Stakeholder Comparison Comment Rationale Matrix
2012-10-16
AESO AUTHORITATIVE DOCUMENT PROCESS
Alberta Reliability Standard – BAL-005-AB-0.2b Automatic Generation Control
NOTE: The AESO is asking market participants to give an initial indication of their support for, or opposition to, the specific Alberta Reliability Standard variances to the NERC requirements
referenced below. Such an initial indication assists in the AESO’s practical understanding of the receptivity of the industry to the proposed changes, and in that regard the AESO thanks, in
advance, all market participants who choose to respond. With regard to the specific standard changes and their implications, such responses are without prejudice to the rights of market
participants under the Act, any regulations, or related decisions of the Commission.
Date of Request for Comment [yyyy/mm/dd]:
Period of Consultation [yyyy/mm/dd]:
2012/10/16
2012/10/16
Comments From:
through 2012/11/16
Contact:
Phone:
E-mail:
ars_comments@aeso.ca
Date [yyyy/mm/dd]:
Listed below is the summary of changes for the proposed new, removed or amended sections of the standard. Please refer back to the Letter of Notice under the “Attachments to Letter of
Notice” section to view the proposed content changes to the standard.
Issued for stakeholder consultation: 2012-10-16
1
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
Purpose
This standard establishes
requirements for Balancing Authority
Automatic Generation Control (AGC)
necessary to calculate Area Control
Error (ACE) and to routinely deploy
the Regulating Reserve. The
standard also ensures that all
facilities and load electrically
synchronized to the Interconnection
are included within the metered
boundary of a Balancing Area so that
balancing of resources and demand
can be achieved.
Purpose
Applicability
4.1. Balancing Authorities
4.2. Generator Operators
4.3. Transmission Operators
4.4. Load Serving Entities
Applicability
1
The purpose of this reliability
standard is to establish the
necessary related requirements for
the ISO`s automatic generation
control.
This reliability standard applies to:
(a) the legal owner of a
transmission facility that
provides frequency data the
ISO uses for automatic
generation control which
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
Alberta Variance1: The AESO
interprets that NERC BAL-005-0.2b
R1 applies to market participants
receiving service under Rate DTS of
the ISO tariff and all generating units,
transmission facilities and load
connected to the interconnected
electric system. These entities are
subject to the ISO tariff and are
already required to be within the
metered boundaries of the Alberta
balancing area. Consequently, it is
not necessary to include the metered
boundary of a balancing authority in
proposed BAL-005-AB-0.2b.
 New
 Amended
 Deleted
The terms used to describe
applicable entities in proposed BAL005-AB-0.2b have been amended
from the NERC version in order to
correctly identify the applicable
An Alberta variance is a change from the US Reliability Standard that the AESO has determined is material.
Issued for stakeholder consultation: 2012-10-16
2
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
such frequency data is
collected from the source the
ISO identifies and publishes
on the AESO website and
may amend from time to time
in accordance with the
process set out in Appendix
1;
(b) the legal owner of a
generating unit that provides
frequency data the ISO uses
for automatic generation
control which such frequency
data is collected from the
source the ISO identifies and
publishes on the AESO
website and may amend from
time to time in accordance
with the process set out in
Appendix 1; and
AESO Reason for Difference
entities in Alberta and to align with
terms included in the AESO's
Consolidated Authoritative
Documents Glossary. In addition, the
legal owner has been assigned as
the applicable entity type rather than
the operator as the requirements
pertain to metering equipment,
devices and their accuracy.
Stakeholder Comments
AESO Replies
(c) the ISO.
(i)
Effective Date
Effective Date
Janaury 1, 2014
R1. All generation, transmission, and
load operating within an
Interconnection must be included
within the metered boundaries of a
Balancing Authority Area.
Issued for stakeholder consultation: 2012-10-16
 New
 Amended
 Deleted
Alberta Variance1: The AESO
3
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
R1.1. Each Generator Operator with
generation facilities operating in an
Interconnection shall ensure that
those generation facilities are
included within the metered
boundaries of a Balancing Authority
Area.
R1.2. Each Transmission Operator
with transmission facilities operating
in an Interconnection shall ensure
that those transmission facilities are
included within the metered
boundaries of a Balancing Authority
Area.
AESO Reason for Difference
interprets that NERC BAL-005-0.2b
applies to market participants
receiving service under Rate DTS of
the ISO tariff and all generating units,
transmission facilities and load
connected to the interconnected
electric system. These entities are
subject to the ISO tariff and are
already required to be within the
metered boundaries of the Alberta
balancing area. Consequently, it is
not necessary to include NERC
requirement R1 and its subsections
in the Alberta reliability standard.
Stakeholder Comments
AESO Replies
R1.3. Each Load-Serving Entity with
load operating in an Interconnection
shall ensure that those loads are
included within the metered
boundaries of a Balancing Authority
Area.
R2. Each Balancing Authority shall
R1 The ISO must maintain
maintain Regulating Reserve that can regulating reserve to meet the
control performance standard.
be controlled by AGC to meet the
Control Performance Standard.
 New
 Amended
 Deleted
Clarified requirement R1 to remove
reference to automatic generation
control as the AESO definition of
regulating reserve contains this term.
For greater certainty, regulating
reserve is defined as follows: “the
Issued for stakeholder consultation: 2012-10-16
4
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
R3. A Balancing Authority providing
Regulation Service shall ensure that
adequate metering, communications,
and control equipment are employed
to prevent such service from
becoming a Burden on the
Interconnection or other Balancing
Authority Areas.
Alberta BAL-005-AB-0.2b
R2 The ISO must, when providing
regulation service, have adequate
metering, communications, and
control equipment employed to
prevent such regulation service from
becoming a burden on the
interconnection or other balancing
authority areas.
AESO Reason for Difference
amount of spinning reserve
responsive to automatic generation
control that is sufficient to provide
normal regulating margin.”
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
Amended NERC requirement R3
when drafting Alberta requirement
R2 in accordance with the reliability
standard drafting principles to add
clarity to the requirements.
NERC requirement R3 has been
retained for possible future use in
Alberta, as currently “regulation
service” does not exist in Alberta.
R4. A Balancing Authority providing
Regulation Service shall notify the
Host Balancing Authority for whom it
is controlling if it is unable to provide
the service, as well as any
Intermediate Balancing Authorities.
R3 The ISO must, when providing
regulation service, notify the host
balancing authority for which it is
controlling if it is unable to provide
the regulation service and must also
notify any intermediate balancing
authorities.
Issued for stakeholder consultation: 2012-10-16
 New
 Amended
 Deleted
Amended NERC requirement R4
when drafting Alberta requirement
R3 in accordance with the reliability
standard drafting principles to add
5
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
AESO Reason for Difference
clarity to the requirements.
Stakeholder Comments
AESO Replies
NERC requirement R4 has been
retained for possible future use in
Alberta, as currently “regulation
service” does not exist in Alberta.
R5. A Balancing Authority receiving
Regulation Service shall ensure that
backup plans are in place to provide
replacement Regulation Service
should the supplying Balancing
Authority no longer be able to provide
this service.
R4 The ISO must, when receiving
regulation service, have backup
plans in place to provide replacement
regulation service should the
supplying balancing authority no
longer be able to provide this service.
 New
 Amended
 Deleted
Amended NERC requirements R5
when drafting Alberta requirement
R4 in accordance with the reliability
standard drafting principles to add
clarity to the requirements.
NERC requirement R5 has been
retained for possible future use in
Alberta, as currently “regulation
service” does not exist in Alberta.
R6. The Balancing Authority’s AGC
shall compare total Net Actual
Interchange to total Net Scheduled
Interchange plus Frequency Bias
obligation to determine the Balancing
Authority’s ACE. Single Balancing
Authorities operating asynchronously
R5 The ISO must use area control
error calculations in its automatic
generation control that compare
total net actual interchange to total
net scheduled interchange plus
frequency bias obligation except that
the ISO’s automatic generation
Issued for stakeholder consultation: 2012-10-16
 New
 Amended
 Deleted
NERC requirement R6 contains two
requirements that have been divided
6
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
may employ alternative ACE
calculations such as (but not limited
to) flat frequency control. If a
Balancing Authority is unable to
calculate ACE for more than 30
minutes it shall notify its Reliability
Coordinator.
Alberta BAL-005-AB-0.2b
control may use alternative area
control error calculations when the
ISO is operating the interconnected
electric system asynchronously.
R7. The Balancing Authority shall
operate AGC continuously unless
such operation adversely impacts the
reliability of the Interconnection. If
AGC has become inoperative, the
Balancing Authority shall use manual
control to adjust generation to
maintain the Net Scheduled
Interchange.
R7 Subject to requirement R8, the
ISO must operate its automatic
generation control continuously.
R8. The Balancing Authority shall
ensure that data acquisition for and
AESO Reason for Difference
into Alberta requirements R5 and R6
to separate the responsibilities of the
AESO.
Stakeholder Comments
AESO Replies
R6 The ISO must notify the WECC
Reliability Coordinator if the ISO is
unable to calculate the area control
error for more than thirty (30)
minutes consecutively.
R8 The ISO must, if automatic
generation control has become
inoperative or operation of
automatic generation control could
adversely impact the reliability of the
interconnection, use manual
controls to adjust generation to
maintain the net scheduled
interchange.
R9 The ISO must acquire data for,
and calculate, the area control error
Issued for stakeholder consultation: 2012-10-16
 New
 Amended
 Deleted
NERC requirement R7 contains two
requirements that have been divided
into Alberta requirements R7 and R8
to separate the responsibilities of the
AESO.
Alberta requirement R8 was
amended to include the use of
manual controls to adjust generation
to maintain the net scheduled
interchange if the operation of
automatic generation control could
adversely impact the reliability of the
interconnection.
 New
 Amended
7
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
calculation of ACE occur at least
every six seconds.
Alberta BAL-005-AB-0.2b
at least every nine (9) seconds.
R8.1. Each Balancing Authority shall
provide redundant and independent
frequency metering equipment that
shall automatically activate upon
detection of failure of the primary
source. This overall installation shall
provide a minimum availability of
99.95%.
R9. The Balancing Authority shall
include all Interchange Schedules
with Adjacent Balancing Authorities in
the calculation of Net Scheduled
Interchange for the ACE equation.
R9.1
The ISO must use
frequency data from
redundant and
independent frequency
metering equipment that
automatically activates
upon detection of failure
of the primary source; and
R9.2
The ISO must provide
frequency metering data
to its automatic
generation control with a
minimum availability of
99.95%.
R10 Subject to requirement R10.1
the ISO must include all interchange
schedules with adjacent balancing
authorities in the ISO’s calculation
of net scheduled interchange for
Issued for stakeholder consultation: 2012-10-16
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 Deleted
Alberta Variance1: The time allotted
for data acquisition and calculation of
ACE was changed from six (6)
seconds to nine (9) seconds due to
communications latency with the
extra link between facility owners and
the AESO. The Alberta
interconnected electric system has
been operating reliably under this
condition for quite some time.
Amended NERC requirement R8.1
when drafting Alberta requirements
R9.1and R9.2 in accordance with the
reliability standard drafting principles
to add clarity to the requirements.
NERC requirement R8.1 has been
divided into Alberta requirements
R9.1 and R9.2 to separate the
requirements for acquiring frequency
data and the availability of frequency
metering data.
 New
 Amended
 Deleted
8
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
the area control error calculation.
R9.1. Balancing Authorities with a
high voltage direct current (HVDC)
link to another Balancing Authority
connected asynchronously to their
Interconnection may choose to omit
the Interchange Schedule related to
the HVDC link from the ACE equation
if it is modeled as internal generation
or load.
R10.1 The ISO may omit the
interchange schedule for a high
voltage direct current link to another
balancing authority from the area
control error calculation if such
interchange schedule is modeled
by the ISO as internal generation or
load.
R10. The Balancing Authority shall
include all Dynamic Schedules in the
calculation of Net Scheduled
Interchange for the ACE equation.
R11 The ISO must include all
dynamic schedules in the calculation
of net scheduled interchange for
the area control error calculation.
AESO Reason for Difference
Amended NERC requirements R9
and R9.1 when drafting Alberta
requirements R10 and R10.1 in
accordance with the reliability
standard drafting principles to add
clarity to the requirements.
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
Amended NERC requirement R10
when drafting Alberta requirement
R11 in accordance with the reliability
standard drafting principles to add
clarity to the requirement.
R11. Balancing Authorities shall
include the effect of ramp rates,
which shall be identical and agreed to
between affected Balancing
Authorities, in the Scheduled
Interchange values to calculate ACE.
R12 The ISO must include the effect
of ramp rates, which must be
identical and agreed to between
affected balancing authorities, in
the scheduled interchange values to
calculate the area control error.
Issued for stakeholder consultation: 2012-10-16
 New
 Amended
 Deleted
Amended NERC requirement R11
when drafting Alberta requirement
R12 in accordance with the reliability
standard drafting principles to add
9
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
R12. Each Balancing Authority shall
include all Tie Line flows with
Adjacent Balancing Authority Areas
in the ACE calculation.
Alberta BAL-005-AB-0.2b
R13 The ISO must include all
synchronous interconnection flows
of real power in the area control
error calculation.
AESO Reason for Difference
clarity to the requirement.
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
Amended NERC requirement R12 to
clarify that the area control error
calculation only includes
synchronous interconnection flows of
real power.
R12.1. Balancing Authorities that
share a tie shall ensure Tie Line MW
metering is telemetered to both
control centers, and emanates from a
common, agreed-upon source using
common primary metering
equipment. Balancing Authorities
shall ensure that megawatt-hour data
is telemetered or reported at the end
of each hour.
R13.1 The ISO must use MW
metering data for each
synchronous
interconnection that:
Issued for stakeholder consultation: 2012-10-16
(a) emanates from a common,
agreed-upon source using
common primary metering
equipment; and
(b) is telemetered to its system
coordination centre and the
control centre of the
adjacent balancing
authority;
 New
 Amended
 Deleted
NERC requirement R12.1 contains
two requirements. The first
requirement has been amended into
Alberta requirement R13.1. the
second is already in effect under
BAL-006-AB-1 requirement R3 “The
ISO must ensure all of the AIES’s
interconnection points are equipped
with common megawatt hour meters,
with readings provided hourly to the
control centers of adjacent balancing
authorities.”
10
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
R12.2. Balancing Authorities shall
ensure the power flow and ACE
signals that are utilized for calculating
Balancing Authority performance or
that are transmitted for Regulation
Service are not filtered prior to
transmission, except for the Antialiasing Filters of Tie Lines.
R13.2 The legal owner of a
transmission facility must
not filter:
(a) MW metering data for
synchronous
interconnections; or
(b) area control error signals
transmitted to the ISO,
except for the anti-aliasing
filters of interconnections;
R13.3 The ISO must use unfiltered:
(a) MW metering data for
synchronous
interconnections; or
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
NERC requirement R12.2 has been
divided into Alberta requirements
R13.2 and R13.3 to separate the
responsibilities of the AESO and the
legal owners of transmission
facilities.
.
(b) area control error signals;
provided by the legal owner
of a transmission facility
for calculating the ISO’s
performance under the
control performance
standard, except for the
anti-aliasing filters of
interconnections; and
Issued for stakeholder consultation: 2012-10-16
11
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
R12.3. Balancing Authorities shall
install common metering equipment
where Dynamic Schedules or
Pseudo-Ties are implemented
between two or more Balancing
Authorities to deliver the output of
Jointly Owned Units or to serve
remote load.
Alberta BAL-005-AB-0.2b
R13.4 The ISO must ensure that
common metering
equipment is installed where
dynamic schedules or
pseudo-ties are implemented
between two (2) or more
balancing authorities to
deliver the output of jointly
owned generating units or
to serve remote load.
R13. Each Balancing Authority shall
perform hourly error checks using Tie
Line megawatt-hour meters with
common time synchronization to
determine the accuracy of its control
equipment. The Balancing Authority
shall adjust the component (e.g., Tie
Line meter) of ACE that is in error (if
known) or use the interchange meter
error (IME) term of the ACE equation
to compensate for any equipment
error until repairs can be made.
R14 The ISO must perform hourly
error checks using intertie MWh
meters with common time
synchronization to determine the
accuracy of its control equipment.
R14. The Balancing Authority shall
provide its operating personnel with
sufficient instrumentation and data
recording equipment to facilitate
R16 The ISO must provide its
operating personnel with real-time
values for the area control error,
interconnection frequency and net
R15 The ISO must adjust the
component of the area control error
that is in error, if known, or use the
interchange meter error (IME) term of
the area control error equation, to
compensate for any metering
equipment error until repairs can be
made.
Issued for stakeholder consultation: 2012-10-16
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
Amended NERC requirement R12.3
when drafting Alberta requirement
R13.4 in accordance with the
reliability standard drafting principles
to add clarity to the requirement.
 New
 Amended
 Deleted
NERC requirement R13 contains two
requirements that have been divided
into Alberta requirements R14 and
R15 to separate the responsibilities
of the AESO.
 New
 Amended
 Deleted
12
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
monitoring of control performance,
generation response, and after-thefact analysis of area performance. As
a minimum, the Balancing Authority
shall provide its operating personnel
with real-time values for ACE,
Interconnection frequency and Net
Actual Interchange with each
Adjacent Balancing Authority Area.
Alberta BAL-005-AB-0.2b
actual interchange with each
adjacent balancing authority.
R15. The Balancing Authority shall
provide adequate and reliable backup
power supplies and shall periodically
test these supplies at the Balancing
Authority’s control center and other
critical locations to ensure continuous
operation of AGC and vital data
recording equipment during loss of
the normal power supply.
R18 The ISO must have adequate
and reliable backup power supplies
at the ISO’s coordination centre and
at the ISO’s backup coordination
centre, which must be periodically
tested, to maintain continuous
operation of the automatic
generation control and vital data
recording equipment during loss of
the normal power supply.
 New
 Amended
 Deleted
R19 The ISO must:
 New
 Amended
 Deleted
R16. The Balancing Authority shall
sample data at least at the same
periodicity with which ACE is
calculated. The Balancing Authority
shall flag missing or bad data for
operator display and archival
R17 The ISO must provide its
operating personnel with sufficient
instrumentation and data recording
equipment to facilitate the monitoring
of the control performance
standard, generation response and
after-the-fact analysis of area
performance.
Issued for stakeholder consultation: 2012-10-16
(a) sample area control errorrelated data at least at the
same periodicity with which
the area control error is
calculated;
AESO Reason for Difference
Stakeholder Comments
AESO Replies
NERC requirement R14 contains two
requirements that have been divided
into Alberta requirements R16 and
R17 to separate the responsibilities
of the AESO.
Amended NERC requirement R15
when drafting Alberta requirement
R18 to align with reliability standard
drafting principles.
Provided clarity that “other critical
locations” only applies to the ISO’s
backup coordination centre.
Amended NERC requirement R16
when drafting Alberta requirement
13
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
purposes. The Balancing Authority
shall collect coincident data to the
greatest practical extent, i.e., ACE,
Interconnection frequency, Net Actual
Interchange, and other data shall all
be sampled at the same time.
R17. Each Balancing Authority shall
at least annually check and calibrate
its time error and frequency devices
against a common reference. The
Balancing Authority shall adhere to
the minimum values for measuring
devices as listed below:
Device
Accuracy
Digital
 0.001 Hz
frequency
transducer
MW, MVAR,
 0.25 % of full
and voltage
scale
transducer
Remote
 0.25 % of full
terminal unit
scale
Potential
 0.30 % of full
transformer
scale
Current
 0.50 % of full
transformer
scale
Alberta BAL-005-AB-0.2b
(b) flag missing or bad area
control error-related data
for operator display and
archival purposes; and
AESO Reason for Difference
R19 to align with reliability standard
drafting principles.
Stakeholder Comments
AESO Replies
(c) collect coincident area
control error-related data to
the greatest extent practical.
R20 Each legal owner of a
transmission facility, legal owner
of a generating unit, and the ISO
must:
(a) at least once every calendar
year, check and calibrate its
time error and frequency
devices used for automatic
generation control against a
common reference; but if
these devices cannot be
calibrated,
(b) cross-check its time error and
frequency devices used for
automatic generation control
against other properly
calibrated equipment at least
once every calendar year;
and replace them if they do not meet
the required level of accuracy as
specified in requirements R21.
Issued for stakeholder consultation: 2012-10-16
 New
 Amended
 Deleted
Note: The AESO will post a list of
time error and frequency devices,
used for automatic generation
control on the AESO website.
Requirements R20 and R21 have
been revised to align with the NERC
interpretation as included in
Appendix 2 at the end of this
document. Please note that the
NERC interpretation will not be
included in proposed BAL-005-AB0.2b.
NERC requirement R17 contains
requirements that have been divided
into Alberta requirements R20 and
R21.
14
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
R21 Each legal owner of a
transmission facility, legal owner
of a generating unit, and the ISO
must adhere to the following
accuracy values for measuring
devices used for automatic
generation control data as
identified in requirement R20:
Device
Digital
frequency
transducer
Stakeholder Comments
AESO Replies
Accuracy
 0.001 Hz
MR1 Evidence of maintaining
regulating reserve as required in
requirement R1 exists. Evidence may
include data files showing the
control performance standard was
met.
Issued for stakeholder consultation: 2012-10-16
AESO Reason for Difference
Alberta Variance: Requirements
R20 and R21 apply to legal owners
of transmission facilities and legal
owners of generating units as
specified in the Applicability section
of this standard in addition to the
AESO.
 New
 Amended
 Deleted
Added to align with Alberta
requirement R1.
15
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
AESO Reason for Difference
Stakeholder Comments
AESO Replies
MR2 Evidence of having adequate
metering, communications, and
control equipment employed as
required in requirement R2 exists.
Evidence may include regulation
reserve service agreements or other
documentation confirming that
metering, communications and
control equipment employed are
adequate to prevent such service
from becoming a burden.
MR3 Evidence of notifying the host
balancing authority and any
intermediate balancing authorities
as required in requirement R3 exists.
Evidence may include voice
recordings or operator logs.
MR4 Evidence of having backup
plans in place as required in
requirement R4 exists, Evidence may
include a dated and in effect backup
plans.
Issued for stakeholder consultation: 2012-10-16
16
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
MR5 Evidence of using area control
error calculations in the automatic
generation control of the ISO as
required in requirement R5 exist.
Evidence may include the algorithm
or codes of the calculation of the
area control error.
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
Added to align with Alberta
requirements R5, R6, and R7.
MR6 Evidence of notifying the
WECC Reliability Coordinator as
required in requirement R6 exists.
Evidence may include operator logs
or voice recordings.
MR7 Evidence of operating
automatic generation control
continuously as required in
requirement R7 exists. Evidence may
include:
(a) data files showing the
automatic generation
control was operated
continuously;
(b) where the automatic
generation control was not
operated continuously
documentation of the
rationale of not operating
automatic generation
control continuously; and
(c) operator logs and voice
Issued for stakeholder consultation: 2012-10-16
17
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
recordings.
MR8 Evidence of using manual
controls to adjust generation as
required in requirement R8 exists.
Evidence may include operator logs
or voice recordings.
MR9 Evidence of acquiring data for,
and calculating area control error
as required in requirement R9 exists.
Evidence may include documentation
of data acquisition and calculation
rate.
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
Added to align with Alberta
requirements R8 and R9 as well as
sub-requirements R9.1and R9.2.
MR9.1 Evidence of using
frequency data as
required in requirement
R9.1 exists. Evidence
may include a list of
independent and
redundant frequency
metering equipment.
MR9.2 Evidence of providing
frequency metering data
as required in
requirement R9.2 exists.
Evidence may include
records of frequency
metering data
availability to its
automatic generation
Issued for stakeholder consultation: 2012-10-16
18
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
control.
MR10 Evidence of including all
interchange schedules with
adjacent balancing authorities in
the ISO’s calculation as required in
R10 exists. Evidence may include
the algorithm or codes of the
calculation of the area control error
MR10.1 Evidence of omitting the
interchange schedule for a high
voltage direct current link as allowed
in requirement R10.1 exists.
Evidence may include modeling data
documentation showing that the
omitted interchange schedule for a
high voltage direct current link was
modeled as internal generation or
load.
MR11 Evidence of including dynamic
schedules in the calculation of net
scheduled interchange as required
in R11 exists. Evidence may include
modeling data documentation
showing dynamic schedules, if they
exist, are included in the area
control error equation.
Issued for stakeholder consultation: 2012-10-16
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
Added to align with Alberta
requirement R10 and its subrequirements R10.1.
 New
 Amended
 Deleted
Added to align with Alberta
requirement R11.
19
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
MR12 Evidence of including the
effect of ramp rates in the
scheduled interchange values as
required in requirement R12 exists.
Evidence may include:
a) documentation showing the effect
of ramp rates was included in the
calculation of the area control error;
and
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 New
 Amended
 Deleted
Added to align with Alberta
requirement R12.
b) documentation showing the ramp
rates were identical and agreed to
between affected balancing
authorities.
MR13 Evidence of including all
synchronous interconnection flows
of real power in the calculation as
required in requirement R13 exists.
Evidence may include the algorithm
or codes of the calculation of the
area control error.
MR13.1 Evidence of using MW
metering values for
synchronous
interconnections as
required in requirement
R13.1 exists. Evidence may
include measurement
definition records and
Issued for stakeholder consultation: 2012-10-16
 New
 Amended
 Deleted
Added to align with Alberta
requirement R13 and its subrequirements R13.1 through to
R13.4.
20
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
documentation showing the
agreement on the source
and metering equipment
with the adjacent balancing
authority.
AESO Reason for Difference
Stakeholder Comments
AESO Replies
MR13.2 Evidence of not filtering
metering data or area
control error signals as
required in requirement
R13.2 exists. Evidence may
include data files showing
that the MW metering data
for synchronous
interconnections or area
control error signals
transmitted to the ISO are
not filtered prior to
transmission.
MR13.3 Evidence of using unfiltered
metering data or area
control error signals as
required in requirement
R13.3 exists. Evidence may
include data files showing
that the unfiltered data
received by the ISO is the
same data used in the area
control error calculation.
MR13.4 Evidence of ensuring that
common metering
Issued for stakeholder consultation: 2012-10-16
21
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
equipment is installed as
required in requirement
R13.4 exists. Evidence may
include documentation
showing the agreement on
the common metering
equipment with the other
balancing authority.
AESO Reason for Difference
MR14 Evidence of performing MWh
hourly error checks as required in
requirement R14 exists. Evidence
may include records of hourly error
checks and records of adjustments
made for each discrepancy, if any,
identified in the hourly error checks.
 New
 Amended
 Deleted
MR15 Evidence of adjusting the
component of the area control error
that is in error as required in
requirement R15 exists. Evidence
may include files or data showing the
error was included in the area
control error.
 New
 Amended
 Deleted
MR16 Evidence of providing real-time
 New
Issued for stakeholder consultation: 2012-10-16
Stakeholder Comments
AESO Replies
Added to align with Alberta
requirement R14.
Added to align with Alberta
requirement R15.
22
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
values for area control error,
interconnection frequency and net
actual interchange, as required in
requirement R16 exists. Evidence
may include screen shots of the
interface displaying the real-time
data.
MR17 Evidence of providing
sufficient instrumentation and data
recording equipment as required in
requirement R17 exists. Evidence
may include a list of instrumentation,
data and recording equipment and
screen shots of the interface
displaying the control performance
standard generation response and
after-the fact analysis of area
performance.
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 Amended
 Deleted
Added to align with Alberta
requirement R16.
 New
 Amended
 Deleted
Added to align with Alberta
requirements R17 and R18.
MR18 Evidence of having adequate
and reliable backup power supplies
and of periodically testing these
supplies as required in requirement
R18 exists. Evidence may include a
list of backup power supplies, a
periodic testing plan for these backup
power supplies and records of the
tests.
MR19 Evidence of sampling, flagging
Issued for stakeholder consultation: 2012-10-16
 New
23
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
and collecting area control errorrelated data as required in
requirement R19 exists. Evidence
may include:
(a) algorithms of the sampling
area control error-related
data;
AESO Reason for Difference
Stakeholder Comments
AESO Replies
 Amended
 Deleted
Added to align with Alberta
requirement R19.
(b) screenshots of the
operator display;
(c) archived files for missing
or bad area control error
related data; and
(d) archived files for coincident
area control error data.
MR20 Evidence of checking,
calibrating and replacing time error
and frequency devices as required in
requirement R20 exists. Evidence
may include:
(a) a list of time error and
frequency devices used for
automatic generation
control ;
 New
 Amended
 Deleted
Added to align with Alberta
requirement R20.
(b) records of check and
calibration against a
common reference;
Issued for stakeholder consultation: 2012-10-16
24
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
AESO Reason for Difference
Stakeholder Comments
AESO Replies
(c) where the manufacturer’s
specification does not
require calibration of these
devices, records of check
and cross-checking
against a properly
calibrated equipment.
MR21 Evidence of adhering to the
minimum values for measuring
devices as identified in requirement
R21 exists. Evidence may include:
(a) records of calibration
against a common
reference showing the
accuracy values of these
devices; and
 New
 Amended
 Deleted
Added to align with Alberta
requirements R21.
(b) where these devices
cannot be calibrated,
records of cross-checking
against a properly
calibrated equipment
showing the accuracy
values of these devices.
Issued for stakeholder consultation: 2012-10-16
25
COMPARISON BETWEEN NERC BAL-005-0.2B AND ALBERTA BAL-005-AB-0.2B
Automatic Generation Control
NERC BAL-005-0.2b
Alberta BAL-005-AB-0.2b
Compliance
To view the compliance section D of
the NERC reliability standard follow
this link:
http://www.nerc.com/files/BAL-0050_2b.pdf
Regional Differences
None identified.
AESO Reason for Difference
Stakeholder Comments
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.
None identified.
Not applicable in Alberta
Appendix 1
Amending Process for List of Frequency Data
In order to amend the lists referenced in subsections (a) and (b) of section 2, Applicability, the ISO must:
(a) upon determining that a source of frequency data is to be added to the list, notify each affected legal owner of a generating unit or legal owner of a transmission facility in writing and determine an
effective date, which must be no less than thirty (30) days after the date of notice, for the legal owner to meet the applicable requirements;
(b) upon determining that a source of frequency data is to be deleted, notify each affected legal owner of a generating unit or legal owner of a transmission facility in writing and determine an effective
date for the legal owner to no longer be required to meet the applicable requirements; and
(c) post the amended list with effective dates on the AESO website.
Issued for stakeholder consultation: 2012-10-16
26
Appendix 22 NERC Interpretation
Effective Date: August 27, 2008 (U.S.)
Interpretation of BAL-005-0 Automatic Generation Control, R17
Request for Clarification received from PGE on July 31, 2007
PGE requests clarification regarding the measuring devices for which the requirement applies, specifically clarification if the requirement applies to the following measuring devices:
• Only equipment within the operations control room
• Only equipment that provides values used to calculate AGC ACE
• Only equipment that provides values to its SCADA system
• Only equipment owned or operated by the BA
• Only to new or replacement equipment
• To all equipment that a BA owns or operates
BAL-005-0
R17. Each Balancing Authority shall at least annually check and calibrate its time error and
frequency devices against a common reference. The Balancing Authority shall adhere to the
minimum values for measuring devices as listed below:
Device Accuracy
Digital frequency transducer ≤ 0.001 Hz
MW, MVAR, and voltage transducer ≤ 0.25% of full scale
Remote terminal unit ≤ 0.25% of full scale
Potential transformer ≤ 0.30% of full scale
Current transformer ≤ 0.50% of full scale
Existing Interpretation Approved by Board of Trustees May 2, 2007
BAL-005-0, Requirement 17 requires that the Balancing Authority check and calibrate its
control room time error and frequency devices against a common reference at least annually.
The requirement to “annually check and calibrate” does not address any devices outside of
the operations control room.
The table represents the design accuracy of the listed devices. There is no requirement within
2
The NERC interpretation in Appendix 2 will not be part of the Alberta reliability standard BAL-005-AB-0.2.b. The interpretation has been applied in the drafting of Alberta requirements R17, R18 and R19.
Issued for stakeholder consultation: 2012-10-16
27
the standard to “annually check and calibrate” the devices listed in the table, unless they are
included in the control center time error and frequency devices.
Interpretation provided by NERC Frequency Task Force on September 7, 2007 and Revised on November 16, 2007
As noted in the existing interpretation, BAL-005-0 Requirement 17 applies only to the time error and frequency devices that provide, or in the case of back-up equipment may provide, input into
the reporting or compliance ACE equation or provide real-time time error or frequency information to the system operator. Frequency inputs from other sources that are for reference only are
excluded. The time error and frequency measurement devices may not necessarily be located in the system operations control room or owned by the Balancing Authority; however the
Balancing Authority has the responsibility for the accuracy of the frequency and time error measurement devices. No other devices are included in R 17.
The other devices listed in the table at the end of R17 are for reference only and do not have any mandatory calibration or accuracy requirements.
New or replacement equipment that provides the same functions noted above requires the same calibrations. Some devices used for time error and frequency measurement cannot be
calibrated as such. In this case, these devices should be cross-checked against other properly calibrated equipment and replaced if the devices do not meet the required level of accuracy.
Issued for stakeholder consultation: 2012-10-16
28