BAL-001-TRE-2

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

A. Introduction
1.

Title: Primary Frequency Response in the ERCOT Region

2.

Number:

3.

Purpose: To maintain Interconnection steady-state frequency within defined limits.

4.

Applicability:

BAL-001-TRE-2

4.1. Functional Entities:
4.1.1 Balancing Authority
4.1.2 Generator Owners
4.1.3 Generator Operators
4.2. Exemptions
4.2.1 Existing generating facilities regulated by the U.S. Nuclear Regulatory
Commission prior to the Effective Date are exempt from Standard BAL001-TRE-2.
4.2.2 Generating units/generating facilities while operating in synchronous
condenser mode are exempt from Standard BAL-001-TRE-2.
4.2.3 Any generators that are not required by the Balancing Authority to
provide primary frequency response are exempt from this standard.
5.

Effective Date: See Implementation Plan for Regional Standard BAL-001-TRE-2.

6.

Background: The ERCOT Interconnection was initially given a waiver of BAL-001 R2
(Control Performance Standard CPS2). In FERC Order 693, NERC was directed to
develop a Regional Standard as an alternate means of assuring frequency
performance in the ERCOT Interconnection. NERC was explicitly directed to
incorporate key elements of the existing Protocols, Section 8.5. This required
governors to be in service and performing with an un-muted response to assure an
Interconnection minimum Frequency Response to a Frequency Measurable Event
(FME) (that starts at t(0)).
This Regional Standard provides requirements related to identifying Frequency
Measureable Events, calculating the Primary Frequency Response of each resource
in the Region, calculating the Interconnection minimum Frequency Response and
monitoring the actual Frequency Response of the Interconnection, setting Governor
deadband and droop parameters, and providing Primary Frequency Response
performance requirements.
Under this standard, two Primary Frequency Response (PFR) performance measures
are calculated: “initial” and “sustained.” The initial PFR performance (R9) measures
the actual response compared to the expected response in the period from 20 to 52
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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

seconds after an FME starts. The sustained PFR performance (R10) measures the best
actual response between 46 and 60 seconds after t(0) compared to the expected
response based on the system frequency at a point 46 seconds after t(0).
In this Regional Standard the term “resource” is synonymous with “generating
unit/generating facility”.

B. Requirements and Measures
R1. The Balancing Authority shall identify Frequency Measurable Events (FMEs), and
within 14 calendar days after each FME the Balancing Authority shall notify the
Compliance Enforcement Authority and make FME information (time of FME (t(0)),
pre-perturbation average frequency, post- perturbation average frequency) publicly
available. [Violation Risk Factor – Lower] [Time Horizon – Operations Assessment]
M1. The Balancing Authority shall have evidence it reported each FME to the Compliance
Enforcement Authority and that it made FME information publicly available within 14
calendar days after the FME as required in Requirement R1.
R2. The Balancing Authority shall calculate the Primary Frequency Response of each
generating unit/generating facility in accordance with this standard and the Primary
Frequency Response Reference Document. 1 This calculation shall provide a 12-month
rolling average of initial and sustained Primary Frequency Response performance. This
calculation shall be completed each month for the preceding 12 calendar months.
[Violation Risk Factor = Lower] [Time Horizon = Operations Assessment]
2.1. The performance of a combined cycle facility will be determined using an
expected performance droop of 5.78%.
2.2. The calculation results shall be submitted to the Compliance Enforcement
Authority and made available to the Generator Owner by the end of the month
in which they were completed.
2.3. If a generating unit/generating facility has not participated in a minimum of (8)
eight FMEs in a 12-month period, its performance shall be based on a rolling
eight FME average response.
M2. The Balancing Authority shall have evidence it calculated and reported the rolling
average initial and sustained Primary Frequency Response performance of each
generating unit/generating facility monthly as required in Requirement R2.
The Primary Frequency Response Reference Document contains the calculations that the Balancing Authority will
use to determine Primary Frequency Response performance of generating units/generating facilities. This
reference document is a Texas RE-controlled document that is subject to revision by the Texas RE Board of
Directors.

1

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

R3. The Balancing Authority shall determine the Interconnection minimum Frequency
Response (IMFR) in December of each year for the following year, and make the IMFR,
the methodology for calculation and the criteria for determination of the IMFR
publicly available. [Violation Risk Factor = Lower] [Time Horizon = Operations
Planning]
M3. The Balancing Authority shall demonstrate that the IMFR was determined in
December of each year per per Requirement R3. The Balancing Authority shall
demonstrate that the IMFR, the methodology for calculation and the criteria for
determination of the IMFR are publicly available.
R4. After each calendar month in which one or more FMEs occurs, the Balancing Authority
shall determine and make publicly available the Interconnection’s combined
Frequency Response performance for a rolling average of the last six (6) FMEs by the
end of the following calendar month. [Violation Risk Factor = Medium] [Time Horizon
= Operations Planning]
M4. The Balancing Authority shall provide evidence that the rolling average of the
Interconnection’s combined Frequency Response performance for the last six (6) FMEs
was calculated and made public per Requirement R4.
R5. Following any FME that causes the Interconnection’s six-FME rolling average
combined Frequency Response performance to be less than the IMFR, the Balancing
Authority shall direct any necessary actions to improve Frequency Response, which
may include, but are not limited to, directing adjustment of Governor deadband
and/or droop settings. [Violation Risk Factor = Medium] [Time Horizon = Operations
Planning]
M5. The Balancing Authority shall provide evidence that actions were taken to improve the
Interconnection’s Frequency Response if the Interconnection’s six-FME rolling average
combined Frequency Response performance was less than the IMFR, per Requirement
R5.

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R6. Each Generator Owner shall set its Governor parameters as follows:
6.1. Limit Governor deadbands within those listed in Table 6.1, unless directed
otherwise by the Balancing Authority.
Table 6.1 Governor Deadband Settings
Generator Type
Steam and Hydro Turbines with
Mechanical Governors
All Other Generating
Units/Generating Facilities*

Max. Deadband
+/- 0.034 Hz
+/- 0.017 Hz

6.2. Limit Governor droop settings such that they do not exceed those listed in
Table 6.2, unless directed otherwise by the Balancing Authority.
Table 6.2 Governor Droop Settings
Generator Type

combined

Max. Droop %
Setting

Hydro
Combustion Turbine (Simple Cycle and SingleShaft Combined Cycle)
Combustion Turbine (Combined Cycle)
Steam Turbine*
Diesel

5%
5%

DC Tie Providing Ancillary Services
Variable Renewable (Non-Hydro)

5%
5%

4%
5%
5%

*
*Requirements R6.1, R6.2, and R6.3 are not applicable to steam turbine(s) of a
cycle resource.

6.3. For digital and electronic Governors, once frequency deviation has exceeded the
Governor deadband from 60.000 Hz, the Governor setting shall follow the slope
derived from the formula below.
Where

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

MWGCS is the maximum megawatt control range of the Governor control
system. For mechanical Governors, droop will be proportional from the
deadband by design. [Violation Risk Factor = Medium] [Time Horizon =
Operations Planning]
M6. Each Generator Owner shall have evidence that it set its Governor parameters in
accordance with Requirement R6. Examples of evidence include but are not limited to:
 Governor test reports
 Governor setting sheets
 Performance monitoring reports
R7. Each Generator Owner shall operate each generating unit/generating facility that is
connected to the interconnected transmission system with the Governor in service
and responsive to frequency when the generating unit/generating facility is online and
released for dispatch, unless the Generator Owner has a valid reason for operating
with the Governor not in service and the Generator Operator has been notified that
the Governor is not in service. [Violation Risk Factor = Medium] [Time Horizon = Realtime Operations]
M7. Each Generator Owner shall have evidence that it notified the Generator Operator as
soon as practical each time it discovered a Governor not in service when the
generating unit/generating facility was online and released for dispatch. Evidence may
include but not be limited to: operator logs, voice logs, or electronic communications.
R8. Each Generator Operator shall notify the Balancing Authority as soon as practical but
within 30 minutes of the discovery of a status change (in service, out of service) of a
Governor. [Violation Risk Factor = Medium][Time Horizon = Real-time Operations]
M8. Each Generator Operator shall have evidence that it notified the Balancing Authority
within 30 minutes of each discovery of a status change (in service, out of service) of a
Governor.
R9. Each Generator Owner shall meet a minimum 12-month rolling average initial Primary
Frequency Response performance of 0.75 on each generating unit/generating facility,
based on participation in at least eight FMEs.
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9.1. The initial Primary Frequency Response performance shall be the ratio of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response during the initial measurement period following the FME.
9.2. If a generating unit/generating facility has not participated in a minimum of eight
FMEs in a 12-month period, performance shall be based on a rolling eight-FME
average.
9.3. A generating unit/generating facility’s initial Primary Frequency Response
performance during an FME may be excluded from the rolling average
calculation by the Balancing Authority due to a legitimate operating condition
that prevented normal Primary Frequency Response performance. Examples of
legitimate operating conditions that may support exclusion of FMEs include, but
are not limited to:
•

Operation at or near auxiliary equipment operating limits (such as
boiler feed pumps, condensate pumps, pulverizers, and forced draft
fans);

•

Data telemetry failure. The Balancing Authority may request raw
data from the Generator Owner as a substitute.

[Violation Risk Factor = Medium] [Time Horizon = Operations Assessment]
M9. Each Generator Owner shall have evidence that each of its generating
units/generating facilities achieved a minimum rolling average of initial Primary
Frequency Response performance level of at least 0.75 as described in Requirement
R9. Each Generator Owner shall have documented evidence of any FMEs where the
generating unit performance was excluded from the rolling average calculation.
R10. Each Generator Owner shall meet a minimum 12-month rolling average sustained
Primary Frequency Response performance of 0.75 on each generating unit/generating
facility, based on participation in at least eight FMEs. [Violation Risk Factor = Medium]
[Time Horizon = Operations Assessment]
10.1. The sustained Primary Frequency Response performance shall be the ratio of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response during the sustained measurement period following the FME.
10.2. If a generating unit/generating facility has not participated in a minimum of eight
FMEs in a 12-month period, performance shall be based on a rolling eight- FME
average.
10.3. A generating unit/generating facility’s sustained Primary Frequency Response
performance during an FME may be excluded from the rolling average
calculation by the Balancing Authority due to a legitimate operating condition
that prevented normal Primary Frequency Response performance. Examples of
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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

legitimate operating conditions that may support exclusion of FMEs include, ,
but are not limited to:
• Operation at or near auxiliary equipment operating limits (such as boiler
feed pumps, condensate pumps, pulverizers, and forced draft fans);
•

Data telemetry failure. The Balancing Authority may request raw
data from the Generator Owner as a substitute.

M10. Each Generator Owner shall have evidence that each of its generating
units/generating facilities achieved a minimum rolling average of sustained Primary
Frequency Response performance of at least 0.75 as described in Requirement R10.
Each Generator Owner shall have documented evidence of any Frequency Measurable
Events where generating unit performance was excluded from the rolling average
calculation.

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means
NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Compliance Monitoring Period and Reset Time Frame: If a generating
unit/generating facility completes a mitigation plan and implements corrective
action(s) to meet requirements R9 and R10 of the standard, and if approved by
the BA and Compliance Enforcement Authority, then the generating
unit/generating facility may begin a new rolling event average performance on
the next performance during an FME. This will count as the first event in the
performance calculation and the entity will have an average frequency
performance score after 12 successive months or eight events per R9 and R10.
1.3. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
The Balancing Authority, Generator Owner, and Generator Operator shall keep
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data or evidence to show compliance, as identified below, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation:
•

The Balancing Authority shall retain a list of identified FMEs and shall
retain FME information since its last compliance audit for Requirement R1,
Measure M1.

•

The Balancing Authority shall retain all monthly PFR performance
reports since its last compliance audit for Requirement R2, Measure M2.

•

The Balancing Authority shall retain all annual IMFR calculations, and
related methodology and criteria documents, relating to time periods since
its last compliance audit for Requirement R3, Measure M3.

•

The Balancing Authority shall retain all data and calculations relating to the
Interconnection’s combined Frequency Response performance, and all
evidence of actions taken to increase the Interconnection’s combined
Frequency Response performance, since its last compliance audit for
Requirements R4 and R5, Measures M4 and M5.

•

Each Generator Operator shall retain evidence since its last compliance
audit for Requirement R8, Measure M8.

•

Each Generator Owner shall retain evidence since its last compliance audit
for Requirements R6, R7, R9 and R10, Measures M6, M7, M9 and M10.

If an entity is found non-compliant, it shall retain information related to the
non- compliance until found compliant, or for the duration specified above,
whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent records.
Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Violation Severity Levels
Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R1.

The Balancing Authority
reported an FME more than
14 days but less than 31 days
after identification of the
event.

The Balancing Authority
reported an FME more than
30 days but less than 51 days
after identification of the
event.

The Balancing Authority
reported an FME more than
50 days but less than 71 days
after identification of the
event.

The Balancing Authority
reported an FME more than
70 days after identification
of the event.

R2.

The Balancing Authority
submitted a monthly report
more than one month but
less than 51 days after the
end of the reporting month.

The Balancing Authority
submitted a monthly report
more than 50 days but less
than 71 days after the end of
the reporting month.

The Balancing Authority
submitted a monthly report
more than 70 days but less
than 91 days after the end of
the reporting month.

The Balancing Authority
failed to submit a monthly
report within 90 days after
the end of the reporting
month.

R3.

The Balancing Authority did
The Balancing Authority did
not make the calculation and not make the IMFR publicly
criteria for determination of available.
the IMFR publicly available.

The Balancing Authority did
not calculate the IMFR for
the following year in
December.

The Balancing Authority did
not calculate the IMFR for a
calendar year.

R4.

N/A

The Balancing Authority did
not make public the six-FME
rolling average
Interconnection combined
Frequency Response by the
end of the following month.

R5.

N/A

N/A

N/A

N/A

The Balancing Authority did not
calculate the six-

FME rolling average
Interconnection combined
Frequency Response for any
month in which an FME
occurred.
The Balancing Authority did
not take action to improve
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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Frequency Response when
the Interconnection’s rollingaverage combined
Frequency Response
performance was less than
the IMFR.
R6.

Any Governor parameter
setting was > 40% outside
setting range specified in R6,
– OR –

Any Governor parameter
setting was > 10% and ≤ 20%
outside setting range
specified in R6.

Any Governor parameter
setting was > 20% and ≤ 30%
outside setting range
specified in R6.

Any Governor parameter
setting was > 30% and ≤ 40%
outside setting range
specified in R6.

R7.

N/A

N/A

N/A

The Generator Owner
operated with its Governor
out of service and did not
notify the Generator
Operator upon discovery of
its Governor out of service.

R8

The Generator Operator
notified the Balancing
Authority of a change in
Governor status between 31
minutes and one hour after
the General Operator was
notified of the discovery of
the change.

The General Operator
notified the Balancing
Authority of a change in
Governor status more than 1
hour but within 4 hours after
the Generator Operator was
notified of the discovery of
the change.

The Generator Operator
notified the Balancing
Authority of a change in
Governor status more than 4
hours but within 24 hours
after the Generator
Operator was notified of the
discovery of the change.

The Generator Operator
failed to notify the Balancing
Authority of a change in
Governor status within 24
hours after the Generator
Operator was notified of the
discovery of the change.

an electronic or digital
Governor was set to step
into the droop curve.

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

R9

A Generator Owner’s rolling
average initial Primary
Frequency Response
performance per R9 was <
0.75 and ≥ 0.65.

A Generator Owner’s rolling
average initial Primary
Frequency Response
performance per R9 was <
0.65 and ≥ 0.55.

A Generator Owner’s rolling
average initial Primary
Frequency Response
performance per R9 was <
0.55 and ≥ 0.45.

A Generator Owner’s rolling
average initial Primary
Frequency Response
performance per R9 was <
0.45.

R10

A Generator Owner’s rolling
average sustained Primary
Frequency Response
performance per R10 was <
0.75 and ≥ 0.65.

A Generator Owner’s rolling
average sustained Primary
Frequency Response
performance per R10 was <
0.65 and ≥ 0.55.

A Generator Owner’s rolling
average sustained Primary
Frequency Response
performance per R10 was <
0.55 and ≥ 0.45.

A Generator Owner’s rolling
average sustained Primary
Frequency Response
performance per R10 was <
0.45.

D. Regional Variances
None

E. Associated Documents

Regional Standard BAL-001-TRE-2 Implementation Plan

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Version History
Version

Date

Action

1

8/15/2013

Adopted by NERC Board of Trustees

1

1/16/2014

FERC Order issued approving BAL-001-TRE-1.
(Order becomes effective April 1, 2014.)

2

12/11/2019

Approved by Texas RE Board of Directors

Change
Tracking

Removed the
requirement
Governor droop
and deadband
settings for
Steam Turbine(s)
of combined
cycle resources.
Edited
Requirements
R9.3 and R10.3
to reflect the
current process
and legitimate
operating
conditions for
submitting an
FME exclusion
request.
Removed
Attachment 1,
which is the
implementation
plan for Regional
Standard BAL-001TRE-1.

2

2/6/2020

Adopted by the NERC Board of Trustees

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Standard Attachments
1. Attachment 1 – Primary Frequency Response Reference Document, including Flow Charts A and B.
a.

This document provides implementation details for calculating Primary Frequency Response
performance as required by Requirements R2, R9 and R10. This reference document is a Texas REcontrolled document that is subject to revision by the Texas RE Board of Directors. It is not part of
the FERC-approved regional standard.

b.

The following process will be used to revise the Primary Frequency Response Reference Document.
A Primary Frequency Response Reference Document revision request may be submitted to the
Texas RE Reliability Standards Manager, who will present the revision request to the Texas RE
Member Representatives Committee (MRC) for consideration. The revision request will be posted
in accordance with MRC procedures. The MRC shall discuss the revision request in a public
meeting, and will accept and consider verbal and written comments pertaining to the request. The
MRC will make a recommendation to the Texas RE Board of Directors, which may adopt the
revision request, reject it, or adopt it with modifications. Any approved revision to the Primary
Frequency Response Reference Document shall be filed with NERC and FERC for informational
purposes.

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Attachment 1

Primary Frequency Response Reference Document
Texas Reliability Entity, Inc.
BAL-001-TRE-2
Requirements R2, R9, and R10
Performance Metric Calculations

I. Introduction
This Primary Frequency Response Reference Document provides a methodology for determining the
Primary Frequency Response (PFR) performance of individual generating units/generating facilities
following Frequency Measurable Events (FMEs) in accordance with Requirements R2, R9 and R10.
Flowcharts in Attachment A (Initial PFR) and Attachment B (Sustained PFR) show the logic and
calculations in graphical form, and they are considered part of this Primary Frequency Response
Reference Document. Several Excel spreadsheets implementing the calculations described herein for
various types of generating units are available 1 for reference and use in understanding and performing
these calculations.
This Primary Frequency Response Reference Document is not considered to be a part of the regional
standard. This document is maintained by Texas RE and subject to modifications as approved by the
Texas RE Board of Directors, without being required to go through the formal Standard Development
Process.
Revision Process: The following process will be used to revise the Primary Frequency Response
Reference Document. A Primary Frequency Response Reference Document revision request may be
submitted to the Texas RE Reliability Standards Manager, who will present the revision request to the
Texas RE Member Representatives Committee (MRC) for consideration. The MRC shall discuss the
revision request in a public meeting, and will accept and consider verbal and written comments pertaining
to the request. The MRC will make a recommendation to the Texas RE Board of Directors, which may
adopt the revision request, reject it, or adopt it with modifications. Any approved revision to the Primary
Frequency Response Reference Document shall be filed with NERC and FERC for informational
purposes.
As used in this document the following terms are defined as shown:
High Sustained Limit (HSL) for a generating unit/generating facility: The limit established by
the GO/GOP, continuously updatable in Real‐Time, that describes the maximum sustained
energy production capability of a generating unit/generating facility.
Low Sustained Limit (LSL) for a generating unit/generating facility: The limit established by
the GO/GOP, continuously updatable in Real‐Time, that describes the minimum sustained
energy production capability of a generating unit/generating facility.
In this regional standard, the term “resource” is synonymous with “generating unit/generating facility”.
1

These spreadsheets are available at www.TexasRE.org.

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

II. Initial Primary Frequency Response Calculations
Requirement 9
R9.

Each Generator Owner shall meet a minimum 12‐month rolling average initial Primary
Frequency Response performance of 0.75 on each generating unit/generating facility,
based on participation in at least eight FMEs.
9.1. The initial Primary Frequency Response performance shall be the ratio of the Actual
Primary Frequency Response to the Expected Primary Frequency Response during the
initial measurement period following the FME.
9.2. If a generating unit/generating facility has not participated in a minimum of eight FMEs in a
12‐month period, performance shall be based on a rolling eight FME average response.
9.3. A generating unit/generating facility’s initial Primary Frequency Response performance
during an FME may be excluded by the Balancing Authority from the rolling average
calculation due to a legitimate operating condition that prevented normal Primary
Frequency Response performance. Examples of legitimate operating conditions that
may support exclusion of FMEs include, but are not limited to:
•

Operation at or near auxiliary equipment operating limits (such as boiler
feed pumps, condensate pumps, pulverizers, and forced draft fans);

•

Data telemetry failure. The Balancing Authority may request raw data from
the Generator Owner as a substitute.

Initial Primary Frequency Response Performance Calculation Methodology
This portion of this PFR Reference Document establishes the process used to calculate initial Primary
Frequency Response performance for each Frequency Measurable Event (FME), and then average the
events over a 12-month period (or 8-event minimum) to establish whether a resource is compliant with
Requirement R9.
This process calculates the initial Per Unit Primary Frequency Response of a resource [P.U.PFRResource]
as a ratio between the Adjusted Actual Primary Frequency Response (APFRAdj),adjusted for the pre‐
event ramping of the unit, and the Final Expected Primary Frequency Response (EPFRfinal) as
calculated using the Pre‐perturbation and Post‐perturbation time periods of the initial measure.
This comparison of actual performance to a calculated target value establishes, for each type of
resource, the initial Per Unit Primary Frequency Response [P.U.PFRResource] for any Frequency
Measurable Event (FME).

Initial Primary Frequency Response performance requirement

Where P.U.PFRResourceis the per unit measure of the initial Primary Frequency Response of a resource
during identified FMEs.
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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

P.U.PFRResource =

Actual Pr imary Frequency Re sponseAdj
Expected Pr imary Frequency Re sponsefinal

Where P.U.PFRResource for each FME is limited to values between 0.0 and 2.0.

The Adjusted Actual Primary Frequency Response (APFRAdj) and the Final Expected Primary
Frequency Response (EPFRfinal) are calculated as described below.
EPFR Calculations use droop and deadband values as stated in Requirement R6 with the exception of
combined‐cycle facilities while being evaluated as a single resource (MW production of both the
combustion turbine generator and the steam turbine generator are included in the evaluation) where the
evaluation droop will be 5.78%. 2

Actual Primary Frequency Response (APFRadj)
The adjusted Actual Primary Frequency Response (APFRadj) is the difference between Post‐
perturbation Average MW and Pre‐perturbation Average MW, including the ramp magnitude
adjustment.

Where:
Pre‐perturbation Average MW: Actual MW averaged from T‐16 to T‐2

∑
=

T −2

MWpre − perturbation

T −16

MW

# Scans

Post‐perturbation Average MW: Actual MW averaged from T+20 to T+52

∑
=

T + 52

MWpost − perturbation

T + 20

MW

# Scans

2

The effective droop of a typical combined‐cycle facility with governor settings per Requirement R6 is 5.78%,
assuming a 2‐to‐1 ratio between combustion turbine capacity and steam turbine capacity. Use 5.78% effective droop
in all combined‐cycle performance calculations.

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Ramp Adjustment: The Actual Primary Frequency Response number that is used to calculate P.U.PFR
is adjusted for the ramp magnitude of the generating unit/generating facility during the pre‐perturbation
minute. The ramp magnitude is subtracted from the APFR.
Ramp Magnitude = (MWT‐4 – MWT‐60)*0.59
(MWT‐4 – MWT‐60) represents the MW ramp of the generator resource/generator facility for
a full minute prior to the event. The factor 0.59 adjusts this full minute ramp to represent
the ramp that should have been achieved during the post‐perturbation measurement
period.

Expected Primary Frequency Response (EPFR)
For all generator types, the ideal Expected Primary Frequency Response (EPFRideal) is calculated as the
difference between the EPFRpost‐perturbation and the EPFRpre‐perturbation.

When the frequency is outside the Governor deadband and above 60Hz:

When the frequency is outside the Governor deadband and below 60Hz:

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

For each formula, when frequency is within the Governor deadband the appropriate EPFR value is
zero. The deadbandmax and droopmax quantities come from Requirement R6.
Where:
Pre‐perturbation Average Hz: Actual Hz averaged from T‐16 to T‐2

∑
=

T −2

Hzpre − perturbation

T −16

Hz

# Scans

Post‐perturbation Average Hz: Actual Hz averaged from T+20 to T+52

∑
=

T + 52

Hzpost − perturbation

T + 20

Hz

# Scans

Capacity and NDC (Net Dependable Capacity) are used interchangeably and the term Capacity
will be used in this document. Capacity is the official reported seasonal capacity of the generating
unit/generating facility. The Capacity for wind‐powered generators is the real time HSL of the wind
plant at the time the FME occurred.
Power Augmentation: For Combined Cycle facilities, Capacity is adjusted by subtracting power
augmentation (PA) capacity, if any, from the HSL. Other generator types may also have power
augmentation that is not frequency responsive. This could be “over‐pressure” operation of a steam
turbine at valves wide open or operating with a secondary fuel in service. The GO should provide the
BA with documentation and conditions when power augmentation is to be considered in PFR
calculations.
EPFRfinal for Combustion Turbines and Combined Cycle Facilities

Note: The 0.00276 constant is the MW/0.1 Hz change per MW of Capacity and represents the MW
change in generator output due to the change in mass flow through the combustion turbine due to
the speed change of the turbine during the post‐perturbation measurement period. This factor is
based on empirical data from a major 2003 event as measured on multiple combustion turbines in
ERCOT.
EPFRfinal for Steam Turbine

Where:
Page 18 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Where:

Throttle Pressure = Interpolation of Pressure curve at MWpre‐perturbation
The Rated Throttle Pressure and the Pressure curve, based on generator MW output, are provided by the
GO to the BA. This pressure curve is defined by up to six pair of Pressure and MW breakpoints where the
Rated Throttle Pressure and MW output, where Rated Throttle Pressure is achieved, is the first pair and
the Minimum Throttle Pressure and MW output, where the Minimum Throttle Pressure is achieved, as the
last pair of breakpoints. If fewer breakpoints are needed, the pair values will be repeated to complete the
six pair table.
The K factor is used to model the stored energy available to the resource. The value ranges between 0.0
and 0.6 psig per MW change when responding during a FME. The GO can measure the drop in throttle
pressure when the resource is operating near 50% output of the steam turbine during a FME and provide
this ratio of pressure change to the BA. K is then adjusted based on rated throttle pressure and resource
capacity. An additional sensitivity factor, the Steam Flow Change Factor, is based on resource loading (%
steam flow) and further modifies the MW adjustment. This sensitivity factor will decrease the adjustment at
resource outputs below 50% and increase the adjustment at outputs above 50%. The GO should
determine the fixed K factor for each resource that generally results in the best match between EPFR and
APFR (resulting in the highest P.U.PFRResource). For any generating unit, K will not change unless the
steam generator is significantly reconfigured.
EPFRfinal for Other Generating Units/Generating Facilities

Where X is an adjustment factor that may be applied to properly model the delivery of PFR. The X
factor will be based on known and accepted technical or physical limitations of the resource. X may
be adjusted by the BA and may be variable across the operating range of a resource. X shall be
zero unless the BA accepts an alternative value.

Page 19 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

III. Sustained Primary Frequency Response Calculations
Requirement 10
R10.

The Generator Owner shall meet a minimum 12‐month rolling average sustained Primary
Frequency Response performance of 0.75 on each generating unit/generating facility, based on
participation in at least eight FMEs.
10.1 The sustained Primary Frequency Response performance shall be the ratio of the
Actual Primary Frequency Response to the Expected Primary Frequency Response
during the sustained measurement period following the FME.
10.2 If a generating unit/generating facility has not participated in a minimum of eight FMEs in a
12‐month period, performance shall be based on a rolling eight‐FME average.
10.3 A generating unit/generating facility’s sustained Primary Frequency Response performance
during an FME may be excluded by the Balancing Authority from the rolling average
calculation due to a legitimate operating condition that prevented normal Primary
Frequency Response performance. Examples of legitimate operating conditions that may
support exclusion of FMEs include, but are not limited to:
• Operation at or near auxiliary equipment operating limits (such as boiler feed
pumps, condensate pumps, pulverizers, and forced draft fans);
•

Data telemetry failure. The Balancing Authority may request raw data from the
Generator Owner as a substitute.

Sustained Primary Frequency Response Performance Calculation Methodology
This portion of this PFR Reference Document establishes the process used to calculate sustained Primary
Frequency Response performance for each Frequency Measurable Event (FME), and then average the
events over a 12-month period (or 8-event minimum) to establish whether a resource is compliant with
Requirement R10.
This process calculates the Per Unit Sustained Primary Frequency Response of a resource
[P.U.SPFRResource] as a ratio between the maximum actual unit response at any time during the period
from T+46 to T+60, adjusted for the pre‐event ramping of the unit, and the Final Expected Primary
Frequency Response (EPFR) value at time T+46. 3

This comparison of actual performance to a calculated target value establishes, for each type of
resource, the Per Unit Sustained Primary Frequency Response [P.U.SPFRResource] for any Frequency
Measurable Event (FME).
Sustained Primary Frequency Response performance requirement:
The standard requires an average performance over a period of 12 months (including at least 8
measured events) that is ≥ 0.75.

3

The time designations used in this section refer to relative time after an FME occurs. For example, “T+46” refers to
46 seconds after the frequency deviation occurred.

Page 20 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

•
•

the average of each resource’s sustained Primary Frequency Response performances
[P.U.SPFRResource] during all of the assessable Frequency Measurable Events (FMEs), for
the most recent rolling 12 month period; or
if the unit has not experienced at least 8 assessable FMEs in the most recent 12 month
period, the average of the unit’s last 8 sustained Primary Frequency Response
performances when the unit provided frequency response during a Frequency Measurable
Event.

Sustained Primary Frequency Response Calculation (P.U.SPFR)

P.U.PFRResource =

Actual Sustained Primary Frequency ResponseAdj
Expected Sustained Primary Frequency Responsefinal

P.U.SPFRResource is the per unit (P.U.) measure of the sustained Primary Frequency Response of a
resource during identified Frequency Measurable Events. For any given event P.U.SPFRResource for each
FME will be limited to values between 0.0 and 2.0.
Actual Sustained Primary Frequency Response (ASPFR) Calculations

Where:
Pre‐perturbation Average MW: Actual MW averaged from T‐16 to T‐2.

∑
=

T −2

MWpre − perturbation

T −16

MW

# Scans

And:
MWMaximumResponse = maximum MW value telemetered by a unit from T+46 through T+60 during low
frequency events and the minimum MW value telemetered by a unit from T+46 through T+60 during a
high frequency event.
Actual Sustained Primary Frequency Response, Adjusted (ASPFRAdj)

Page 21 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

RampMW Sustained (MW) – The Standard requires a unit/facility to sustain its response to a Frequency
Measureable Event. An adjustment available in determining a unit’s sustained Primary Frequency
Response performance (P.U.SPFRResource ) is to account for the direction in which a resource was moving
(increasing or decreasing output) when the event occurred T=t(0). This is the RampMW Sustained
adjustment:
RampMW Sustained = (MWT‐4 – MWT‐60) x 0.821
Note: The terminology “MWT‐4” refers to MW output at 4 seconds before the Frequency
Measurable Event (FME) occurs at T=t(0).
By subtracting a reading at 4 seconds before, from a reading at 60 seconds before, the formula
calculates the MWs a generator moved in the minute (56 seconds) prior to T=t(0). The formula is
then modified by a factor to indicate where the generator would have been at T+46, had the event
not occurred: the “RampMW Sustained.” It does this by multiplying the MW change over 56
seconds before the event (MWT‐4 – MWT‐60) by a modifier. This extrapolates to an equivalent
number of MWs the generator would have changed if it had been allowed to continue on its ramp
to T+46 unencumbered by the FME. The modifier is

Expected Sustained Primary Frequency Response (ESPFR) Calculations
The Expected Sustained Primary Frequency Response (ESPFRfinal) is calculated using the actual
frequency at T+46, HZT+46.
This ESPFRfinal is the MW value a unit should have responded with if it is properly sustaining the output of
its generating unit/generating facility in response to an FME. Determination of this value begins with
establishing where it would be in an ideal situation; considers proper droop and dead‐band values
established in Requirement R6, High Sustainable Limit (HSL), Low Sustainable Limit (LSL) and actual
frequency. It then allows for adjusting the value to compensate for the various types of Limiting Factors
each generating units / generating facilities may have and any Power Augmentation Capacity (PA
Capacity) that may be included in the HSL/LSL.

Establishing the Ideal Expected Sustained Primary Frequency Response
For all generator types, the ideal Expected Sustained Primary Frequency Response (ESPFRideal) is
calculated as the difference between the ESPFRT+46 and the EPFRpre‐perturbation. The EPFRpre‐perturbation is the
same EPFRpre-perturbation value used in the Initial measure of R9.

When the frequency is outside the Governor deadband and above 60Hz:

 (HZT + 46 − 60 − deadband max )

ESPFRT + 46 = 
× (HSL − PA Capacity ) × (− 1)
 (droop max× 60 − deadband max )

Page 22 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

When the frequency is outside the Governor deadband and below 60Hz:

 (HZT + 46 − 60 + deadband max )

ESPFRT + 46 = 
× (HSL − PA Capacity ) × (− 1)
 (droop max× 60 − deadband max )

Capacity and Net Dependable Capability (NDC) are used interchangeably and the term Capacity will be
used in this document. Capacity is the official reported seasonal capacity of the generating unit/generating
facility. The capacity for wind‐powered generators is the real‐time HSL of the wind plant at the time the
FME occurred. The deadbandmax and droopmax quantities come from Requirement R6.

For Combined Cycle facilities, determination of Capacity includes subtracting Power Augmentation (PA)
Capacity, if any, from the original HSL. Other generator types may also have Power Augmentation that is
not frequency responsive. This could be “over‐pressure” operation of a steam turbine at valves wide open
or operating with a secondary fuel in service. The GO is required to provide the BA with documentation
and identify conditions when this augmentation is in service.
ESPFRfinal for Combustion Turbines and Combined Cycle Facilities

ESPFR final = ESPFRIdeal + ( HZT + 46 − 60) *10 * 0.00276 * ( HSL − PACapacity )
Note: The 0.00276 constant is the MW/0.1 Hz change per MW of Capacity and represents the
MW change in generator output due to the change in mass flow through the combustion turbine
due to the speed change of the turbine at HZT+46. (This is based on empirical data from a major

2003 event as measured on multiple combustion turbines in ERCOT.)
ESPFRfinal for Steam Turbine

Where:

MWAdj = ESPFRideal ×

K
× ( HSL − PACapacity ) × Steam Flow Change Factor × ( −1)
Rated Throttle Pressure

Where:

Throttle Pressure = Interpolation of Pressure curve at MWpre‐perturbation

Page 23 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

The Rated Throttle Pressure and the Pressure curve, based on generator MW output, are
provided by the GO to the BA. This pressure curve is defined by up to six pair of Pressure and
MW breakpoints where the Rated Throttle Pressure and MW output where Rated Throttle
Pressure is achieved is the first pair and the Minimum Throttle Pressure and MW output where
the Minimum Throttle Pressure is achieved as the last pair of breakpoints. If fewer breakpoints
are needed, the pair values will be repeated to complete the six pair table.
The K factor is used to model the stored energy available to the resource and ranges between 0.0
and 0.6 psig per MW change when responding during a FME. The GO can measure the drop in
throttle pressure, when the resource is operating near 50% output of the steam turbine during a
FME and provide this ratio of pressure change to the BA. K is then adjusted based on rated throttle
pressure and resource capacity. An additional sensitivity factor, the Steam Flow Change Factor, is
based on resource loading (% steam flow) and further modifies the MW adjustment. This sensitivity
factor will decrease the adjustment at resource outputs below 50% and increase the adjustment at
outputs above 50%. The GO should determine the fixed K factor for each resource that generally
results in the best match between ESPFR and ASPFR (resulting in the highest P.U.SPFRResource).
For any generating unit, K will not change unless the steam generator is significantly reconfigured.
ESPFRfinal for Other Generating Units/Generating Facilities

ESPFR final = ESPFRIdeal + X
Where X is an adjustment factor that may be applied to properly model the delivery of PFR. The X
factor will be based on known and accepted technical or physical limitations of the resource. X may
be adjusted by the BA and may be variable across the operating range of a resource. X shall be
zero unless the BA accepts an alternative value.
IV. Limits on Calculation of Primary Frequency Response Performance (Initial and Sustained):
If the generating unit/generating facility is operating within 2% of its (HSL – PA Capacity) or within 5 MW
(whichever is greater) from its applicable operating limit (high or low) at the time an FME occurs (pre‐
perturbation), then that resource’s Primary Frequency Response performance is not evaluated for that
FME.
For frequency deviations below 60 Hz (HzPost‐perturbation < 60 if:

then Primary Frequency Response is not evaluated for this FME.
For frequency deviations above 60 Hz (HzPost‐perturbation > 60, if:

then Primary Frequency Response is not evaluated for this FME.
Final Expected Primary Frequency Response (EPFRfinal) is greater than Operating Margin:
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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Caps and limits exist for resources operating with adequate reserve margin to be evaluated (at least 2%
of (HSL less PA Capacity) or 5 MW), but with Expected Primary Frequency Responsefinal greater than the
actual margin available.
1. The P.U.PFRResource will be set to the greater of 0.75 or the calculated P.U.PFRResource if all of the
following conditions are met:
a. The generating unit/generating facility’s pre‐perturbation operating margin
(appropriate for the frequency deviation direction) is greater than 2% of its (HSL
less PA Capacity) and greater than 5 MW; and
b. The Expected Primary Frequency Responsefinal is greater than the generating
unit/generating facility’s available frequency responsive Capacity 4; and
c. The generating unit/generating facility’s APFRadj response is in the correct direction.
2. When calculation of the P.U.PFRResource uses the resource’s (HSL less PA Capacity) as the
maximum expected output, the calculated P.U.PFRResource will not be greater than 1.0.
3. When calculation of the P.U.PFRResource uses the resource’s LSL as the minimum expected output,
the calculated P.U.PFRResource will not be greater than 1.0.
4. If the APFRAdj is in the wrong direction, then P.U.PFRResource is 0.0.
5. These caps and limits apply to both the Initial and Sustained Primary Frequency Response
measures.

4

In this circumstance, when frequency is below 60 Hz, the EPFRfinal is set to operating margin based on HSL
(adjusted for any augmentation capacity) AND when frequency is above 60 Hz, the EPFRfinal is set to operating
margin based on LSL for the purpose of calculating PUPFRresource.

Page 25 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Attachment A to
Primary Frequency Response Reference Document

Initial Primary Frequency Response Methodology for
BAL-001-TRE-2

Page 26 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Primary Frequency Response Measurement and Rolling Average Calculation – Initial Response
PA=Power Augmentation
HSL=High Sustained Limit
Read Deadband, Droop, HSL, PA
Capacity, Frequency and Resource
MW and Resource MW

Calculate Ramp
Magnitude

Calculate Expected
Primary Frequency
Response
Calculate Actual
Primary Frequency
Response
Calculate P.U. Primary
Frequency Response

Calculate P.U. Primary
Frequency Response
Rolling Average

Is Rolling
Average ≥ 0.75

No
Fail R9

Yes
Pass R9

End

Page 27 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Pre/Post-Perturbation Average MW and Average Frequency Calculations

Read Actual MW &
Frequency

Calculate Pre-Perturbation average for MW and
Frequency

Calculate Post-Perturbation average for MW and
Frequency

End

Page 28 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Ramp Magnitude Calculation

Ramp Magnitude = (MWT-4 – MWT-60)*0.59

End

(MWT-4 – MWT-60) represents the MW ramp of the generator resource/generator facility for a full minute prior
to the event. The factor 0.59 adjusts this full minute ramp to represent the ramp that should have been
achieved during the post-perturbation measurement period.

Actual Primary Frequency Response (APFRAdj)

APFRAdj = MWpost-perturbation – MWpre-perturbation – Ramp Magnitude

End

Page 29 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Expected Primary Frequency Response Calculation
Use the maximum droop and maximum deadband as required by R6. For Combined Cycle Facility
evaluation as a single resource (includes MW production of the steam turbine generator), the EPFR will
use 5.78% droop in all calculations.

Read Deadband, Droop, HSL, PA
Capacity and HZpre-perturbation*

No

If (HZpre – perturbation < 60)

Yes

No

Yes

No

Yes

End

Page 30 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Read Deadband, Droop, HSL, PA
Capacity and HZpost-perturbation*

No

If (HZpost – perturbation < 60)

Yes

No

Yes

No

Y

End

Page 31 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Adjustment for Steam Turbine

Read K(Limiting Factor),
Throttle Pressure curve
breakpoints, HSL, MWpre-perturbation

Throttle Pressure = Interpolation of Pressure curve at MWpre-perturbation

End

Page 32 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Adjustment for Combustion Turbines and Combined Cycle Facilities

Read HSL, PA Capacity, HZpost-perturbation*

End

0.00276 is the MW/0.1 Hz change per MW of Capacity and represents the MW change in generator output
due to the change in mass flow through the combustion turbine due to the speed change of the turbine
during the post‐perturbation measurement period. (This factor is based on empirical data from a major
2003 event as measured on multiple combustion turbines in ERCOT.)

Adjustment for Other Units

Read Limiting Factor

End

Page 33 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

∑
=

T + 52

* HZ post − perturbation

T + 20

HZ Actual

# of Scans

This adjustment Factor X will be developed to properly model the delivery of PFR due to known and
approved technical limitations of the resource. X may be adjusted by the BA and may be variable across
the operating range of a resource.

Page 34 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

P.U. Initial Primary Frequency Response Calculation

Page 35 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

N

**

If Unit has
Headroom* AND
MWT+0 > LSL

Y
N

Y

N
If P.U.
PFR > 2.0
Y
N

P.U.PFR = 0

Y

P.U. PFR = 2.0
Note, EPFRfinal = Headroom

If P.U. PFR <
0.0

N

Y

If P.U. PFR < 0.75
Y

P.U.PFR = 0

P.U.PFR = 0.75

N

If P.U. PFR >
1.0

Y

P.U.PFR = 1.0

N
End

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

*Check for adequate up headroom, low frequency events. Headroom must be greater than either 5MW or
2% of (HSL less PA Capacity), whichever is larger. If a unit does not have adequate up headroom, the unit
is considered operating at full capacity and will not be evaluated for low frequency events.

Check for adequate down headroom, high frequency events. Headroom must be greater than either 5MW
or 2% of (HSL less PA Capacity), whichever is larger. If a unit does not have adequate down headroom,
the unit is considered operating at low capacity and will not be evaluated for high frequency events.

For low frequency events:

For high frequency events:

**No further evaluation is required for Sustained Primary Frequency Response. This event will not be
included in the Rolling Average calculation of either Initial or Sustained Primary Frequency Response.

T = Time in Seconds

Page 37 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Attachment B to
Primary Frequency Response Reference Document

Sustained Primary Frequency Response Methodology for
BAL-001-TRE-2

Page 38 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Primary Frequency Response Measurement and Rolling Average
Calculation–Sustained Response
Read Deadband, Droop,
HSL, PA Capacity, Frequency
and Resource

Calculate Ramp
Magnitude

Calculate Expected
Primary Frequency
Response
Calculate Actual
Primary

Calculate P.U.
Primary

Calculate P.U. Primary
Frequency Response
Rolling Average

Is Rolling
Average ≥
0.75

No
Fail R10

Yes
Pass R10

End

Page 39 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Pre/Post-Perturbation Average MW and Average Frequency Calculations

Read Actual MW &
Frequency

Calculate Pre-Perturbation average for MW and
Frequency

Calculate Post-Perturbation MW and Frequency at T+46

End

Page 40 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Ramp Magnitude Calculation - Sustained

End

(MWT-4 – MWT-60) represents the MW ramp of the generator resource/generator facility for a full minute prior
to the event. The factor 0.821 adjusts this full minute ramp to represent the ramp the generator would have
changed the system had it been allowed to continue on its ramp to T+46 unencumbered.

Actual Sustained Primary Frequency Response (ASPFRadj)

For low frequency events:

End

For high frequency events:

End

Expected Sustained Primary Frequency Response Calculation
Page 41 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Use the droop and deadband as required by R6. For Combined Cycle Facility evaluation as a single
resource (includes MW production of the steam turbine generator), the EPFR will use 5.78% droop in all
calculations.
Read Deadband, Droop, HSL, PA
Capacity and HZpre-perturbation*

No

If (HZpre – perturbation < 60)

Yes

No

Yes

No

Yes

End

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Read Deadband, Droop, HSL, PA
Capacity and HZpost-perturbation*

No

If (HZpost – perturbation < 60)

Yes

No

Yes

No

Yes

End

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Adjustment for Steam Turbine
Read K(Limiting Factor), Throttle
Pressure curve breakpoints, HSL,
MWpre-perturbation and MWpost-perturbation

Throttle Pressure = Interpolation of Pressure curve at MWpre-perturbation

End

Page 44 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Adjustment for Combustion Turbines and Combined Cycle Facilities

Read HSL, PA Capacity, HZpost-perturbation*

End

0.00276 is the MW/0.1 Hz change per MW of Capacity and represents the MW change in generator output
due to the change in mass flow through the combustion turbine due to the speed change of the turbine
during the post‐perturbation measurement period. (This factor is based on empirical data from a major
2003 event as measured on multiple combustion turbines in ERCOT.)

Adjustment for Other Units

Read Limiting Factor

End

* HZ Actual = HZ(T + 46)
Page 45 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

This adjustment Factor X will be developed to properly model the delivery of PFR due to known and
approved technical limitations of the resource. X may be adjusted by the BA and may be variable across
the operating range of a resource.

P.U. Sustained Primary Frequency Response Calculation

* HZ Actual = HZ(T + 46)

Page 46 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

**

N

If Unit has
Headroom* AND
MWT+0 > LSL

Y
N

Y

N
If P.U. SPFR
> 2.0

N

If P.U. SPFR
< 0.0

P.U.SPFR = 0

Y

Y

P.U. SPFR = 2.0

N

Note, EPFRfinal = Headroom

Y
If P.U. SPFR <
0.75

P.U.SPFR = 0

Y

P.U.SPFR = 0.75

N

End

N

If P.U. SPFR >
1.0

Y

P.U.SPFR = 1.0

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

*Check for adequate up headroom, low frequency events. Headroom must be greater than either 5MW or
2% of (HSL less PA Capacity), whichever is larger. If a unit does not have adequate up headroom, the unit
is considered operating at full capacity and will not be evaluated for low frequency events.

Check for adequate down headroom, high frequency events. Headroom must be greater than either 5MW
or 2% of (HSL less PA Capacity), whichever is larger. If a unit does not have adequate down headroom,
the unit is considered operating at low capacity and will not be evaluated for high frequency events.

For low frequency events:

For high frequency events:

**No further evaluation is required for Sustained Primary Frequency Response. This event will not be
included in the Rolling Average calculation of either Initial or Sustained Primary Frequency Response.

T = Time in Seconds

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BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

Revision History
Version
Date
1
7/25/2011

1.1

12/7/2012

1.1

3/6/2013

1.1

4/23/2013

1.1

9/18/2013

1.1
1.2

1/16/2014
5/21/2015

Action
Approved by SDT and submitted to
Texas RE RSC for approval to post
for regional ballot
Approved by SDT for submission to
Texas RE RSC for approval to post
for second regional ballot.

Texas RE RSC approves submittal
to Texas RE Board
Texas RE Board approves submittal
to NERC and FERC
NERC and Texas RE file Petition for
approval to FERC
Approved by FERC
Texas RE Board approves revisions
to Attachment 2 Primary Frequency
Response Reference Document

Change Tracking

Changed sustained measure from
average over event recovery period to
point at 46 seconds after FME, and other
changes to respond to field trial results,
comments, and corrections.

For clarification and consistency of the
equations used in the Attachment,
changes performed to:
- “T” in the equations refers to the
start of the Frequency
Measurable Event.
- “T-2” nomenclature utilized for
clarity rather than “t(-2)”
(applicable to numerous
equations)
- Removed floating x in EPFRfinal
for Steam Turbine equation
- Corrected sign convention for
Expected Sustained Primary
Frequency Response to match
the calculation for expected
primary frequency response.
Corrected Adjusted MW for
ESPFRfinal for Steam Turbine by
multiplying -1 to calculate proper
value.
- On Steam Flow Change Factor
removed floating x and reinserted
PA Capacity.
- Clarified Footnote 5 for scenario
of high frequency event for
setting LSL as operating margin
(similar to HSL for low frequency
events).
- Clarified in flowcharts for both
P.U. Initial Primary & Sustained
Page 49 of 50

BAL-001-TRE-2 — Primary Frequency Response in the ERCOT Region

-

1.3

11/14/2016

RSC approves minor changes to
Attachment 2 Primary Frequency
Response Reference Document

1.3

12/07/2016

Texas RE Board approves minor
changes to Attachment 2 Primary
Frequency Response Reference
Document.

2.0

12/11/2019

Texas RE Board approves changes
to the Attachment.

Frequency Response
Calculations:
o Unit needs to have
Headroom and be above
LSL to be scored.
o Cap EPFRfinal at value of
Headroom on unit
Per RSC 5/11/2015, all
references to “Final” were
changed to “final”.
Per RSC 5/11/2015, P.U.PFR
and P.U.S.PFR removed italics in
flowcharts.

Replaced Reliability Standards
Committee with Members
Representative Committee to conform
with changes to the Texas RE bylaws
and regional standards development
process.
Replaced Reliability Standards
Committee with Members
Representative Committee to conform
with changes to the Texas RE bylaws
and regional standards development
process.
Removed the requirement for Governor
droop and deadband settings for Steam
turbines of combined cycle resources.
Edited Requirements R9.3 and R10.3 to
reflect the current process for submitting
an exclusion request.
Removed Attachment 1, which is the
implementation plan for Regional
Standard BAL-001-TRE-1. Changed
numbering on Attachment 2 to
Attachment 1

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