Download Stakeholder Comparison Comment Rationale Matrix 2012-09-06 AESO AUTHORITATIVE DOCUMENT PROCESS

Stakeholder Comparison Comment Rationale Matrix
2012-09-06
AESO AUTHORITATIVE DOCUMENT PROCESS
Alberta Reliability Standard – PRC-023-AB-2 Transmission Relay Loadability
Date of Request for Comment [yyyy/mm/dd]:
Period of Consultation [yyyy/mm/dd]:
2012-09-06
2012-09-06
through 2012-09-28
Comments From:
EPCOR Distribution & Transmission Inc. (EDTI)
Date [yyyy/mm/dd]:
2012-09-28
Issued for Stakeholder Consultation: 2012-09-06
Contact:
Travis Robinson
Phone:
780-412-3079
E-mail:
[email protected]
1
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
Purpose
Protective relay settings shall not
limit transmission loadability; not
interfere with system operators’
ability to take remedial action to
protect system reliability and; be set
to reliably detect all fault conditions
and protect the electrical network
from these faults.
Purpose
Applicability
Applicability
This reliability standard applies to:
4.1. Functional Entity
4.1 Transmission Owners with loadresponsive phase protection
systems as described in PRC-023-2
- Attachment A, applied to circuits
defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.2 Generator Owners with loadresponsive phase protection
systems as described in PRC-0232 - Attachment A, applied to
circuits defined in 4.2.1 (Circuits
Subject to Requirements R1 – R5).
4.1.3 Distribution Providers with
load-responsive phase protection
systems as described in PRC-0232 - Attachment A, applied to
circuits defined in 4.2.1(Circuits
Subject to Requirements R1 – R5),
AESO Replies
The purpose of this reliability standard
is to ensure the protective relay settings
do not limit transmission loadability, do
not interfere with an operator’s ability
to take remedial action to protect the
reliability of the system, and are set to
reliably detect all fault conditions and
protect the electrical network from these
faults.
(a) a legal owner of a
transmission facility with
load-responsive phase
protection systems, as
described in Appendix 1
applied to any one (1) or more
of the following facilities:
Issued for Stakeholder Consultation: 2012-09-06
(i) transmission lines operated
at two hundred (200) kV
and above;
The terms used to describe
applicable entities in proposed PRC023-AB-2 have been amended from
the NERC version in order to
correctly identify the applicable
entities in Alberta and to align with
terms included in the AESO’s
Consolidated Authoritative
Documents Glossary.
.
EDTI notes that the applicability
section of the standard in this
comment matrix differs from the
draft Reliability Standard that
accompanied it. The proposed
standard is drafted in a manner to
not be applicable to any facilities
below 100kV. This is consistent
with the previous version of PCR023 that was consulted on in 2011,
but inconsistent with the comment
matrix version presented here.
(ii) transmission lines operated
below two hundred (200)
kV which the ISO identifies
as essential to the
reliability of the bulk
electric system as
required in requirement
R6.2;
2
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
provided those circuits have bidirectional flow capabilities.
4.1.4 Planning Coordinator
4.2. Circuits
4.2.1 Circuits Subject to
Requirements R1 – R5
4.2.1.1 Transmission lines
operated at 200 kV and above.
4.2.1.2 Transmission lines
operated at 100 kV to 200 kV
selected by the Planning
Coordinator in accordance with
R6.
4.2.1.3 Transmission lines
operated below 100 kV that are
part of the BES and selected by
the Planning Coordinator in
accordance with R6.
4.2.1.4 Transformers with low
voltage terminals connected at
200 kV and above.
4.2.1.5 Transformers with low
voltage terminals connected at
100 kV to 200 kV selected by
the Planning Coordinator in
accordance with R6.
4.2.1.6 Transformers with low
voltage terminals connected
below 100 kV that are part of
the BES and selected by the
Planning Coordinator in
accordance with R6.
AESO Replies
(iii) transformers with low
voltage terminals
connected at two hundred
(200) kV and above; or
(iv) transformers with low
voltage terminals
connected below two
hundred (200) kV which the
ISO identifies in
accordance with
requirement R6.2;
(b) a legal owner of a generating
unit, that also owns the
associated switch yard, with
load-responsive phase
protection systems, as
described in Appendix 1
applied to any one (1) or more
of the following facilities:
Issued for Stakeholder Consultation: 2012-09-06
(i) transmission lines operated
at two hundred (200) kV
and above;
(ii) transmission lines operated
below two hundred (200)
kV which the ISO identifies
as essential to the
reliability of the bulk
electric system as
required in requirement
R6.2;
(iii) transformers with low
voltage terminals
3
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
4.2.2 Circuits Subject to
Requirement R6
4.2.2.1 Transmission lines
operated at 100 kV to 200 kV
and transformers with low
voltage terminals connected at
100 kV to 200 kV
4.2.2.2 Transmission lines
operated below100 kV and
transformers with low voltage
terminals connected below 100
kV that are part of the BES.
AESO Replies
connected at two hundred
(200) kV and above; or
(iv) transformers with low
voltage terminals
connected below two
hundred (200) kV which the
ISO identifies in
accordance with
requirement R6.2;
(c) a legal owner of an
aggregated generating
facility, that also owns the
associated switch yard, with
load-responsive phase
protection systems, as
described in Appendix 1
applied to any one (1) or more
of the following facilities:
(i) transmission lines operated
at two hundred (200) kV
and above;
(ii) transmission lines operated
below two hundred (200)
kV which the ISO identifies
as essential to the
reliability of the bulk
electric system as
required in requirement
R6.2;
(iii) transformers with low
voltage terminals
connected at two hundred
Issued for Stakeholder Consultation: 2012-09-06
4
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
AESO Replies
(200) kV and above; or
(iv) transformers with low
voltage terminals
connected below two
hundred (200) kV which the
ISO identifies in
accordance with
requirement R6.2; and
(d) the ISO.
Issued for Stakeholder Consultation: 2012-09-06
5
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
Effective Date
The effective dates of the
requirements in the PRC-023-2
standard corresponding to the
applicable Functional Entities and
circuits are summarized in Table
1:NERC Effective Dates.
Effective Date
January 1, 2014 for requirements
R1, R2, R3, R4 and R5 for:
(a) transmission lines operated at
two hundred (200) kV and
above; and
AESO Replies
The proposed effective date has
been amended to allow a reasonable
amount of time for Alberta entities to
implement proposed PRC-023-AB-2
(b) transformers with low voltage
terminals connected at two
hundred (200) kV and above,
July 1, 2014 for requirement R6.
The date set out in the list the ISO
maintains .for requirements R1, R2,
R3, R4 and R5 for:
R1 Each Transmission Owner,
Generator Owner, and Distribution
Provider shall use any one of the
following criteria (Requirement R1,
criteria 1 through 13) for any
specific circuit terminal to prevent its
(a) transmission lines operated
below two hundred (200) kV
which the ISO identifies as
essential to the reliability of the
bulk electric system; and
(b) transformers with low voltage
terminals connected below two
hundred (200) kV the ISO
identifies as essential to the
reliability of the bulk electric
system.
R1 Each legal owner of a
transmission facility, legal owner of a
generating unit and legal owner of an
aggregated generating facility must
use one of the criteria set out in
requirements R1.1 through R1.14,
inclusive, for each specific circuit
Issued for Stakeholder Consultation: 2012-09-06
Based on the list being posted by the
AESO on July 1, 2014, the effective
date for transmission lines and
transformers on the list would be no
earlier than July 1, 2016 (24 months
from identification of the
transmission lines)
 New
 Amended
 Deleted
Alberta requirement R1 has been
6
NERC PRC-023-2
phase protective relay settings from
limiting transmission system
loadability while maintaining reliable
protection of the BES for all fault
conditions. 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. [Violation Risk Factor:
High] [Time Horizon: Long Term
Planning].
Criteria
1. Set transmission line relays so
they do not operate at or below
150% of the highest seasonal
Facility Rating of a circuit, for the
available defined loading duration
nearest 4 hours (expressed in
amperes).
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
terminal to prevent its phase protective
drafted in accordance with the
relay settings from limiting transmission AESO’s Alberta reliability standards
system loadability while maintaining
drafting principles to add clarity to
reliable protection of the bulk electric
the requirement.
system for all fault conditions and
evaluate the phase protective relay’s
loadability at zero point eight five (0.85)
per unit voltage and a power factor
angle of thirty (30) degrees.
AESO Replies
.
R1. Set transmission line relays so they
do not operate at or below one hundred
and fifty (150 %) percent of the highest
seasonal facility rating of a circuit for
the available defined loading duration
nearest to four (4) hours, expressed in
amperes;
R1.2 Set transmission line relays so
2. Set transmission line relays so
they do not operate at or below
they do not operate at or below one
hundred and fifteen (115 %) percent of
the highest seasonal 15-minute facility
Issued for Stakeholder Consultation: 2012-09-06
7
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
115% of the highest seasonal 15minute Facility Rating1 of a circuit
(expressed in amperes).
AESO Replies
rating of a circuit, expressed in
amperes;
R1.3 Set transmission line relays so
3. Set transmission line relays so
they do not operate at or below
115% of the maximum theoretical
power transfer capability (using a
90-degree angle between the
sending-end and receiving-end
voltages and either reactance or
complex impedance) of the circuit
(expressed in amperes) using one
of the following to perform the
power transfer calculation: of a
circuit (expressed in amperes).
R1.3.1 an infinite source, i.e. zero
• An infinite source (zero source
impedance) with a 1.00 per unit
bus voltage at each end of the
line.
source impedance, with a one point
zero zero (1.00) per unit bus voltage at
each end of the transmission line; or
• An impedance at each end of
the line, which reflects the actual
system source impedance with a
1.05 per unit voltage behind each
source impedance.
the transmission line, which reflects the
actual system source impedance with a
one point zero five (1.05) per unit
voltage behind each source impedance;
4. Set transmission line relays on
series compensated transmission
lines so they do not operate at or
1
they do not operate at or below one
hundred and fifteen (115%) percent of
the maximum theoretical power transfer
capability, using a ninety (90) degree
angle between the sending-end and
receiving-end voltages and either
reactance or complex impedance, of
the circuit, expressed in amperes, using
one of the following to perform the
power transfer calculation:
R1.3.2 an impedance at each end of
R1.4 Set transmission line relays on
series compensated transmission lines
When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating can be used to establish the loadability requirement for the protective relays
Issued for Stakeholder Consultation: 2012-09-06
8
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
below the maximum power transfer
capability of the line, determined as
the greater of:
• 115% of the highest emergency
rating of the series capacitor.
• 115% of the maximum power
transfer capability of the circuit
(expressed in amperes),
calculated in accordance with
Requirement R1, criterion 3,
using the full line inductive
reactance.
5. Set transmission line relays on
weak source systems so they do not
operate at or below 170% of the
maximum end-of-line three-phase
fault magnitude (expressed in
amperes).
6. Set transmission line relays
applied on transmission lines
connected to generation stations
remote to load so they do not
operate at or below 230% of the
aggregated generation nameplate
capability.
AESO Replies
so they do not operate at or below the
maximum power transfer capability of
the transmission line, determined as the
greater of:
(a) one hundred and fifteen (115 %)
percent of the highest emergency
rating of the series capacitor, or
(b) one hundred and fifteen (115%)
percent of the maximum power
transfer capability of the circuit,
expressed in amperes, calculated in
accordance with requirement R1.3,
using the full transmission line
inductive reactance;
R1.5 Set transmission line relays on
weak source systems so they do not
operate at or below one hundred and
seventy (170%) percent of the
maximum end-of-line three-phase fault
magnitude, expressed in amperes;
R1.6 Set transmission line relays
applied on transmission lines connected
to a generating unit or aggregated
generating facility remote to load so
they do not operate at or below two
hundred and thirty (230%) percent of
the total nameplate capability of all the
generating units at the facility;
R1.7 Set transmission line relays
applied at the load center terminal,
Issued for Stakeholder Consultation: 2012-09-06
9
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
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
configuration.
AESO Replies
remote from a generating unit or
aggregated generating facility, so
they do not operate at or below one
hundred and fifteen (115%) percent of
the maximum current flow from the load
to the generation source under any
system configuration;
R1.8 Set transmission line relays
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 configuration.
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
load to the system under any
system configuration.
10. Set transformer fault protection
relays and transmission line relays
on transmission lines terminated
applied on the system-end of
transmission lines that serve load
remote to the system so they do not
operate at or below one hundred and
fifteen (115%) percent of the maximum
current flow from the system to the load
under any system configuration;
R1.9 Set transmission line relays
applied on the load-end of transmission
lines that serve load remote to the
system so they do not operate at or
below one hundred and fifteen (115%)
of the maximum current flow from the
load to the system under any system
configuration;
R1.10 Set transformer fault protection
relays and transmission line relays on
transmission lines terminated only with
a transformer so that they do not
operate at or below the greater of:
Issued for Stakeholder Consultation: 2012-09-06
10
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
only with a transformer so that the
relays do not operate at or below
the greater of:
• 150% of the applicable
maximum transformer nameplate
rating (expressed in amperes),
including the forced cooled
ratings corresponding to all
installed supplemental cooling
equipment.
AESO Replies
(a) one hundred and fifty (150%)
percent of the applicable maximum
transformer nameplate rating,
expressed in amperes, including the
forced cooled ratings corresponding
to all installed supplemental cooling
equipment; or
(b) one hundred and fifteen (115%)
percent of the highest established
emergency transformer rating;
• 115% of the highest operator
established emergency
transformer rating
10.1 Set load responsive
transformer fault protection relays, if
used, such that the protection
settings do not expose the
transformer to a fault level and
duration that exceeds the
transformer’s mechanical withstand
capability2
R1.11 Set load responsive transformer
fault protection relays, if used, such that
the protection settings do not expose
the transformer to a fault level and
duration that exceeds the transformer’s
mechanical withstand capability;
R1.12 For transformer overload
protection relays that do not comply
11. For transformer overload
protection relays that do not comply with requirement R1.10:
(a) set the relays to allow the
with the loadability component of
2
As illustrated by the “dotted line” in IEEE C57.109-1993 - IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4
Issued for Stakeholder Consultation: 2012-09-06
11
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
Requirement R1, criterion 10 set the
relays according to one of the
following: .
AESO Replies
transformer to be operated at an
overload level of at least one
hundred and fifty (150%) percent of
the maximum applicable nameplate
rating, or one hundred and fifteen
(115%) percent of the highest
emergency transformer rating,
whichever is greater;
• Set the relays to allow the
transformer to be operated at an
overload level of at least 150% of
the maximum applicable
nameplate rating, or 115% of the (b) the protection relay must allow
highest operator established
overload in subsection 1.12(a) for at
emergency transformer rating,
least fifteen (15) minutes to allow the
ISO to take controlled action to
whichever is greater, for at least
relieve the overload;
15 minutes to provide time for the
operator to take controlled action (c) install supervision for the relays
to relieve the overload.
using either a top oil or simulated
winding hot spot temperature
element; and
• Install supervision for the relays (d) the relay setting should be no less
using either a top oil or simulated
than one hundred (100°C) degrees
winding hot spot temperature
Celsius for the top oil or one
element set no less than 100° C
hundred and forty (140°C) degrees
for the top oil temperature or no
Celsius for the winding hot spot
temperature;
less than 140° C for the winding
hot spot temperature3
3
4 IEEE standard C57.91, Tables 7 and 8, specify that transformers are to be designed to withstand a winding hot spot temperature of 180 degrees C, and Annex A cautions that bubble formation may occur
above 140 degrees C
Issued for Stakeholder Consultation: 2012-09-06
12
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
12. When the desired transmission
line capability is limited by the
requirement to adequately protect
the transmission line, set the
transmission line distance relays to
a maximum of 125% of the apparent
impedance (at the impedance angle
of the transmission line) subject to
the following constraints: .
a. Set the maximum torque angle
(MTA) to 90 degrees or the
highest supported by the
manufacturer.
b. Evaluate the relay loadability in
amperes at the relay trip point at
0.85 per unit voltage and a power
factor angle of 30 degrees.
c. Include a relay setting
component of 87% of the current
calculated in Requirement R1,
criterion 12 in the Facility Rating
determination for the circuit.
AESO Replies
R1.13 When the desired transmission
line capability is limited by the
requirement to adequately protect the
transmission line, set the transmission
line distance relays to a maximum of
one hundred and twenty five (125%)
percent of the apparent impedance, at
the impedance angle of the
transmission line, subject to the
following constraints:
R1.13.1 Set the maximum torque
angle to ninety (90) degrees or the
highest setting supported by the
manufacturer;
R1.13.2 Evaluate the relay loadability
in amperes at the relay trip point at
zero point eight five (0.85) per unit
voltage and a power factor angle of
thirty (30) degrees; and
R1.13.3 Include a relay setting
component of eighty seven (87%)
percent of the current calculated in
requirement R1.13.2 in the facility
rating determination for the circuit; and
R1.14 Where other situations present
13. Where other situations present
practical limitations on circuit
practical limitations on circuit capability,
set the phase protection relays so they
do not operate at or below one hundred
Issued for Stakeholder Consultation: 2012-09-06
13
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
4
capability, set the phase protection
relays so they do not operate at or
below 115% of such limitations.
and fifteen (115%) percent of such
limitations.
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. [Violation Risk
Factor: High] [Time Horizon: Long
Term Planning]
R2 Each legal owner of a
transmission facility, legal owner
of a generating unit and legal
owner of an aggregated
generating facility must set its outof-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.
R3. Each Transmission Owner,
Generator Owner, and Distribution
Provider that uses a circuit
capability with the practical
limitations described in Requirement
R1, criterion 6, 7, 8, 9, 12, or 13
shall use the calculated circuit
capability as the Facility Rating of
the circuit and shall obtain the
agreement of the Planning
Coordinator, Transmission
Operator, and Reliability
Coordinator with the calculated
circuit capability. [Violation Risk
Factor: Medium] [Time Horizon:
R3 Any legal owner of a
transmission facility, legal owner
of a generating unit or legal owner
of an aggregated generating
facility that uses a circuit capability
with the practical limitations
described in requirements R1.6,
R1.7, R1.8, R1.9, R1.13, or R1.14
must use the calculated circuit
capability as the facility rating of the
circuit and must obtain the
agreement of the ISO to use the
calculated circuit capability.
AESO Replies
 New
 Amended
 Deleted
Alberta requirement R2 has been
drafted in accordance with the
AESO’s Alberat reliability standards
drafting principles to add clarity to
the requirement.
 New
 Amended
 Deleted
NERC requirement R3 has been
amended in proposed PRC-023-AB-2 to
identify requirements of the responsible
entities in Alberta.
4
Alberta Variance : The WECC
Reliability Coordinator is not included in
Alberta requirement R3. NERC
requirement R3 states that agreement
shall be obtained from the Planning
Coordinator, Transmission Operator,
and Reliability Coordinator. The AESO is
An Alberta variance is a change from the US Reliability Standard that the AESO has determined is material.
Issued for Stakeholder Consultation: 2012-09-06
14
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
the authority from which legal owners of
transmission facilities, generating units
and aggregated generating units will
obtain agreement for the calculated
circuit capability and the AESO will
consult with the WECC Reliability
Coordinator at its discretion.
Long Term Planning]
R4. Each Transmission Owner,
Generator Owner, and Distribution
Provider that chooses to use
Requirement R1 criterion 2 as the
basis for verifying transmission line
relay loadability shall provide its
Planning Coordinator, Transmission
Operator, and Reliability
Coordinator with an updated list of
circuits associated with those
transmission line relays at least
once each calendar year, with no
more than 15 months between
reports. [Violation Risk Factor:
Lower] [Time Horizon: Long Term
Planning]
AESO Replies
R4 Any legal owner of a
transmission facility, legal owner
of a generating unit or legal owner
of an aggregated generating
facility that uses requirement R1.2
as the basis for verifying
transmission line relay loadability
must provide the ISO with an
updated list of circuits associated
with those transmission line relays
at least once each calendar year,
with no more than fifteen (15)
months between reports.
Issued for Stakeholder Consultation: 2012-09-06
 New
 Amended
 Deleted
Alberta requirement R4 has been
drafted in accordance with the
AESO’s Alberta reliability standards
drafting principles to add clarity to
the requirement.
15
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
NERC PRC-023-2
PRC-023-AB-2
Reason for Differences
(Insert comments here)
 New
R5. Each Transmission Owner,
R5 Any legal owner of a
transmission facility, legal owner  Amended
Generator Owner, and Distribution
of a generating unit or legal owner  Deleted
Provider that sets transmission line
relays according to Requirement R1 of an aggregated generating
criterion 12 shall provide an updated facility that uses requirement R1.13
Alberta requirement R5 has been
list of the circuits associated with
as the basis for verifying
drafted in accordance with the
those relays to its Regional Entity at transmission line relay loadability
AESO’s Alberta reliability standards
least once each calendar year, with must provide the ISO with an
drafting principles to add clarity to
no more than 15 months between
updated list of circuits associated
the requirement.
reports, to allow the ERO to compile with those transmission line relays
a list of all circuits that have
at least once each calendar year,
protective relay settings that limit
with no more than fifteen (15)
circuit capability. [Violation Risk
months between reports.
Factor: Lower] [Time Horizon: Long
Term Planning]
 New
R6. Each Planning Coordinator shall R6 The ISO must conduct an
 Amended
conduct an assessment at least
assessment at least once each
once each calendar year, with no
calendar year, with no more than
 Deleted
more than 15 months between
fifteen (15) months between
assessments, by applying the
assessments, by applying the
Alberta requirement R6 has been
criteria in Attachment B to
criteria in Appendix 2 to determine
drafted in accordance with the
determine the circuits in its Planning the circuits in its Planning
Coordinator area for which the legal AESO’s Alberta reliability standards
Coordinator area for which
drafting principles to add clarity to
owner of a transmission facility,
Transmission Owners, Generator
the requirement.
legal owner of a generating unit
Owners, and Distribution Providers
must comply with Requirements R1 and legal owner of an aggregated
generating facility must comply
through R5. The Planning
Coordinator shall: [Violation Risk
with requirements R1 through R5.
The ISO must:
Factor: High] [Time Horizon: Long
Term Planning]
Issued for Stakeholder Consultation: 2012-09-06
AESO Replies
16
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
NERC PRC-023-2
6.1 Maintain a list of circuits
subject to PRC-023-2 per
application of Attachment B,
including identification of the first
calendar year in which any
criterion in Attachment B applies.
R6.1 Maintain a list of circuits
per the application of Appendix 2,
including an effective date that is
no earlier than twenty-four (24)
months from identification of the
circuits; and
6.2 Provide the list of circuits to all
Regional Entities, Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator area within
30 calendar days of the
establishment of the initial list and
within 30 calendar days of any
changes to that list.
R6.2 Provide the list of circuits
to the legal owner of a
transmission facility, legal
owner of a generating unit and
legal owner of an aggregated
generating facility within its
Planning Coordinator area within
thirty (30) days of the
establishment of the initial list and
within thirty (30) days of any
changes to that list.
M1. Each Transmission Owner,
Generator Owner, and Distribution
Provider shall have evidence such
as spreadsheets or summaries of
calculations to show that each of its
transmission relays is set according
to one of the criteria in Requirement
R1, criterion 1 through 13 and shall
have evidence such as coordination
curves or summaries of calculations
that show that relays set per
criterion 10 do not expose the
MR1. Evidence of using one of the
criteria set out in requirements R1.1
through R1.14 as required in
requirement R1 exists. Evidence
may include:
Issued for Stakeholder Consultation: 2012-09-06
AESO Replies
(a) spreadsheets or
summaries of calculations
to show that each of its
transmission relays is set
in accordance with one of
the criteria set out in
17
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
requirements R1.1 through
R1.14; and
NERC PRC-023-2
transformer to fault levels and
durations beyond those indicated in
the standard. (R1)
AESO Replies
(b) coordination curves or
summaries of calculations
that show that relays set
per criterion set out in
requirement R1.11 do not
expose the transformer to
fault levels and durations
beyond those indicated in
the reliability standard.
M2. Each Transmission Owner,
Generator Owner, and Distribution
Provider shall have evidence such
as spreadsheets or summaries of
calculations to show that each of its
out-of-step blocking elements is set
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. (R2)
MR2 Evidence of setting its out-ofstep blocking elements as required
in requirement R2 exists. Evidence
may include spreadsheets or
summaries of calculations..
M3. Each Transmission Owner,
Generator Owner, and Distribution
Provider with transmission relays
set according to Requirement R1,
criterion 6, 7, 8, 9, 12, or 13 shall
have evidence such as Facility
MR3. Evidence of using, and
obtaining the agreement to use, the
calculated circuit capability as
required in requirement R3 exists.
Evidence may include:
(a) facility rating spreadsheets or
Issued for Stakeholder Consultation: 2012-09-06
18
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
facility rating database to show
that the calculated circuit
capability was used as the
facility rating of the circuit; and
NERC PRC-023-2
Rating spreadsheets or Facility
Rating database to show that it
used the calculated circuit capability
as the Facility Rating of the circuit
and evidence such as dated
correspondence that the resulting
Facility Rating was agreed to by its
associated Planning Coordinator,
Transmission Operator, and
Reliability Coordinator. (R3)
AESO Replies
(b) dated correspondence to show
that the ISO agreed to the
calculated circuit capability.
M4. Each Transmission Owner,
Generator Owner, or Distribution
Provider that sets transmission line
relays according to Requirement
R1, criterion 2 shall have evidence
such as dated correspondence to
show that it provided its Planning
Coordinator, Transmission
Operator, and Reliability
Coordinator with an updated list of
circuits associated with those
transmission line relays within the
required timeframe. The updated list
may either be a full list, a list of
incremental changes to the previous
list, or a statement that there are no
changes to the previous list. (R4)
MR4 Evidence of providing the ISO
with an updated list of circuits as
required in requirement R4 exists.
Evidence may include email or mail
to the appropriate ISO recipient with
the updated list which may either be
a full list, a list of incremental
changes to the previous list, or a
statement that there are no changes
to the previous list.
M5. Each Transmission Owner,
Generator Owner, or Distribution
Provider that sets transmission line
MR5 Evidence of providing the ISO
with an updated list of circuits as
required in requirement R5 exists.
Issued for Stakeholder Consultation: 2012-09-06
19
NERC PRC-023-2
relays according to Requirement
R1, criterion 12 shall have evidence
such as dated correspondence that
it provided an updated list of the
circuits associated with those relays
to its Regional Entity within the
required timeframe. The updated list
may either be a full list, a list of
incremental changes to the previous
list, or a statement that there are no
changes to the previous list. (R5)
M6. Each Planning Coordinator
shall have evidence such as power
flow results, calculation summaries,
or study reports that it used the
criteria established within
Attachment B to determine the
circuits in its Planning Coordinator
area for which applicable entities
must comply with the standard as
described in Requirement R6. The
Planning Coordinator shall have a
dated list of such circuits and shall
have evidence such as dated
correspondence that it provided the
list to the Regional Entities,
Reliability Coordinators,
Transmission Owners, Generator
Owners, and Distribution Providers
within its Planning Coordinator area
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
Evidence may include email or mail
to the appropriate ISO recipient with
the updated list which may either be
a full list, a list of incremental
changes to the previous list, or a
statement that there are no changes
to the previous list.
AESO Replies
MR6. Evidence of conducting an
assessment as required in
requirement R6 exists. Evidence
may include as power flow results,
calculation summaries, or study
reports that the ISO used the criteria
established within Appendix 2 to
determine the circuits in its Planning
Coordinator area.
MR6.1 Evidence of maintaining the
list of circuits as required in
requirement R6.1 exists. Evidence
may include a documented list of
circuits with the effective date and
the revision history captured.
MR6.2 Evidence of providing the list
Issued for Stakeholder Consultation: 2012-09-06
20
NERC PRC-023-2
within the required timeframe.
COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2
Transmission Relay Loadability
Stakeholder Comments
PRC-023-AB-2
Reason for Differences
(Insert comments here)
of circuits as required in
requirement R6.2 exists. Evidence
may include email or mail to the
applicable entities.
Compliance
To view the compliance section D of
the NERC reliability standard follow
this link:
http://www.nerc.com/files/BAL-0020.pdf
AESO Replies
The Alberta reliability standards do
not contain a compliance section.
Compliance with all Alberta reliability
standards is completed in
accordance with the Alberta
Reliability Standards Compliance
Monitoring Program, available on the
AESO website at:
http://www.aeso.ca/loadsettlement/1
7189.html
Regional Differences
Regional Differences
None identified.
None identified.
Issued for Stakeholder Consultation: 2012-09-06
21
Table 1: NERC Effective Dates – Per Applicability Section for Alberta (this table will not be included in the final Alberta
version)
Requirement
Applicability
NERC: Each Transmission Owner, Generator Owner, and
Distribution Provider with transmission lines operating at 200 kV
and above and transformers with low voltage terminals connected
at 200 kV and above, except as noted below.
Effective Date
Jurisdictions where Regulatory Approval
Jurisdictions where No Regulatory
is Required
Approval is Required
NERC: First day of the first calendar quarter,
NERC: First calendar quarter after Board of
after applicable regulatory approvals
Trustees adoption
AB: Per Effective Date Section above.
AB: N/A
NERC: First day of the first calendar quarter
12 months after applicable regulatory
approvals
NERC: First day of the first calendar quarter
12 months after Board of Trustees adoption
AB: Per Applicability Section above.
NERC: • For Requirement R1, criterion 10.1, to set transformer fault
protection 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
AB: N/A
AB: Per Effective Date Section above.
R1
AB: Per Applicability Section above.
NERC: • For supervisory elements as described in PRC-023-2 Attachment A, Section 1.6
NERC: First day of the first calendar quarter
24 months after applicable regulatory
approvals
AB: Per Applicability Section above.
NERC: For switch-on-to-fault schemes as described in PRC-023-2 Attachment A, Section 1.3
AB: Per Applicability Section above.
5
NERC: First day of the first calendar quarter
24 months after Board of Trustees adoption
AB: N/A
AB: Per Effective Date Section above.
NERC: Later of the first day of the first
calendar quarter after applicable regulatory
approvals of PRC-023-2 or the first day of the
first calendar quarter 39 months following
applicable regulatory approvals of PRC-023-1
NERC: Later of the first day of the first
calendar quarter after Board of Trustees
adoption of PRC-023-2 or July 1, 20115
AB: N/A
1 July 1, 2011 is the first day of the first calendar quarter 39 months following the Board of Trustees February 12, 2008 approval of PRC-023-1.
Issued for Stakeholder Consultation: 2012-09-06
22
(October 1, 2013)
NERC: Each Transmission Owner, Generator Owner, and
Distribution Provider with circuits identified by the Planning
Coordinator pursuant to Requirement R6
AB: Per Applicability Section above.
NERC: Each Transmission Owner, Generator Owner, and
Distribution Provider with transmission lines operating at 200 kV
and above and transformers with low voltage terminals connected
at 200 kV and above
AB: Per Effective Date Section above.
NERC: Later of the first day of the first
calendar quarter 39 months following
notification by the Planning Coordinator of a
circuit’s inclusion on a list of circuits subject to
PRC-023-2 per application of Attachment B,
or the first day of the first calendar year in
which any criterion in Attachment B applies,
unless the Planning Coordinator removes the
circuit from the list before the applicable
effective date
NERC: Later of the first day of the first
calendar quarter 39 months following
notification by the Planning Coordinator of a
circuit’s inclusion on a list of circuits subject to
PRC-023-2 per application of Attachment B,
or the first day of the first calendar year in
which any criterion in Attachment B applies,
unless the Planning Coordinator removes the
circuit from the list before the applicable
effective date
AB: Per Effective Date Section above.
AB: N/A
NERC: First day of the first calendar quarter
after applicable regulatory approvals
NERC: First day of the first calendar quarter
after Board of Trustees adoption
AB: Per Effective Date Section above.
AB: N/A
NERC: Later of the first day of the first
calendar quarter 39 months following
notification by the Planning Coordinator of a
circuit’s inclusion on a list of circuits subject to
PRC-023-2 per application of Attachment B,
or the first day of the first calendar year in
which any criterion in Attachment B applies,
unless the Planning Coordinator removes the
circuit from the list before the applicable
effective date
NERC: Later of the first day of the first
calendar quarter 39 months following
notification by the Planning Coordinator of a
circuit’s inclusion on a list of circuits subject to
PRC-023-2 per application of Attachment B,
or the first day of the first calendar year in
which any criterion in Attachment B applies,
unless the Planning Coordinator removes the
circuit from the list before the applicable
effective date
AB: Per Effective Date Section above.
AB: N/A
AB: Per Applicability Section above.
R2 and R3
NERC: Each Transmission Owner, Generator Owner, and
Distribution Provider with circuits identified by the Planning
Coordinator pursuant to Requirement R6
AB: Per Applicability Section above.
Issued for Stakeholder Consultation: 2012-09-06
23
R4
R5
NERC: Each Transmission Owner, Generator Owner, and
Distribution Provider that chooses to use Requirement R1 criterion
2 as the basis for verifying transmission line relay loadability
NERC: First day of the first calendar quarter
six months after applicable regulatory
approvals
NERC: First day of the first calendar quarter
six months after Board of Trustees adoption
AB: Per Applicability Section above.
AB: Per Effective Date Section above.
AB: N/A
NERC: Each Transmission Owner, Generator Owner, and
Distribution Provider that sets transmission line relays according to
Requirement R1 criterion 12
NERC: First day of the first calendar quarter
six months after applicable regulatory
approvals
NERC: First day of the first calendar quarter
six months after Board of Trustees adoption
AB: Per Applicability Section above.
AB: Per Effective Date Section above.
NERC: Each Planning Coordinator shall conduct an assessment by
applying the criteria in Attachment B to determine the circuits in its
Planning Coordinator area for which Transmission Owners,
Generator Owners, and Distribution Providers must comply with
Requirements R1 through R5
NERC: First day of the first calendar quarter
18 months after applicable regulatory
approvals
AB: N/A
R6
NERC: First day of the first calendar quarter
18 months after Board of Trustees adoption
AB: N/A
AB: Per Effective Date Section above.
AB: ISO
Issued for Stakeholder Consultation: 2012-09-06
24
Table 2: NERC Violation Severity Levels – Not Used in Alberta (this table will not be included in the final Alberta version)
Requirement
Lower
Moderate
High
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
R1
R2
R3
Issued for Stakeholder Consultation: 2012-09-06
Severe
The responsible entity did not use
any one of the following criteria
(Requirement R1 criterion 1 through
13) for any specific circuit terminal to
prevent its phase protective relay
settings from limiting transmission
system loadability while maintaining
reliable protection of the Bulk Electric
System for all fault conditions.
OR
The responsible entity did not
evaluate relay loadability at 0.85 per
unit voltage and a power factor angle
of 30 degrees.
The responsible entity failed to
ensure that its out-of-step blocking
elements allowed tripping of phase
protective relays for faults that occur
during the loading conditions used to
verify transmission line relay
loadability per Requirement R1.
The responsible entity that uses a
circuit capability with the practical
limitations described in Requirement
R1 criterion 6, 7, 8, 9, 12, or 13 did
not use the calculated circuit
capability as the Facility Rating of
the circuit.
25
N/A
N/A
N/A
N/A
N/A
N/A
N/A
The Planning Coordinator used
the criteria established within
Attachment B to determine the
circuits in its Planning Coordinator
area for which applicable entities
must comply with the standard
and met parts 6.1 and 6.2, but
more than 15 months and less
than 24 months lapsed between
assessments.
The Planning Coordinator used the
criteria established within
Attachment B to determine the
circuits in its Planning Coordinator
area for which applicable entities
must comply with the standard and
met parts 6.1 and 6.2, but 24 months
or more lapsed between
assessments.
OR
R4
R5
R6
Issued for Stakeholder Consultation: 2012-09-06
OR
The responsible entity did not obtain
the agreement of the Planning
Coordinator, Transmission Operator,
and Reliability Coordinator with the
calculated circuit capability.
The responsible entity did not
provide its Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with an
updated list of circuits that have
transmission line relays set
according to the criteria established
in Requirement R1 criterion 2 at
least once each calendar year, with
no more than 15 months between
reports.
The responsible entity did not
provide its Regional Entity, with an
updated list of circuits that have
transmission line relays set
according to the criteria established
in Requirement R1 criterion 12 at
least once each calendar year, with
no more than 15 months between
reports.
The Planning Coordinator failed to
use the criteria established within
Attachment B to determine the
circuits in its Planning Coordinator
area for which applicable entities
must comply with the standard.
OR
The Planning Coordinator used the
criteria established within
Attachment B, at least once each
26
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard and met
6.1 and 6.2 but provided the list of
circuits to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator area
between 31 days and 45 days
after the list was established or
updated. (part 6.2)
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard and met
6.1 and 6.2 but provided the list of
circuits to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator area
between 31 days and 45 days
Issued for Stakeholder Consultation: 2012-09-06
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than 15
months between assessments to
determine the circuits in its Planning
Coordinator area for which
applicable entities must comply with
the standard and met 6.1 and 6.2 but
provided the list of circuits to the
Reliability Coordinators,
Transmission Owners, Generator
Owners, and Distribution Providers
within its Planning Coordinator area
between 46 days and 60 days after
list was established or updated. (part
6.2)
calendar year, with no more than 15
months between assessments to
determine the circuits in its Planning
Coordinator area for which
applicable entities must comply with
the standard but failed to meet parts
6.1 and 6.2.
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than 15
months between assessments to
determine the circuits in its Planning
Coordinator area for which
applicable entities must comply with
the standard but failed to maintain
the list of circuits determined
according to the process described
in Requirement R6. (part 6.1)
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than 15
months between assessments to
determine the circuits in its Planning
Coordinator area for which
applicable entities must comply with
the standard and met 6.1 but failed
to provide the list of circuits to the
Reliability Coordinators,
Transmission Owners, Generator
Owners, and Distribution Providers
within its Planning Coordinator area
or provided the list more than 60
27
after the list was established or
updated. (part 6.2)
Issued for Stakeholder Consultation: 2012-09-06
days after the list was established or
updated. (part 6.2)
OR
The Planning Coordinator failed to
determine the circuits in its Planning
Coordinator area for which
applicable entities must comply with
the standard.
28
Attachment A/Appendix 1- Associated Switch Yard with Load-Responsive Phase Protection Systems
NERC PRC-023-2
1. This standard includes any
protective functions which could trip
with or without time delay, on load
current, including but not limited to:
1.1 Phase distance.
1.2. Out-of-step tripping.
1.3. Switch-on-to-fault.
1.4. Overcurrent relays.
1.5. Communications aided
protection schemes including but
not limited to:
1.5.1 Permissive overreach
transfer trip (POTT).
1.5.2 Permissive under-reach
transfer trip (PUTT).
1.5.3 Directional comparison
blocking (DCB).
1.5.4 Directional comparison
unblocking (DCUB).
1.6. Phase overcurrent
supervisory elements (i.e., phase
fault detectors) associated with
current-based, communicationassisted schemes (i.e., pilot wire,
phase comparison, and line
current differential) where the
scheme is capable of tripping for
loss of communications.
2. The following protection systems
are excluded from requirements of
this standard:
2.1. Relay elements that are only
PRC-023-AB-02
Reason for Differences
Stakeholder Comments
(Insert comments here)
AESO Replies
1. This reliability standard includes
any protective functions which could trip
with or without time delay, on load
current, including:
(a) phase distance;
(b) out-of-step tripping;
(c) switch-on-to-fault;
(d) overcurrent relays;
(e) communications aided
protection schemes including:
(i) permissive overreach
transfer trip;
(ii) permissive under-reach
transfer trip;
(iii) directional comparison
blocking; and
(iv) directional comparison
unblocking; and
(f) phase overcurrent supervisory
elements (i.e. phase fault
detectors) associated with
current-based, communicationassisted schemes (i.e. pilot
wire, phase comparison, and
line current differential) where
the scheme is capable of
tripping for loss of
communications.
2. The following protection systems
Issued for Stakeholder Consultation: 2012-09-06
29
NERC PRC-023-2
enabled when other relays or
associated systems fail. For
example:
• Overcurrent elements that
are only enabled during loss
of potential conditions.
• Elements that are only
enabled during a loss of
communications except as
noted in section 1.6
2.2. Protection systems intended
for the detection of ground fault
conditions.
2.3. Protection systems intended
for protection during stable
power swings.
2.4. Generator protection relays
that are susceptible to load.
2.5. Relay elements used only
for Special Protection Systems
applied and approved in
accordance with NERC
Reliability Standards PRC-012
through PRC-017 or their
successors.
2.6. Protection systems that are
designed only to respond in time
periods which allow 15 minutes
or greater to respond to overload
conditions.
2.7. Thermal emulation relays
which are used in conjunction
with dynamic Facility Ratings.
2.8. Relay elements associated
PRC-023-AB-02
Reason for Differences
Stakeholder Comments
(Insert comments here)
AESO Replies
are excluded from the requirements of
this reliability standard:
(a) relay elements that are only
enabled when other relays or
associated systems fail, including:
(i) overcurrent elements that
are only enabled during
loss of potential conditions;
and
(ii) elements that are only
enabled during a loss of
communications except as
noted in subsection 1(f)
above;
(b) protection systems intended
for the detection of ground fault
conditions;
(c) protection systems intended
for protection during stable power
swings;
(d) generator protection relays that
are susceptible to load;
(e) relay elements used only for
remedial action scheme purposes;
(f) protection systems that are
designed only to respond in
time periods which allow fifteen
(15) minutes or greater to
respond to overload conditions;
(g) thermal emulation relays which
are used in conjunction with
dynamic facility ratings; and
(h) relay elements associated with
Issued for Stakeholder Consultation: 2012-09-06
30
NERC PRC-023-2
with dc lines.
PRC-023-AB-02
Reason for Differences
Stakeholder Comments
(Insert comments here)
AESO Replies
direct current lines.
Issued for Stakeholder Consultation: 2012-09-06
31
Attachment B/Appendix 2 - Criteria for Establishing List of Circuits
NERC PRC-023-2
Circuits to Evaluate
PRC-023-AB-02
Circuits to Evaluate
• Transmission lines operated at 100 The ISO must evaluate the following
circuits:
kV to 200 kV and transformers with
low voltage terminals connected at
(a) transmission lines operated at
100 kV to 200 kV.
one hundred (100) kV to two
• Transmission lines operated below
hundred (200) kV and
100 kV and transformers with low
transformers with low voltage
terminals connected at one
voltage terminals connected below
hundred (100) kV to two
100 kV that are part of the BES.
Reason for Differences
Stakeholder Comments
(Insert comments here)
AESO Replies
EDTI recommends that (b) be
removed. The applicability section
of the proposed standard does not
include any facilities below 100 kV,
and thus evaluating facilities below
100 kV is unnecessary.
hundred (200) kV; and
Criteria
If any of the following criteria apply
to a circuit, the applicable entity
must comply with the standard for
that circuit.
B1. The circuit is a monitored
Facility of a permanent flowgate in
the Eastern Interconnection, a
major transfer path within the
Western Interconnection as
defined by the Regional Entity, or
a comparable monitored Facility
in the Québec Interconnection,
that has been included to address
reliability concerns for loading of
that circuit, as confirmed by the
applicable Planning Coordinator.
B2. The circuit is a monitored
Facility of an IROL, where the
IROL was determined in the
planning horizon pursuant to
(b) transmission lines operated
below one hundred (100) kV
and transformers with low
voltage terminals connected
below one hundred (100) kV
that are essential to the
reliability of the bulk electric
system.
Criteria
If any of the following criteria apply to a
circuit, the ISO must identify the circuit
as required in requirement R6.
1
A major transfer path within the
Western Interconnection as defined
by the Regional Entity.
2
The circuit is a monitored
facility of an interconnection
reliability operating limit, where the
interconnection reliability
operating limit was determined in
the planning horizon pursuant to
Issued for Stakeholder Consultation: 2012-09-06
32
NERC PRC-023-2
FAC-010.
B3. The circuit forms a path (as
agreed to by the Generator
Operator and the transmission
entity) to supply off-site power to
a nuclear plant as established in
the Nuclear Plant Interface
Requirements (NPIRs) pursuant
to NUC-001.
B4. The circuit is identified
through the following sequence of
power flow analyses6
a. Simulate double contingency
combinations selected by
engineering judgment, without
manual system adjustments in
between the two contingencies
(reflects a situation where a
System Operator may not have
time between the two
contingencies to make
appropriate system
adjustments). performed by the
Planning Coordinator for the
one-to-five-year planning
horizon:
b. For circuits operated
between 100 kV and 200 kV
evaluate the post-contingency
loading, in consultation with the
Facility owner, against a
PRC-023-AB-02
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reliability standard FAC-010-AB2.1, System Operation Limits
Methodology for the Planning
Horizon.
3
The circuit is identified through
the following sequence of power flow
analyses:
(a) simulate double
contingency combinations
selected by engineering
judgment, without manual
system adjustments in
between the two (2)
contingencies (reflects a
situation where a system
operator may not have time
between the two (2)
contingencies to make
appropriate system
adjustments), performed by
the ISO for the one-to-fiveyear planning horizon;
(b) for circuits operated
between one hundred (100)
kV and two hundred (200)
kV, evaluate the postcontingency loading, in
consultation with the legal
owner, against a threshold
based on the facility rating
assigned for that circuit and
used in the power flow case
by the ISO;
6
Past analyses may be used to support the assessment if no material changes to the system have occurred since the last assessment
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33
NERC PRC-023-2
threshold based on the Facility
Rating assigned for that circuit
and used in the power flow
case by the Planning
Coordinator.
c. When more than one Facility
Rating for that circuit is
available in the power flow
case, the threshold for selection
will be based on the Facility
Rating for the loading duration
nearest four hours.
d. The threshold for selection of
the circuit will vary based on the
loading duration assumed in the
development of the Facility
Rating.
i. If the Facility Rating is
based on a loading duration
of up to and including four
hours, the circuit must
comply with the standard if
the loading exceeds 115% of
the Facility Rating.
ii. If the Facility Rating is
based on a loading duration
greater than four and up to
and including eight hours,
the circuit must comply with
the standard if the loading
exceeds 120% of the Facility
Rating.
iii. If the Facility Rating is
based on a loading duration
Issued for Stakeholder Consultation: 2012-09-06
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(c) when more than one (1)
facility rating for that circuit
is available in the power
flow case, the ISO must
base the threshold for
selection on the facility
rating for the loading
duration nearest four (4)
hours;
(d) the threshold for selection
of the circuit will vary based
on the loading duration
assumed in the
development of the facility
rating:
(i) if the facility rating is
based on a loading
duration of up to and
including four hours,
the circuit must comply
with the standard if the
loading exceeds one
hundred and fifteen
percent (115%) of the
facility rating;
(ii) if the facility rating is
based on a loading
duration greater than
four and up to and
including eight hours,
the circuit must comply
with the standard if the
loading exceeds one
hundred and twenty
percent (120%) of the
facility rating; or
34
NERC PRC-023-2
of greater than eight hours,
the circuit must comply with
the standard if the loading
exceeds 130% of the Facility
Rating.
e. Radially operated circuits
serving only load are excluded.
B5. The circuit is selected by the
Planning Coordinator based on
technical studies or assessments,
other than those specified in
criteria B1 through B4, in
consultation with the Facility
owner.
B6. The circuit is mutually agreed
upon for inclusion by the Planning
Coordinator and the Facility
owner.
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(iii) if the facility rating is
based on a loading
duration of greater than
eight (8) hours, the
circuit must comply with
the standard if the
loading exceeds one
hundred and thirty
percent (130%) of the
facility rating; and
(e) radially operated circuits
serving only load are excluded.
4
The ISO must select the circuit
based on technical studies or
assessments, other than those
specified in criteria 1 through 4, in
consultation with the legal owner.
5
The ISO and the legal owner
must mutually agree upon the circuit
for inclusion.
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35