𝑗26 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝐿𝐿 = 1.3 + 𝑗𝑗8.7 Ω
𝑍𝑍𝑅𝑅 = 0.3 + 𝑗𝑗7.3 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (3 + 𝑗𝑗26) Ω + (1.3 + 𝑗𝑗8.7) Ω + (0.3 + 𝑗𝑗7.3) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 4.6 + 𝑗𝑗42 Ω
Total system current.
Eq. (105)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
(𝑉𝑉𝑆𝑆 − 𝑉𝑉𝑅𝑅 )
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
(139,430∠120° 𝑉𝑉 − 139,430∠0° 𝑉𝑉)
(4.6 + 𝑗𝑗42) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 5,715.82∠66.25° 𝐴𝐴
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Application Specific to Three-Terminal Lines
If a three-terminal line is identified as an Element that is susceptible to a power swing based on
Requirement R1, the load-responsive protective relays at each end of the three-terminal line must
be evaluated.
As shown in Figure 15j, the source impedances at each end of the line can be obtained from the
similar short circuit calculation as for the two-terminal line (assuming the parallel transfer
impedances are ignored).
EA
A
B
ZSA
ZL2
ZL1
R
ZSB
EB
ZL3
C
ZSC
EC
Figure 15j: Three-terminal line. To evaluate the load-responsive protective relays on the threeterminal line at Terminal A, the circuit in Figure 15j is first reduced to the equivalent circuit
shown in Figure 15k. The evaluation process for the load-responsive protective relays on the
line at Terminal A will now be the same as that of the two-terminal line.
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Figure 15k: Three-terminal line reduced to a two-terminal line.
Application to Generation Elements
As with transmission BES Elements, the determination of the apparent impedance seen at an
Element located at, or near, a generation Facility is complex for power swings due to various
interdependent quantities. These variances in quantities are caused by changes in machine internal
voltage, speed governor action, voltage regulator action, the reaction of other local generators, and
the reaction of other interconnected transmission BES Elements as the event progresses through
the time domain. Though transient stability simulations may be used to determine the apparent
impedance for verifying load-responsive relay settings, 20,21 Requirement R2, PRC-026-1 –
Attachment B, Criteria A and B provides a simplified method for evaluating the load-responsive
protective relay’s susceptibility to tripping in response to a stable power swing without requiring
stability simulations.
In general, the electrical center will be in the transmission system for cases where the generator is
connected through a weak transmission system (high external impedance). In other cases where
the generator is connected through a strong transmission system, the electrical center could be
inside the unit connected zone. 22 In either case, load-responsive protective relays connected at the
generator terminals or at the high-voltage side of the generator step-up (GSU) transformer may be
challenged by power swings. Relays that may be challenged by power swings will be determined
by the Planning Coordinator in Requirement R1 or by the Generator Owner after becoming aware
of a generator, transformer, or transmission line BES Element that tripped 23 in response to a stable
or unstable power swing due to the operation of its protective relay(s) in Requirement R2.
20
Donald Reimert, Protective Relaying for Power Generation Systems, Boca Raton, FL, CRC Press, 2006.
21
Prabha Kundur, Power System Stability and Control, EPRI, McGraw Hill, Inc., 1994.
22
Ibid, Kundur.
23
See Guidelines and Technical Basis section, “Becoming Aware of an Element That Tripped in Response to a
Power Swing,”
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Voltage controlled time-overcurrent and voltage-restrained time-overcurrent relays are excluded
from this standard. When these relays are set based on equipment permissible overload capability,
their operating times are much greater than 15 cycles for the current levels observed during a power
swing.
Instantaneous overcurrent, time-overcurrent, and definite-time overcurrent relays with a time delay
of less than 15 cycles for the current levels observed during a power swing are applicable and are
required to be evaluated for identified Elements.
The generator loss-of-field protective function is provided by impedance relay(s) connected at the
generator terminals. The settings are applied to protect the generator from a partial or complete
loss of excitation under all generator loading conditions and, at the same time, be immune to
tripping on stable power swings. It is more likely that the loss-of-field relay would operate during
a power swing when the automatic voltage regulator (AVR) is in manual mode rather than when
in automatic mode. 24 Figure 16 illustrates the loss-of-field relay in the R-X plot, which typically
includes up to three zones of protection.
Figure 16: An R-X graph of typical impedance settings for loss-of-field relays.
24
John Burdy, Loss-of-excitation Protection for Synchronous Generators GER-3183, General Electric Company.
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Loss-of-field characteristic 40-1 has a wider impedance characteristic (positive offset) than
characteristic 40-2 or characteristic 40-3 and provides additional generator protection for a partial
loss of field or a loss of field under low load (less than 10% of rated). The tripping logic of this
protection scheme is established by a directional contact, a voltage setpoint, and a time delay. The
voltage and time delay add security to the relay operation for stable power swings. Characteristic
40-3 is less sensitive to power swings than characteristic 40-2 and is set outside the generator
capability curve in the leading direction. Regardless of the relay impedance setting, PRC-01925
requires that the “in-service limiters operate before Protection Systems to avoid unnecessary trip”
and “in-service Protection System devices are set to isolate or de-energize equipment in order to
limit the extent of damage when operating conditions exceed equipment capabilities or stability
limits.” Time delays for tripping associated with loss-of-field relays 26,27 have a range from 15
cycles for characteristic 40-2 to 60 cycles for characteristic 40-1 to minimize tripping during stable
power swings. In PRC-026-1, 15 cycles establishes a threshold for applicability; however, it is the
responsibility of the Generator Owner to establish settings that provide security against stable
power swings and, at the same time, dependable protection for the generator.
The simple two-machine system circuit (method also used in the Application to Transmission
Elements section) is used to analyze the effect of a power swing at a generator facility for loadresponsive relays. In this section, the calculation method is used for calculating the impedance
seen by the relay connected at a point in the circuit. 28 The electrical quantities used to determine
the apparent impedance plot using this method are generator saturated transient reactance (X’ d ),
GSU transformer impedance (X GSU ), transmission line impedance (Z L ), and the system equivalent
(Z e ) at the point of interconnection. All impedance values are known to the Generator Owner
except for the system equivalent. The system equivalent is obtainable from the Transmission
Owner. The sending-end and receiving-end source voltages are varied from 0.0 to 1.0 per unit to
form the lens shape portion of the unstable power swing region. The voltage range of 0.7 to 1.0
results in a ratio range from 0.7 to 1.43. This ratio range is used to form the lower and upper lossof-synchronism circle shapes of the unstable power swing region. A system separation angle of
120 degrees is used in accordance with PRC-026-1 – Attachment B criteria for each loadresponsive protective relay evaluation.
Table 15 below is an example calculation of the apparent impedance locus method based on
Figures 17 and 18. 29 In this example, the generator is connected to the 345 kV transmission system
through the GSU transformer and has the listed ratings. Note that the load-responsive protective
relays in this example may have ownership with the Generator Owner or the Transmission Owner.
25
Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection
26
Ibid, Burdy.
27
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
28
Edward Wilson Kimbark, Power System Stability, Volume II: Power Circuit Breakers and Protective Relays,
Published by John Wiley and Sons, 1950.
29
Ibid, Kimbark.
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Figure 17: Simple one-line diagram of the
system to be evaluated.
Figure 18: Simple system equivalent
impedance diagram to be evaluated. 30
Table15: Example Data (Generator)
Input Descriptions
Input Values
Synchronous Generator nameplate (MVA)
940 MVA
Saturated transient reactance (940 MVA base)
Generator rated voltage (Line-to-Line)
Generator step-up (GSU) transformer rating
GSU transformer reactance (880 MVA base)
System Equivalent (100 MVA base)
𝑋𝑋𝑑𝑑′ = 0.3845 per unit
20 𝑘𝑘𝑘𝑘
880 𝑀𝑀𝑀𝑀𝑀𝑀
XGSU = 16.05%
𝑍𝑍𝑒𝑒 = 0.00723∠90° per unit
Generator Owner Load-Responsive Protective Relays
40-1
Positive Offset Impedance
Offset = 0.294 per unit
Diameter = 0.294 per unit
40-2
Negative Offset Impedance
Offset = 0.22 per unit
Diameter = 2.24 per unit
40-3
21-1
30
Negative Offset Impedance
Offset = 0.22 per unit
Diameter = 1.00 per unit
Diameter = 0.643 per unit
MTA = 85°
Ibid, Kimbark.
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Table15: Example Data (Generator)
I (pickup) = 5.0 per unit
50
Transmission Owned Load-Responsive Protective Relays
Diameter = 0.55 per unit
21-2
MTA = 85°
Calculations shown for a 120 degree angle and E S /E R = 1. The equation for calculating Z R is: 31
Eq. (106)
𝑍𝑍𝑅𝑅 = �
(1 − 𝑚𝑚)(𝐸𝐸𝑆𝑆 ∠𝛿𝛿) + (𝑚𝑚)(𝐸𝐸𝑅𝑅 )
� × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝐸𝐸𝑆𝑆 ∠𝛿𝛿 − 𝐸𝐸𝑅𝑅
Where m is the relay location as a function of the total impedance (real number less than 1)
E S and E R is the sending-end and receiving-end voltages
Z sys is the total system impedance
Z R is the complex impedance at the relay location and plotted on an R-X diagram
All of the above are constants (940 MVA base) while the angle δ is varied. Table 16 below contains
calculations for a generator using the data listed in Table 15.
Table16: Example Calculations (Generator)
The following calculations are on a 940 MVA base.
Given:
Eq. (107)
𝑋𝑋𝑑𝑑′ = 𝑗𝑗0.3845 𝑝𝑝𝑝𝑝
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑋𝑋𝑑𝑑′ + 𝑋𝑋𝐺𝐺𝐺𝐺𝐺𝐺 + 𝑍𝑍𝑒𝑒
𝑋𝑋𝐺𝐺𝐺𝐺𝐺𝐺 = 𝑗𝑗0.17144 𝑝𝑝𝑝𝑝
𝑍𝑍𝑒𝑒 = 𝑗𝑗0.06796 𝑝𝑝𝑝𝑝
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑗𝑗0.3845 𝑝𝑝𝑝𝑝 + 𝑗𝑗0.17144 𝑝𝑝𝑝𝑝 + 𝑗𝑗0.06796 𝑝𝑝𝑝𝑝
Eq. (108)
Eq. (109)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 0.6239 ∠90° 𝑝𝑝𝑝𝑝
𝑚𝑚 =
𝑋𝑋𝑑𝑑′
0.3845
=
= 0.6163
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 0.6239
𝑍𝑍𝑅𝑅 = �
𝑍𝑍𝑅𝑅 = �
31
(1 − 𝑚𝑚)(𝐸𝐸𝑆𝑆 ∠𝛿𝛿) + (𝑚𝑚)(𝐸𝐸𝑅𝑅 )
� × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝐸𝐸𝑆𝑆 ∠𝛿𝛿 − 𝐸𝐸𝑅𝑅
(1 − 0.6163) × (1∠120°) + (0.6163)(1∠0°)
� × (0.6239∠90°) 𝑝𝑝𝑝𝑝
1∠120° − 1∠0°
Ibid, Kimbark.
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Table16: Example Calculations (Generator)
0.4244 + 𝑗𝑗0.3323
Z𝑅𝑅 = �
� × (0.6239∠90°) 𝑝𝑝𝑝𝑝
−1.5 + 𝑗𝑗 0.866
Z𝑅𝑅 = (0.3116 ∠ − 111.95°) × (0.6239∠90°) 𝑝𝑝𝑝𝑝
Z𝑅𝑅 = 0.194 ∠ − 21.95° 𝑝𝑝𝑝𝑝
Z𝑅𝑅 = −0.18 − 𝑗𝑗0.073 𝑝𝑝𝑝𝑝
Table 17 lists the swing impedance values at other angles and at E S /E R = 1, 1.43, and 0.7. The
impedance values are plotted on an R-X graph with the center being at the generator terminals for
use in evaluating impedance relay settings.
Table 17: Sample Calculations for a Swing Impedance Chart for Varying Voltages
at the Sending-End and Receiving-End.
E S /E R =1
E S /E R =1.43
E S /E R =0.7
ZR
ZR
ZR
Angle (δ)
(Degrees)
Magnitude
(pu)
Angle
(Degrees)
Magnitude
(pu)
Angle
Magnitude
Angle
(Degrees)
(pu)
(Degrees)
90
0.320
-13.1
0.296
6.3
0.344
-31.5
120
0.194
-21.9
0.173
-0.4
0.227
-40.1
150
0.111
-41.0
0.082
-10.3
0.154
-58.4
210
0.111
-25.9
0.082
190.3
0.154
238.4
240
0.194
201.9
0.173
180.4
0.225
220.1
270
0.320
193.1
0.296
173.7
0.344
211.5
Requirement R2 Generator Examples
Distance Relay Application
Based on PRC-026-1 – Attachment B, Criterion A, the distance relay (21-1) (i.e., owned by the
Generation Owner) characteristic is in the region where a stable power swing would not occur as
shown in Figure 19. There is no further obligation to the owner in this standard for this loadresponsive protective relay.
The distance relay (21-2) (i.e., owned by the Transmission Owner) is connected at the high-voltage
side of the GSU transformer and its impedance characteristic is in the region where a stable power
swing could occur causing the relay to operate. In this example, if the intentional time delay of this
relay is less than 15 cycles, the PRC-026 – Attachment B, Criterion A cannot be met, thus the
Transmission Owner is required to create a CAP (Requirement R3). Some of the options include,
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but are not limited to, changing the relay setting (i.e., impedance reach, angle, time delay), modify
the scheme (i.e., add PSB), or replace the Protection System. Note that the relay may be excluded
from this standard if it has an intentional time delay equal to or greater than 15 cycles.
Figure 19: Swing impedance graph for impedance relays at a generating facility.
Loss-of-Field Relay Application
In Figure 20, the R-X diagram shows the loss-of-field relay (40-1 and 40-2) characteristics are in
the region where a stable power swing can cause a relay operation. Protective relay 40-1 would
be excluded if it has an intentional time delay equal to or greater than 15 cycles. Similarly, 40-2
would be excluded if its intentional time delay is equal to or greater than 15 cycles. For example,
if 40-1 has a time delay of 1 second and 40-2 has a time delay of 0.25 seconds, they are excluded
and there is no further obligation on the Generator Owner in this standard for these relays. The
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loss-of-field relay characteristic 40-3 is entirely inside the unstable power swing region. In this
case, the owner may select high speed tripping on operation of the 40-3 impedance element.
Figure 20: Typical R-X graph for loss-of-field relays with a portion of the unstable power swing
region defined by PRC-026-1 – Attachment B, Criterion A.
Instantaneous Overcurrent Relay
In similar fashion to the transmission line overcurrent example calculation in Table 14, the
instantaneous overcurrent relay minimum setting is established by PRC-026-1 – Attachment B,
Criterion B. The solution is found by:
Eq. (110)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍sys
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
(1.05∠120° − 1.05∠0°)
𝑝𝑝𝑝𝑝
0.6239∠90°
As stated in the relay settings in Table 15, the relay is installed on the high-voltage side of the GSU
transformer with a pickup of 5.0 per unit. The maximum allowable current is calculated below.
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𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
1.819∠150°
𝑝𝑝𝑝𝑝
0.6239∠90°
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 2.91 ∠60° 𝑝𝑝𝑝𝑝
The instantaneous phase setting of 5.0 per unit is greater than the calculated system current of 2.91
per unit; therefore, it meets the PRC-026-1 – Attachment B, Criterion B.
Out-of-Step Tripping for Generation Facilities
Out-of-step protection for the generator generally falls into three different schemes. The first
scheme is a distance relay connected at the high-voltage side of the GSU transformer with the
directional element looking toward the generator. Because this relay setting may be the same
setting used for generator backup protection (see Requirement R2 Generator Examples, Distance
Relay Application), it is susceptible to tripping in response to stable power swings and would
require modification. Because this scheme is susceptible to tripping in response to stable power
swings and any modification to the mho circle will jeopardize the overall protection of the outof-step protection of the generator, available technical literature does not recommend using this
scheme specifically for generator out-of-step protection. The second and third out-of-step
Protection System schemes are commonly referred to as single and double blinder schemes.
These schemes are installed or enabled for out-of-step protection using a combination of
blinders, a mho element, and timers. The combination of these protective relay functions
provides out-of-step protection and discrimination logic for stable and unstable power swings.
Single blinder schemes use logic that discriminate between stable and unstable power swings by
issuing a trip command after the first slip cycle. Double blinder schemes are more complex than
the single blinder scheme and, depending on the settings of the inner blinder, a trip for a stable
power swing may occur. While the logic discriminates between stable and unstable power
swings in either scheme, it is important that the trip initiating blinders be set at an angle greater
than the stability limit of 120 degrees to remove the possibility of a trip for a stable power swing.
Below is a discussion of the double blinder scheme.
Double Blinder Scheme
The double blinder scheme is a method for measuring the rate of change of positive sequence
impedance for out-of-step swing detection. The scheme compares a timer setting to the actual
elapsed time required by the impedance locus to pass between two impedance characteristics. In
this case, the two impedance characteristics are simple blinders, each set to a specific resistive
reach on the R-X plane. Typically, the two blinders on the left half plane are the mirror images of
those on the right half plane. The scheme typically includes a mho characteristic which acts as a
starting element, but is not a tripping element.
The scheme detects the blinder crossings and time delays as represented on the R-X plane as
shown in Figure 21. The system impedance is composed of the generator transient (X d ’), GSU
transformer (X T) , and transmission system (X system ), impedances.
The scheme logic is initiated when the swing locus crosses the outer Blinder R1 (Figure 21), on
the right at separation angle α. The scheme only commits to take action when a swing crosses the
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inner blinder. At this point the scheme logic seals in the out-of-step trip logic at separation angle
β. Tripping actually asserts as the impedance locus leaves the scheme characteristic at separation
angle δ.
The power swing may leave both inner and outer blinders in either direction, and tripping will
assert. Therefore, the inner blinder must be set such that the separation angle β is large enough
that the system cannot recover. This angle should be set at 120 degrees or more. Setting the angle
greater than 120 degrees satisfies the PRC-026-1 – Attachment B, Criterion A (No. 1, 1st bullet)
since the tripping function is asserted by the blinder element. Transient stability studies may
indicate that a smaller stability limit angle is acceptable under PRC-026-1 – Attachment B,
Criterion A (No. 1, 2nd bullet). In this respect, the double blinder scheme is similar to the double
lens and triple lens schemes and many transmission application out-of-step schemes.
Figure 21: Double Blinder Scheme generic out of step characteristics.
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Figure 22 illustrates a sample setting of the double blinder scheme for the example 940 MVA
generator. The only setting requirement for this relay scheme is the right inner blinder, which
must be set greater than the separation angle of 120 degrees (or a lesser angle based on a
transient stability study) to ensure that the out-of-step protective function is expected to not trip
in response to a stable power swing during non-Fault conditions. Other settings such as the mho
characteristic, outer blinders, and timers are set according to transient stability studies and are not
a part of this standard.
Figure 22: Double Blinder Out-of-Step Scheme with unit impedance data and load-responsive
protective relay impedance characteristics for the example 940 MVA generator, scaled in relay
secondary ohms.
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Requirement R3
To achieve the stated purpose of this standard, which is to ensure that relays are expected to not
trip in response to stable power swings during non-Fault conditions, this Requirement ensures
that the applicable entity develops a Corrective Action Plan (CAP) that reduces the risk of relays
tripping in response to a stable power swing during non-Fault conditions that may occur on any
applicable BES Element.
Requirement R4
To achieve the stated purpose of this standard, which is to ensure that load-responsive protective
relays are expected to not trip in response to stable power swings during non-Fault conditions, the
applicable entity is required to implement any CAP developed pursuant to Requirement R3 such
that the Protection System will meet PRC-026-1 – Attachment B criteria or can be excluded under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay
functions are supervised by power swing blocking or using relay systems that are immune to power
swings), while maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the BES Element). Protection System owners are
required in the implementation of a CAP to update it when actions or timetable change, until all
actions are complete. Accomplishing this objective is intended to reduce the occurrence of
Protection System tripping during a stable power swing, thereby improving reliability and
minimizing risk to the BES.
The following are examples of actions taken to complete CAPs for a relay that did not meet PRC026-1 – Attachment B and could be at-risk of tripping in response to a stable power swing during
non-Fault conditions. A Protection System change was determined to be acceptable (without
diminishing the ability of the relay to protect for faults within its zone of protection).
Example R4a: Actions: Settings were issued on 6/02/2015 to reduce the Zone 2 reach of
the impedance relay used in the directional comparison unblocking (DCUB) scheme from
30 ohms to 25 ohms so that the relay characteristic is completely contained within the lens
characteristic identified by the criterion. The settings were applied to the relay on
6/25/2015. CAP was completed on 06/25/2015.
Example R4b: Actions: Settings were issued on 6/02/2015 to enable out-of-step blocking
on the existing microprocessor-based relay to prevent tripping in response to stable power
swings. The setting changes were applied to the relay on 6/25/2015. CAP was completed
on 06/25/2015.
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The following is an example of actions taken to complete a CAP for a relay responding to a stable
power swing that required the addition of an electromechanical power swing blocking relay.
Example R4c: Actions: A project for the addition of an electromechanical power swing
blocking relay to supervise the Zone 2 impedance relay was initiated on 6/5/2015 to prevent
tripping in response to stable power swings. The relay installation was completed on
9/25/2015. CAP was completed on 9/25/2015.
The following is an example of actions taken to complete a CAP with a timetable that required
updating for the replacement of the relay.
Example R4d: Actions: A project for the replacement of the impedance relays at both
terminals of line X with line current differential relays was initiated on 6/5/2015 to prevent
tripping in response to stable power swings. The completion of the project was postponed
due to line outage rescheduling from 11/15/2015 to 3/15/2016. Following the timetable
change, the impedance relay replacement was completed on 3/18/2016. CAP was
completed on 3/18/2016.
The CAP is complete when all the documented actions to remedy the specific problem (i.e.,
unnecessary tripping during stable power swings) are completed.
Justification for Including Unstable Power Swings in the Requirements
Protection Systems that are applicable to the Standard and must be secure for a stable power swing
condition (i.e., meets PRC-026-1 – Attachment B criteria) are identified based on Elements that
are susceptible to both stable and unstable power swings. This section provides an example of why
Elements that trip in response to unstable power swings (in addition to stable power swings) are
identified and that their load-responsive protective relays need to be evaluated under PRC-026-1
– Attachment B criteria.
Figure 23: A simple electrical system where two lines tie a small utility to a much larger
interconnection.
In Figure 23 the relays at circuit breakers 1, 2, 3, and 4 are equipped with a typical overreaching
Zone 2 pilot system, using a Directional Comparison Blocking (DCB) scheme. Internal faults (or
power swings) will result in instantaneous tripping of the Zone 2 relays if the measured fault or
power swing impedance falls within the zone 2 operating characteristic. These lines will trip on
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pilot Zone 2 for out-of-step conditions if the power swing impedance characteristic enters into
Zone 2. All breakers are rated for out-of-phase switching.
Figure 24: In this case, the Zone 2 element on circuit breakers 1, 2, 3, and 4 did not meet the
PRC-026-1 – Attachment B criteria (this figure depicts the power swing as seen by relays on
breakers 3 and 4).
In Figure 24, a large disturbance occurs within the small utility and its system goes out-of-step
with the large interconnect. The small utility is importing power at the time of the disturbance. The
actual power swing, as shown by the solid green line, enters the Zone 2 relay characteristic on the
terminals of Lines 1, 2, 3, and 4 causing both lines to trip as shown in Figure 25.
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1
Line 1
3
Large
Small
Utility
2
Line 2
4
Interconnect
Figure 25: Islanding of the small utility due to Lines 1 and 2 tripping in response to an unstable
power swing.
In Figure 25, the relays at circuit breakers 1, 2, 3, and 4 have correctly tripped due to the unstable
power swing (shown by the dashed green line in Figure 24), de-energizing Lines 1 and 2, and
creating an island between the small utility and the big interconnect. The small utility shed 500
MW of load on underfrequency and maintained a load to generation balance.
Figure 26: Line 1 is out-of-service for maintenance, Line 2 is loaded beyond its normal rating
(but within its emergency rating).
Subsequent to the correct tripping of Lines 1 and 2 for the unstable power swing in Figure 25,
another system disturbance occurs while the system is operating with Line 1 out-of-service for
maintenance. The disturbance causes a stable power swing on Line 2, which challenges the relays
at circuit breakers 2 and 4 as shown in Figure 27.
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Figure 27: Relays on circuit breakers 2 and 4 were not addressed to meet the PRC-026-1 –
Attachment B criteria following the previous unstable power swing event.
If the relays on circuit breakers 2 and 4 were not addressed under the Requirements for the previous
unstable power swing condition, the relays would trip in response to the stable power swing, which
would result in unnecessary system separation, load shedding, and possibly cascading or blackout.
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1
Line 1
3
Large
Small
Utility
2
Line 2
4
Interconnect
Figure 28: Possible blackout of the small utility.
If the relays that tripped in response to the previous unstable power swing condition in Figure 24
were addressed under the Requirements to meet PRC-026-1 - Attachment B criteria, the
unnecessary tripping of the relays for the stable power swing shown in Figure 28 would have been
averted, and the possible blackout of the small utility would have been avoided.
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PRC-026-1 — Relay Performance During Stable Power Swings
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. Standards Authorization Request (SAR) posted for comment from August 19, 2010,
through September 19, 2010.
2. Standards Committee (SC) authorized moving the SAR forward into standard
development on August 12, 2010.
3. SC authorized initial posting of Draft 1 on April 24, 2014.
4. Draft 1 of PRC-026-1 was posted for a 45-day formal comment period from April 25 –
June 9, 2014, with a concurrent/parallel initial ballot in the last ten days of the comment
period from May 30 – June 9, 2014.
5. Draft 2 of PRC-026-1 was posted for an additional 45-day formal comment period from
August 22 – October 6, 2014 with a concurrent/parallel additional ballot in the last ten
days of the comment period from September 26 – October 6, 2014.
6. SC authorized a waiver of the Standards Process Manual on October 22, 2014 to reduce
the Draft 3 additional formal comment period of PRC-026-1 from 45 days to 21 days
with a concurrent/additional ballot period in the last ten days of the comment period.
7. Draft 3 of PRC-026-1 was posted for an additional 21-day formal comment period from
November 4 – November 24, 2014 with a concurrent/parallel additional ballot in the last
ten days of the comment period from November 14 – November 24, 2014
Description of Current Draft
The Protection System Response to Power Swings Standard Drafting Team (PSRPS SDT) is
posting Draft 34 of PRC-026-1 – Relay Performance During Stable Power Swings for a 2110-day
additional comment period and concurrent/parallel additionalfinal ballot in the last ten days of the
comment period.
Anticipated Actions
Anticipated Date
45-day Formal Comment Period with Concurrent/Parallel Initial 10-day
Ballot
April 2014
45-day Formal Comment Period with Concurrent/Parallel Additional 10day Ballot
August 2014
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PRC-026-1 — Relay Performance During Stable Power Swings
Anticipated Actions
Anticipated Date
21-day Formal Comment Period with Concurrent/Parallel Additional 10day Ballot (Standards Committee authorized a waiver of the Standards
Process Manual, October 22, 2014)
OctoberNovember
2014
Final Ballot
December 2014
NERC Board of Trustees Adoption
December 2014
Version History
Version
Date
1.0
TBD
Action
Effective Date
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Change
Tracking
New
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PRC-026-1 — Relay Performance During Stable Power Swings
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Glossary of Terms Used in Reliability Standards (Glossary) are not repeated
here. 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.
Term: None.
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PRC-026-1 — Relay Performance During Stable Power Swings
When this standard has received ballot approval, the rationale boxes will be moved to the
Application Guidelines Section of the standard.
A. Introduction
1. Title:
Relay Performance During Stable Power Swings
2. Number:
PRC-026-1
3. Purpose:
To ensure that load-responsive protective relays are expected to not trip in
response to stable power swings during non-Fault conditions.
4. Applicability:
4.1.
4.2.
Functional Entities:
4.1.1
Generator Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
4.1.2
Planning Coordinator.
4.1.3
Transmission Owner that applies load-responsive protective relays as
described in PRC-026-1 – Attachment A at the terminals of the Elements
listed in Section 4.2, Facilities.
Facilities: The following Elements that are part of the Bulk Electric System
(BES):
4.2.1
Generators.
4.2.2
Transformers.
4.2.3
Transmission lines.
5. Background:
This is the third phase of a three-phased standard development project that focused on
developing this new Reliability Standard to address protective relay operations due to
stable power swings. The March 18, 2010, Federal Energy Regulatory Commission
(FERC) Order No. 733, approved Reliability Standard PRC-023-1 – Transmission Relay
Loadability. In thisthat Order, FERC directed NERC to address three areas of relay
loadability that include modifications to the approved PRC-023-1, development of a new
Reliability Standard to address generator protective relay loadability, and a new Reliability
Standard to address the operation of protective relays due to stable power swings. This
project’s SAR addresses these directives with a three-phased approach to standard
development.
Phase 1 focused on making the specific modifications from FERC Order No. 733 to PRC023-1 and was completed in the approved. Reliability Standard PRC-023-2, which
incorporated these modifications, became mandatory on July 1, 2012.
Phase 2 focused on developing a new Reliability Standard, PRC-025-1 – Generator Relay
Loadability, to address generator protective relay loadability. PRC-025-1 became
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PRC-026-1 — Relay Performance During Stable Power Swings
mandatory on October 1, 2014, along with PRC-023-3, which was modified to harmonize
PRC-023-2 with PRC-025-1.
Phase 3 of the project establishes Requirements aimed atfocuses on preventing protective
relays from tripping unnecessarily due to stable power swings by requiring the
identification of Elements on which a stable or unstable power swing may affect Protection
System operation, and to develop Requirements to assessassessment of the security of loadresponsive protective relays to tripping in response to only a stable power swing. Last, to
require entities to implement, and implementation of Corrective Action Plans (CAP),
where necessary, to improve. Phase 3 improves security of load-responsive protective
relays for stable power swings so they are expected to not trip in response to stable power
swings during non-Fault conditions, while maintaining dependable fault detection and
dependable out-of-step tripping.
6. Effective Dates:
Requirement R1
First day of the first full calendar year that is 12 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 12 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
Requirements R2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first full calendar year
that is 36 months after the date the standard is adopted by the NERC Board of Trustees or
as otherwise provided for in that jurisdiction.
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PRC-026-1 — Relay Performance During Stable Power Swings
B. Requirements and Measures
R1. Each Planning Coordinator shall, at least once each calendar year, provide notification
of each generator, transformer, and transmission line BES Element in its area that
meetmeets one or more of the following criteria, if any, to the respective Generator
Owner and Transmission Owner: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
Criteria:
1. Generator(s) where an angular stability constraint exists that is addressed by a
System Operating Limit (SOL) or a Remedial Action Scheme (RAS) and those
Elements terminating at the Transmission station associated with the generator(s).
2. An Element that is monitored as part of aan SOL identified by the Planning
Coordinator’s methodology1 based on an angular stability constraint.
3. An Element that forms the boundary of an island in the most recent
underfrequency load shedding (UFLS) design assessment based on application of
the Planning Coordinator’s criteria for identifying islands, whereonly if the island
is formed by tripping the Element due to angular instability.
4. An Element identified in the most recent annual Planning Assessment where relay
tripping occurs due to a stable or unstable 2 power swing during a simulated
disturbance.
M1. Each Planning Coordinator shall have dated evidence that demonstrates notification of
the generator, transformer, and transmission line BES Element(s) that meet one or
more of the criteria in Requirement R1, if any, to the respective Generator Owner and
Transmission Owner. Evidence may include, but is not limited to, the following
documentation: emails, facsimiles, records, reports, transmittals, lists, or spreadsheets.
1
NERC Reliability Standard FAC-10 –014-2 – Establish and Communicate System Operating Limits Methodology
for the Planning Horizon, Requirement R3.
2
An example of an unstable power swing is provided in the Guidelines and Technical Basis section, “Justification
for Including Unstable Power Swings in the Requirements section of the Guidelines and Technical Basis.”
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PRC-026-1 — Relay Performance During Stable Power Swings
Rationale for R1: The Planning Coordinator has a wide-area view and is in the position to
identify generator, transformer, and transmission line BES Elements which meet the criteria, if
any. The criteria-based approach is consistent with the NERC System Protection and Control
Subcommittee (SPCS) technical document Protection System Response to Power Swings,
August 2013 (“PSRPS Report”), 3 which recommends a focused approach to determine an atrisk BES Element. See the Guidelines and Technical Basis for a detailed discussion of the
criteria.
R2. Each Generator Owner and Transmission Owner shall determine: [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
2.1 Within 12 full calendar months of notification of a BES Element pursuant to
Requirement R1, determine whether its load-responsive protective relay(s)
applied to that BES Element meets the criteria in PRC-026-1 – Attachment B
where an evaluation of that Element’s load-responsive protective relay(s) based
on PRC-026-1 – Attachment B criteria has not been performed in the last five
calendar years.
2.2 Within 12 full calendar months of becoming aware 4 of a generator, transformer,
or transmission line BES Element that tripped in response to a stable or unstable 5
power swing due to the operation of its protective relay(s), determine whether its
load-responsive protective relay(s) applied to that BES Element meets the criteria
in PRC-026-1 – Attachment B.
M2. Each Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the evaluation was performed according to Requirement R2. Evidence
may include, but is not limited to, the following documentation: apparent impedance
characteristic plots, email, design drawings, facsimiles, R-X plots, software output,
records, reports, transmittals, lists, settings sheets, or spreadsheets.
3
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
4
Some examples of the ways an entity may become aware of a power swing are provided in the Guidelines and
Technical Basis section, “Becoming Aware of an Element That Tripped in Response to a Power Swing.”
5
An example of an unstable power swing is provided in the Guidelines and Technical Basis section, “Justification
for Including Unstable Power Swings in the Requirements section of the Guidelines and Technical Basis.”
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PRC-026-1 — Relay Performance During Stable Power Swings
Rationale for R2: The Generator Owner and Transmission Owner are in a position to determine
whether itstheir load-responsive protective relays meet the PRC-026-1 – Attachment B criteria.
Generator, transformer, and transmission line BES Elements are identified by the Planning
Coordinator in Requirement R1 and by the Generator Owner and Transmission Owner
following an actual event where the Generator Owner and Transmission Owner became aware
(i.e., through an event analysis or Protection System review) tripping was due to a stable or
unstable power swing. A period of 12 calendar months allows sufficient time for protection
staffthe entity to conduct the evaluation.
R3. Each Generator Owner and Transmission Owner shall, within six full calendar months
of determining a load-responsive protective relay does not meet the PRC-026-1 –
Attachment B criteria pursuant to Requirement R2, develop a Corrective Action Plan
(CAP) to meet one or more of the following: [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
•
The Protection System meets the PRC-026-1 – Attachment B criteria, while
maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the BES Element); or
•
The Protection System is excluded under the PRC-026-1 – Attachment A criteria
(e.g., modifying the Protection System so that relay functions are supervised by
power swing blocking or using relay systems that are immune to power swings),
while maintaining dependable fault detection and dependable out-of-step tripping
(if out-of-step tripping is applied at the terminal of the BES Element).
M3. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates the development of a CAP in accordance with Requirement R3. Evidence
may include, but is not limited to, the following documentation: corrective action
plans, maintenance records, settings sheets, project or work management program
records, or work orders.
Rationale for R3: To meet the reliability purpose of the standard, a CAP is necessary to ensure
the entity’s Protection System meets the PRC-026-1 – Attachment B criteria (1st bullet) so that
protective relays are expected to not trip in response to stable power swings. A CAP may also
be developed to modify the Protection System for exclusion under PRC-026-1 – Attachment A
(2nd bullet). Such an exclusion will allow the Protection System to be exempt from the
Requirement for future events. The phrase, “…while maintaining dependable fault detection
and dependable out-of-step tripping…” in Requirement R2R3 describes that the entity is to
comply with this standard, while achieving their desired protection goals. Refer to the
Guidelines and Technical Basis, Introduction, for more information.
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PRC-026-1 — Relay Performance During Stable Power Swings
R4. Each Generator Owner and Transmission Owner shall implement each CAP developed
pursuant to Requirement R3 and update each CAP if actions or timetables change until
all actions are complete. [Violation Risk Factor: Medium][Time Horizon: Long-Term
Planning]
M4. The Generator Owner and Transmission Owner shall have dated evidence that
demonstrates implementation of each CAP according to Requirement R4, including
updates to the CAP when actions or timetables change. Evidence may include, but is
not limited to, the following documentation: corrective action plans, maintenance
records, settings sheets, project or work management program records, or work orders.
Rationale for R4: Implementation of the CAP must accomplish all identified actions to be
complete to achieve the desired reliability goal. During the course of implementing a CAP,
updates may be necessary for a variety of reasons such as new information, scheduling conflicts,
or resource issues. Documenting CAP changes and completion of activities provides measurable
progress and confirmation of completion.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention
The following evidence retention periods 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 CEA may ask an entity to provide other evidence to show that it was
compliant for the full time period since the last audit.
The Generator Owner, Planning Coordinator, and Transmission Owner shall keep
data or evidence to show compliance as identified below unless directed by its CEA
to retain specific evidence for a longer period of time as part of an investigation.
•
The Planning Coordinator shall retain evidence of Requirement R1 for a
minimum of one calendar year following the completion of the
Requirement.
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirement R2 evaluation for a minimum of 12 calendar months following
completion of each evaluation where a CAP is not developed.
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PRC-026-1 — Relay Performance During Stable Power Swings
•
The Generator Owner and Transmission Owner shall retain evidence of
Requirements R2, R3, and R4 for a minimum of 12 calendar months
following completion of each CAP.
If a Generator Owner, Planning Coordinator, or Transmission Owner is found noncompliant, it shall keep information related to the non-compliance until mitigation
is complete and approved, or for the time specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3.
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure; “Compliance Monitoring and
Assessment Processes” 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.
1.4.
Additional Compliance Information
None.
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PRC-026-1 — Relay Performance During Stable Power Swings
Table of Compliance Elements
R#
R1
Time
Horizon
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was less than or equal
to 30 calendar days
late.
Moderate VSL
High VSL
Severe VSL
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Planning
Coordinator provided
notification of the
BES Element(s) in
accordance with
Requirement R1, but
was more than 90
calendar days late.
OR
The Planning
Coordinator failed to
provide notification
of the BES
Element(s) in
accordance with
Requirement R1.
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R2
Time
Horizon
Operations
Planning
Violation Severity Levels
VRF
High
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was less than or equal
to 30 calendar days
late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 30
calendar days and less
than or equal to 60
calendar days late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 60
calendar days and less
than or equal to 90
calendar days late.
The Generator Owner
or Transmission
Owner evaluated its
load-responsive
protective relay(s) in
accordance with
Requirement R2, but
was more than 90
calendar days late.
OR
The Generator Owner
or Transmission
Owner failed to
evaluate its loadresponsive protective
relay(s) in accordance
with Requirement R2.
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PRC-026-1 — Relay Performance During Stable Power Swings
R#
R3
R4
Time
Horizon
Long-term
Planning
Long-term
Planning
Violation Severity Levels
VRF
Lower VSL
Medium The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than six
calendar months and
less than or equal to
seven calendar
months.
Medium The Generator Owner
or Transmission
Owner implemented a
Corrective Action
Plan (CAP), but failed
to update a CAP when
actions or timetables
changed, in
accordance with
Requirement R4.
Moderate VSL
High VSL
Severe VSL
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than seven
calendar months and
less than or equal to
eight calendar
months.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than eight
calendar months and
less than or equal to
nine calendar months.
The Generator Owner
or Transmission
Owner developed a
Corrective Action
Plan (CAP) in
accordance with
Requirement R3, but
in more than nine
calendar months.
N/A
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4: December 5, 2014)
OR
The Generator Owner
or Transmission
Owner failed to
develop a CAP in
accordance with
Requirement R3.
N/A
The Generator Owner
or Transmission
Owner failed to
implement a
Corrective Action
Plan (CAP) in
accordance with
Requirement R4.
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PRC-026-1 — Relay Performance During Stable Power Swings
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
Burdy, John, Loss-of-excitation Protection for Synchronous Generators GER-3183, General
Electric Company.
IEEE Power System Relaying Committee WG D6, Power Swing and Out-of-Step
Considerations on Transmission Lines, July 2005: http://www.pes-psrc.org/Reports
/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission%20
Lines%20F..pdf.
Kimbark Edward Wilson, Power System Stability, Volume II: Power Circuit Breakers and
Protective Relays, Published by John Wiley and Sons, 1950.
Kundur, Prabha, Power System Stability and Control, 1994, Palo Alto: EPRI, McGraw Hill,
Inc.
NERC System Protection and Control Subcommittee, Protection System Response to Power
Swings, August 2013: http://www.nerc.com/comm/PC/System%20Protection%20
and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20
Report_Final_20131015.pdf.
Reimert, Donald, Protective Relaying for Power Generation Systems, 2006, Boca Raton: CRC
Press.
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment A
This standard applies to any protective functions which could trip instantaneously or with a time
delay of less than 15 cycles on load current (i.e., “load-responsive”) including, but not limited to:
•
•
•
•
Phase distance
Phase overcurrent
Out-of-step tripping
Loss-of-field
The following protection functions are excluded from Requirements of this standard:
•
•
•
•
•
•
•
•
•
•
•
Relay elements supervised by power swing blocking
Relay elements that are only enabled when other relays or associated systems fail. For
example:
o Overcurrent elements that are only enabled during loss of potential conditions.
o Relay elements that are only enabled during a loss of communications
Thermal emulation relays which are used in conjunction with dynamic Facility Ratings
Relay elements associated with direct current (dc) lines
Relay elements associated with dc converter transformers
Phase fault detector relay elements employed to supervise other load-responsive phase
distance elements (i.e.g., in order to prevent false operation in the event of a loss of
potential) provided the distance element is set in accordance with the criteria outlined in
the standard
Relay elements associated with switch-onto-fault schemes
Reverse power relay on the generator
Generator relay elements that are armed only when the generator is disconnected from the
system, (e.g., non-directional overcurrent elements used in conjunction with inadvertent
energization schemes, and open breaker flashover schemes)
Current differential relay, pilot wire relay, and phase comparison relay
Voltage-restrained or voltage-controlled overcurrent relays
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
CriteriaCriterion A:
An impedance-based relay used for tripping is expected to not trip for a stable power swing,
when the relay characteristic is completely contained within the unstable power swing region. 6
The unstable power swing region is formed by the union of three shapes in the impedance (RX) plane; (1) a lower loss-of-synchronism circle based on a ratio of the sending-end to
receiving-end voltages of 0.7; (2) an upper loss-of-synchronism circle based on a ratio of the
sending-end to receiving-end to sending-end voltages of 1.43; (3) a lens that connects the
endpoints of the total system impedance (with the parallel transfer impedance removed)
bounded by varying the sending-end and receiving-end voltages from 0.0 to 1.0 per unit, while
maintaining a constant system separation angle across the total system impedance where:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
Rationale for Attachment B (CriteriaCriterion A): The PRC-026-1 – Attachment B,
CriteriaCriterion A provides a basis for determining if the relays are expected to not trip for a
stable power swing having a system separation angle of up to 120 degrees with the sending-end
and receiving-end voltages varying from 0.7 to 1.0 per unit (See Guidelines and Technical
Basis).
6
Guidelines and Technical Basis, Figures 1 and 2.
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PRC-026-1 — Relay Performance During Stable Power Swings
PRC-026-1 – Attachment B
CriteriaCriterion B:
The pickup of an overcurrent relay element used for tripping, that is above the calculated
current value (with the parallel transfer impedance removed) for the conditions below:
1. The system separation angle is:
• At least 120 degrees, or
• An angle less than 120 degrees where a documented transient stability analysis
demonstrates that the expected maximum stable separation angle is less than 120
degrees.
2. All generation is in service and all transmission BES Elements are in their normal
operating state when calculating the system impedance.
3. Saturated (transient or sub-transient) reactance is used for all machines.
4. Both the sending-end and receiving-end voltages at 1.05 per unit.
Rationale for Attachment B (CriteriaCriterion B): The PRC-026-1 – Attachment B,
CriteriaCriterion B provides a basis for determining if the relays are expected to not trip for a
stable power swing having a system separation angle of up to 120 degrees with the sendingend and receiving-end voltages at 1.05 per unit (See Guidelines and Technical Basis).
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PRC-026-1 – Application Guidelines
Guidelines and Technical Basis
Introduction
The NERC System Protection and Control Subcommittee technical document, Protection System
Response to Power Swings, August 2013, 7 (“PSRPS Report” or “report”) was specifically prepared
to support the development of this NERC Reliability Standard. The report provided a historical
perspective on power swings as early as 1965 up through the approval of the report by the NERC
Planning Committee. The report also addresses reliability issues regarding trade-offs between
security and dependability of Protection Systems, considerations for this NERC Reliability
Standard, and a collection of technical information about power swing characteristics and varying
issues with practical applications and approaches to power swings. Of these topics, the report
suggests an approach for this NERC Reliability Standard (“standard” or “PRC-026-1”) which is
consistent with addressing two of the three regulatory directives in the FERC Order No. 733. The
first directive concerns the need for “…protective relay systems that differentiate between faults
and stable power swings and, when necessary, phases out protective relay systems that cannot meet
this requirement.” 8 Second, is “…to develop a Reliability Standard addressing undesirable relay
operation due to stable power swings.” 9 The third directive “…to consider “islanding” strategies
that achieve the fundamental performance for all islands in developing the new Reliability
Standard addressing stable power swings” 10 was considered during development of the standard.
The development of this standard implements the majority of the approaches suggested by the
report. However, it is noted that the Reliability Coordinator and Transmission Planner have not
been included in the standard’s Applicability section (as suggested by the PSRPS Report). This is
so that a single entity, the Planning Coordinator, may be the single source for identifying Elements
according to Requirement R1. A single source will insure that multiple entities will not identify
Elements in duplicate, nor will one entity fail to provide an Element because it believes the
Element is being provided by another entity. The Planning Coordinator has, or has access to, the
wide-area model and can correctly identify the Elements that may be susceptible to a stable or
unstable power swing. Additionally, not including the Reliability Coordinator and Transmission
Planner is consistent with the applicability of other relay loadability NERC Reliability Standards
(e.g., PRC-023 and PRC-025). It is also consistent with the NERC Functional Model.
The phrase, “while maintaining dependable fault detection and dependable out-of-step tripping”
in Requirement R2R3, describes that the Generator Owner and Transmission Owner isare to
comply with this standard, while achieving its desired protection goals. Load-responsive protective
relays, as addressed within this standard, may be intended to provide a variety of backup protection
functions, both within the generating unit or generating plant and on the transmission system, and
7
NERC System Protection and Control Subcommittee, Protection System Response to Power Swings, August 2013:
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPC
S%20Power%20Swing%20Report_Final_20131015.pdf)
8
Transmission Relay Loadability Reliability Standard, Order No. 733, P.150 FERC ¶ 61,221 (2010).
9
Ibid. P.153.
10
Ibid. P.162.
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PRC-026-1 – Application Guidelines
this standard is not intended to result in the loss of these protection functions. Instead, it is
suggested that the Generator Owner and Transmission Owner must consider both the
Requirements within this standard and its desired protection goals, and perform modifications to
its protective relays or protection philosophies as necessary to achieve both.
Power Swings
The IEEE Power System Relaying Committee WG D6 developed a technical document called
Power Swing and Out-of-Step Considerations on Transmission Lines (July 2005) that provides
background on power swings. The following are general definitions from that document: 11
Power Swing: a variation in three phase power flow which occurs when the generator rotor
angles are advancing or retarding relative to each other in response to changes in load
magnitude and direction, line switching, loss of generation, faults, and other system
disturbances.
Pole Slip: a condition whereby a generator, or group of generators, terminal voltage angles
(or phases) go past 180 degrees with respect to the rest of the connected power system.
Stable Power Swing: a power swing is considered stable if the generators do not slip poles
and the system reaches a new state of equilibrium, i.e. an acceptable operating condition.
Unstable Power Swing: a power swing that will result in a generator or group of generators
experiencing pole slipping for which some corrective action must be taken.
Out-of-Step Condition: Same as an unstable power swing.
Electrical System Center or Voltage Zero: it is the point or points in the system where the
voltage becomes zero during an unstable power swing.
Burden to Entities
The PSRPS Report provides a technical basis and approach for focusing on Protection Systems,
which are susceptible to power swings, while achieving the purpose of the standard. The approach
reduces the number of relays to which the PRC-026-1 Requirements would apply by first
identifying the BES Element(s) on which load-responsive protective relays must be evaluated. The
first step uses criteria to identify the Elements on which a Protection System is expected to be
challenged by power swings. Of those Elements, the second step is to evaluate each loadresponsive protective relay that is applied on each identified Element. Rather than requiring the
Planning Coordinator or Transmission Planner to perform simulations to obtain information for
each identified Element, the Generator Owner and Transmission Owner will reduce the need for
simulation by comparing the load-responsive protective relay characteristic to specific criteria in
PRC-026-1 – Attachment B.
11
http://www.pes-psrc.org/Reports/Power%20Swing%20and%20OOS%20Considerations%20on%20Transmission
%20Lines%20F..pdf.
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PRC-026-1 – Application Guidelines
Applicability
The standard is applicable to the Generator Owner, Planning Coordinator, and Transmission
Owner entities. More specifically, the Generator Owner and Transmission Owner entities are
applicable when applying load-responsive protective relays at the terminals of the applicable BES
Elements. The standard is applicable to the following BES Elements: generators, transformers, and
transmission lines. The Distribution Provider was considered for inclusion in the standard;
however, it is not subject to the standard because this entity, by functional registration, would not
own generators, transmission lines, or transformers other than load serving.
Load-responsive protective relays include any protective functions which could trip with or
without time delay, on load current.
Requirement R1
The Planning Coordinator has a wide-area view and is in the positonposition to identify what, if
any, Elements meet the criteria. The criterion-based approach is consistent with the NERC System
Protection and Control Subcommittee (SPCS) technical document, Protection System Response to
Power Swings (August 2013), 12 which recommends a focused approach to determine an at-risk
Element. Identification of Elements comes from the annual Planning Assessments pursuant to the
transmission planning (i.e., “TPL”) and other NERC Reliability Standards (e.g., PRC-006), and
the standard is not requiring any other assessments to be performed by the Planning Coordinator.
The required notification on a calendar year basis to the respective Generator Owner and
Transmission Owner is sufficient because it is expected that the Planning Coordinator will make
its notifications following the completion of its annual Planning Assessments. The Planning
Coordinator will continue to provide notification of Elements on a calendar year basis even if a
study is performed less frequently (e.g., PRC-006 – Automatic Underfrequency Load Shedding,
which is five years) and has not changed. It is possible that thea Planning Coordinator provided
notification of Elementscould utilize studies from a prior year in two different calendar years using
the same annual Planning Assessmentdetermining the necessary notifications pursuant to
Requirement R1.
Criterion 1
The first criterion involves generator(s) where an angular stability constraint exists that is
addressed by a System Operating Limit (SOL) or a Remedial Action Scheme (RAS) and those
Elements terminating at the Transmission station associated with the generator(s). For example, a
scheme to remove generation for specific conditions is implemented for a four-unit generating
plant (1,100 MW). Two of the units are 500 MW each; one is connected to the 345 kV system and
one is connected to the 230 kV system. The Transmission Owner has two 230 kV transmission
lines and one 345 kV transmission line all terminating at the generating facility as well as a 345/230
kV autotransformer. The remaining 100 MW consists of two 50 MW combustion turbine (CT)
units connected to four 66 kV transmission lines. The 66 kV transmission line islines are not
12
http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%20
20/SPCS%20Power%20Swing%20Report_Final_20131015.pdf)
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electrically joined to the 345 kV and 230 kV transmission lines at the plant site and isare not a part
ofsubject to the operating limit or RAS. A stability constraint limits the output of the portion of
the plant affected by the RAS to 700 MW for an outage of the 345 kV transmission line. The RAS
trips one of the 500 MW units to maintain stability for a loss of the 345 kV transmission line when
the total output from both 500 MW units is above 700 MW. For this example, both 500 MW
generating units and the associated generator step-up (GSU) transformers would be identified as
Elements meeting this criterion. The 345/230 kV autotransformer, the 345 kV transmission line,
and the two 230 kV transmission lines would also be identified as Elements meeting this criterion.
The 50 MW combustion turbines and 66 kV transmission lines would not be identified pursuant
to Criterion 1 because these Elements are not subject to an operating limit or RAS and do not
terminate at the Transmission station associated with the generators that are subject to the SOL or
RAS.
Criterion 2
The second criterion involves Elements that are monitored as a part of an established System
Operating Limit (SOL) based on an angular stability limit regardless of the outage conditions that
result in the enforcement of the SOL. For example, if two long parallel 500 kV transmission lines
have a combined SOL of 1,200 MW, and this limit is based on angular instability resulting from a
fault and subsequent loss of one of the two lines, then both lines would be identified as an
ElementElements meeting the criterion.
Criterion 3
The third criterion involves Elements that form the boundary of an island within an underfrequency
load shedding (UFLS) design assessment. The criterion applies to islands identified based on
application of the Planning Coordinator’s criteria for identifying islands, where the island is
formed by tripping the Elements based on angular instability. The criterion applies if the angular
instability is modeled in the UFLS design assessment, or if the boundary is identified “off-line”
(i.e., the Elements are selected based on angular instability considerations, but the Elements are
tripped in the UFLS design assessment without modeling the initiating angular instability). In cases
where an out-of-step condition is detected and tripping is initiated at an alternate location, the
criterion applies to the Element on which the power swing is detected. The criterion does not apply
to islands identified based on other considerations that do not involve angular instability, such as
excessive loading, Planning Coordinator area boundary tie lines, or Balancing Authority boundary
tie lines.
Criterion 4
The fourth criterion involves Elements identified in the most recent annual Planning Assessment
where relay tripping occurs due to a stable or unstable 13 power swing during a simulated
disturbance. The intent is for the Planning Coordinator to include any Element(s) where relay
13
Refer to the “Justification for Including Unstable Power Swings in the Requirements” section.
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tripping was observed during simulations performed for the most recent annual Planning
Assessment associated with the transmission planning TPL-001-4 Reliability Standard. Note that
relay tripping must be assessed within those annual Planning Assessments per TPL-001-4, R4,
Part 4.3.1.3, which indicates that analysis shall include the “Tripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic or actual
relay models.” Identifying such Elements according to Criterion 4 and notifying the respective
Generator Owner and Transmission Owner will require that the owners of any load-responsive
protective relay applied at the terminals of the identified Element evaluate the relay’s susceptibility
to tripping in response to a stable power swing.
Planning Coordinators have the discretion to determine whether the observed tripping for a power
swing in its Planning Assessments occurs for valid contingencies and system conditions. The
Planning Coordinator will address tripping that is observed in transient analyses on an individual
basis; therefore, the Planning Coordinator is responsible for identifying the Elements based only
on simulation results that are determined to be valid.
Due to the nature of how a Planning Assessment is performed, there may be cases where a
previously-identified Element is not identified in the most recent annual Planning Assessment. If
so, this is acceptable because the Generator Owner and Transmission Owner would have taken
action upon the initial notification of the previously identified Element. When an Element is not
identified in later Planning Assessments, the risk of load-responsive protective relays tripping in
response to a stable power swing during non-Fault conditions would have already been assessed
under Requirement R2 and mitigated according to Requirements R3 and R4 where the relays did
not meet the PRC-026-1 – Attachment B criteria. According to Requirement R2, the Generator
Owner and Transmission Owner are only required to re-evaluate each load-responsive protective
relay for an identified Element where the evaluation has not been performed in the last five
calendar years.
Although Requirement R1 requires the Planning Coordinator to notify the respective Generator
Owner and Transmission Owner of any Elements meeting one or more of the four criteria, it does
not preclude the Planning Coordinator from providing additional information, such as apparent
impedance characteristics, in advance or upon request, that may be useful in evaluating protective
relays. Generator Owners and Transmission Owners are able to complete protective relay
evaluations and perform the required actions without additional information. The standard does
not include any requirement for the entities to provide information that is already being shared or
exchanged between entities for operating needs. While a Requirement has not been included for
the exchange of information, entities should recognize that relay performance needs to be
measured against the most current information.
Requirement R2
Requirement R2 requires the Generator Owner and Transmission Owner to evaluate its loadresponsive protective relays to ensure that they are expected to not trip in response to stable power
swings.
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The PRC-026-1 – Attachment A lists the applicable load-responsive relays that must be evaluated.
These relays which include phase distance, phase overcurrent, out-of-step tripping, and loss-offield. relay functions. Phase distance relays cancould include, but are not limited to, the following:
•
•
Mho element characteristics such as Zone 1, Zone 2, or Zone 3elements with instantaneous
tripping or intentional time delays of less than 15 cycles or less.
Mho element characteristics that overreach the remote line terminalPhase distance elements
used in high-speed, communications assisted communication-aided tripping schemes
including:
Directional Comparison Blocking (DCB) schemes
Directional Comparison Un-Blocking (DCUB) schemes
Permissive Overreach Transfer Trip (POTT) schemes
Permissive Underreach Transfer Trip (PUTT) schemes
A method is provided within the standard to support consistent evaluation by Generator Owners
and Transmission Owners based on specified conditions. Once a Generator Owner or Transmission
Owner is notified of Elements pursuant to Requirement R1, it has 12 full calendar months to
determine if each Element’s load-responsive protective relays meet the applicable PRC-026-1 –
Attachment B criteria, if the determination has not been performed in the last five calendar years.
Additionally, each Generator Owner and Transmission Owner, that becomes aware of a generator,
transformer, or transmission line BES Element that tripped in response to a stable or unstable
power swing due to the operation of its protective relays pursuant to Requirement R2, Part 2.2,
must perform the same PRC-026-1 – Attachment B criteria determination within 12 full calendar
months.
Becoming Aware of an Element That Tripped in Response to a Power Swing
Part 2.2 in Requirement R2 is intended to initiate action by the Generator Owner and Transmission
Owner when there is a known stable or unstable power swing and it resulted in the entity’s Element
tripping. The criterion starts with becoming aware of the event (i.e., power swing) and then any
connection with the entity’s Element tripping. By doing so, the focus is removed from the entity
having to demonstrate that it performedmade a determination whether a power swing analysiswas
present for every Element trip. The basis for structuring the criterion in this manner is driven by
the available ways that a Generator Owner and Transmission Owner could become aware of an
Element that tripped in response to a stable or unstable power swing due to the operation of its
protective relay(s).
Element trips caused by stable or unstable power swings, though infrequent, would be more
common in a larger event. The identification of power swings will be revealed during an analysis
of the event. Event analysis where an entity may become aware of a stable or unstable power swing
could include internal analysis conducted by the entity, the entity’s Protection System review
following a trip, or a larger scale analysis which includesby other entities. Event analysis could
include involvement by the entity’s Regional Entity, and in some cases NERC.
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Information Common to Both Generation and Transmission Elements
The PRC-026-1 – Attachment A lists the load-responsive protective relays that are subject to this
standard. Generator Owners and Transmission Owners may own load-responsive protective relays
(i.e.g., distance relays) that directly affect generation or transmission BES Elements and will
require analysis as a result of Elements being identified by the Planning Coordinator in
Requirement R1 or the Generator Owner or Transmission Owner in Requirement R2. For example,
distance relays owned by the Transmission Owner may be installed at the high-voltage side of the
generator step-up (GSU) transformer (directional toward the generator) providing backup to
generation protection. Generator Owners may have distance relays applied to backup transmission
protection or backup protection to the GSU transformer. The Generator Owner may have relays
installed at the generator terminals or the high-voltage side of the GSU transformer.
Exclusion of Time Based Load-Responsive Protective Relays
The purpose of the standard is “[t]o ensure that load-responsive protective relays are expected to
not trip in response to stable power swings during non-Fault conditions.” Load-responsive, highspeed tripping protective relays pose the highest risk of operating during a power swing. Because
of this, high-speed tripping protective relays and relays with a time delay of less than 15 cycles are
included in the standard; whereas other relays (i.e., Zones 2 and 3) with a time a delay of 15 cycles
or greater are excluded. The time delay used for exclusion on some load-responsive protective
relays is recommended based on 1) the minimum time delay these relays are set in practice, and
2)based on the maximum expected time that load-responsive protective relays would be exposed
to a stable power swing based onwith a swingslow slip rate frequency.
In order to establish a time delay that distinguishes a high-risk load-responsive protective relay
from one that has a time delay for tripping (lower-risk), a sample of swing rates were calculated
based on a stable power swing entering and leaving the impedance characteristic as shown in Table
1. For a relay impedance characteristic that has thea power swing entering and leaving, beginning
at 90 degrees with a termination at 120 degrees before exiting the zone, calculation of the zone
timer must be greater than the calculated time the stable power swing is inside the relay operate
zonerelay’s operating zone to not trip in response to the stable power swing.
Eq. (1)
(120° − 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑜𝑜𝑜𝑜 𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒 𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖 𝑡𝑡ℎ𝑒𝑒 𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟 𝑐𝑐ℎ𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎) × 60
𝑍𝑍𝑍𝑍𝑍𝑍𝑍𝑍 𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 > 2 × �
�
(360 × 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅)
Table 1.: Swing Rates
Zone Timer
(Cycles)
Slip Rate
(Hz)
10
1.00
15
0.67
20
0.50
30
0.33
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With a minimum zone timer of 15 cycles, the corresponding slip rate of the system is 0.67 Hz.
This represents an approximation of a slow slip rate during a system Disturbance. Consequently,
this value corresponds to the typical minimum time delay used for Zone 2 distance relays in
transmission line protection. Longer time delays allow for slower slip rates.
Application to Transmission Elements
CriteriaCriterion A in PRC-026-1 – Attachment B describes an unstable power swing region that
is formed by the union of three shapes in the impedance (R-X) plane. The first shape is a lower
loss -of -synchronism circle based on a ratio of the sending-end to receiving-end voltages of 0.7
(i.e., E S / E R = 0.7 / 1.0 = 0.7). The second shape is an upper loss -of -synchronism circle based on
a ratio of the sending-end to receiving-end to sending-end voltages of 1.43 (i.e., E S / E R / E S = 1.0
/ 0.7 = 1.43). The third shape is a lens that connects the endpoints of the total system impedance
together by varying the sending-end and receiving-end system voltages from 0.0 to 1.0 per unit,
while maintaining a constant system separation angle across the total system impedance (with the
parallel transfer impedance removed—see Figures 1 through 5). The total system impedance is
derived from a two-bus equivalent network and is determined by summing the sending-end source
impedance, the line impedance (excluding the Thévenin equivalent transfer impedance), and the
receiving-end source impedance as shown in Figures 6 and 7. The goal in establishingEstablishing
the total system impedance is to representprovides a conservative condition that will maximize the
security of the relay against various system conditions. The smallest total system impedance
represents a condition where the size of the lens characteristic in the R-X plane is smallest and is
a conservative operating point from the standpoint of ensuring a load-responsive protective relay
is expected to not trip given a predetermined angular displacement between the sending-end and
receiving-end voltages. The smallest total system impedance results when all generation is in
service and all transmission BES Elements are modeled in their “normal” system configuration
(PRC-026-1 – Attachment B, CriteriaCriterion A). The parallel transfer impedance is removed to
represent a likely condition where parallel elementsElements may be lost during the disturbance,
and the loss of these elementsElements magnifies the sensitivity of the load-responsive relays on
the parallel line by removing the “infeed effect” (i.e., the apparent impedance sensed by the relay
is decreased as a result of the loss of the transfer impedance, thus making the relay more likely to
trip for a stable power swing—See Figures 13 and 14).
The sending-end and receiving-end source voltages are varied from 0.7 to 1.0 per unit to form the
lower and upper loss -of -synchronism circles. The ratio of these two voltages is used in the
calculation of the loss -of -synchronism circles, and result in a ratio range from 0.7 to 1.43.
Eq. (2)
𝐸𝐸𝑆𝑆 0.7
=
= 0.7
𝐸𝐸𝑅𝑅 1.0
Eq. (3):
𝐸𝐸𝑅𝑅 𝐸𝐸𝑆𝑆 1.0
=
= 1.43
𝐸𝐸𝑆𝑆 𝐸𝐸𝑅𝑅 0.7
The internal generator voltage during severe power swings or transmission system fault conditions
will be greater than zero, due to voltage regulator support. The voltage ratio of 0.7 to 1.43 is chosen
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to be more conservative than the PRC-023 14 and PRC-025 15 NERC Reliability Standards, where
a lower bound voltage of 0.85 per unit voltage is used. A ±15% internal generator voltage range
was chosen as a conservative voltage range for calculation of the voltage ratio used to calculate
the loss -of -synchronism circles. For example, the voltage ratio using these voltages would result
in a ratio range from 0.739 to 1.353.
Eq. (4)
𝐸𝐸𝑆𝑆 0.85
=
= 0.739
𝐸𝐸𝑅𝑅 1.15
Eq. (5):
𝐸𝐸𝑅𝑅 𝐸𝐸𝑆𝑆 1.15
=
= 1.353
𝐸𝐸𝑆𝑆 𝐸𝐸𝑅𝑅 0.85
The lower ratio is rounded down to 0.7 to be more conservative, allowing a voltage range of 0.7
to 1.0 per unit to be used for the calculation of the loss -of -synchronism circles. 16
When the parallel transfer impedance is included in the model, the split indivision of current
through the parallel transfer impedance path results in actual measured relay impedances that are
larger than those measured when the parallel transfer impedance is removed (i.e., infeed effect),
which would make it more likely for an impedance relay element to be completely contained
within the unstable power swing region as shown in Figure 11. If the transfer impedance is
included in the evaluation, a distance relay element could be deemed as meeting PRC-026-1 –
Attachment B criteria and, in fact would be secure, assuming all elementsElements were in their
normal state. In this case, the distance relay element could trip forin response to a stable power
swing during an actual event if the system was weakened (i.e., a higher transfer impedance) by the
loss of a subset of lines that make up the parallel transfer impedance. as shown in Figure 10. This
could happen because the subset of lines that make up the parallel transfer impedance tripped on
unstable swings, contained the initiating fault, and/or were lost due to operation of breaker failure
or remote back-up protection schemes in Figure 10.
Table 10 shows the percent size increase of the lens shape as seen by the relay under evaluation
when the parallel transfer impedance is included. The parallel transfer impedance has minimal
effect on the apparent size of the lens shape as long as the parallel transfer impedance is at least
10 multiples of the parallel line impedance (less than 5% lens shape expansion), therefore, its
removal has minimal impact, but results in a slightly more conservative, smaller lens shape.
TransferParallel transfer impedances of 5 multiples of the parallel line impedance or less result in
an apparent lens shape size of 10% or greater as seen by the relay. If two parallel lines and a
parallel transfer impedance tie the sending-end and receiving-end buses together, the total parallel
transfer impedance will be one or less multiples of the parallel line impedance, resulting in an
apparent lens shape size of 45% or greater. It is a realistic contingency that the parallel line could
be out-of-service, leaving the parallel transfer impedance making up the rest of the system in
parallel with the line impedance. Since it is not known exactly which lines making up the parallel
14
Transmission Relay Loadability
15
Generator Relay Loadability
16
Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations,
April 2004, Section 6 (The Cascade Stage of the Blackout), p. 94 under “Why the Generators Tripped Off,” states,
“Some generator undervoltage relays were set to trip at or above 90% voltage. However, a motor stalls out at about
70% voltage and a motor starter contactor drops out around 75%, so if there is a compelling need to protect the
turbine from the system the under-voltage trigger point should be no higher than 80%.”
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transfer impedance that will be out of service during a major system disturbance, it is most
conservative to assume that all of them are out, leaving just the line under evaluation in service.
Either the saturated transient or sub-transient direct axis reactance values may be used for machines
in the evaluation because they are smaller than the un-saturated reactance values.reactances. Since
saturated sub-transient saturated generator reactances are smaller than the transient or synchronous
reactance, theyreactances, the use of sub-transient reactances will result in a smaller source
impedance and a smaller unstable power swing region in the graphical analysis as shown in Figures
8 and 9. SinceBecause power swings occur in a time frame where generator transient reactances
will be prevalent, it is acceptable to use saturated transient reactances instead of saturated subtransient reactance values. Somereactances. Because some short-circuit models may not include
transient reactance values, so in this casereactances, the use of sub-transient reactances is also
acceptable because it also produces more conservative results than transient reactances.. For this
reason, either value is acceptable when determining the system source impedances (PRC-026-1 –
Attachment B, CriteriaCriterion A and B, No. 3).
Saturated reactance valuesreactances are also the values used in short-circuit programs that
produce the system impedance mentioned above. Planning and stability software generally use the
un-saturated reactance valuesreactances. Generator models used in transient stability analyses
recognize that the extent of the saturation effect depends upon both rotor (field) and stator currents.
Accordingly, they derive the effective saturated parameters of the machine at each instant by
internal calculation from the specified (constant) unsaturated values of machine reactances and the
instantaneous internal flux level. The specific assumptions regarding which inductances are
affected by saturation, and the relative effect of that saturation, are different for the various
generator models used. Thus, unsaturated values of all machine reactances are used in setting up
planning and stability software data, and the appropriate set of open-circuit magnetization curve
data is provided for each machine.
Saturated reactance values are smaller than unsaturated reactance values and are used in shortcircuit programs owned by the Generator and Transmission Owners. Because of this, saturated
reactance values are to be used in the development of the system source impedances.
The source or system equivalent impedances can be obtained by a number of different methods
using commercially available short-circuit calculation tools. 17 Most short-circuit tools have a
network reduction feature that allows the user to select the local and remote terminal buses to
retain. The first method reduces the system to one that contains two buses, an equivalent generator
at each bus (representing the source impedanceimpedances at the sending-end and receivingendsend), and two parallel lines; one being the line impedance of the protected line with relays
being analyzed, the other being the parallel transfer impedance representing all other combinations
of lines that connect the two buses together as shown in Figure 6. Another conservative method is
to open both ends of the line in questionbeing evaluated, and apply a three-phase bolted fault at
each bus. The resulting source to determine the Thévenin equivalent impedance at each endbus.
The source impedances are set equal to the Thévenin equivalent impedances and will be less than
17
Demetrios A. Tziouvaras and Daqing Hou, Appendix in Out-Of-Step Protection Fundamentals and
Advancements, April 17, 2014: https://www.selinc.com.
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or equal to the actual source impedanceimpedances calculated by the network reduction method.
Either method can be used to develop the system source impedances at both ends.
The two bullets of PRC-026-1 – Attachment B, CriteriaCriterion A, No. 1, identify the system
separation angles used to identify the size of the power swing stability boundary to be used to
testfor evaluating load-responsive protective relay impedance elements. Both bullets test
impedance relay elements that are not supervised by power swing blocking (PSB). The first bullet
of PRC-026-1 – Attachment B, CriteriaCriterion A, No. 1 evaluates a system separation angle of
at least 120 degrees that is held constant while varying the sending-end and receiving-end source
voltages from 0.7 to 1.0 per unit, thus creating an unstable power swing region about the total
system impedance in Figure 1. This unstable power swing region is compared to the tripping
portion of the distance relay characteristic; that is, the portion that is not supervised by load
encroachment, blinders, or some other form of supervision as shown in Figure 12 that restricts the
distance element from tripping for heavy, balanced load conditions. If the tripping portion of the
impedance characteristics are completely contained within the unstable power swing region, the
relay impedance element meets CriteriaCriterion A in PRC-026-1 – Attachment B. A system
separation angle of 120 degrees was chosen for the evaluation where PSB is not applied because
it is generally accepted in the industry that recovery for a swing beyond this angle is unlikely to
occur. 18
The second bullet of PRC-026-1 – Attachment B, CriteriaCriterion A, No. 1 evaluates impedance
relay elements at a system separation angle of less than 120 degrees, similar to the first bullet
described above. An angle less than 120 degrees may be used if a documented stability analysis
demonstrates that the power swing becomes unstable at a system separation angle of less than 120
degrees.
The exclusion of relay elements supervised by Power Swing Blocking (PSB) in PRC-026-1 –
Attachment A allows the Generator Owner or Transmission Owner to exclude protective relay
elements if they are blocked from tripping by PSB relays. A PSB relay applied and set according
to industry accepted practices prevent supervised load-responsive protective relays from tripping
in response to power swings. Further, PSB relays are set to allow dependable tripping of supervised
elements. The criteria in PRC-026-1 – Attachment B specifically applies to unsupervised elements
that could trip for stable power swings. Therefore, load-responsive protective relay elements
supervised by PSB can be excluded from the Requirements of this standard.
18
“The critical angle for maintaining stability will vary depending on the contingency and the system condition at
the time the contingency occurs; however, the likelihood of recovering from a swing that exceeds 120 degrees is
marginal and 120 degrees is generally accepted as an appropriate basis for setting out‐of‐step protection. Given the
importance of separating unstable systems, defining 120 degrees as the critical angle is appropriate to achieve a
proper balance between dependable tripping for unstable power swings and secure operation for stable power
swings.” NERC System Protection and Control Subcommittee, Protection System Response to Power Swings,
August 2013: http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20
SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf), p. 28.
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Figure 1.: An enlarged graphic illustrating the unstable power swing region formed by the union
of three shapes in the impedance (R-X) plane: Shape 1) Lower loss -of -synchronism circle,
Shape 2) Upper loss -of -synchronism circle, and Shape 3) Lens. The mho element characteristic
is completely contained within the unstable power swing region (i.e.g., it does not intersect any
portion of the unstable power swing region), therefore it complies withmeets PRC-026-1 –
Attachment B, CriteriaCriterion A, No. 1.
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Figure 2.: Full graphic of the unstable power swing region formed by the union of the three
shapes in the impedance (R-X) plane: Shape 1) Lower loss -of -synchronism circle, Shape 2)
Upper loss -of -synchronism circle, and Shape 3) Lens. The mho element characteristic is
completely contained within the unstable power swing region, therefore it meets PRC-26-1 –
Attachment B, CriteriaCriterion A, No.1.
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Figure 3.: System impedanceimpedances as seen by relayRelay R. (voltage connections are not
shown).
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Figure 4.: The defining unstable power swing region points where the lens shape intersects the
lower and upper loss -of -synchronism circle shapes and where the lens intersects the equal EMF
(electromotive force) power swing.
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Figure 5.: Full table of 31 detailed lens shape point calculations. The bold highlighted rows
correspond to the detailed calculations in Tables 2-7.
Table 2.: Example Calculation (Lens Point 1)
This example is for calculating the impedance the first point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) leading
the receiving-end voltage (E R ) by 120 degrees. See Figures 3 and 4.
Eq. (6)
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
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Table 2.: Example Calculation (Lens Point 1)
𝐸𝐸𝑆𝑆 =
Eq. (7)
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positivePositive sequence impedance data (Thewith transfer impedance Z TR is set to
infinitya large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (8)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (9)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (10)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50 )Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,511∠71.3° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (11)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
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Table 2.: Example Calculation (Lens Point 1)
𝐼𝐼𝐿𝐿
= 4,511∠71.3° 𝐴𝐴
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) × 1010 Ω
×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (12)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10) Ω × 4,511∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,757∠106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (13)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,757∠106.1° 𝑉𝑉
4,511∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 17.434 + 𝑗𝑗12.113 Ω
Table 3.: Example Calculation (Lens Point 2)
This example is for calculating the impedance second point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) at 70% of
the receiving-end voltage (E R ) and leading the receiving-end voltage by 120 degrees. See
Figures 3 and 4.
Eq. (14)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (15)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
× 70%
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 92,953.7∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
× 0.70
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
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Table 3.: Example Calculation (Lens Point 2)
Given positivePositive sequence impedance data (Thewith transfer impedance Z TR is set to
infinitya large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (16)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (17)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (18)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
92,953.7∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠77° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (19)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿
= 3,854∠77° 𝐴𝐴
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) × 1010 Ω
×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠77° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (20)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 92,953∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 )Ω × 3,854∠77° 𝐴𝐴]
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Table 3.: Example Calculation (Lens Point 2)
𝑉𝑉𝑆𝑆 = 65,271∠99° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (21)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
65,271∠99° 𝑉𝑉
3,854∠77° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 15.676 + 𝑗𝑗6.41 Ω
Table 4.: Example Calculation (Lens Point 3)
This example is for calculating the impedance third point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (E R ) at 70%
of the sending-end voltage (E S ) and the sending-end voltage leading the receiving-end voltage
by 120 degrees. See Figures 3 and 4.
Eq. (22)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (23)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
× 70%
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 92,953.7∠0° 𝑉𝑉
× 0.70
Given positivePositive sequence impedance data (Thewith transfer impedance Z TR is set to
infinitya large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (24)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
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Table 4.: Example Calculation (Lens Point 3)
Total system impedance.
Eq. (25)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (26)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 92,953.7∠0° 𝑉𝑉
(10 + 𝑗𝑗50) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠65.5° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (27)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿
= 3,854∠65.5° 𝐴𝐴
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) × 1010 Ω
×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠65.5° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (28)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10) Ω × 3,854∠65.5° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 98,265∠110.6° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (29)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
98,265∠110.6° 𝑉𝑉
3,854∠65.5° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 18.005 + 𝑗𝑗18.054 Ω
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Table 5.: Example Calculation (Lens Point 4)
This example is for calculating the impedance fourth point of the lens characteristic. Equal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) leading
the receiving-end voltage (E R ) by 240 degrees. See Figures 3 and 4.
Eq. (30)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (31)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠240° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positivePositive sequence impedance data (Thewith transfer impedance Z TR is set to
infinitya large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (32)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (33)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (34)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠240° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
(10 + 𝑗𝑗50 )Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,510511∠131.3° 𝐴𝐴
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Table 5.: Example Calculation (Lens Point 4)
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (35)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿
= 4,510511∠131.1° 𝐴𝐴
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) × 1010 Ω
×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 4,510511∠131.1° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (36)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠240° 𝑉𝑉
− [(2 + 𝑗𝑗10 ) Ω × 4,510∠131.1° 𝐴𝐴][(2 + 𝑗𝑗10 ) Ω
× 4,511∠131.1° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,756∠ − 106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (37)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,756∠ − 106.1° 𝑉𝑉 95,756∠ − 106.1° 𝑉𝑉
4,510∠131.1° 𝐴𝐴
4,511∠131.1° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −11.434 + 𝑗𝑗17.887 Ω
Table 6.: Example Calculation (Lens Point 5)
This example is for calculating the impedance fifth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the sending-end voltage (E S ) at 70% of
the receiving-end voltage (E R ) and leading the receiving-end voltage by 240 degrees. See
Figures 3 and 4.
Eq. (38)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (39)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
× 70%
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 92,953.7∠240° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
× 0.70
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
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Table 6.: Example Calculation (Lens Point 5)
𝐸𝐸𝑅𝑅 =
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given positivePositive sequence impedance data (Thewith transfer impedance Z TR is set to
infinitya large value).
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (40)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (41)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10 Ω) + (4 + 𝑗𝑗20 Ω) + (4 + 𝑗𝑗20 Ω)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (42)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
92,953.7∠240° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠125.5° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (43)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿
= 3,854∠125.5° 𝐴𝐴
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) × 1010 Ω
×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠125.5° 𝐴𝐴
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Table 6.: Example Calculation (Lens Point 5)
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (44)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 92,953.7∠240° 𝑉𝑉 − [(2 + 𝑗𝑗10 ) Ω × 3,854∠125.5° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 65,270.5∠ − 99.4° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (45)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
65,270.5∠ − 99.4° 𝑉𝑉
3,854∠125.5° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −12.005 + 𝑗𝑗11.946 Ω
Table 7.: Example Calculation (Lens Point 6)
This example is for calculating the impedance sixth point of the lens characteristic. Unequal
source voltages are used for the 230 kV (base) line with the receiving-end voltage (E R ) at 70%
of the sending-end voltage (E S ) and the sending-end voltage leading the receiving-end voltage
by 240 degrees. See Figures 3 and 4.
Eq. (46)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠240°
√3
230,000∠240° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠240° 𝑉𝑉
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
Eq. (47)
𝐸𝐸𝑅𝑅 =
× 70%
√3
230,000∠0° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
× 0.70
√3
𝐸𝐸𝑅𝑅 = 92,953.7∠0° 𝑉𝑉
Given positivePositive sequence impedance data (Thewith transfer impedance Z TR is set to
infinitya large value).
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Given:
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
Total impedance between the generators.
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
Eq. (48)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
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Table 7.: Example Calculation (Lens Point 6)
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
Eq. (49)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
Eq. (50)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠240° 𝑉𝑉 − 92,953.7∠0° 𝑉𝑉
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 3,854∠137.1° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
𝑍𝑍𝑇𝑇𝑇𝑇
Eq. (51)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿
= 3,854∠137.1° 𝐴𝐴
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) × 1010 Ω
×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 3,854∠137.1° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (52)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − (𝑍𝑍𝑆𝑆 × 𝐼𝐼𝐿𝐿 )
𝑉𝑉𝑆𝑆 = 132,791∠240° 𝑉𝑉
− [(2 + 𝑗𝑗10 )Ω × 3,854∠137.1° 𝐴𝐴][(2 + 𝑗𝑗10 ) Ω
× 3,854∠137.1° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 98,265∠ − 110.6° 𝑉𝑉
The impedance seen by the relay on Z L .
𝑉𝑉𝑆𝑆
Eq. (53)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝐼𝐼𝐿𝐿
98,265∠ − 110.6° 𝑉𝑉
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
3,854∠137.1° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = −9.676 + 𝑗𝑗23.59 Ω
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Figure 6.: Reduced two bus system with sending-end source impedance Z S , receiving-end
source impedance Z R , line impedance Z L , and parallel transfer impedance Z TR .
Figure 7.: Reduced two bus system with sending-end source impedance Z S , receiving-end
source impedance Z R , and line impedance Z L , and with the parallel transfer impedance Z TR
removed.
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Figure 8.: A strong-source system with a line impedance of Z L = 20.4 ohms (i.e., the thicker
red line). This mho element characteristic (i.e., the blue circle) does not meet the PRC-026-1 –
Attachment B, CriteriaCriterion A because it is not completely contained within the unstable
power swing region (i.e., the orange characteristic).
The figureFigure 8 above represents a heavyheavily-loaded system using a maximumwith all
generation profilein service and all transmission BES Elements in their normal operating state.
The mho element characteristic (set at 137% of Z L ) extends into the unstable power swing region
(i.e., the orange characteristic). Using the strongest source system is more conservative because it
shrinks the unstable power swing region, bringing it closer to the mho element characteristic. This
figure also graphically represents the effect of a system strengthening over time and this is the
reason for re-evaluation if the relay has not been evaluated in the last five calendar years. Figure
9 below depicts a relay that meets the PRC-026-1 – Attachment B, CriteriaCriterion A. Figure 8
depicts the same relay with the same setting five years later, where each source has strengthened
by about 10% and now the same mho element characteristic does not meet CriteriaCriterion A.
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Figure 9.: A weak-source system with a line impedance of Z L = 20.4 ohms (i.e., the thicker red
line). This mho element characteristic (i.e., the blue circle) meets the PRC-026-1 – Attachment
B, CriteriaCriterion A because it is completely contained within the unstable power swing
region (i.e., the orange characteristic).
The figureFigure 9 above represents a lightly -loaded system, using a minimum generation profile.
The mho element characteristic (set at 137% of Z L ) does not extend into the unstable power swing
region (i.e., the orange characteristic). Using a weaker source system expands the unstable power
swing region away from the mho element characteristic.
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Figure 10.: This is an example of an unstable power swing region (i.e., the orange characteristic)
with the parallel transfer impedance removed. This relay mho element characteristic (i.e., the
blue circle) does not meet PRC-026-1 – Attachment B, CriteriaCriterion A because it is not
completely contained within the unstable power swing region.
Table 8.: Example Calculation (Parallel Transfer Impedance Removed)
Calculations for the point at 120 degrees with equal source impedances. The total system current
equals the line current. See Figure 10.
Eq. (54)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
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Table 8.: Example Calculation (Parallel Transfer Impedance Removed)
Eq. (55)
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given impedance data.
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
Total impedance between the generators.
Eq. (56)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
�(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω × (4 + 𝑗𝑗20) × 1010 Ω�
=
�(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω� �(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω�
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 4 + 𝑗𝑗20 Ω
Total system impedance.
Eq. (57)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
Total system current from sending-end source.
Eq. (58)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
10 + 𝑗𝑗50 Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,511∠71.3° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (59)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿
= 4,511∠71.3° 𝐴𝐴
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) × 1010 Ω
×
(4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20)10 Ω (4 + 𝑗𝑗20) Ω + (4 + 𝑗𝑗20) × 1010 Ω
𝐼𝐼𝐿𝐿 = 4,511∠71.3° 𝐴𝐴
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Table 8.: Example Calculation (Parallel Transfer Impedance Removed)
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (60)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉 − [(2 + 𝑗𝑗10 Ω) × 4,511∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 95,757∠106.1° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (61)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
95,757∠106.1° 𝑉𝑉
4,511∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 17.434 + 𝑗𝑗12.113 Ω
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Figure 11.: This is an example of an unstable power swing region (i.e., the orange characteristic)
with the parallel transfer impedance included. The causing the mho element characteristic (i.e.,
the blue circle) meetsto appear to meet the PRC-026-1 – Attachment B, CriteriaCriterion A
because it is completely contained within the unstable power swing region. However,
includingIncluding the parallel transfer impedance in the calculation is not compliant
withallowed by the PRC-026-1 – Attachment B Criteria, Criterion A.
In the figureFigure 11 above, the parallel transfer impedance is 5 times the line impedance. The
unstable power swing region has expanded out beyond the mho element characteristic due to the
infeed effect from the parallel current through the parallel transfer impedance, thus allowing the
mho element characteristic to appear to meet the PRC-026-1 – Attachment B, CriteriaCriterion A.
However, includingIncluding the parallel transfer impedance in the calculation is not compliant
withallowed by the PRC-026-1 – Attachment B Criteria, Criterion A.
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Table 9.: Example Calculation (Parallel Transfer Impedance Included)
Calculations for the point at 120 degrees with equal source impedances. The total system current
does not equal the line current. See Figure 11.
Eq. (62)
𝐸𝐸𝑆𝑆 =
𝐸𝐸𝑆𝑆 =
Eq. (63)
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
√3
230,000∠120° 𝑉𝑉
√3
𝐸𝐸𝑆𝑆 = 132,791∠120° 𝑉𝑉
𝐸𝐸𝑅𝑅 =
𝐸𝐸𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
√3
230,000∠0° 𝑉𝑉
√3
𝐸𝐸𝑅𝑅 = 132,791∠0° 𝑉𝑉
Given impedance data.
Given:
Given:
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 5
𝑍𝑍𝑇𝑇𝑇𝑇 = (4 + 𝑗𝑗20) Ω × 5
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 20 + 𝑗𝑗100 Ω
Total impedance between the generators.
Eq. (64)
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 =
(𝑍𝑍𝐿𝐿 × 𝑍𝑍𝑇𝑇𝑇𝑇 )
(𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇 )
(4 + 𝑗𝑗20) Ω × (20 + 𝑗𝑗100) Ω
(4 + 𝑗𝑗20) Ω + (20 + 𝑗𝑗100) Ω
𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 = 3.333 + 𝑗𝑗16.667 Ω
Total system impedance.
Eq. (65)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (2 + 𝑗𝑗10) Ω + (3.333 + 𝑗𝑗16.667) Ω + (4 + 𝑗𝑗20) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 9.333 + 𝑗𝑗46.667 Ω
Total system current from sending-end source.
Eq. (66)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
132,791∠120° 𝑉𝑉 − 132,791∠0° 𝑉𝑉
9.333 + 𝑗𝑗46.667 Ω
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Table 9.: Example Calculation (Parallel Transfer Impedance Included)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 4,832833∠71.3° 𝐴𝐴
The current, as measured by the relay on Z L (Figure 3), is only the current flowing through that
line as determined by using the current divider equation.
Eq. (67)
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝐼𝐼𝐿𝐿
= 4,832833∠71.3° 𝐴𝐴
(20 + 𝑗𝑗100) Ω
(20 + 𝑗𝑗100) Ω
×
(9.333 + 𝑗𝑗46.667) Ω + (20 + 𝑗𝑗100) Ω (4 + 𝑗𝑗20) Ω + (20 + 𝑗𝑗100) Ω
𝐼𝐼𝐿𝐿 = 4,027.4∠71.3° 𝐴𝐴
The voltage, as measured by the relay on Z L (Figure 3), is the voltage drop from the sendingend source through the sending-end source impedance.
Eq. (68)
𝑉𝑉𝑆𝑆 = 𝐸𝐸𝑆𝑆 − �𝑍𝑍𝑆𝑆 × 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 �
𝑉𝑉𝑆𝑆 = 132,791∠120° 𝑉𝑉
− [(2 + 𝑗𝑗10 Ω) × 4,027∠71.3° 𝐴𝐴][(2 + 𝑗𝑗10 Ω)
× 4,833∠71.3° 𝐴𝐴]
𝑉𝑉𝑆𝑆 = 93,417∠104.7° 𝑉𝑉
The impedance seen by the relay on Z L .
Eq. (69)
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝐿𝐿
93,417∠104.7° 𝑉𝑉
4,027∠71.3° 𝐴𝐴
𝑍𝑍𝐿𝐿−𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 19.366 + 𝑗𝑗12.767 Ω
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Table 10.: Percent Increase of a Lens Due To Parallel Transfer Impedance.
The following demonstrates the percent size increase of the lens characteristic for Z TR in
multiples of Z L with the parallel transfer impedance included.
Z TR in multiples of Z L
Percent increase of lens with equal EMF
sources (Infinite source as reference)
Infinite
N/A
1000
0.05%
100
0.46%
10
4.63%
5
9.27%
2
23.26%
1
46.76%
0.5
94.14%
0.25
189.56%
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Figure 12.: The tripping portion of the mho element characteristic (i.e., the blue circle) not
blocked by load encroachment (i.e., the parallel green lines) of the mho element characteristic
(i.e., the blue circle) is completely contained within the unstable power swing region (i.e., the
orange characteristic). Therefore, the mho element characteristic meets the PRC-026-1 –
Attachment B, CriteriaCriterion A.
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Figure 13: The infeed diagram shows the impedance in front of the relay R with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes Z L + Z R .
Table 11.: Calculations (System Apparent Impedance in the forward direction)
The following equations are provided for calculating the apparent impedance back to the E R
source voltage as seen by relay R. Infeed equations from V S to source E R where E R = 0. See
Figure 13.
Eq. (70)
Eq. (71)
Eq. (72)
Eq. (73)
Eq. (74)
Eq. (75)
Eq. (76)
Eq. (77)
Eq. (78)
Eq. (79)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑆𝑆 − 𝑉𝑉𝑅𝑅
𝑍𝑍𝐿𝐿
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑅𝑅 − 𝐸𝐸𝑅𝑅
𝑍𝑍𝑅𝑅
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝐿𝐿 =
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅
𝑍𝑍𝑅𝑅
Since 𝐸𝐸𝑅𝑅 = 0
Rearranged:
𝑉𝑉𝑆𝑆 − 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑅𝑅
𝑍𝑍𝐿𝐿
𝑉𝑉𝑅𝑅 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑅𝑅
𝑉𝑉𝑆𝑆 − [(𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇 ) × 𝑍𝑍𝑅𝑅 ]
𝑍𝑍𝐿𝐿
𝑉𝑉𝑆𝑆 = (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝐿𝐿 ) + (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝑅𝑅 ) + (𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅 )
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑆𝑆
𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅
𝐼𝐼𝑇𝑇𝑇𝑇
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 +
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
�
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝑇𝑇𝑇𝑇 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
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Table 11.: Calculations (System Apparent Impedance in the forward direction)
Eq. (80)
𝐼𝐼𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
=
𝐼𝐼𝐿𝐿
𝑍𝑍𝑇𝑇𝑇𝑇
The infeed equations shows the impedance in front of the relay R (Figure 13) with the parallel
transfer impedance included. As the parallel transfer impedance approaches infinity, the
impedances seen by the relay R in the forward direction becomes Z L + Z R .
Eq. (81)
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
Figure 14: The infeed diagram shows the impedance behind relay R with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes Z S .
Table 12.: Calculations (System Apparent Impedance in the reverse
directionReverse Direction)
The following equations are provided for calculating the apparent impedance back to the E S
source voltage as seen by relay R. Infeed equations from V R back to source E S where E S = 0.
See Figure 14.
Eq. (82)
Eq. (83)
Eq. (84)
Eq. (85)
Eq. (86)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅 − 𝑉𝑉𝑆𝑆
𝑍𝑍𝐿𝐿
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑆𝑆 − 𝐸𝐸𝑆𝑆
𝑍𝑍𝑆𝑆
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑆𝑆
𝑍𝑍𝑆𝑆
𝑉𝑉𝑅𝑅 − 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑆𝑆
𝑍𝑍𝐿𝐿
Since 𝐸𝐸𝑠𝑠 = 0
Rearranged:
𝑉𝑉𝑆𝑆 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 × 𝑍𝑍𝑆𝑆
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Table 12.: Calculations (System Apparent Impedance in the reverse
directionReverse Direction)
Eq. (87)
Eq. (88)
Eq. (89)
Eq. (90)
Eq. (91)
Eq. (92)
𝐼𝐼𝐿𝐿 =
𝑉𝑉𝑅𝑅 − [(𝐼𝐼𝐿𝐿 + 𝐼𝐼𝑇𝑇𝑇𝑇 ) × 𝑍𝑍𝑆𝑆 ]
𝑍𝑍𝐿𝐿
𝑉𝑉𝑅𝑅 = (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝐿𝐿 ) + (𝐼𝐼𝐿𝐿 × 𝑍𝑍𝑆𝑆 ) + (𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑅𝑅𝑅𝑅 )
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 =
𝑉𝑉𝑅𝑅
𝐼𝐼𝑇𝑇𝑇𝑇 × 𝑍𝑍𝑆𝑆
𝐼𝐼𝑇𝑇𝑇𝑇
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 +
= 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 × �1 +
�
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝐿𝐿
𝐼𝐼𝑇𝑇𝑇𝑇 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝐿𝐿 = 𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 ×
𝐼𝐼𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
=
𝐼𝐼𝐿𝐿
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑇𝑇𝑇𝑇
The infeed equations shows the impedance behind relay R (Figure 14) with the parallel transfer
impedance included. As the parallel transfer impedance approaches infinity, the impedances
seen by the relay R in the reverse direction becomes Z S .
Eq. (93)
Eq. (94)
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 = 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝐿𝐿
�
𝑍𝑍𝑇𝑇𝑇𝑇
As seen by relay R at the receiving-end of
the line.
Subtract Z L for relay R impedance as seen
at sending-end of the line.
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Figure 15.: Out-of-step trip (OST) inner blinder (i.e., the parallel green lines) meets the PRC026-1 – Attachment B, CriteriaCriterion A because the inner OST blinder initiates tripping
either On-The-Way-In or On-The-Way-Out. Since the inner blinder is completely contained
within the unstable power swing region (i.e., the orange characteristic), it meets the PRC-026-1
– Attachment B, CriteriaCriterion A.
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Table 13.: Example Calculation (Voltage Ratios)
These calculations are based on the loss -of -synchronism characteristics for the cases of N < 1
and N > 1 as found in the Application of Out-of-Step Blocking and Tripping Relays, GER-3180,
p. 12, Figure 13. 19 The GE illustration shows the formulae used to calculate the radius and center
of the circles that make up the ends of the portion of the lens.
Voltage ratio equations, source impedance equation with infeed formulae applied, and circle
equations.
Given:
Eq. (95)
Eq. (96)
𝐸𝐸𝑆𝑆 = 0.7
𝑁𝑁𝑎𝑎 =
𝑁𝑁𝑏𝑏 =
|𝐸𝐸𝑆𝑆 |
|𝐸𝐸𝑆𝑆 | 0.7
𝑁𝑁 =
=
= 0.7
|𝐸𝐸𝑅𝑅 |
|𝐸𝐸𝑅𝑅 | 1.0
𝐸𝐸𝑅𝑅 = 1.0
|𝐸𝐸𝑅𝑅 | 1.0
=
= 1.43
|𝐸𝐸𝑆𝑆 | 0.7
The total system impedance as seen by the relay with infeed formulae applied.
Given:
Given:
Eq. (9796)
𝑍𝑍𝑆𝑆 = 2 + 𝑗𝑗10 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = 𝑍𝑍𝐿𝐿 × 1010 Ω
𝑍𝑍𝐿𝐿 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝑇𝑇𝑇𝑇 = (4 + 𝑗𝑗20)10 (4 + 𝑗𝑗20) × 1010 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 × �1 +
𝑍𝑍𝑅𝑅 = 4 + 𝑗𝑗20 Ω
𝑍𝑍𝐿𝐿
𝑍𝑍𝐿𝐿
� + �𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅 × �1 +
��
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑇𝑇𝑇𝑇
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 10 + 𝑗𝑗50 Ω
The calculated coordinates of the lower loss-of-synchronism circle center.
Eq. (9897)
𝑍𝑍𝐶𝐶1
𝑁𝑁𝑎𝑎2 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 𝑁𝑁 2 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝑍𝑍𝐿𝐿
= − �𝑍𝑍𝑆𝑆 × �1 +
�� − �
��
�
𝑍𝑍𝑇𝑇𝑇𝑇
1 − 𝑁𝑁𝑎𝑎2
1 − 𝑁𝑁 2
(4 + 𝑗𝑗20) Ω
�� � (2 + 𝑗𝑗10) Ω
(4 + 𝑗𝑗20)10 Ω
(4 + 𝑗𝑗20) Ω
0.72 × (10 + 𝑗𝑗50) Ω
× �1 +
−
�
�
��
(4 + 𝑗𝑗20) × 1010 Ω
1 − 0.72
𝑍𝑍𝐶𝐶1 = − � (2 + 𝑗𝑗10) Ω × �1 +
𝑍𝑍𝐶𝐶1 = −11.608 − 𝑗𝑗58.039 Ω
The calculated radius of the lower loss-of-synchronism circle.
Eq. (9998)
𝑟𝑟𝑎𝑎 = �
𝑁𝑁𝑎𝑎 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 𝑁𝑁 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
��
�
1 − 𝑁𝑁𝑎𝑎2
1 − 𝑁𝑁 2
𝑟𝑟𝑎𝑎 = �
19
0.7 × (10 + 𝑗𝑗50) Ω 0.7 × (10 + 𝑗𝑗50) Ω
��
�
1 − 0.72
1 − 0.72
http://store.gedigitalenergy.com/faq/Documents/Alps/GER-3180.pdf
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Table 13.: Example Calculation (Voltage Ratios)
𝑟𝑟𝑎𝑎 = 69.987 Ω
The calculated coordinates of the upper loss-of-synchronism circle center.
Given:
Eq. (99)
Eq. (100)
𝐸𝐸𝑆𝑆 = 1.0
𝑁𝑁 =
|𝐸𝐸𝑆𝑆 | 1.0
=
= 1.43
|𝐸𝐸𝑅𝑅 | 0.7
𝑍𝑍𝐶𝐶2 = 𝑍𝑍𝐿𝐿 + �𝑍𝑍𝑅𝑅 × �1 +
𝐸𝐸𝑅𝑅 = 0.7
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝑍𝑍𝐿𝐿
�� + � 2
�� 2
�
𝑍𝑍𝑇𝑇𝑇𝑇
𝑁𝑁𝑏𝑏 − 1 𝑁𝑁 − 1
(4 + 𝑗𝑗20) Ω
(10 + 𝑗𝑗50) Ω
�� + �
� 𝑍𝑍𝐶𝐶2
10
(4 + 𝑗𝑗20) Ω
1.432 − 1
(4 + 𝑗𝑗20) Ω
= 4 + 𝑗𝑗20 Ω + � (4 + 𝑗𝑗20) Ω × �1 +
��
(4 + 𝑗𝑗20) × 1010 Ω
(10 + 𝑗𝑗50) Ω
+�
�
2
𝑍𝑍𝐶𝐶2 = − � (4 + 𝑗𝑗20) Ω × �1 +
1.43 − 1
𝑍𝑍𝐶𝐶2 = 17.608 + 𝑗𝑗88.039 Ω
The calculated radius of the upper loss-of-synchronism circle.
Eq. (101)
𝑟𝑟𝑏𝑏 = �
𝑟𝑟𝑏𝑏 = �
𝑁𝑁𝑏𝑏 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 𝑁𝑁 × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
�� 2
�
𝑁𝑁 − 1
𝑁𝑁𝑏𝑏2 − 1
1.43 × (10 + 𝑗𝑗50) Ω 1.43 × (10 + 𝑗𝑗50) Ω
��
�
1.432 − 1
1.432 − 1
𝑟𝑟𝑏𝑏 = 69.987 Ω
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Figure 15a: Lower circle loss -of -synchronism region showing the coordinates of the circle
center and the circle radius.
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Figure 15b: Lower circle loss -of -synchronism region showing the first three steps to
calculate the coordinates of the points on the circle. 1) Identify the lower circle loss-ofsynchronism points that intersect the lens shape where the sending-end to receiving-end
voltage ratio is 0.7 (see lens shape calculations in Tables 2-7). 2) Calculate the distance
between the two lower circle loss-of-synchronism points identified in Step 1. 3) Calculate the
angle of arc that connects the two lower circle loss-of-synchronism points identified in Step 1.
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Figure 15c: Lower circle loss -of -synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1)
Calculate the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4)
Calculate the angle step size for the desired number of points.
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Figure 15d: Lower circle loss -of -synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R–X coordinates.
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Figure 15e: Upper circle loss -of -synchronism region showing the coordinates of the circle
center and the circle radius.
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Figure 15f: Upper circle loss -of -synchronism region showing the first three steps to calculate
the coordinates of the points on the circle. 1) Identify the upper circle points that intersect the
lens shape where the sending-end to receiving-end voltage ratio is 1.43 (see lens shape
calculations in Tables 2-7). 2) Calculate the distance between the two upper circle points
identified in Step 1. 3) Calculate the angle of arc that connects the two upper circle points
identified in Step 1.
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Figure 15g: Upper circle loss -of -synchronism region showing the steps to calculate the start
angle, end angle, and the angle step size for the desired number of calculated points. 1) Calculate
the system angle. 2) Calculate the start angle. 3) Calculate the end angle. 4) Calculate the angle
step size for the desired number of points.
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Figure 15h: Upper circle loss -of -synchronism region showing the final steps to calculate the
coordinates of the points on the circle. 1) Start at the intersection with the lens shape and
proceed in a clockwise direction. 2) Advance the step angle for each point. 3) Calculate the
new angle after step advancement. 4) Calculate the R-X coordinates.
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Figure 15i: Full tables of calculated lower and upper loss -of -synchronism circle coordinates.
The highlighted row is the detailed calculated points in Figures 15d and 15h.
Application Specific to CriteriaCriterion B
The PRC-026-1 – Attachment B, CriteriaCriterion B evaluates overcurrent elements used for
tripping. The same criteria as PRC-026-1 – Attachment B, CriteriaCriterion A is used except for
an additional criteriacriterion (No. 4) that calculates a current magnitude based upon generator
terminal voltages internal voltage of 1.05 per unit. A value of 1.05 per unit generator voltage is
used to establish a minimum pickup current value for overcurrent relays that have a time delay less
than 15 cycles. The formulasending-end and receiving-end voltages are established at 1.05 per unit
at 120 degree system separation angle. The 1.05 per unit is the typical upper end of the operating
voltage, which is also consistent with the maximum power transfer calculation using actual system
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source impedances in the PRC-023 NERC Reliability Standard. The formulas used to calculate the
current is as follows:are in Table 14 below.
Table 14.: Example Calculation (Overcurrent)
This example is for a 230 kV line terminal with a directional instantaneous phase overcurrent
element set to 50 amps secondary times a CT ratio of 160:1 that equals 8,000 amps, primary.
The following calculation is where V S equals the base line-to-ground sending-end generator
source voltage times 1.05 at an angle of 120 degrees, V R equals the base line-to-ground
receiving-end generator terminalinternal voltage times 1.05 at an angle of 0 degrees, and Z sys
equals the sum of the sending-end source, line, and receiving-end source impedances in ohms.
Here, the phase instantaneous phase setting of 8,000 amps is greater than the calculated system
current of 5,716 amps; therefore, it meets PRC-026-1 – Attachment B, CriteriaCriterion B.
Eq. (102)
𝑉𝑉𝑆𝑆 =
𝑉𝑉𝑆𝑆 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠120°
× 1.05
√3
230,000∠120° 𝑉𝑉
√3
𝑉𝑉𝑆𝑆 = 139,430∠120° 𝑉𝑉
× 1.05
Receiving-end generator terminal voltage.
Eq. (103)
𝑉𝑉𝑅𝑅 =
𝑉𝑉𝑅𝑅 =
𝑉𝑉𝐿𝐿𝐿𝐿 ∠0°
× 1.05
√3
230,000∠0° 𝑉𝑉
√3
𝑉𝑉𝑅𝑅 = 139,430∠0° 𝑉𝑉
× 1.05
The total impedance of the system (Z sys ) equals the sum of the sending-end source impedance
(Z S ), the impedance of the line (Z L ), and receiving-end impedance (Z R ) in ohms.
Given:
Eq. (104)
𝑍𝑍𝑆𝑆 = 3 + 𝑗𝑗26 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑍𝑍𝑆𝑆 + 𝑍𝑍𝐿𝐿 + 𝑍𝑍𝑅𝑅
𝑍𝑍𝐿𝐿 = 1.3 + 𝑗𝑗8.7 Ω
𝑍𝑍𝑅𝑅 = 0.3 + 𝑗𝑗7.3 Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = (3 + 𝑗𝑗26) Ω + (1.3 + 𝑗𝑗8.7) Ω + (0.3 + 𝑗𝑗7.3) Ω
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 4.6 + 𝑗𝑗42 Ω
Total system current from sending-end source.
Eq. (105)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
(𝑉𝑉𝑆𝑆 − 𝑉𝑉𝑅𝑅 )
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
(139,430∠120° 𝑉𝑉 − 139,430∠0° 𝑉𝑉)
(4.6 + 𝑗𝑗42) Ω
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 5,715.82∠66.25° 𝐴𝐴
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Application Specific to Three-Terminal Lines
If a three-terminal line is identified as an Element that is susceptible to a power swing based on
Requirement R1, the load-responsive protective relays at each end of the three-terminal line must
be evaluated.
As shown in Figure 15j, the source impedances at each end of the line can be obtained from the
similar short circuit calculation as for the two-terminal line. (assuming the parallel transfer
impedances are ignored).
EA
A
B
ZSA
ZL2
ZL1
R
ZSB
EB
ZL3
C
ZSC
EC
Figure 15j.: Three-terminal line. To evaluate the load-responsive protective relays on the threeterminal line at Terminal A, the circuit in Figure 15j is first reduced to the equivalent circuit
shown in Figure 15k. The evaluation process for the load-responsive protective relays on the
line at Terminal A will now be the same as that of the two-terminal line.
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Figure 15k.: Three-terminal line reduced to a two-terminal line.
Application to Generation Elements
As with transmission BES Elements, the determination of the apparent impedance seen at an
Element located at, or near, a generation Facility is complex for power swings due to various
interdependent quantities. These variances in quantities are caused by changes in machine internal
voltage, speed governor action, voltage regulator action, the reaction of other local generators, and
the reaction of other interconnected transmission BES Elements as the event progresses through
the time domain. Though transient stability simulations may be used to determine the apparent
impedance for verifying load-responsive relay settings, 20,21 Requirement R2, PRC-026-1 –
Attachment B, Criteria A and B provides a simplified method for evaluating the load-responsive
protective relay’s susceptibility to tripping in response to a stable power swing without requiring
stability simulations.
In general, the electrical center will be in the transmission system for cases where the generator is
connected through a weak transmission system (high external impedance). OtherIn other cases
where the generator is connected through a strong Transmissiontransmission system, the electrical
center could be inside the unit connected zone. 22 In either case, load-responsive protective relays
connected at the generator terminals or at the high-voltage side of the generator step-up (GSU)
transformer may be challenged by power swings as. Relays that may be challenged by power
swings will be determined by the Planning Coordinator in Requirement R1 or by the Generator
Owner after becoming aware of a generator, transformer, or transmission line BES Element that
tripped 23 in response to a stable or unstable power swing due to the operation of its protective
relay(s) in Requirement R2.
20
Donald Reimert, Protective Relaying for Power Generation Systems, Boca Raton, FL, CRC Press, 2006.
21
Prabha Kundur, Power System Stability and Control, EPRI, McGraw Hill, Inc., 1994.
22
Ibid, Kundur.
23
See Guidelines and Technical Basis section, “Becoming Aware of an Element That Tripped in Response to a
Power Swing,”
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Load-responsive protective relays such as time over-current, voltageVoltage controlled timeovercurrent orand voltage-restrained time-overcurrent relays are excluded from this standard if
they. When these relays are set based on equipment permissible overload capability. Their, their
operating time istimes are much greater than 15 cycles for the current levels observed during a
power swing.
Instantaneous overcurrent, time-overcurrent, and definite-time overcurrent relays with a time delay
of less than 15 cycles for the current levels observed during a power swing are applicable and are
required to be evaluated for identified Elements.
The generator loss-of-field protective function is provided by impedance relay(s) connected at the
generator terminals. The settings are applied to protect the generator from a partial or complete
loss of excitation under all generator loading conditions and, at the same time, be immune to
tripping on stable power swings. It is more likely that the loss-of-field relay would operate during
a power swing when the automatic voltage regulator (AVR) is in manual mode rather than when
in automatic mode. 24 Figure 16 illustrates the loss-of-field relay in the R-X plot, which typically
includes up to three zones of protection.
24
John Burdy, Loss-of-excitation Protection for Synchronous Generators GER-3183, General Electric Company.
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Figure 16.: An R-X graph of typical impedance settings for loss-of-field relays.
Loss-of-field characteristic 40-1 has a wider impedance characteristic (positive offset) than
characteristic 40-2 or characteristic 40-3 and provides additional generator protection for a partial
loss of field or a loss of field under low load (less than 10% of rated). The tripping logic of this
protection scheme is established by a directional contact, a voltage setpoint, and a time delay. The
voltage and time delay add security to the relay operation for stable power swings. Characteristic
40-3 is less sensitive to power swings than characteristic 40-2 and is set outside the generator
capability curve in the leading direction. Regardless of the relay impedance setting, PRC-01925
requires that the “in-service limiters operate before Protection Systems to avoid unnecessary trip”
and “in-service Protection System devices are set to isolate or de-energize equipment in order to
limit the extent of damage when operating conditions exceed equipment capabilities or stability
limits.” Time delays for tripping associated with loss-of-field relays 26,27 have a range from 15
cycles for characteristic 40-2 to 60 cycles for characteristic 40-1 to minimize tripping during stable
25
Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection
26
Ibid, Burdy.
27
Applied Protective Relaying, Westinghouse Electric Corporation, 1979.
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power swings. In the standardPRC-026-1, 15 cycles establishes a threshold for applicability;
however, it is the responsibility of the Generator Owner to establish settings that provide security
against stable power swings and, at the same time, dependable protection for the generator.
The simple two-machine system circuit (method also used in the Application to Transmission
Elements section) is used to analyze the effect of a power swing at a generator facility for loadresponsive relays. In this section, the calculation method is used for calculating the impedance
seen by the relay connected at a point in the circuit. 28 The electrical quantities used to determine
the apparent impedance plot using this method are generator saturated transient reactance (X’ d ),
GSU transformer impedance (X GSU ), transmission line impedance (Z L ), and the system equivalent
(Z e ) at the point of interconnection. All impedance values are known to the Generator Owner
except for the system equivalent. The system equivalent is obtainable from the Transmission
Owner. The sending-end and receiving-end source voltages are varied from 0.0 to 1.0 per unit to
form the lens shape portion of the unstable power swing region. The voltage range of 0.7 to 1.0
results in a ratio range from 0.7 to 1.43. This ratio range is used to form the lower and upper lossof-synchronism circle shapes of the unstable power swing region. A system separation angle of
120 degrees is used in accordance with PRC-026-1 – Attachment B criteria for each loadresponsive protective relay evaluation.
Table 15 below is an example calculation of the apparent impedance locus method based on
Figures 17 and 18. 29 In this example, the generator is connected to the 345 kV transmission system
through the GSU transformer and has the listed ratings. Note that the load-responsive protective
relays in this example may have ownership with the Generator Owner or the Transmission Owner.
Figure 17.: Simple one-line diagram of the
system to be evaluated.
Figure 18.: Simple system equivalent
impedance diagram to be evaluated. 30
Table15.: Example Data (Generator)
Input Descriptions
Input Values
Synchronous Generator nameplate (MVA)
940 MVA
28
Edward Wilson Kimbark, Power System Stability, Volume II: Power Circuit Breakers and Protective Relays,
Published by John Wiley and Sons, 1950.
29
Ibid, Kimbark.
30
Ibid, Kimbark.
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Table15.: Example Data (Generator)
Sub-Saturated transient reactance (940MVA940
MVA base)
Generator rated voltage (Line-to-Line)
Generator step-up (GSU) transformer rating
GSU transformer reactance (880 MVA base)
System Equivalent (100 MVA base)
𝑋𝑋𝑑𝑑′ = 0.3845 (per unit)
20 𝑘𝑘𝑘𝑘
880 𝑀𝑀𝑀𝑀𝑀𝑀
XGSU = 16.05%
𝑍𝑍𝑒𝑒 = 0.00723∠86° ohms90° per unit
Generator Owner Load-Responsive Protective Relays
Positive Offset Impedance
Offset = 0.294 per unit ohms
40-1
Diameter = 0.294 per unit ohms
Negative Offset Impedance
Offset = 0.22 per unit ohms
40-2
Diameter = 2.24 per unit ohms
Negative Offset Impedance
Offset = 0.22 per unit ohms
40-3
Diameter = 1.00 per unit ohms
Diameter = 0.643 per unit ohms
21-1
MTA = 85°
I (pickup) = 5.0 per unit
50
Transmission Owned Load-Responsive Protective Relays
Diameter = 0.55 per unit ohms
21-2
MTA = 85°
Calculations shown for a 120 degree angle and E S /E R = 1. The equation for calculating Z R is: 31
Eq. (106)
31
𝑍𝑍𝑅𝑅 = �
(1 − 𝑚𝑚)(𝐸𝐸𝑆𝑆 ∠𝛿𝛿) + (𝑚𝑚)(𝐸𝐸𝑅𝑅 )
� × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝐸𝐸𝑆𝑆 ∠𝛿𝛿 − 𝐸𝐸𝑅𝑅
Ibid, Kimbark.
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Where m is the relay location as a function of the total impedance (real number less than 1)
E S and E R is the sending-end and receiving-end voltages
Z sys is the total system impedance
Z R is the complex impedance at the relay location and plotted on an R-X diagram
All of the above are constants (940 MVA base) while the angle δ is varied. Table 16 below contains
calculations for a generator using the data listed in Table 15.
Table16.: Example Calculations (Generator)
The following calculations are on a 940 MVA base.
Given:
Eq. (107)
𝑋𝑋𝑑𝑑′ = 𝑗𝑗0.3845 Ω𝑝𝑝𝑝𝑝
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑋𝑋𝑑𝑑′ + 𝑋𝑋𝐺𝐺𝐺𝐺𝐺𝐺 + 𝑍𝑍𝑒𝑒
𝑋𝑋𝐺𝐺𝐺𝐺𝐺𝐺 =
𝑗𝑗0.171 Ω17144 𝑝𝑝𝑝𝑝
𝑍𝑍𝑒𝑒 = 0𝑗𝑗0.06796 Ω𝑝𝑝𝑝𝑝
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 𝑗𝑗0.3845 Ω𝑝𝑝𝑝𝑝 + 𝑗𝑗0.171 Ω + 017144 𝑝𝑝𝑝𝑝 + 𝑗𝑗0.06796 Ω𝑝𝑝𝑝𝑝
Eq. (108)
Eq. (109)
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 = 0.6239 ∠90° Ω 𝑝𝑝𝑝𝑝
𝑚𝑚 =
𝑋𝑋𝑑𝑑′
0.3845
=
= 0.616336163
𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠 0.6239
𝑍𝑍𝑅𝑅 = �
𝑍𝑍𝑅𝑅 = �
(1 − 𝑚𝑚)(𝐸𝐸𝑆𝑆 ∠𝛿𝛿) + (𝑚𝑚)(𝐸𝐸𝑅𝑅 )
� × 𝑍𝑍𝑠𝑠𝑠𝑠𝑠𝑠
𝐸𝐸𝑆𝑆 ∠𝛿𝛿 − 𝐸𝐸𝑅𝑅
(1 − 0.61633) × (1∠120°) + (0.61633)(1∠0°)
�
1∠120° − 1∠0°
× (0.6234∠90°) Ω𝑍𝑍𝑅𝑅
(1 − 0.6163) × (1∠120°) + (0.6163)(1∠0°)
=�
�
1∠120° − 1∠0°
× (0.6239∠90°) 𝑝𝑝𝑝𝑝
0.4244 + 𝑗𝑗0.3323
Z𝑅𝑅 = �
� × (0.6234∠90°)(0.6239∠90°) Ω𝑝𝑝𝑝𝑝
−1.5 + 𝑗𝑗 0.866
Z𝑅𝑅 = (0.3112 ∠ − 111.94°)(0.3116 ∠ − 111.95°)
× (0.6234∠90°)(0.6239∠90°) Ω𝑝𝑝𝑝𝑝
Z𝑅𝑅 = 0.194 ∠ − 21.94° Ω95° 𝑝𝑝𝑝𝑝
Z𝑅𝑅 = −0.18 − 𝑗𝑗0.073 Ω𝑝𝑝𝑝𝑝
Table 17 lists the swing impedance values at other angles and at E S /E R = 1, 1.43, and 0.7. The
impedance values are plotted on an R-X graph with the center being at the generator terminals for
use in evaluating impedance relay settings.
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Table 17: Sample calculationsCalculations for a swing impedance chartSwing
Impedance Chart for varying voltagesVarying Voltages at the sending-endSendingEnd and receiving-endReceiving-End.
E S /E R =1
E S /E R =1.43
E S /E R =0.7
ZR
ZR
ZR
Angle (δ)
(Degrees)
Magnitude
(PU
Ohmspu)
Angle
(Degrees)
Magnitude
(PU
Ohmspu)
Angle
Magnitude
Angle
(Degrees)
(PU
(Degrees)
Ohmspu)
90
0.320
-13.1
0.296
6.3
0.344
-31.5
120
0.194
-21.9
0.173
-0.4
0.227
-40.1
150
0.111
-41.0
0.082
-10.3
0.154
-58.4
210
0.111
-25.9
0.082
190.3
0.154
238.4
240
0.194
201.9
0.173
180.4
0.225
220.1
270
0.320
193.1
0.296
173.7
0.344
211.5
Requirement R2 Generator Examples
Distance Relay Application
Based on PRC-026-1 – Attachment B, CriteriaCriterion A, the distance relay (21-1) (i.e., owned
by the Generation Owner) characteristic is in the region where a stable power swing would not
occur as shown in Figure 19. There is no further obligation to the owner in this standard for this
load-responsive protective relay.
The distance relay (21-2) (i.e., owned by the Transmission Owner) is connected at the high-voltage
side of the GSU transformer and its impedance characteristic is in the region where a stable power
swing could occur causing the relay to operate. In this example, if the intentional time delay of this
relay is less than 15 cycles, the PRC-026 – Attachment B, Criteria BCriterion A cannot be met,
thus the Transmission Owner is required to create a CAP (Requirement R3). Some of the options
include, but are not limited to, changing the relay setting (i.e., impedance reach, angle, time delay),
modify the scheme (i.e., add PSB), or replace the Protection System. Note that the relay may be
excluded from this standard if it has an intentional time delay equal to or greater than 15 cycles.
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Figure 19.: Swing impedance graph for impedance relays at a generating facility.
Loss-of-Field Relay Application
In Figure 20, the R-X diagram shows the loss-of-field relay (40-1 and 40-2) characteristics are in
the region where a stable power swing can cause a relay operation. Protective relay 40-1 would
be excluded if it has an intentional time delay equal to or greater than 15 cycles. Similarly, 40-2
would be excluded if its intentional time delay is equal to or greater than 15 cycles. For example,
if 40-1 has a time delay of 1 second and 40-2 has a time delay of 0.25 seconds, they are excluded
and there is no further obligation on the Generator Owner in this standard for these relays. The
loss-of-field relay characteristic 40-3 is outsideentirely inside the region where a stableunstable
power swing can cause a relay operationregion. In this case, the owner may select high speed
tripping on operation of the 40-3 impedance element.
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Figure 20: Stable power swing Typical R-X graph for loss-of-field relays with a portion of the
unstable power swing region defined by PRC-026-1 – Attachment B, Criterion A.
Instantaneous Overcurrent Relay
In similar fashion to the transmission line overcurrent example calculation in Table 14, the
instantaneous overcurrent relay minimum setting is established by PRC-026-1 – Attachment B,
CriteriaCriterion B. The solution is found by:
Eq. (110)
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
𝐸𝐸𝑆𝑆 − 𝐸𝐸𝑅𝑅
𝑍𝑍sys
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
(1.05∠120° − 1.05∠0°) (1.05∠120° − 1.05∠0°)
𝐴𝐴𝑝𝑝𝑝𝑝
0.6234∠90°
0.6239∠90°
As stated in the relay settings in Table 15, the relay is installed on the high-voltage side of the GSU
transformer with a pickup of 5.0 per unit amps. The maximum allowable current is calculated
below.
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 =
1.775∠150° 𝑉𝑉 1.819∠150°
𝐴𝐴
𝑝𝑝𝑝𝑝
0.6234∠90° Ω 0.6239∠90°
𝐼𝐼𝑠𝑠𝑠𝑠𝑠𝑠 = 2.8491 ∠60° 𝐴𝐴𝑝𝑝𝑝𝑝
The phase instantaneous phase setting of 5.0 per unit amps is greater than the calculated system
current of 2.8491 per unit amps; therefore, it meets the PRC-026-1 – Attachment B,
CriteriaCriterion B.
Out-of-Step Tripping for Generation Facilities
Out-of-step protection for the generator generally falls into three different schemes. The first
scheme is a distance relay connected at the high-voltage side of the GSU transformer with the
directional element looking toward the generator. Because this relay setting may be the same
setting used for generator backup protection (see Requirement R2 Generator Examples, Distance
Relay Application), it is susceptible to tripping in response to stable power swings and would
require modification. Because this scheme is susceptible to tripping in response to stable power
swings and any modification to the mho circle will jeopardize the overall protection of the outof-step protection of the generator, available technical literature does not recommend using this
scheme specifically for generator out-of-step protection. The second and third out-of-step
Protection System schemes are commonly referred to as single and double blinder schemes.
These schemes are installed or enabled for out-of-step protection using a combination of
blinders, a mho element, and timers. The combination of these protective relay functions
provides out-of-step protection and discrimination logic for stable and unstable power swings.
Single blinder schemes use logic that discriminate between stable and unstable power swings by
issuing a trip command after the first slip cycle. Double blinder schemes are more complex
thatthan the single blinder scheme and, depending on the settings of the inner blinder, a trip for a
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stable power swing may occur. While the logic discriminates between stable and unstable power
swings in either scheme, it is important that the trip initiating blinders be set at an angle greater
than the stability limit of 120 degrees to remove the possibility of a trip for a stable power swing.
Below is a discussion of the double blinder scheme.
Double Blinder Scheme
The double blinder scheme is a method for measuring the rate of change of positive sequence
impedance for out-of-step swing detection. The scheme compares a timer setting to the actual
elapsed time required by the impedance locus to pass between two impedance characteristics. In
this case, the two impedance characteristics are simple blinders, each set to a specific resistive
reach on the R-X plane. Typically, the two blinders on the left half plane are the mirror images of
those on the right half plane. The scheme typically includes a mho characteristic which acts as a
starting element, but is not a tripping element.
The scheme detects the blinder crossings and time delays as represented on the R-X plane as
shown in Figure 21. The system impedance is composed of the generator transient (X d ’), GSU
transformer (X T) , and transmission system (X system ), impedances.
The scheme logic is initiated when the swing locus crosses the outer Blinder R1 (Figure 21), on
the right at separation angle α. The scheme only commits to take action when a swing crosses the
inner blinder. At this point the scheme logic seals in the out-of-step trip logic at separation angle
β. Tripping actually asserts as the impedance locus leaves the scheme characteristic at separation
angle δ.
The power swing may leave both inner and outer blinders in either direction, and tripping will
assert. Therefore, the inner blinder must be set such that the separation angle β is large enough
that the system cannot recover. This angle should be set at 120 degrees or more. Setting the angle
greater than 120 degrees satisfies the PRC-026-1 – Attachment B Criteria, Criterion A (No. 1, 1st
bullet) since the tripping function is asserted by the blinder element. Transient stability studies
are usually required to determine an appropriate inner blinder setting. Such studies may indicate
that a smaller stability limit angle is acceptable under PRC-026-1 – Attachment B Criteria,
Criterion A (No. 1, 2nd bullet). In this respect, the double blinder scheme is similar to the double
lens and triple lens schemes, and many transmission application out-of-step schemes.
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Figure 21: Double Blinder Scheme generic out of step characteristics.
Figure 22 illustrates a sample setting of the double blinder scheme for the example 940 MVA
generator. The only setting requirement for this relay scheme is the right inner blinder, which
must be set greater than the separation angle of 120 degrees (or a lesser angle based on a
transient stability study) to ensure that the out-of-step protective function is expected to not trip
in response to a stable power swing during non-Fault conditions. Other settings such as the mho
characteristic, outer blinders, and timers are set according to transient stability studies and are not
a part of this standard.
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Figure 22: Double Blinder Out-of-Step Scheme with unit impedance data and load-responsive
protective relay impedance characteristics for the example 940 MVA generator, scaled in relay
secondary ohms.
Requirement R3
To achieve the stated purpose of this standard, which is to ensure that relays are expected to not
trip in response to stable power swings during non-Fault conditions, this Requirement ensures
that the applicable entity develops a Corrective Action Plan (CAP) that reduces the risk of relays
tripping in response to a stable power swing during non-Fault conditions that may occur on any
applicable BES Element.
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Requirement R4
To achieve the stated purpose of this standard, which is to ensure that load-responsive protective
relays are expected to not trip in response to stable power swings during non-Fault conditions, the
applicable entity is required to implement any CAP developed pursuant to Requirement R3 such
that the Protection System will meet PRC-026-1 – Attachment B criteria or can be excluded under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay
functions are supervised by power swing blocking or using relay systems that are immune to power
swings), while maintaining dependable fault detection and dependable out-of-step tripping (if outof-step tripping is applied at the terminal of the BES Element). Protection System owners are
required in the implementation of a CAP to update it when actions or timetable change, until all
actions are complete. Accomplishing this objective is intended to reduce the occurrence of
Protection System tripping during a stable power swing, thereby improving reliability and
minimizing risk to the BES.
The following are examples of actions taken to complete CAPs for a relay that did not meet PRC026-1 – Attachment B and could be at-risk of tripping in response to a stable power swing during
non-Fault conditions. A Protection System change was determined to be acceptable (without
diminishing the ability of the relay to protect for faults within its zone of protection).
Example R4a: Actions: Settings were issued on 6/02/2015 to reduce the Zone 2 reach of
the impedance relay used in the directional comparison unblocking (DCUB) scheme from
30 ohms to 25 ohms so that the relay characteristic is completely contained within the lens
characteristic identified by the criterion. The settings were applied to the relay on
6/25/2015. CAP was completed on 06/25/2015.
Example R4b: Actions: Settings were issued on 6/02/2015 to enable out-of-step blocking
on the existing microprocessor-based relay to prevent tripping in response to stable power
swings. The setting changes were applied to the relay on 6/25/2015. CAP was completed
on 06/25/2015.
The following is an example of actions taken to complete a CAP for a relay responding to a stable
power swing that required the addition of an electromechanical power swing blocking relay.
Example R4c: Actions: A project for the addition of an electromechanical power swing
blocking relay to supervise the Zone 2 impedance relay was initiated on 6/5/2015 to prevent
tripping in response to stable power swings. The relay installation was completed on
9/25/2015. CAP was completed on 9/25/2015.
The following is an example of actions taken to complete a CAP with a timetable that required
updating for the replacement of the relay.
Example R4d: Actions: A project for the replacement of the impedance relays at both
terminals of line X with line current differential relays was initiated on 6/5/2015 to prevent
tripping in response to stable power swings. The completion of the project was postponed
due to line outage rescheduling from 11/15/2015 to 3/15/2016. Following the timetable
change, the impedance relay replacement was completed on 3/18/2016. CAP was
completed on 3/18/2016.
The CAP is complete when all the documented actions to remedy the specific problem (i.e.,
unnecessary tripping during stable power swings) are completed.
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Justification for Including Unstable Power Swings in the Requirements
Protection Systems that are applicable to the Standard and must be secure for a stable power swing
condition (i.e., meets PRC-026-1 – Attachment B criteria) are identified based on Elements that
are susceptible to both stable and unstable power swings. This section provides an example of why
Elements that trip in response to unstable power swings (in addition to stable power swings) are
identified and that their load-responsive protective relays need to be evaluated under PRC-026-1
– Attachment B criteria.
Figure 23: A simple electrical system where two lines tie a small utility to a much larger
interconnection.
In Figure 23 the relays at circuit breakers 1, 2, 3, and 4 are equipped with a typical overreaching
Zone 2 pilot system, using a Directional Comparison Blocking (DCB) scheme. Internal faults (or
power swings) will result in instantaneous tripping of the Zone 2 relays if the measured fault or
power swing impedance falls within the zone 2 operating characteristic. These lines will trip on
pilot Zone 2 for out-of-step conditions if the power swing impedance characteristic enters into
Zone 2. All breakers are rated for out-of-phase switching.
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Figure 24: In this case, the Zone 2 element on circuit breakers 1, 2, 3, and 4 did not meet the
PRC-026-1 – Attachment B criteria (this figure depicts the power swing as seen by relays on
breakers 3 and 4).
In Figure 24, a large disturbance occurs within the small utility and its system goes out-of-step
with the large interconnect. The small utility is importing power at the time of the disturbance. The
actual power swing, as shown by the solid green line, enters the Zone 2 relay characteristic on the
terminals of Lines 1, 2, 3, and 4 causing both lines to trip as shown in Figure 25.
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1
Line 1
3
Large
Small
Utility
2
Line 2
4
Interconnect
Figure 25: Islanding of the small utility due to Lines 1 and 2 tripping in response to an unstable
power swing.
In Figure 25, the relays at circuit breakers 1, 2, 3, and 4 have correctly tripped due to the unstable
power swing (shown by the dashed green line in Figure 24), de-energizing Lines 1 and 2, and
creating an island between the small utility and the big interconnect. The small utility shed 500
MW of load on underfrequency and maintained a load to generation balance.
Figure 26: Line 1 is out-of-service for maintenance, Line 2 is loaded beyond its normal rating
(but within its emergency rating).
Subsequent to the correct tripping of Lines 1 and 2 for the unstable power swing in Figure 25,
another system disturbance occurs while the system is operating with Line 1 out-of-service for
maintenance. The disturbance causes a stable power swing on Line 2, which challenges the relays
at circuit breakers 2 and 4 as shown in Figure 27.
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Figure 27: Relays on circuit breakers 2 and 4 were not addressed to meet the PRC-026-1 –
Attachment B criteria following the previous unstable power swing event.
If the relays on circuit breakers 2 and 4 were not addressed under the Requirements for the previous
unstable power swing condition, the relays would trip in response to the stable power swing, which
would result in unnecessary system separation, load shedding, and possibly cascading or blackout.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4: December 5, 2014)
Page 101 of 102
PRC-026-1 – Application Guidelines
1
Line 1
3
Large
Small
Utility
2
Line 2
4
Interconnect
Figure 28: Possible blackout of the small utility.
If the relays that tripped in response to the previous unstable power swing condition in Figure 24
were addressed under the Requirements to meet PRC-026-1 - Attachment B criteria, the
unnecessary tripping of the relays for the stable power swing shown in Figure 28 would have been
averted, and the possible blackout of the small utility would have been avoided.
Project 2010-13.3 – Phase 3 Relay Loadability (Draft 3: November 4: December 5, 2014)
Page 102 of 102
Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power
Swings
Requested Approvals
PRC-026-1 – Relay Performance During Stable Power Swings
Requested Retirements
None.
Prerequisite Approvals
None.
General Considerations
There are a number of factors that influenced the determination of an implementation period for the
new proposed standard. The following factors may be specific to one or more of the applicable entities
listed below.
1. The effort and resources for all applicable entities to develop or modify internal processes
and/or procedures.
2. The effort and resources for the Planning Coordinator to begin identifying Element(s) according
to the criteria in Requirement R1 is based on existing information (e.g., the most recent
Planning Assessment).
3. The notification of Elements in Requirement R1 is based on the Planning Coordinator’s existing
studies (i.e., annual Planning Assessments) and there will be minimal additional effort to
identify Elements according to the criteria.
4. The need for the Generator Owner or Transmission Owner to plan for and secure resources
(e.g., availability of consultants, if needed) to address the initial influx of Element notifications
from the Planning Coordinator during the implementation period of Requirement R2.
Applicable Entities
Generator Owner
Planning Coordinator
Transmission Owner
Effective Dates
R equirem ent R 1
First day of the first full calendar year that is 12 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 12 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
R equirem ents R 2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 36 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Notifications Prior to the Effective Date of Requirement R2
The implementation plan is designed such that the Planning Coordinator will begin notifying the
respective Generator Owners and Transmission Owners of any Elements in Requirement R1 based on
the effective date language. The 36 months for the Generator Owner and Transmission Owner in
Requirement R2 (and Requirements R3 and R4) to become compliant is intended to allow the entity an
opportunity to address the initial influx of identified Elements in Requirement R1. There is no
obligation on the Generator Owner or Transmission Owner to perform Requirement R2, R3, or R4 until
the effective date of these Requirements. Although there is no compliance obligation during the 36
month implementation period, an entity will have the full obligation of Requirements R2, R3, and R4
following the 36 month period. The 36 month implementation period also allows an opportunity for
the entity to establish the evaluation of load-responsive protective relays pursuant to Requirement R2
which will provide the point in time that the five year re-evaluation of such relays will occur. “No
change made.
Justification
The implementation plan is based on the general considerations above and provides sufficient time for
the Generator Owner, Planning Coordinator, and Transmission Owner to begin becoming compliant
with the standard. The Effective date is constructed such that once the standard is adopted or
approved it would become effective on the first day of the first whole calendar year that is 12 months
for Requirement R1 and 36 months for Requirements R2, R3, and R4 after applicable adoption or
approval.
Implementation Plan (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings| December 5, 2014
2
Requirement R1 – The Planning Coordinator will have at least one full calendar year to prepare
itself to identify any generator, transformer, and transmission line BES Elements that meet the
criteria and notify the respective Generator Owner and Transmission Owner of identified
Elements, if any, within the allotted timeframe.
Requirement R2 – The Generator Owner and Transmission Owner will have 36 calendar months
to determine if its load-responsive protective relays for an identified Element pursuant to
Requirement R1 meet the PRC-026-1 – Attachment B criteria for the initial influx of Elements.
Also, both entities are provided an implementation that will allow the entity to conduct initial
evaluations of its load-responsive protective relays for an identified Element during the first 36
calendar months of approval.
Requirement R3 – The implementation period for the development of a Corrective Action Plan
(CAP) is set to be consistent with Requirement R2 to begin during the fourth calendar year of
adoptions or approvals to address any load-responsive protective relays determined in
Requirement R2 not to meet the PRC-026-1 – Attachment B criteria.
Requirement R4 – The implementation period for this Requirement is set to be consistent with
Requirement R3, the development of a CAP.
Implementation Plan (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings| December 5, 2014
3
Implementation Plan
Project 2010-13.3 – Relay Loadability: Stable Power
Swings
Requested Approvals
PRC-026-1 – Relay Performance During Stable Power Swings
Requested Retirements
None.
Prerequisite Approvals
None.
General Considerations
There are a number of factors that influenceinfluenced the determination of an implementation period
for the new proposed standard. The following factors may be specific to one or more of the applicable
entities listed below.
1. The effort and resources for all applicable entities to develop or modify internal processes
and/or procedures.
2. The effort and resources for the Planning Coordinator to begin identifying Element(s) according
to the criteria in Requirement R1 is based on existing information (e.g., the most recent
Planning Assessment).
3. The notification of Elements in Requirement R1 is based on the Planning Coordinator’s existing
studies (i.e., annual Planning Assessments) and there will be minimal additional effort to
identify Elements according to the criteria.
4. The need for the Generator Owner or Transmission Owner to plan for and secure resources
(e.g., availability of consultants, if needed) to address the initial influx of ElementsElement
notifications from the Planning Coordinator during the implementation period of Requirement
R2.
Applicable Entities
Generator Owner
Planning Coordinator
Transmission Owner
Effective Dates
R equirem ent R 1
First day of the first full calendar year that is 12 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 12 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
R equirem ents R 2, R3, and R4
First day of the first full calendar year that is 36 months after the date that the standard is approved by
an applicable governmental authority or as otherwise provided for in a jurisdiction where approval by
an applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first full calendar year that is 36 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
Notifications Prior to the Effective Date of Requirement R2
During the implementation of the standard, notifications are likely to occur prior to Requirement R2
becoming effective. Where notification of Elements under Requirement R1 or becoming aware of an
Element tripping due to a stable or unstable power swing prior to the Effective Date of Requirement
R2, the 12 month time period to evaluate if an Element’s load-responsive protective relays meet the
criteria in PRC-026-1 – Attachment B in Requirement R2 will begin, as expected, from the Effective
Date of Requirement R2. Thereafter, entities will follow the 12 month time period in accordance with
Requirement R2. The intention of the additional time for R2 to become effective is to handle the initial
influx of notifications and identifications.
The implementation plan is designed such that the Planning Coordinator will begin notifying the
respective Generator Owners and Transmission Owners of any Elements in Requirement R1 based on
the effective date language. The 36 months for the Generator Owner and Transmission Owner in
Requirement R2 (and Requirements R3 and R4) to become compliant is intended to allow the entity an
opportunity to address the initial influx of identified Elements in Requirement R1. There is no
obligation on the Generator Owner or Transmission Owner to perform Requirement R2, R3, or R4 until
the effective date of these Requirements. Although there is no compliance obligation during the 36
month implementation period, an entity will have the full obligation of Requirements R2, R3, and R4
following the 36 month period. The 36 month implementation period also allows an opportunity for
the entity to establish the evaluation of load-responsive protective relays pursuant to Requirement R2
which will provide the point in time that the five year re-evaluation of such relays will occur.
Implementation Plan (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings| November 4December 5, 2014
2
Justification
The implementation plan is based on the general considerations above and provides sufficient time for
the Generator Owner, Planning Coordinator, and Transmission Owner to begin becoming compliant
with the standard. The Effective date is constructed such that once the standard is adopted or
approved it would become effective on the first day of the first whole calendar year that is 12 months
for Requirement R1 and 36 months for Requirements R2, R3, and R4 after applicable adoption or
approval.
Requirement R1 – The Planning Coordinator will have at least one full calendar year to prepare
itself to identify any generator, transformer, and transmission line BES Elements that meet the
criteria and notify the respective Generator Owner and Transmission Owner of identified
Elements, if any, within the allotted timeframe.
Requirement R2 – The Generator Owner and Transmission Owner will have 36 calendar months
to determine if its load-responsive protective relays for an identified Element pursuant to
Requirement R1 meet the PRC-026-1 – Attachment B criteria for the initial influx of Elements.
Also, both entities are provided an implementation that will allow the entity to conduct initial
evaluations of its load-responsive protective relays for an identified Element during the first 36
calendar months of approval.
Requirement R3 – The implementation period for the development of a Corrective Action Plan
(CAP) is set to be consistent with Requirement R2 to begin during the fourth calendar year of
adoptions or approvals to address any load-responsive protective relays determined in
Requirement R2 not to meet the PRC-026-1 – Attachment B criteria.
Requirement R4 – The implementation period for this Requirement is set to be consistent with
Requirement R3, the development of a CAP.
Implementation Plan (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings| November 4December 5, 2014
3
Violation Risk Factors and
Violation Severity Level Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
(PRC-026-1 – Relay Performance During Stable Power Swings)
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: PRC-026-1 – Relay
Performance During Stable Power Swings.
Each primary requirement is assigned a VRF and a set of one or more VSLs. 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 ERO
Sanction Guidelines.
The Protection System Response to Power Swings Standard Drafting Team applied the following
NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under
this project.
NERC Criteria - Violation Risk Factors
High Risk Requirem ent
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
M edium R isk Requirem ent
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric 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 electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
Low er R isk Requirem ent
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 electric system, or the
ability to effectively monitor and control the bulk electric 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 electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
The standard drafting team (SDT) also considered consistency with the FERC Violation Risk Factor
Guidelines for setting VRFs: 1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors 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: 2
•
•
•
•
•
•
•
•
•
•
•
•
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
Guideline (2) — Consistency within a Reliability Standard
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
2 Id. at footnote 15.
1
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
2
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk
Factor 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.
NERC Criteria - Violation Severity Levels
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.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets
the full intent of the
requirement.
Moderate
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
High
Severe
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
3
FER C Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the
following four guidelines for determining whether to approve VSLs:
Guideline 1: Violation Severity Level Assignm ents Should Not Have the Unintended
Consequence of Low ering the Current Level of Com pliance
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 Assignm ents Should Ensure Uniform ity and
Consistency in the Determ ination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe
noncompliant performance.
Guideline 3: Violation Severity Level Assignm ent Should Be Consistent w ith the
Corresponding Requirem ent
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignm ent Should Be Based on A Single
Violation, Not on A Cum ulative Num ber 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 and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
4
VRF and VSL Justifications – PRC-026-1, R1
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to notify the respective Generator Owner or Transmission Owner of the BES Element(s) that
meet the Requirement R1 criteria prohibits further evaluation of any load-responsive protective relay
applied at the terminal of the Element(s). A load-responsive protective relay that goes without evaluation
may not be secure for a stable power swing and could, in the planning time frame, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two Bulk Power System (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Identification and
evaluation of BES Elements susceptible to power swings and the subsequent mitigation of load-responsive
protective relays applied at the terminals of these BES Elements that do not meet the PRC-026-1 –
Attachment B criteria will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on the issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
5
VRF and VSL Justifications – PRC-026-1, R1
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard FAC-014-2, R6 (“…Planning Authority shall
identify the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure of the Planning Coordinator to notify the respective Generator Owner or Transmission Owner of
the BES Element(s) that meet the Requirement R1 criteria prohibits further evaluation of any loadresponsive protective relay applied at the terminal of the Element. A load-responsive protective relay that
goes without evaluation may not be secure for a stable power swing and could, in the planning time
frame, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
6
VRF and VSL Justifications – PRC-026-1, R1
Proposed VSL
Lower
Moderate
High
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was less
than or equal to 30 calendar
days late.
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The Planning Coordinator provided
notification of the BES Element(s)
in accordance with Requirement
R1, but was more than 60 calendar
days and less than or equal to 90
calendar days late.
Severe
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 90 calendar days late.
OR
The Planning Coordinator failed to
provide notification of the BES
Element(s) in accordance with
Requirement R1.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is Element-driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
7
VRF and VSL Justifications – PRC-026-1, R1
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is binary and utilizes a VSL of Severe for failure in addition to incremental VSLs for
tardiness.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
8
VRF and VSL Justifications – PRC-026-1, R2
Proposed VRF
High
NERC VRF Discussion
A Violation Risk Factor of High is consistent with the NERC VRF Guidelines:
A failure to evaluate the Protection System to determine that it is expected to not trip for a stable power
swing for a BES Element could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
A Protection System that does not meet the PRC-026-1 – Attachment B criteria is less secure during stable
power swings, which increases the risk of tripping should the Protection System be challenged by a power
swing.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Evaluation of loadresponsive protective relays applied at the terminals of identified BES Elements will allow the Generator
Owner and Transmission Owner to determine whether the load-responsive protective relays meet the
PRC-026-1 – Attachment B criteria.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
9
VRF and VSL Justifications – PRC-026-1, R2
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard PRC-023-3, R1 “…Each Transmission Owner,
Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per unit voltage and a
power factor angle of 30 degrees”) which has a VRF of High.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure of the Generator Owner or Transmission Owner to evaluate that the Protection System is
expected to not trip in response to a stable power swing during a non-Fault condition for a BES Element
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to bulk electric system instability, separation, or a cascading sequence of failures, or
could place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures,
or could hinder restoration to a normal condition.
A Protection System that does not meet the PRC-026-1 – Attachment B criteria is less secure during stable
power swings, it increases the risk of tripping should the Protection System be challenged by a power
swing.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
10
VRF and VSL Justifications – PRC-026-1, R2
Proposed VSL
Lower
Moderate
High
The Generator Owner or
Transmission Owner evaluated
its load-responsive protective
relay(s) in accordance with
Requirement R2, but was less
than or equal to 30 calendar
days late.
The Generator Owner or
Transmission Owner evaluated
its load-responsive protective
relay(s) in accordance with
Requirement R2, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The Generator Owner or
Transmission Owner evaluated its
load-responsive protective relay(s)
in accordance with Requirement
R2, but was more than 60 calendar
days and less than or equal to 90
calendar days late.
Severe
The Generator Owner or
Transmission Owner evaluated its
load-responsive protective relay(s)
in accordance with Requirement
R2, but was more than 90 calendar
days late.
OR
The Generator Owner or
Transmission Owner failed to
evaluate its load-responsive
protective relay(s) in accordance
with Requirement R2.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is driven by exception. For example, each
identified Element must be evaluated.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
11
VRF and VSL Justifications – PRC-026-1, R2
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
12
VRF and VSL Justifications – PRC-004-3, R3
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
Failure to develop a Corrective Action Plan (CAP) such that the Protection System of a BES Element will
meet the PRC-026-1 – Attachment B criteria or to exclude the Protection System under the PRC-026-1 –
Attachment A criteria (e.g., modifying the Protection System so that relay functions are supervised by
power swing blocking or using relay systems that are immune to power swings) could in the planning time
frame, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Developing a CAP such
that the Protection System will meet the Attachment B criteria or to exclude the Protection System under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) applied at
the terminals of BES Elements will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
13
VRF and VSL Justifications – PRC-004-3, R3
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
This Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which require corrective actions
(e.g., Corrective Action Plans); PRC-016-0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC-003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all three of which have a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to develop the Corrective Action Plan (CAP) such that the Protection System of a BES Element will
meet the Attachment B criteria or to exclude the Protection System under the PRC-026-1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings) could, in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
14
VRF and VSL Justifications – PRC-004-3, R3
Proposed VSL
Lower
Moderate
High
Severe
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R3, but in more
than six calendar months and
less than or equal to seven
calendar months.
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R3, but in more
than seven calendar months
and less than or equal to eight
calendar months.
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement R3,
but in more than eight calendar
months and less than or equal to
nine calendar months.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to develop the
Corrective Action Plan in a timely fashion and a binary aspect for a complete failure. The VSL is entity sizeneutral because performance is driven by the need to mitigate the Protection System so that it is expected
to not trip on a stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement R3,
but in more than nine calendar
months.
OR
The Generator Owner or
Transmission Owner failed to
develop a CAP in accordance with
Requirement R3.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
15
VRF and VSL Justifications – PRC-004-3, R3
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is binary and utilizes a VSL of Severe for failure in addition to incremental VSLs for
tardiness.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
This proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
This proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with this Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
16
VRF and VSL Justifications – PRC-026-1, R4
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan (CAP) to meet the PRC-026-1 – Attachment B criteria or
to exclude the Protection System under the PRC-026-1 – Attachment A criteria (e.g., modifying the
Protection System so that relay functions are supervised by power swing blocking or using relay systems
that are immune to power swings) could, in the planning time frame, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk
electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Implementing a CAP such
that the Protection System will meet the Attachment B criteria or to exclude the Protection System under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) applied at
the terminals of these Elements will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
17
VRF and VSL Justifications – PRC-026-1, R4
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which require corrective actions
(e.g., Corrective Action Plans): PRC-016-0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC-003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all of which have a VRF of Medium.
FERC VRF G4 Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan such that the Protection System of a BES Element will
meet the Attachment B criteria or to exclude the Protection System under the PRC-026-1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings) could, in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
18
VRF and VSL Justifications – PRC-026-1, R4
Proposed VSL
Lower
Moderate
The responsible entity
implemented, but failed to
update a CAP, when actions or
timetables changed, in
accordance with Requirement
R4.
N/A
High
N/A
Severe
The responsible entity failed to
implement a CAP in accordance
with Requirement R4.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to update the
Corrective Action Plan and a binary aspect for failure to implement. The VSL is entity size-neutral because
performance is driven by the need to mitigate the Protection System so that it is expected to not trip on a
stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
19
VRF and VSL Justifications – PRC-026-1, R4
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
20
Violation Risk Factors and
Violation Severity Level Justifications
Project 2010-13.3 – Relay Loadability: Stable Power Swings
(PRC-026-1 – Relay Performance During Stable Power Swings)
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: PRC-026-1 – Relay
Performance During Stable Power Swings.
Each primary requirement is assigned a VRF and a set of one or more VSLs. 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 ERO
Sanction Guidelines.
The Protection System Response to Power Swings Standard Drafting Team applied the following
NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under
this project.
NERC Criteria - Violation Risk Factors
High Risk Requirem ent
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
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 electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
M edium R isk Requirem ent
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric 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 electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
Low er R isk Requirem ent
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 electric system, or the
ability to effectively monitor and control the bulk electric 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 electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
The standard drafting team (SDT) also considered consistency with the FERC Violation Risk Factor
Guidelines for setting VRFs: 1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors 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: 2
•
•
•
•
•
•
•
•
•
•
•
•
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
Guideline (2) — Consistency within a Reliability Standard
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
2 Id. at footnote 15.
1
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
2
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk
Factor 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.
NERC Criteria - Violation Severity Levels
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.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets
the full intent of the
requirement.
Moderate
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
High
Severe
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
3
FER C Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the
following four guidelines for determining whether to approve VSLs:
Guideline 1: Violation Severity Level Assignm ents Should Not Have the Unintended
Consequence of Low ering the Current Level of Com pliance
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 Assignm ents Should Ensure Uniform ity and
Consistency in the Determ ination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe
noncompliant performance.
Guideline 3: Violation Severity Level Assignm ent Should Be Consistent w ith the
Corresponding Requirem ent
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignm ent Should Be Based on A Single
Violation, Not on A Cum ulative Num ber 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 and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
4
VRF and VSL Justifications – PRC-026-1, R1
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to notify the respective Generator Owner or Transmission Owner of the BES Element(s) that
meet the Requirement R1 criteria prohibits further evaluation of any load-responsive protective relay
applied at the terminal of the Element(s). A load-responsive protective relay that goes without evaluation
may not be secure for a stable power swing and could, in the planning time frame, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system.
Identifying an Element for notification that is expected to encounter stable power swings based on
Requirement R1 criteria is the first step in ensuring the reliable operation of the Bulk Electric System (BES)
and in preventing the future severity of disturbances from affecting a wider area.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two Bulk Power System (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Identification and
evaluation of BES Elements susceptible to power swings and the subsequent mitigation of load-responsive
protective relays applied at the terminals of these BES Elements that do not meet the PRC-026-1 –
Attachment B criteria will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on the issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
5
VRF and VSL Justifications – PRC-026-1, R1
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard FAC-014-2, R6 (“…Planning Authority shall
identify the subset of multiple contingencies…”) which has a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure of the Planning Coordinator to notify the respective Generator Owner or Transmission Owner of
the BES Element(s) that meet the Requirement R1 criteria prohibits further evaluation of any loadresponsive protective relay applied at the terminal of the Element. A load-responsive protective relay that
goes without evaluation may not be secure for a stable power swing and could, in the planning time
frame, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
Identifying an Element for notification that is expected to encounter stable power swings based on the
Requirement R1 criteria is the first step in ensuring the reliable operation of the BES and in preventing the
future severity of disturbances from affecting a wider area.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
6
VRF and VSL Justifications – PRC-026-1, R1
Proposed VSL
Lower
Moderate
High
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was less
than or equal to 30 calendar
days late.
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The Planning Coordinator provided
notification of the BES Element(s)
in accordance with Requirement
R1, but was more than 60 calendar
days and less than or equal to 90
calendar days late.
Severe
The Planning Coordinator
provided notification of the BES
Element(s) in accordance with
Requirement R1, but was more
than 90 calendar days late.
OR
The Planning Coordinator failed to
provide notification of the BES
Element(s) in accordance with
Requirement R1.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is Element-driven and not by the total
assets which an entity may have awareness over.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
7
VRF and VSL Justifications – PRC-026-1, R1
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply and utilizes a VSL of Severe for
failure in addition to incremental VSLs for tardiness.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
8
VRF and VSL Justifications – PRC-026-1, R2
Proposed VRF
High
NERC VRF Discussion
A Violation Risk Factor of High is consistent with the NERC VRF Guidelines:
A failure to evaluate the Protection System to determine that it is expected to not trip for a stable power
swing for a BES Element could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
A Protection System that does not meet the PRC-026-1 – Attachment B criteria is less secure during stable
power swings, which increases the risk of tripping should the Protection System be challenged by a power
swing.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Evaluation of loadresponsive protective relays applied at the terminals of identified BES Elements will allow the Generator
Owner and Transmission Owner to determine whether the load-responsive protective relays meet the
PRC-026-1 – Attachment B criteria.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
9
VRF and VSL Justifications – PRC-026-1, R2
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The Requirement is consistent with NERC Reliability Standard PRC-023-3, R1 “…Each Transmission Owner,
Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per unit voltage and a
power factor angle of 30 degrees”) which has a VRF of High.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A failure of the Generator Owner or Transmission Owner to evaluate that the Protection System is
expected to not trip in response to a stable power swing during a non-Fault condition for a BES Element
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to bulk electric system instability, separation, or a cascading sequence of failures, or
could place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures,
or could hinder restoration to a normal condition.
A Protection System that does not meet the PRC-026-1 – Attachment B criteria is less secure during stable
power swings, it increases the risk of tripping should the Protection System be challenged by a power
swing.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
10
VRF and VSL Justifications – PRC-026-1, R2
Proposed VSL
Lower
Moderate
High
The Generator Owner or
Transmission Owner evaluated
its load-responsive protective
relay(s) in accordance with
Requirement R2, but was less
than or equal to 30 calendar
days late.
The Generator Owner or
Transmission Owner evaluated
its load-responsive protective
relay(s) in accordance with
Requirement R2, but was more
than 30 calendar days and less
than or equal to 60 calendar
days late.
The Generator Owner or
Transmission Owner evaluated its
load-responsive protective relay(s)
in accordance with Requirement
R2, but was more than 60 calendar
days and less than or equal to 90
calendar days late.
Severe
The Generator Owner or
Transmission Owner evaluated its
load-responsive protective relay(s)
in accordance with Requirement
R2, but was more than 90 calendar
days late.
OR
The Generator Owner or
Transmission Owner failed to
evaluate its load-responsive
protective relay(s) in accordance
with Requirement R2.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for tardiness and a binary aspect
for failure. The VSL is entity size-neutral because performance is driven by exception. For example, each
identified Element must be evaluated.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
11
VRF and VSL Justifications – PRC-026-1, R2
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
12
VRF and VSL Justifications – PRC-004-3, R3
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
Failure to develop a Corrective Action Plan (CAP) such that the Protection System of a BES Element will
meet the PRC-026-1 – Attachment B criteria or to exclude the Protection System under the PRC-026-1 –
Attachment A criteria (e.g., modifying the Protection System so that relay functions are supervised by
power swing blocking or using relay systems that are immune to power swings) could in the planning time
frame, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
An unmitigated Protection System could affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
could negatively impact system reliability under different operating conditions. Developing a CAP such
that the Protection System will meet the Attachment B criteria or to exclude the Protection System under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) applied at
the terminals of BES Elements will reduce the likelihood of reoccurrence.
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
13
VRF and VSL Justifications – PRC-004-3, R3
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
This Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which requiringrequire corrective
actions (e.g., Corrective Action Plans); PRC-016-0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC-003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all three of which have a VRF of Medium.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to develop the Corrective Action Plan (CAP) such that the Protection System of a BES Element will
meet the Attachment B criteria or to exclude the Protection System under the PRC-026-1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings) could, in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
14
VRF and VSL Justifications – PRC-004-3, R3
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
Moderate
High
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R3, but in more
than six calendar months and
less than or equal to seven
calendar months.
The Generator Owner or
Transmission Owner developed
a Corrective Action Plan (CAP)
in accordance with
Requirement R3, but in more
than seven calendar months
and less than or equal to eight
calendar months.
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement R3,
but in more than eight calendar
months and less than or equal to
nine calendar months.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to develop the
Corrective Action Plan in a timely fashion and a binary aspect for a complete failure. The VSL is entity sizeneutral because performance is driven by the need to mitigate the Protection System so that it is expected
to not trip on a stable power swing.
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
Severe
The Generator Owner or
Transmission Owner developed a
Corrective Action Plan (CAP) in
accordance with Requirement R3,
but in more than nine calendar
months.
OR
The Generator Owner or
Transmission Owner failed to
develop a CAP in accordance with
Requirement R3.
15
VRF and VSL Justifications – PRC-004-3, R3
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply and utilizes a VSL of Severe for
failure in addition to incremental VSLs for tardiness.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
This proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
This proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with this Requirement.
The VSL is based on a single violation and not cumulative violations.
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
16
VRF and VSL Justifications – PRC-004-3, R3
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications – PRC-026-1, R4
Proposed VRF
Medium
NERC VRF Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan (CAP) to meet the PRC-026-1 – Attachment B criteria or
to exclude the Protection System under the PRC-026-1 – Attachment A criteria (e.g., modifying the
Protection System so that relay functions are supervised by power swing blocking or using relay systems
that are immune to power swings) could, in the planning time frame, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk
electric system.
An unmitigated Protection System could affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
The blackout report and subsequent technical analysis identified that two bulk power system (BPS)
transmission lines tripped due to protective relay operation in response to stable power swings. The
Protection System operations on these lines did not contribute significantly to the overall outcome of the
August 14, 2003 system disturbance; however, Protection System operation during stable powers swings
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
17
VRF and VSL Justifications – PRC-026-1, R4
could negatively impact system reliability under different operating conditions. Implementing a CAP such
that the Protection System will meet the Attachment B criteria or to exclude the Protection System under
the PRC-026-1 – Attachment A criteria (e.g., modifying the Protection System so that relay functions are
supervised by power swing blocking or using relay systems that are immune to power swings) applied at
the terminals of these Elements will reduce the likelihood of reoccurrence.
This Requirement is consistent with the intent of Recommendation 8: Improve System Protection to Slow
or Limit the Spread of Future Cascading Outages. While the actions associated with this recommendation
did not focus specifically on this issue of Protection Systems tripping in response to stable power swings,
the recommendation does note that “power system protection devices should be set to address the
specific condition of concern, such as a fault, out-of-step condition, etc., and should not compromise a
power system’s inherent physical capability to slow down or stop a cascading event.”
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The Requirement has a single reliability activity associated with the reliability objective and no subRequirement(s) which allows a single VRF to be assigned; therefore no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
This Requirement is consistent with the following Reliability Standards which requiringrequire corrective
actions (e.g., Corrective Action Plans): PRC-016-0.1, R2 (“…shall take corrective actions to avoid future
Misoperations”), PRC-022-1, R1.5 (“For any Misoperation, a Corrective Action Plan…”), and FAC-003, R5
(“…Transmission Owner or applicable Generator Owner shall take corrective action to ensure continued
vegetation management”) all of which have a VRF of Medium.
FERC VRF G4 Discussion
A Violation Risk Factor of Medium is consistent with the NERC VRF Guidelines:
A failure to implement the Corrective Action Plan such that the Protection System of a BES Element will
meet the Attachment B criteria or to exclude the Protection System under the PRC-026-1 – Attachment A
criteria (e.g., modifying the Protection System so that relay functions are supervised by power swing
blocking or using relay systems that are immune to power swings) could, in the planning time frame,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
18
VRF and VSL Justifications – PRC-026-1, R4
adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system.
An unmitigated Protection System could contribute to the severity of future disturbances affecting a wider
area, or potential equipment damage.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This Requirement does not co-mingle reliability objectives of differing risk; therefore, the assigned VRF of
Medium is consistent.
Proposed VSL
Lower
The responsible entity
implemented, but failed to
update a CAP, when actions or
timetables changed, in
accordance with Requirement
R4.
Moderate
N/A
High
N/A
Severe
The responsible entity failed to
implement a CAP in accordance
with Requirement R4.
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the VSL for failing to update the
Corrective Action Plan and a binary aspect for failure to implement. The VSL is entity size-neutral because
performance is driven by the need to mitigate the Protection System so that it is expected to not trip on a
stable power swing.
FERC VSL G1
The proposed VSL does not lower the current level of compliance because the Requirement is new.
Violation Severity Level
Assignments Should Not Have
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
19
VRF and VSL Justifications – PRC-026-1, R4
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
This Requirement is not binary; therefore, this criterion does not apply.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSL uses similar terminology to that used in the corresponding Requirement, and is
therefore consistent with the Requirement.
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
20
VRF and VSL Justifications – PRC-026-1, R4
Cumulative Number of
Violations
VRF and VSL Justifications (Draft 34: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | November 4December 5, 2014
21
Table of Issues and Directives
Project 2010-13.3 – Relay Loadability: Stable Power Swings
Table of Issues and Directives Associated with PRC-026-1
Source
FERC
Order
733
1
Issue or Directive Language
(including Para. #)
Section and/or
Requirement(s)
150. We will not direct the ERO to modify All requirements
PRC-023-1 to address stable power
swings. However, because both NERC and
the Task Force have identified
undesirable relay operation due to stable
power swings as a reliability issue, we
direct the ERO to develop a Reliability
Standard that requires the use of
protective relay systems that can
differentiate between faults and stable
power swings and, when necessary,
phases out protective relay systems that
cannot meet this requirement.
Consideration of Issue or Directive
The PRC-026-1 standard is responsive to this directive by using
an equally effective and efficient focused approach for the
Planning Coordinator to provide notification of BES Elements
according to the Requirement R1 criteria to the respective
Generator Owner and Transmission Owner. The criteria used
to identify a BES Element are based on the NERC System
Protection and Control Subcommittee technical document,
Protection System Response to Power Swings (“PSRPS
Report”).1 The specific criteria are based on where power
swings are expected to challenge load-responsive protective
relays.
The criteria include 1) Generator(s) where an angular stability
constraint exists that is addressed by a System Operating Limit
(SOL) or a Remedial Action Scheme (RAS) and those Elements
NERC System Protection and Control Subcommittee technical document, Protection System Response to Power Swings, August 2013: http://www.nerc.com/comm/PC/
System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Power%20Swing%20Report_Final_20131015.pdf
We also direct the ERO to file a report no
later than 120 days of this Final Rule
addressing the issue of protective relay
operation due to power swings. The
report should include an action plan and
timeline that explains how and when the
ERO intends to address this issue through
its Reliability Standards development
process.
AND
153. While we recognize that addressing
stable power swings is a complex issue,
we note that more than six years have
passed since the August 2003 blackout
and there is still no Reliability Standard
that addresses relays tripping due to
stable power swings. Additionally, NERC
has long identified undesirable relay
operation due to stable power swings as
a reliability issue. Consequently, pursuant
to section 215(d)(5) of the FPA, we find
that undesirable relay operation due to
stable power swings is a specific matter
that the ERO must address to carry out
the goals of section 215, and we direct
the ERO to develop a Reliability Standard
Table of Issues and Directives (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
terminating at the Transmission station associated with the
generator(s); 2) An Element that is monitored as part of an SOL
identified by the Planning Coordinator’s methodology based on
an angular stability constraint; 3)
An Element that forms
the boundary of an island in the most recent underfrequency
load shedding (UFLS) design assessment based on application
of the Planning Coordinator’s criteria for identifying islands,
only if the island is formed by tripping the Element based on
angular instability; 4) An Element identified in the most recent
annual Planning Assessment where relay tripping occurs due to
a stable or unstable power swing during a simulated
disturbance.
Requirement R2 requires the Generator Owner and
Transmission Owner to evaluate their load-responsive
protective relays that are applied at all of the terminals of each
BES Element identified by the Planning Coordinator in
Requirement R1 or upon becoming aware of a generator,
transformer, or transmission line BES Element that tripped in
response to a stable or unstable power swing due to the
operation of their protective relay(s). The initial evaluation
allows the Generator Owner and Transmission Owner to
determine whether their load-responsive protective relays
applied at all of the terminals of the BES Element meet the
PRC-026-1 – Attachment B criteria. Additionally, the
Requirement ensures that the Generator Owner and
Transmission Owner must re-evaluate the Protection System
2
addressing undesirable relay operation
due to stable power swings.
on a five year basis should the BES Element continue to be
identified by the Planning Coordinator in Requirement R1.
Requirement R3 mandates the development of a Corrective
Action Plan (CAP) such that the Protection System of a BES
Element will meet the PRC-026-1 –Attachment B criteria or the
Protection System can be excluded under the PRC-026-1 –
Attachment A criteria (e.g., modifying the Protection System so
that relay functions are supervised by power swing blocking or
using relay systems that are immune to power swings).
Requirement R4 mandates that the Generator Owner and
Transmission Owner implement each developed CAP in
Requirement R3 so that load-responsive protective relays are
expected to not trip in response to stable power swings during
non-Fault conditions.
162. The PSEG Companies also assert that Requirement R1,
the Commission’s approach to stable
Criterion 3
power swings should be inclusive and
include “islanding” strategies in
conjunction with out-of-step blocking or
tripping requirements. We agree with the
PSEG Companies and direct the ERO to
consider “islanding” strategies that
achieve the fundamental performance for
all islands in developing the new
Table of Issues and Directives (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
Islanding strategies were considered during the development
of the proposed standard. It was determined that islanding
strategies are not an appropriate method to meet the purpose
of the proposed standard. Islanding strategies are developed
to isolate the system from unstable power swings, which is not
prohibited under the proposed standard. The proposed
standard’s intent is to ensure that load-responsive protective
relays are expected to not trip in response to stable power
swings during non-Fault conditions, while maintaining
dependable fault detection and dependable out-of-step
3
Reliability Standard addressing stable
power swings.
Table of Issues and Directives (Draft 4: PRC-026-1)
Project 2010-13.3 – Relay Loadability: Stable Power Swings | December 5, 2014
tripping (if out-of-step tripping is applied at the terminal of the
BES Element).
4
Standards Announcement
Project 2010-13.3 Phase 3 of Relay Loadability: Stable
Power Swings
Final Ballot Now Open through December 16, 2014
Now Available
A final ballot for PRC-026-1 – Relay Performance During Stable Power Swings is open through 8 p.m.
Eastern, Monday, December 16, 2014.
Background information for this project can be found on the project page.
Instructions for Balloting
In the final ballot, votes are counted by exception. Only members of the ballot pool may cast a ballot; all
ballot pool members may change their previously cast votes. A ballot pool member who failed to cast a
vote during the last ballot window may cast a vote in the final ballot window. If a ballot pool member
cast a vote in the previous ballot and does not participate in the final ballot, that member’s vote will be
carried over in the final ballot.
Members of the ballot pool associated with this project may log in and submit their vote for the standard
by clicking here.
Next Steps
The voting results for the standard will be posted and announced after the ballot window closes. If
approved, it 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, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Scott Barfield-McGinnis, Standards Developer at
404-446-9689.
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 2010-13.3 Phase 3 of Relay Loadability:
Stable Power Swings
PRC-026-1
Final Ballot Results
Now Available
A final ballot for PRC-026-1 – Relay Performance During Stable Power Swings concluded 8 p.m. Eastern
on Tuesday, December 16, 2014.
The standard achieved a quorum and received sufficient affirmative votes for approval. Voting statistics
are listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Quorum /Approval
84.81% / 68.08%
Background information for this project can be found on the project page.
Next Steps
The standard will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Standards Developer, Scott Barfield,
or by telephone at 404-446-9689.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC Standards
Newsroom • Site Map • Contact NERC
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Log In
Ballot Results
Ballot Name:
-Ballot Pools
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-Registered Ballot Body
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Home Page
Project 2010-13.3 Relay Loadability Stable Power Swings PRC-0261_Final_Ballot_December_2014
Ballot Period: 12/5/2014 - 12/16/2014
Ballot Type: Final
Total # Votes: 307
Total Ballot Pool: 362
Quorum: 84.81 % The Quorum has been reached
Weighted Segment
68.08 %
Vote:
A quorum was reached and there were sufficient affirmative votes for
Ballot Results: approval.
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
#
#
No
without a
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
1
2Segment
2
3Segment
3
4Segment
4
5Segment
5
6Segment
6
7Segment
7
8Segment
8
9-
104
1
44
0.62
27
0.38
0
15
18
9
0.8
6
0.6
2
0.2
0
0
1
76
1
37
0.698
16
0.302
0
10
13
25
1
12
0.6
8
0.4
0
3
2
79
1
35
0.574
26
0.426
0
6
12
52
1
25
0.61
16
0.39
0
4
7
2
0.1
0
0
1
0.1
0
0
1
4
0.3
2
0.2
1
0.1
0
1
0
https://standards.nerc.net/BallotResults.aspx?BallotGUID=81b0f0d8-375c-4ae4-bb59-bb8859e9dc11[12/17/2014 10:33:01 AM]
NERC Standards
Segment
9
10 Segment
10
Totals
2
0.2
2
0.2
0
0
0
0
0
9
0.8
8
0.8
0
0
0
0
1
362
7.2
171
4.902
97
2.298
0
39
55
Individual Ballot Pool Results
Ballot
Segment
Organization
Member
1
1
1
1
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Eric Scott
Paul B Johnson
Andrew Z Pusztai
Robert Smith
1
Associated Electric Cooperative, Inc.
John Bussman
1
1
1
1
1
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
1
BC Hydro and Power Authority
Patricia Robertson
1
1
1
Black Hills Corp
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
Wes Wingen
Tony Kroskey
John C Fontenot
1
CenterPoint Energy Houston Electric, LLC
John Brockhan
Negative
1
Central Electric Power Cooperative
Michael B Bax
Negative
1
1
1
1
1
Central Iowa Power Cooperative
Kevin J Lyons
City of Tacoma, Department of Public Utilities,
Chang G Choi
Light Division, dba Tacoma Power
City of Tallahassee
Daniel S Langston
Clark Public Utilities
Jack Stamper
Colorado Springs Utilities
Shawna Speer
Consolidated Edison Co. of New York
Christopher L de Graffenried
1
CPS Energy
Glenn Pressler
1
1
1
Dairyland Power Coop.
Deseret Power
Dominion Virginia Power
Robert W. Roddy
James Tucker
Larry Nash
1
Duke Energy Carolina
Doug E Hils
1
1
1
1
1
1
1
1
1
1
1
1
Empire District Electric Co.
Encari
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JDRJC Associates
Ralph F Meyer
Steven E Hamburg
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Muhammed Ali
Martin Boisvert
Molly Devine
1
1
1
Affirmative
Affirmative
Affirmative
Negative
NERC
Notes
SUPPORTS
THIRD
PARTY
COMMENTS
Abstain
Abstain
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Abstain
Abstain
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Negative
Jim D Cyrulewski
Affirmative
COMMENT
https://standards.nerc.net/BallotResults.aspx?BallotGUID=81b0f0d8-375c-4ae4-bb59-bb8859e9dc11[12/17/2014 10:33:01 AM]
NERC Standards
1
JEA
Ted E Hobson
Negative
1
KAMO Electric Cooperative
Walter Kenyon
Negative
1
Kansas City Power & Light Co.
Daniel Gibson
Negative
1
Keys Energy Services
Stan T Rzad
Negative
1
1
1
1
1
1
1
1
Lakeland Electric
Lee County Electric Cooperative
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Larry E Watt
John Chin
faranak sarbaz
Martyn Turner
Jo-Anne M Ross
Danny Dees
Terry Harbour
Daniel L Inman
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
1
1
1
1
National Grid USA
NB Power Corporation
Nebraska Public Power District
New York Power Authority
Michael Jones
Alan MacNaughton
Jamison Cawley
Bruce Metruck
1
Northeast Missouri Electric Power Cooperative Kevin White
1
1
1
1
1
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
William Temple
Julaine Dyke
John Canavan
Scott R Cunningham
Terri Pyle
1
Omaha Public Power District
Doug Peterchuck
1
Oncor Electric Delivery
Jen Fiegel
1
Otter Tail Power Company
Daryl Hanson
1
1
1
1
1
1
1
Pacific Gas and Electric Company
Peak Reliability
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Bangalore Vijayraghavan
Jared Shakespeare
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
1
Public Service Electric and Gas Co.
Kenneth D. Brown
1
1
1
1
1
1
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
SaskPower
Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Wayne Guttormson
1
Seattle City Light
Pawel Krupa
1
1
1
1
1
1
1
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Southern California Edison Company
Southern Company Services, Inc.
Glenn Spurlock
Denise Stevens
Long T Duong
Tom Hanzlik
Shawn T Abrams
Steven Mavis
Robert A. Schaffeld
https://standards.nerc.net/BallotResults.aspx?BallotGUID=81b0f0d8-375c-4ae4-bb59-bb8859e9dc11[12/17/2014 10:33:01 AM]
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS
COMMENT
RECEIVED
NO
COMMENT
RECEIVED
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Abstain
Negative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Abstain
Affirmative
Negative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
NERC Standards
1
1
1
1
1
1
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Steven Powell
1
1
1
1
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State Generation & Transmission
Association, Inc.
Tucson Electric Power Co.
U.S. Bureau of Reclamation
United Illuminating Co.
Vermont Electric Power Company, Inc.
1
Westar Energy
Allen Klassen
Negative
1
1
1
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Xcel Energy, Inc.
Lloyd A Linke
Michelle Clements
Gregory L Pieper
Negative
2
BC Hydro
Venkataramakrishnan
Vinnakota
Negative
2
California ISO
Rich Vine
Negative
2
2
2
2
2
2
2
3
3
3
3
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
MISO
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Corp.
APS
Cheryl Moseley
Leonard Kula
Matthew F Goldberg
Marie Knox
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
David J Jendras
Sarah Kist
1
Tracy Sliman
John Tolo
Richard T Jackson
Jonathan Appelbaum
Kim Moulton
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
3
Associated Electric Cooperative, Inc.
Todd Bennett
3
3
Atlantic City Electric Company
Avista Corp.
NICOLE BUCKMAN
Scott J Kinney
Abstain
3
BC Hydro and Power Authority
Pat G. Harrington
Negative
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Redding
City of Tallahassee
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Dominion Resources, Inc.
DTE Electric
FirstEnergy Corp.
Florida Keys Electric Cooperative
Florida Municipal Power Agency
Florida Power & Light Co.
Adam M Weber
Andrew Gallo
Lynne Mila
Linda R Jacobson
Mark Schultz
Bill Hughes
Bill R Fowler
Jean Mueller
John Bee
Peter T Yost
Gerald G Farringer
Russell A Noble
Jose Escamilla
Michael R. Mayer
Connie B Lowe
Kent Kujala
Cindy E Stewart
Tom B Anthony
Joe McKinney
Summer C. Esquerre
3
Florida Power Corporation
Lee Schuster
https://standards.nerc.net/BallotResults.aspx?BallotGUID=81b0f0d8-375c-4ae4-bb59-bb8859e9dc11[12/17/2014 10:33:01 AM]
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
NERC Standards
3
3
3
3
3
3
3
Georgia System Operations Corporation
Great River Energy
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Lakeland Electric
Lee County Electric Cooperative
Scott McGough
Brian Glover
Ayesha Sabouba
Garry Baker
Joshua D Bach
Mace D Hunter
David A Hadzima
3
Lincoln Electric System
Jason Fortik
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Ocala Utility Services
Oklahoma Gas and Electric Co.
Mike Anctil
Charles A. Freibert
Greg C. Parent
Roger Brand
Thomas C. Mielnik
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Ramon J Barany
David McDowell
Randy Hahn
Donald Hargrove
Affirmative
Negative
3
Omaha Public Power District
Blaine R. Dinwiddie
Negative
3
3
3
3
3
3
3
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Ballard K Mutters
Thomas T Lyons
John H Hagen
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
3
Public Service Electric and Gas Co.
Jeffrey Mueller
3
3
3
3
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Mariah R Kennedy
James Leigh-Kendall
John T. Underhill
James M Poston
3
Seattle City Light
Dana Wheelock
Negative
3
3
3
3
3
3
3
3
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Tacoma Power
Tampa Electric Co.
Tennessee Valley Authority
Tri-State Generation & Transmission
Association, Inc.
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Lujuanna Medina
Marc Donaldson
Ronald L. Donahey
Ian S Grant
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Janelle Marriott
Affirmative
3
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Abstain
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
3
Westar Energy
Bo Jones
Negative
3
Xcel Energy, Inc.
Michael Ibold
Negative
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
Negative
4
4
4
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Redding
Duane S Dahlquist
Reza Ebrahimian
Nicholas Zettel
Affirmative
Abstain
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
https://standards.nerc.net/BallotResults.aspx?BallotGUID=81b0f0d8-375c-4ae4-bb59-bb8859e9dc11[12/17/2014 10:33:01 AM]
NERC Standards
4
City Utilities of Springfield, Missouri
John Allen
4
4
4
4
4
4
4
Consumers Energy Company
Cowlitz County PUD
DTE Electric
Florida Municipal Power Agency
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Tracy Goble
Rick Syring
Daniel Herring
Frank Gaffney
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
4
Indiana Municipal Power Agency
Jack Alvey
4
Madison Gas and Electric Co.
Joseph DePoorter
4
Modesto Irrigation District
Spencer Tacke
4
4
4
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Affirmative
Abstain
Affirmative
John D Martinsen
Affirmative
4
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Mike Ramirez
Affirmative
4
Seattle City Light
Hao Li
Negative
4
4
4
4
5
5
5
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Amerenue
American Electric Power
Arizona Public Service Co.
Steven R Wallace
Steve McElhaney
Keith Morisette
Brian Evans-Mongeon
Sam Dwyer
Thomas Foltz
Scott Takinen
Negative
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
Negative
5
BC Hydro and Power Authority
Clement Ma
Negative
4
5
5
5
5
5
5
5
5
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
Bonneville Power Administration
Francis J. Halpin
Brazos Electric Power Cooperative, Inc.
Shari Heino
City and County of San Francisco
Daniel Mason
City of Austin dba Austin Energy
Jeanie Doty
City of Redding
Paul A. Cummings
City of Tallahassee
Karen Webb
City Water, Light & Power of Springfield
Steve Rose
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Negative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Negative
Abstain
Affirmative
Negative
5
Cleco Power
Stephanie Huffman
Negative
5
5
5
5
5
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Con Edison Company of New York
Consumers Energy Company
Cowlitz County PUD
Mike D Hirst
Kaleb Brimhall
Brian O'Boyle
David C Greyerbiehl
Bob Essex
Negative
Negative
Affirmative
Affirmative
5
Dairyland Power Coop.
Tommy Drea
Negative
5
Dominion Resources, Inc.
Mike Garton
Affirmative
5
DTE Electric
Mark Stefaniak
Negative
5
Duke Energy
Dale Q Goodwine
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=81b0f0d8-375c-4ae4-bb59-bb8859e9dc11[12/17/2014 10:33:01 AM]
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
NERC Standards
5
5
5
5
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
Entergy Services, Inc.
Exelon Nuclear
Dan Roethemeyer
Abstain
Dana Showalter
Tracey Stubbs
Mark F Draper
5
First Wind
John Robertson
5
5
5
5
5
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Ingleside Cogeneration LP
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Michelle R DAntuono
5
JEA
John J Babik
5
5
5
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Brett Holland
Mike Blough
James M Howard
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Liberty Electric Power LLC
Daniel Duff
Negative
5
Lincoln Electric System
Dennis Florom
Negative
5
5
5
5
Kenneth Silver
Dixie Wells
Rick Terrill
Chris Mazur
Abstain
Affirmative
Negative
Affirmative
David Gordon
Abstain
5
5
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Muscatine Power & Water
Steven Grego
Mike Avesing
Affirmative
Negative
5
Nebraska Public Power District
Don Schmit
5
5
5
5
5
5
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
Michael D Melvin
Bernard Johnson
Henry L Staples
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
5
Omaha Public Power District
Mahmood Z. Safi
Negative
5
5
5
Pacific Gas and Electric Company
Platte River Power Authority
Portland General Electric Co.
Alex Chua
Christopher R Wood
Matt E. Jastram
5
PPL Generation LLC
Annette M Bannon
Negative
5
PSEG Fossil LLC
Tim Kucey
Negative
5
Steven Grega
5
5
5
5
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Affirmative
Affirmative
Affirmative
Abstain
5
Seattle City Light
Michael J. Haynes
Negative
5
Snohomish County PUD No. 1
Sam Nietfeld
5
COMMENT
RECEIVED
Negative
Affirmative
Affirmative
5
5
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Michiko Sell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=81b0f0d8-375c-4ae4-bb59-bb8859e9dc11[12/17/2014 10:33:01 AM]
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
NERC Standards
5
5
5
5
5
5
5
Edward Magic
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Mark Stein
Affirmative
5
5
South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State Generation & Transmission
Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
5
Westar Energy
Bryan Taggart
5
Affirmative
Melissa Kurtz
Erika Doot
Negative
5
Xcel Energy, Inc.
Mark A Castagneri
6
6
6
AEP Marketing
Ameren Missouri
APS
Edward P. Cox
Robert Quinlivan
Randy A. Young
Affirmative
Affirmative
Negative
Negative
6
Associated Electric Cooperative, Inc.
Brian Ackermann
Negative
6
6
6
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Brenda S. Anderson
Lisa Martin
Marvin Briggs
6
Cleco Power LLC
Robert Hirchak
Negative
6
6
6
6
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Negative
Affirmative
Affirmative
Affirmative
6
Duke Energy
Greg Cecil
6
6
6
6
6
6
6
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Negative
6
Lincoln Electric System
Eric Ruskamp
Negative
6
Lower Colorado River Authority
Michael Shaw
Affirmative
6
Luminant Energy
Brenda Hampton
6
6
6
6
6
6
Manitoba Hydro
Modesto Irrigation District
New York Power Authority
Northern Indiana Public Service Co.
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Blair Mukanik
James McFall
Shivaz Chopra
Joseph O'Brien
Donna Johnson
Jerry Nottnagel
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
6
Omaha Public Power District
Douglas Collins
Negative
6
6
6
6
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Sandra L Shaffer
Carol Ballantine
Shawn P Davis
Stephen C Knapp
6
Powerex Corp.
Gordon Dobson-Mack
https://standards.nerc.net/BallotResults.aspx?BallotGUID=81b0f0d8-375c-4ae4-bb59-bb8859e9dc11[12/17/2014 10:33:01 AM]
SUPPORTS
THIRD
PARTY
COMMENTS
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
NERC Standards
COMMENTS
6
Elizabeth Davis
Affirmative
6
PSEG Energy Resources & Trade LLC
Peter Dolan
6
6
6
6
6
6
6
6
Hugh A. Owen
Diane Enderby
William Abraham
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Joseph T Marone
Abstain
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S Parsons
Grant L Wilkerson
Affirmative
6
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Peter Colussy
Negative
7
Occidental Chemical
Venona Greaff
Negative
7
8
8
8
Siemens Energy, Inc.
Massachusetts Attorney General
Frank R. McElvain
David L Kiguel
Roger C Zaklukiewicz
Frederick R Plett
8
Volkmann Consulting, Inc.
Terry Volkmann
6
6
6
6
6
6
9
9
10
10
10
10
10
10
10
10
10
PPL EnergyPlus LLC
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
Affirmative
Affirmative
Peter H Kinney
Commonwealth of Massachusetts Department
of Public Utilities
New York State Public Service Commission
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Affirmative
Affirmative
Abstain
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
Donald Nelson
Affirmative
Diane J Barney
Linda C Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Bob Reynolds
Karin Schweitzer
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Legal and Privacy : 404.446.2560 voice : 404.467.0474 fax : 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2014 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=81b0f0d8-375c-4ae4-bb59-bb8859e9dc11[12/17/2014 10:33:01 AM]
Exhibit H
Standard Drafting Team Roster
Team Roster
Project 2010-13.3 Phase 3 of Relay Loadability: Stable Power
Swings
Participant
Contact Information
Chair
Bill Middaugh, P.E.
System Protection Manager
Tri-State Generation & Transmission Association,
Inc.
1100 W. 116th Avenue
Westminster, Colorado 80234
(303) 254-3433
(303) 254-3566 Fx
[email protected]
Vice Chair
Kevin W. Jones, P.E.
Xcel Energy, Inc.
Principal Engineer, System Protection 600 South Tyler Street
Engineering
Suite 2800
Amarillo, Texas 79101
(806) 378-2376
(806) 378-2883 Fx
[email protected]
Member
David E. Barber, P.E.
Supervisor Transmission Protection
FirstEnergy
P.O. Box 16001
Reading, Pennsylvania 19612-6001
(610) 921-6542
[email protected]
Member
Steven Black, P.E.
Project Planning Engineer
Florida Reliability Coordinating Council
3000 Bayport Drive
Suite 600
Tampa, Florida 33607
(813) 289-5644
(813) 289-5646 Fx
[email protected]
Member
Ding Lin, P.Eng.
Principal System Protection Engineer
Manitoba Hydro
PO Box 815
Winnipeg, Manitoba 815 R3C 2P4
(204) 360-5416
[email protected]
Member
Slobodan Pajic
Principal Engineer
GE Energy
One River Road
Bldg. 53, Room 302A
Schenectady, New York 12345
(518) 385-3963
[email protected]
Member
Fabio Rodriguez, P.E.
Principal Engineer
Duke Energy - Florida
6565 38th Avenue N.
St. Petersburg, Florida 33710
(727) 384-7544
[email protected]
Member
John Schmall, P.E.
Senior Planning Engineer
Electric Reliability Council of Texas, Inc.
2705 West Lake Drive
Taylor, Texas 76574-4953
(512) 248-4243
[email protected]
Member
Matthew H. Tackett, P.E.
Principal Advisor-Transmission
Expansion Planning
MISO
P.O. Box 4202
Carmel, Indiana 46082-4202
(317) 249-5455
[email protected]
Observer
Gene Henneberg
Staff Protection Engineer
NV Energy
1 Ohm Place
P.O. Box 10100
Reno, Nevada 89511
(775) 834-7187
(775) 834-7199 Fx
[email protected]
Project 2010-13.3 Stable Power Swings
Team Roster
2
Observer
David Youngblood
Luminant Energy
500 North Akard Street
Dallas, Texas 75201
(903) 360-1202
[email protected]
NERC Staff
Scott Barfield-McGinnis, P.E.
Standards Developer
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, Georgia 30326
(404) 446-2560
(404) 446-2595 Fx
[email protected]
NERC Staff
William Edwards
Counsel, Standards
North American Electric Reliability Corporation
1325 G Street, N.W.
Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 Fx
[email protected]
NERC Staff
Al McMeekin, P.E.
Standards Developer
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, Georgia 30326
(404) 446-2560
(404) 446-2595 Fx
[email protected]
Project 2010-13.3 Stable Power Swings
Team Roster
3
| File Type | application/octet-stream |
| File Title | NERC |
| File Modified | 0000-00-00 |
| File Created | 0000-00-00 |