Template: AEMO Generator Performance Standards (GPS)

Template version: v8

Country:

AU

Software required:

PSS®E

PSCAD™

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How to add this template to your project

1. From within your gridmo project, open the flow dropdown and select 'Add flow'.
2. Select the template you want to use and click 'Add to project'.

Background

The number and complexity of generation interconnections have increased during the energy transition. In an effort to ensure the adequate performance of generating systems and to ensure efficient design principles by utilising standards where possible, the AEMC established Technical Requirements in the National Electricity Rules. AEMO requires proponents to show compliance with these Technical Requirements (i.e. NER S5.2.5), as well as other requirements, and establish access standards - collectively referred to as "Generator Performance Standards (GPS)". This template includes a selection of tests to demonstrate compliance with these "Generator Performance Standards (GPS)".

Transition to new requirements

This template is based on the requirements of v234 of the National Electricity Rules in accordance with the Final Determination of AEMC Rule Change ERC0393, released on 22 May 2025. ERC0393 represents one of the most significant changes to Australian grid connection requirements since ERC0222 in 2018.

Click here for a summary of the new modelling requirements introduced in this rule change - and when to switch to the new requirements.

As shown in the image below, these new grid connection requirements become mandatory for all projects which haven't received a connection enquiry response by 21 August 2025. Projects which have received a connection enquiry response but have not yet received an offer to connect "may choose to apply some or all of the new access standards for their connection".

Reference

Common assumptions

• Generally, Automatic Access Standard (AAS) is assumed for all tests and Analysis Nodes within the template.
• By default, the template is configured for asynchronous generating systems.
• Some GPS tests require a PSS®E model of the NEM (colloquially known as an 'OPDMS snapshot' in the industry). We do not provide these snapshots. You will have to provide your own pre-tuned dynamic base cases for these tests.
• Network frequency dependency is by default disabled, but can be enabled if desired using Advanced Parameters
• For tests using a Thévenin equivalent source, the equivalent source is modelled with infinite inertia.
• For tests which are confirming parameters which only affect a final settled value (e.g. Q(V) droop characteristic parameters, P(f) droop characteristic parameters, and Iq(V) droop characteristic parameters), these are often conducted at infinite SCR to simplify the test methodology and interpretation of results. For tests which are confirming parameters which may affect transient dynamic performance (e.g. Kp gain for the Iq(V) response), these are conducted using site-specific SCR values. To learn more, visit Choosing test SCR.
• The majority of tests are only completed in the default reactive power control system mode (e.g. S5.2.5.4). Where a change in the reactive power control system mode is required, this change is made (e.g. S5.2.5.13).
• This template uses dedicated calculation plots to show commencement time, rise time, recovery time, settling time and similar calculations. Generally, there is a 'default' Plot Node which shows the typical channels, and a separate Plot Node which provides transparency into how each metric is calculated.
• Generating system performance can change depending on the specific initial operating conditions (e.g. plant starting at Qmin vs Qmax). There are technically an infinite number of potential initial operating conditions. By default, the following operating conditions are considered a comprehensive combination and this list, or a subset, is used for testing:
  • Active power: Pmin and Pmax
  • Reactive power: Qmin, Qnormal and Qmax
  • Grid strength: SCRmin and SCRmax

S5.2.4 Provision of information

The purpose of S5.2.4 is to outline the information which your project must provide to AEMO or the NSP. In particular, this includes the provision of PSS®E and PSCAD™ models of your generating system which meet the requirements of the AEMO | Power System Model Guidelines | Version 3.0 | 2025. We've included tests which assess some of these requirements.

Model initialisation

The purpose of this test is to check the initialisation time of your PSCAD™ model is in accordance with the requirements of the PSMG. Initialisation time is/isn't assessed for the following channels:

• Ppoc and Qpoc: Initialisation time is assessed because these quantities are directly controlled by the generation control system.
• Vpoc: Initialisation time is not assessed because this quantity is not directly controlled by the generation system.

Initialisation time can vary depending on the operating condition and control mode of the generating system. Therefore, a broad combination of variable conditions should be assessed, including:

• Active power: Pmin and Pmax
• Reactive power: Qmin, Qnormal and Qmax
• Voltage: V at Qmin, Vnormal and V at Qmax
• Grid strength: SCRmin and SCRmax
• Control mode: Voltage, Reactive power and Power factor

Assumption

• The Power System Model Guidelines (PSMG 4.3.5 and 4.3.6) require PSCAD™/EMTDC™ models to initialise within 3 seconds. However, they don't provide a methodology to calculate the initialisation time. We have assumed the definition of initialisation time is when Ppoc and Qpoc settle within a tolerance of ±2% of the project's rated active power. This 2% value was chosen to align with the steady state modelling accuracy requirements provided in Section 6.2.1(d)(i) in the Power System Model Guidelines - while acknowledging that this section is actually used for benchmarking site-data with simulation results.

The plot below shows an example of the initialisation time calculation. In this example, the initialisation time is non-compliant as the Qpoc settling time is greater than 3 seconds.

Pass criteria

• S5.2.4 - PSMG 4.3.5 and 4.3.6: Model initialisation time is within 3 seconds.
• S5.2.4 - PSMG 4.3.1: Once initialised, remain stable during the simulation.

S5.2.5.1 Reactive power capability

The purpose of S5.2.5.1 is to identify your generating system's reactive power capability while operating across a range of different conditions (e.g. active power outputs, connection point voltages and ambient temperatures).

This template creates a constrained reactive power capability curve. This means that all limiters are included and modelled (e.g. PPC limits, generating unit limits and excitation system limiters). It is a representation of the actual reactive power capability of the generating system as configured.

In contrast, an unconstrained capability curve is the raw generator capability without any external limitations. Creating an unconstrained reactive power capability curve using PSS®E and PSCAD™ is possible; however, due to model aggregation, it can often not align very well with the actual capability.

If you need to create an unconstrained capability curve, we recommend you use the DIgSILENT PowerFactory disaggregated model which is used for the S5.2.5.2 harmonic studies and using the PowerFactory built-in PQ capability curve macro. PowerFactory supports voltage dependent capability curves (unlike PSS®E's GCAP function) which is important for inverter based generation. Note that this macro creates a PQ capability curve across a range of voltages, whereas the constrained capability curve created in this template creates a VQ capability curve across a range of active powers.

Constrained VQ capability

By default, our AEMO GPS template only tests a selection of points over the S5.2.5.1 VQ capability curve. The generating system is initialised at the target value of Vpoc, Pmin and Qnormal - an operating condition known to be within the limits of the generating system. Then, the generating system is instructed to ramp to the following Ppoc and Qpoc points:

• Ppoc is ramped to either 0 or 1.2 [p.u.] of Pmax (i.e. values outside of the capability curve).
• Qpoc is ramped to 0, -0.5 or +0.5 [p.u.] (i.e. values outside of the typical 0.395 [p.u.] capability).

The values of Ppoc=1.2 [p.u.] and Qpoc=±0.5 [p.u.] are arbitrary values which are known to be beyond the generating system capability and will therefore cause the limiters (e.g. PPC limits, generating unit limits and excitation system limiters) to prevent the generating system from reaching the specified value. However, the plant will settle to a value which is at the limit of its capability - this is the constrained capability. The image below shows an example of this methodology, where the plant is initialised at Vpoc=0.9 [p.u.], Ppoc=0 [p.u.], Qpoc=0 [p.u.] - then ramped to Ppoc=1.2 [p.u.], Qpoc=+0.5 [p.u.] and the resultant constrained Qpoc value is observed.

As outlined in S5.2.5.1(a1), the generating system must meet the polygon requirements in the VQ capability curve, "at any level of active power". However, it is difficult to visualise on the VQ capability curve that the requirements are met at different active powers. You should therefore confirm via the time-series plots that the generating system did meet the expected active power levels for the range of values provided on the VQ capability curve.

Assumption

• Only steady state values are assessed and therefore tests are conducted at infinite SCR and X/R. To learn more, visit Choosing test SCR.

Visualising a VQ capability curve

The diagram below shows an example AAS VQ capability curve with a mid-point voltage of 1.0 [p.u.]. The purpose of this interactive diagram is to help visualise how the VQ curve relates to the PQ curve.

Drag to rotate

Plants electrically connected but not in service

In accordance with S5.2.5.1(a2) and S5.2.5.1(b2), plants which are electrically connected to the grid but not in service (i.e. not exporting active power), have requirements regarding how they can affect the connection point voltage. This may be relevant in the following situations:

• Solar farms which are operating in 'Q at night mode'.
• Wind farms which have reactive power compensation devices such as STATCOMs.
• Synchronous machines operating in 'synchronous condenser mode'.

To check compliance with these requirements, we have not included tests under the S5.2.5.1 section. Instead, we recommend creating a relevant scenario in your project using Scenario Variables and running the relevant tests from S5.2.5.13.

Pass criteria

• S5.2.5.1: Constrained operating points are on the VQ capability curve.

S5.2.5.2 Quality of electricity generated

The purpose of S5.2.5.2 is to confirm that your generating system's output does not exceed specified voltage fluctuation, harmonic voltage distortion and voltage unbalance limits. We don't currently provide tests for S5.2.5.2.

S5.2.5.3 Response to frequency disturbances

The purpose of S5.2.5.3 is to confirm the ability of your generating system to maintain continuous uninterrupted operation for a particular frequency operating standard. We've also included tests to confirm that some form of frequency protection exists and its behaviour is as expected.

Frequency ride-through

The diagram below is from the NER - S5.2.5.3 showing the most onerous frequency profile that generating systems must ride through according to the Automatic Access Standard.

This image refers to terms such as, "normal operating frequency band", "operational frequency tolerance band", and "extreme frequency excursion tolerance limits" whose values are provided in the AEMC | Frequency Operating Standard | Effective 9 October 2023. You must select the operating standard which is relevant to your generating system. The "System restoration - Mainland" option is chosen by default in the template because it represents the most difficult frequency ride-through disturbances for the majority of projects on the mainland. The frequency ride-through requirements for several common operating standards have been provided below. Copy and paste the chosen frequency operating standard into the PSS®E Dynamic and PSCAD™ Nodes SMIB frequency playback fields in all Nodes connected to Start Node 1028.

Under frequency

Normal - Mainland

0,          50
5,          50
5.25,       49
5.91667,    47
125,        47
125.25,     48
125.58333,  49
605,        49
605.2125,   49.85

Island - Tasmania

0,          50
5,          50
5.25,       49
5.91667,    47
125,        47
125.25,     48
605,        48
605.25,     49

System restoration - Mainland [Default]

0,          50
5,          50
5.25,       49
5.91667,    47
125,        47
125.25,     48
125.58333,  49
605,        49
605.125,    49.5

CWO REZ

0,          50
5,          50
6,          47
125,        47
125.33333,  48
605,        48
605.5,      49.5

Over frequency

Normal - Mainland

0,          50
5,          50
5.25,       51
5.58333,    52
125,        52
125.25,     51
605,        51
605.2125,   50.15

Island - Tasmania

0,          50
5,          50
5.25,       51
6.25,       54
6.75,       55
125,        55
125.25,     54
125.91667,  52
605,        52
605.25,     51

System restoration - Mainland [Default]

0,          50
5,          50
5.25,       51
5.58333,    52
125,        52
125.25,     51
605,        51
605.125,    50.5

CWO REZ

0,          50
5,          50
5.66667,    52
605,        52
605.5,      50.5

Frequency ride-through ability is unlikely to change depending on different operating conditions. However, it is industry practice to conduct the test across a range of operating conditions, including:

• Active power: Pmin and Pmax
• Reactive power: Qmin, Qnormal and Qmax

Assumption

• It is assumed that the frequency ride-through ability is being assessed in isolation and therefore tests are conducted at infinite SCR and X/R. To learn more, visit Choosing test SCR.
• S5.2.5.3(b) states that the frequency ride-through requirements apply "unless the rate of change of frequency is outside the range of -4 Hz to 4 Hz per second for more than 0.25 seconds, -3 Hz to 3 Hz per second for more than one second". Therefore, in this test we have applied the frequency disturbances such that a RoCoF of 4 Hz/s is applied for a maximum of 0.25 seconds and a RoCoF of 3 Hz/s is applied for a maximum of 1 second. For disturbances exceeding this duration, we have assumed a RoCoF of 2 Hz/s to reach the final value of the desired frequency disturbance.

FAQ

Should I use one frequency profile to test all frequency excursion values sequentially or a different frequency profile to test each frequency excursion individually?

gridmo recommends one frequency profile to test all frequency excursion values sequentially because it is the more onerous assessment and more closely aligns with how frequency excursions occur in reality.

Sequential methodology [Default]

The example below shows each frequency excursion requirement applied sequentially. This profile more closely represents a real frequency disturbance whereby there is an initial large frequency excursion and then the frequency is regulated back towards normal operating conditions.

Individual methodology [Not recommended]

The example below shows each frequency excursion requirement tested using an individual frequency profile. Each frequency band is a separate test, starting from the pre-disturbance frequency.

The example below shows the sequential methodology and individual methodologies overlaid. This example shows that it is more onerous to apply the frequency excursions sequentially.

Pass criteria

• S5.2.5.3(b): The generating system rides through the frequency disturbances.

Frequency protection verification

The template includes tests to confirm that some form of frequency protection exists in the generating system model. To test this, extreme underfrequency and overfrequency disturbances are applied, to 45 Hz and 57 Hz respectively. The RoCoF for reaching these values is set low (~0.5 Hz/s) so that the protection doesn't trip on RoCoF. The test is conducted at only one operating condition to confirm the existence of the protection.

Assumption

• It is assumed that the frequency protection verification is being assessed in isolation and therefore tests are conducted at infinite SCR and X/R. To learn more, visit Choosing test SCR.

Pass criteria

• The generating system trips during the extreme underfrequency and overfrequency disturbances.

S5.2.5.4 Response to voltage disturbances

The purpose of S5.2.5.4 is to confirm the ability of your generating system to maintain continuous uninterrupted operation for particular voltages at the connection point.

Voltage ride-through

The generating system is subjected to the following sequential voltage playback profiles, as defined in the NER. The last defined voltage is held until the end of the simulation.

Under voltage

0,       1.00
5,       1.00
5.001,   0.70
7,       0.70
7.001,   0.80
15,      0.80
15.001,  0.90

Over voltage

0,         1.00
5,         1.00
5.001,     1.32
5.02,      1.32
5.021,     1.30
5.2,       1.30
5.201,     1.25
7,         1.25
7.001,     1.20
25,        1.20
25.001,    1.15
1205,      1.15
1205.001,  1.10

Voltage ride-through ability for the above profiles can be dependent on the initial operating conditions of the generating system. This is because the generating unit terminal voltages will vary depending on the active and reactive power output of the generating system. Voltage protection settings are generally implemented at the generating units, specifically monitoring the terminal voltage of the generating units. It is therefore important to assess multiple different operating conditions since it is possible that the generating system will trip on voltage protection for some of these cases but not the others due to the difference in terminal voltages. We therefore recommend conducting the tests across a range of operating conditions, including:

• Active power: Pmin and Pmax
• Reactive power: Qmin, Qnormal and Qmax

Assumption

• It is assumed that the voltage ride-through ability is being assessed in isolation and therefore tests are conducted at infinite SCR and X/R. To learn more, visit Choosing test SCR.
• "at least marginally exceeding 130%" is represented by 132%.

FAQ

Should I use one voltage profile to test all voltage excursion values sequentially or a different voltage profile to test each voltage excursion individually?

gridmo recommends one voltage profile to test all voltage excursion values sequentially because it is the more onerous assessment and more closely aligns with how voltage excursions occur in reality.

Sequential methodology [Default]

The example below shows each voltage excursion requirement applied sequentially. This profile more closely represents a real voltage disturbance whereby there is an initial large voltage excursion and then the voltage is regulated back towards normal operating conditions.

Individual methodology [Not recommended]

The example below shows each voltage excursion requirement tested using an individual voltage profile. Each voltage band is a separate test, starting from the pre-disturbance voltage.

The example below shows the sequential and individual methodologies overlaid. This example shows that it is more onerous to apply the voltage excursions sequentially.

Pass criteria

• S5.2.5.4(a): The generating system rides through the voltage disturbances.

Voltage protection verification

The template includes tests to confirm that some form of voltage protection exists in the generating system model. To test this, extreme OV and UV disturbances are applied, to 1.35 p.u. and 0.1 p.u. for 20 seconds each respectively. The test is conducted at only one operating condition to confirm the existence of the protection.

Assumption

• It is assumed that the voltage protection verification is being assessed in isolation and therefore tests are conducted at infinite SCR and X/R. To learn more, visit Choosing test SCR.

Pass criteria

The generating system trips during the extreme undervoltage and overvoltage disturbances.

Voltage disturbances - Maintain CUO

The purpose of the S5.2.5.4 CUO assessment is to confirm the ability of your generating system to maintain continuous uninterrupted operation (CUO) for particular voltages at the connection point.

The most onerous form of this assessment is to have the generating system operating at different points within the VQ S5.2.5.1 AAS polygon and then step the grid voltage to the extremities of the polygon (noting that the maximum voltage disturbance is ±10%).

The initial active power is set to maximum active power for the most onerous assessment. Assessment is performed in reactive power control to assess ability of the plant to maintain reactive power during the voltage disturbance (instead of opposing the change in voltage as it would if it were in voltage droop control mode).

S5.2.5.4(e2)(1) states that generating systems may use "onload tap-changing transformers, plant switching and overload capability" to meet the requirements of S5.2.5.4(e1). Therefore, sufficient simulation time should be allowed for the tap-changing operation(s) to complete.

Grid voltage step up

A 10% overvoltage disturbance is applied such that the final value is on the upper bounds of the S5.2.5.1 AAS polygon.

Grid voltage step down

A 10% undervoltage disturbance is applied such that the final value is on the lower bounds of the S5.2.5.1 AAS polygon.

Assumption

• We haven't included tests to demonstrate compliance with S5.2.5.4(c1). This clause allows a generating system with point of connection voltages below 66 kV and without a main onload tap-changing transformer to use a negotiated access provision for applying under/over voltage events at the electrically closest bus that is ≥66 kV, instead of at the connection point. We haven't added tests for this negotiated access provision. If you need to complete such a test, you may need to perform additional network PSS®E dynamic studies which aren't currently included in this template.
• We haven't included tests to demonstrate compliance with S5.2.5.4(e3), given the subjective nature of the term "reasonable temporary alterations". For clarity, if those tests were completed, they would follow the methodology shown in the image below.

Pass criteria

• S5.2.5.4(e1): The generating system can maintain the initial active and reactive power output for the tested grid voltage changes which align with the S5.2.5.1 AAS polygon. (i.e. the active and reactive power at the connection point does not settle to new values due to the grid voltage changes).

S5.2.5.5 Disturbance ride-through capability

The purpose of S5.2.5.5 is to confirm your generating system's ability to ride through voltage disturbances. Since S5.2.5.5(c) references continuous uninterrupted operation requirements and clause (b) of the Chapter 10 definition of this term references the broader performance standards requirements, the purpose of the clause is also to confirm your generating system's active and reactive power response during and after disturbances.

Network fault performance

The purpose of these network studies is to determine the generating system response to faults applied in network model including monitoring of active power recovery time, reactive current commencement and rise time in response to these events.

The tests complete dynamic power system studies on a wide-area PSS®E model, known as NEM snapshots (or colloquially also known as 'OPDMS snapshots'). These tests help demonstrate compliance to S5.2.5.5(c) and S5.2.5.5(k).

Assumption

Currently, this template assumes that all generators which are to be considered as part of the studies are already merged into the network model. The network model is also load flow stable and dynamically stable. Your generating system does not need to be present in the NEM snapshot as it will be auto-merged by gridmo. See our example for more information on merging multiple generators into a network model.

Pass criteria

• S5.2.5.5A(g)(2): Iq positive sequence reactive current commences within 10 milliseconds of the response initiating conditions being met
• S5.2.5.5A(g)(2): Iq positive sequence reactive current rise time ≤ 40 ms
• S5.2.5.5A(f)(3)(i): Active power recovery time ≤ 100 ms
• S5.2.5.5(c)(1): Generating system successfully rides through the network disturbances (i.e. does not trip).
• S5.2.5.5A(g)(2): Generating system response is adequately controlled.

Balanced MFRT

S5.2.5.5(d) outlines that generating systems must remain in CUO for "a series of up to 15 disturbances within any five minute period caused by any combination of the events described [below]". It is impractical during simulations to cater for "any combination of events" meeting certain requirements. Therefore, we have created a selection of deterministic MFRT sequences in the MULTIFAULT Command. These sequences were built in accordance with the AEMO GPS and AEMO DMAT requirements and are used across both AEMO GPS and AEMO DMAT testing.

We recommend completing the MFRT testing across at least two MFRT sequences for balanced and unbalanced testing (e.g. P1 and P2 by default for balanced MFRT tests).

By default the testing is only completed at SCRmin because assessment is primarily considering ride-through capability rather than specific response characteristics (e.g. Iq rise time). SCRmin was chosen as the harder of SCRmin and SCRmax to ride through and therefore chosen for assessment.

An example of a balanced MFRT sequence is shown below.

Pass criteria

• S5.2.5.5(d): Generating system successfully rides through the series of voltage disturbances (i.e. does not trip).

Unbalanced MFRT

S5.2.5.5(d) outlines that generating systems must remain in CUO for "a series of up to 15 disturbances within any five minute period caused by any combination of the events described [below]". It is impractical during simulations to cater for "any combination of events" meeting certain requirements. Therefore, we have created a selection of deterministic MFRT sequences in the MULTIFAULT Command. These sequences were built in accordance with the AEMO GPS and AEMO DMAT requirements and are used across both AEMO GPS and AEMO DMAT testing.

We recommend completing the MFRT testing across at least two MFRT sequences for balanced and unbalanced testing (e.g. S2 and S3 by default for unbalanced MFRT tests).

By default the testing is only completed at SCRmin because assessment is primarily considering ride-through capability rather than specific response characteristics (e.g. Iq rise time). SCRmin was chosen as the harder of SCRmin and SCRmax to ride through and therefore chosen for assessment.

An example of an unbalanced MFRT sequence is shown below.

Pass criteria

• S5.2.5.5(d): Generating system successfully rides through the series of voltage disturbances (i.e. does not trip).

S5.2.5.5A Responses to disturbances following contingency events

The purpose of S5.2.5.5A is to identify the response of your generating system during and after disturbances following contingency events. There are several parts of this performance standard:

• [SMIB] Fault during frequency disturbance: Apply voltage disturbances at project-specific SCR during frequency disturbance and assess response performance in accordance with S5.2.5.5A(d)(3)(ii) and S5.2.5.5A(f)(3)(ii).
• [SMIB] Balanced voltage disturbances - Response performance calculations: Apply voltage disturbances at project-specific SCR and assess response performance (Iq commencement time, Iq rise time, Ppoc recovery time).
• [SMIB] Balanced voltage disturbances - Iq curve: Apply voltage disturbances at infinite SCR to construct the Iq curve.
• [SMIB] Unbalanced voltage disturbances (1PHG, 2PHG and PHPH) - Response performance calculations: Apply voltage disturbances at project-specific SCR and assess response performance (Iq commencement time, Iq rise time, Ppoc recovery time).
• [SMIB] Unbalanced voltage disturbances (1PHG, 2PHG and PHPH) - Iq curve: Apply voltage disturbances at infinite SCR to construct the positive sequence Iq curve.

Fault during frequency disturbance

The purpose of this assessment is to check that the generating system control logic works as expected when there is a frequency change during a fault.

Sample desired logic	Sample undesirable logic
A fault occurs. The control system switches into fault ride-through mode and prioritises reactive current injection.	A fault occurs. The control system switches into fault ride-through mode and prioritises reactive current injection.
A frequency disturbance occurs during the fault. The control system stays in fault ride-through mode, and the frequency controller keeps tracking the frequency change without acting on active power until the fault clears.	A frequency disturbance occurs during the fault. The frequency controller is frozen during the fault and ignores the frequency change.
The fault clears. Active power recovers to the level set by the frequency response (S5.2.5.11) at the post-fault frequency within 100 ms.	The fault clears. Active power recovers to the pre-fault setpoint, so the frequency response is lost.

The control system logic can be assessed by applying a frequency disturbance during a fault and observing the active power response. The following disturbances were chosen:

• Frequency disturbance: 49.5 Hz and 50.5 Hz - chosen based on the maximum and minimum thresholds of the 'normal operating frequency band' for Mainland Australia. RoCoF of 2 Hz/s.
• Voltage disturbance: 0.4 p.u. residual voltage arbitrarily chosen.

Pass criteria

• S5.2.5.5A(f)(3)(ii): Check Ppoc recovery time ≤ 100 ms where the level of active power is consistent with S5.2.5.11.

Balanced voltage disturbances - Response calculations

The purpose of this assessment is to find the performance metrics of the generating system when subjected to balanced voltage disturbances. The following disturbances are applied:

• Residual voltage:
  • Undervoltage: 0.05 to 0.85 p.u. in 0.05 p.u. steps
  • Overvoltage: 1.15 to 1.3 p.u. in 0.025 p.u. steps
• Fault duration: 430 ms
• Initiating voltages: 0.85 and 1.15 p.u. (AAS)

The first part of the response calculation methodology is to find the 'window' of the disturbance (i.e. find the start and end conditions of the disturbance). The diagram below shows how the 'initiating condition' and 'end of disturbance' are determined.

• Initiating condition: Time where the voltage falls below 0.85 p.u. or rises above 1.15 p.u.
• End of disturbance: Time where the voltage recovers to within 0.9 p.u. to 1.1 p.u.

Now that the initiating condition is known, the performance metrics of the generating system's response to the disturbance can be calculated.

Iq commencement time

Iq rise time

Active power recovery time

Response performance assessment criteria

S5.2.5.5A describes several assessment criteria, namely:

• Adequately controlled - S5.2.5.5A(b)(1)
• Iq commencement time - S5.2.5.5A(g)(2)
• Iq rise time - S5.2.5.5A(g)(2)
• Ppoc recovery time - S5.2.5.5A(f)(3)

These assessment criteria are unfortunately subjective and we have therefore detailed our interpretations of the key aspects of these assessment criteria.

Notes on the interpretation of "adequately controlled" in Chapter 5 of AEMC | National Electricity Rules | ERC0393 | 22 May 2025

S5.2.5.5A(b)(1) introduced a new term, `Adequately Controlled` which replaces the well-defined `Adequately Damped` term in the previous version of the NER. Unfortunately, this new definition is so subjective that we have not yet implemented an automated assessment of `Adequately Controlled` in this template.

Notes on the interpretation of "must commence" in Chapter 5 of AEMC | National Electricity Rules | ERC0393 | 22 May 2025

S5.2.5.5A(g)(2) states the following:

[for disturbances, a plant]...positive sequence reactive current response opposing the voltage change must commence within 10 milliseconds of the response initiating conditions being met, be adequately controlled and, for a step-like voltage profile at the connection point, have a positive sequence reactive current rise time of no greater than 40 milliseconds.

However, this definition is subjective due to the lack of definition of the term "must commence". The following note details gridmo's interpretation of this subjective definition as well as unused alternate interpretations.

Interpretation [Default]

• Start time: When fault is applied
• End time: When fault is cleared
• Pass/fail requirement: Initiating conditions met + 10 ms

This interpretation of the grid code requirements is used by default in the gridmo template.

We assume that the commencement time is the rise time from 0% to 10% of the final Iq value in the fault, using the same Chapter 10 rise time definition which includes the term "mean sustained change". We assume that the start time of the calculation is when the fault is applied. We assume that the end time of this calculation is the time at which the fault clears. The commencement time pass/fail requirement is interpreted as the time at which "the response initiating conditions [are] met" + 10 ms. The term "initiating conditions" is not a defined term in Chapter 10 and we assume that this is defined in S5.2.5.5A(g)(1) as the time after the fault is applied when the voltage first falls under 0.85 [p.u.] or rises above 1.15 [p.u.].

The commencement time pass/fail requirement is shown by the red vertical line, positioned 10 ms after the initiating condition time, which is indicated by the green vertical line. In this example, the generating system’s reactive current commencement time does not comply with the requirement as the shaded area exceeds the red line. The commencement time pass/fail requirement is not a fixed duration; it varies depending on when the initiating condition of the fault is met.

Alternate interpretation 1

• Start time: When initiating conditions are met
• End time: When fault is cleared
• Pass/fail requirement: 10 ms

We assume that the commencement time is the rise time from 0% to 10% of the final Iq value in the fault, using the same Chapter 10 rise time definition which includes the term "mean sustained change". We assume that the start time of the calculation is when the initiating condition is met. We assume that the end time of this calculation is the time at which the fault clears.

The commencement time pass/fail requirement is a fixed duration of 10 ms.

This interpretation was not chosen because, for some Iq signals with rapid responses, it is possible for the Iq response to completely rise to its final value prior to the initiating conditions being met. In this situation, the commencement time calculation is not fit for purpose. See below for an example of such a signal.

Alternate interpretation 2

• Start time: When initiating conditions are met
• End time: When voltage has recovered within 0.9 [p.u.] to 1.1 [p.u.] + 20 ms
• Pass/fail requirement: 10 ms

We assume that the commencement time is the rise time from 0% to 10% of the final Iq value in the fault, using the same Chapter 10 rise time definition which includes the term "mean sustained change". We assume that the start time of the calculation is when the initiating condition is met. We assume that the end time of this calculation is when the voltage had recovered to within 0.9 [p.u.] to 1.1 [p.u.] + 20 ms. The image below shows an example where the end of disturbance definition from S5.2.5.5(b)(3) is used, showing the final value doesn't appear to meet the intentions of the rule. The final value does not represent the magnitude of the reactive current at the end of the fault; therefore, this interpretation is no longer used.

Notes on the interpretation of "mean sustained change" in Chapter 10 of AEMC | National Electricity Rules | ERC0393 | 22 May 2025

Rise time will be defined in Chapter 10 of the NER [1] as the following:

In relation to a control system, the time taken for an output quantity to rise from 10% to 90% of the mean sustained change induced in that quantity by a step change of an input quantity, disregarding longer-term dynamics and influences external to the generating system following the step change.

However, this definition is subjective due to the lack of definition of the term "mean sustained change". The following note details gridmo's interpretation of this subjective definition.

We assume that the term "mean sustained change" was used rather than "sustained change" to address the instance where a channel towards the end of the rise time calculation window may not have settled and instead have an oscillatory component. In this instance, simply taking the final value to be the value at the end of the calculation window and using this to calculate the sustained change (i.e. final value - initial value) may not have the intended result.

The images below show the results for a signal where the calculated rise time would be different based on considering the "sustained change" or the "mean sustained change". Note that even if this interpretation of the "mean sustained change" is correct and the AEMC intended participants to employ an averaging window in the calculation methodology, there is still subjectivity in the length of such an averaging window. For this reason, we have created an argument `END_MEAN_T` in the `RISE_TIME` Plot Command so that the user can specify this averaging window length. Until further guidance is provided by AEMO, we recommend setting `END_MEAN_T` as 5%.

Notes on the interpretation of "after the end of the disturbance, reach at least 95% of...the pre-disturbance active power level controlled" in Chapter 5 of AEMC | National Electricity Rules | ERC0393 | 22 May 2025

S5.2.5.5A(f)(3)(i) states the following:

[for disturbances, a plant must]...within 100 milliseconds after the end of the disturbance, reach at least 95% of...the pre-disturbance active power level

However, this definition is subjective due to the lack of definition of the term "end of the disturbance". The following note details gridmo's interpretation of this subjective definition.

We assume that the recovery time calculation considers the new definition of the end of a disturbance as outlined in S5.2.5.5(b)(3). The start of the recovery time calculation is 20 ms after the connection point voltage has recovered to within 0.9 [p.u.] to 1.1 [p.u.].

Assumption

S5.2.5.5A(g)(2) states that 'the positive sequence reactive current response opposing the voltage change must...' It does not specify whether the value refers to the positive-sequence voltage or the total voltage. This template assumes total voltage, as the reactive current is explicitly defined as ‘positive sequence’ while the voltage is not.

FAQ

Why do you analyse positive sequence Iq even for balanced disturbances?

Even for balanced faults, there is a difference between Ipoc and Ipoc positive sequence when applied in PSCAD™. This occurs because, for a brief period immediately after the fault is applied, the phase currents are not perfectly equal, which results in a small negative sequence component in Iq. As a consequence, Ipoc and Ipoc positive sequence may differ, and therefore the resulting Iq commencement time and rise time calculations will differ as well. The NER specifically states that the positive sequence current must be used for both the commencement and rise time calculations.

gridmo explicitly calculates the positive sequence Ipoc for balanced faults, as well as unbalanced faults.

Pass criteria

• S5.2.5.5A(g)(2): Iq commencement time ≤ Initiating condition time + 10 ms
• S5.2.5.5A(g)(2): Iq rise time ≤ 40 ms
• S5.2.5.5A(f)(3)(i): Ppoc recovery time ≤ 100 ms
• S5.2.5.5(c)(1): Generating system does not trip
• S5.2.5.5A(g)(2): Response is adequately controlled

We note that S5.2.5.5A is frequently a Negotiated Access Standard (NAS) based on the following:

• Achieving the AAS 10 ms commencement time and 40 ms rise time requirements for reactive current may result in unstable performance (LVRT/HVRT flag retriggering) under very low SCR conditions.
• Achieving the AAS 100 ms active power recovery time after a fault may not be achievable for large generating systems under low SCR conditions.

Unbalanced voltage disturbances - Response calculations

The purpose of this assessment is to find the performance metrics of the generating system when subjected to unbalanced voltage disturbances. This is predominantly the same as the balanced assessment, but with unbalanced faults. Because the faults are unbalanced, this is a PSCAD™ only assessment. The following disturbances are applied:

• Residual voltage:
  • Undervoltage: 0.05 to 0.85 p.u. in 0.05 p.u. steps
• Fault duration: 430 ms
• Fault types: PHG, 2PHG, PHPH
• Initiating voltages: 0.85 and 1.15 p.u. (AAS)

Assumption

S5.2.5.5A(f)(1)(iii) requires negative sequence Iq injection to avoid excessive voltage rise on unfaulted phases during unbalanced faults. It is unclear what is deemed excessive. We have arbitrarily assumed that a voltage rise of > 0.05 [p.u.] is excessive.

Assumption

S5.2.5.5A(t)(1) implies that assessment of unbalanced overvoltages may be required. We have assumed that performance assessments for unbalanced overvoltages are not required in this template as they are only mentioned in one location in the NER under the General requirements section.

Pass criteria

• S5.2.5.5A(g)(2): Iq commencement time ≤ Initiating condition time + 10 ms
• S5.2.5.5A(g)(2): Iq rise time ≤ 40 ms
• S5.2.5.5A(f)(3)(i): Ppoc recovery time ≤ 100 ms
• S5.2.5.5(c)(1): Generating system does not trip
• S5.2.5.5A(g)(2): Response is adequately controlled
• S5.2.5.5A(f)(1)(iii): Check ΔVa / ΔVb / ΔVc ≤ 5%

Balanced voltage disturbances - Iq curve

The purpose of this assessment is to produce a ΔIq(V) (positive sequence) curve for the generating system. The following disturbances are applied:

• Residual voltage:
  • Undervoltage: 0.1 to 0.4 p.u. in 0.1 p.u. steps; 0.45 to 0.65 p.u. in 0.05 p.u. steps; 0.67 to 0.83 p.u. in 0.02 p.u. steps; 0.849 p.u.
  • Overvoltage: 1.151 p.u.; 1.17 to 1.25 p.u. in 0.02 p.u. steps
• Fault duration: 430 ms
• Initiating voltages: 0.85 and 1.15 p.u. (AAS)

For Iq curve tests with an undervoltage event, a fault is used to create the disturbance. This methodology helps to avoid using a Thévenin equivalent voltage source playback for very low voltage dips (e.g. 10%) which has been known to cause unrealistic and undesirable generating system responses.

For simulations involving an overvoltage event, the voltage disturbance is applied through a voltage playback rather than by switching a capacitor. In some cases, switching a capacitor can introduce oscillations in the Iq signal due to interactions between the plant and the capacitor used to create the disturbance. This is undesirable for assessing the Iq curve, as the objective is to analyse the settled Iq response, which becomes difficult when high‑frequency oscillations are present. Therefore, voltage playback is used for the overvoltage events.

This approach is appropriate for this assessment because we are not monitoring Iq commencement or settling time, both of which vary with network SCR. In this assessment, only the settled Iq value is recorded, and this parameter is not dependent on the network SCR, which allows use of the voltage playback command.

Assumption

• It is assumed that for this test we are only interested in the settled value of the generating system and therefore tests are conducted at infinite SCR and X/R. To learn more, visit Choosing test SCR.

There are four Iq curves produced in this template:

1. ΔIq vs. V (unsaturated points)
2. ΔIq vs. V (All points, i.e. saturated and unsaturated)
3. ΔIq vs. ΔV
4. Iq vs. V

Note: Iq and V quantities presented above are positive sequence.

LVRT K-factor

The AAS requires a positive-sequence capacitive reactive current, in addition to its pre-disturbance level, of at least 4% of the "maximum continuous current" for each 1% reduction of positive-sequence voltage at the connection point below the voltage at which the reactive current response commences. Under the AAS, this commencement voltage is 0.85 p.u. for undervoltage events. The corresponding K-factor is therefore calculated as:

$$\text{K-factor} = \frac{I_{q,\text{fault end}} - I_{q,\text{pre fault}}}{0.85 - V_{\text{fault end}}}$$

As shown, $I_{q,\text{fault end}}$ and $V_{\text{fault end}}$ are the "mean sustained change" values of the positive-sequence connection point reactive current (Iqpoc) and voltage (Vpoc), respectively, calculated over the final 5% of the fault duration. $I_{q,\text{pre fault}}$ is the value of Iqpoc recorded immediately prior to fault inception.

HVRT K-factor

The AAS requires a positive-sequence inductive reactive current, in addition to its pre-disturbance level, of at least 6% of the "maximum continuous current" for each 1% increase of positive-sequence voltage at the connection point above the voltage at which the reactive current response commences. Under the AAS, this commencement voltage is 1.15 p.u. for overvoltage events. The corresponding K-factor is therefore calculated as:

$$\text{K-factor} = \frac{I_{q,\text{fault end}} - I_{q,\text{pre fault}}}{1.15 - V_{\text{fault end}}}$$

Saturation

As per S5.2.5.5A(s)(1)(i), the saturation point is defined as the point where the Iqpoc (total) reaches 1.0 p.u. (i.e. Iq ≥ 100% of the "maximum continuous current"). Note that this is reactive current total, not reactive current positive sequence.

K-factor calculations for compliance purposes are not performed for simulations where the Iqpoc has "saturated".

FAQ

Why does your Iq curve not show a flat period at Iq = 1 [p.u.]?

Default Iq curve [Recommended]

The diagram below is an example of the type of output that this template produces by default. This scatter plot is for unsaturated points only. Each point corresponds to a single simulation. Simulations that are outside the green region are non-compliant with the AAS requirements as they do not demonstrate an LVRT K-factor of at least 4% or HVRT K-factor of at least 6%. Simulations inside the green region are compliant with the AAS requirements for Iq injection/absorption.

Alternate Iq curve

The diagram below is an example of the type of output that is often seen in the industry. This shows a flat compliance region where ΔIqpoc (pos seq) > 1.0 p.u. However, ΔIqpoc (pos seq) > 1.0 p.u. does not guarantee compliance. Saturation is based on the absolute value of Iqpoc, not the change. That is why, on the compliance curve, the 4% gradient line continues; it does not plateau at ΔIqpoc (pos seq) = 1.0 p.u.

A generating system importing reactive power pre-disturbance can have ΔIqpoc (pos seq) > 1.0 p.u. while Iqpoc remains below 1.0 p.u., and is therefore unsaturated. Because the response is unsaturated, the point appears on the unsaturated plot. If it falls below the 4% line (or above the 6% line for HVRT), it is non-compliant.

Pass criteria

• S5.2.5.5A(f)(1)(i): Check capacitive Iq injection ≥ 4%.
• S5.2.5.5A(f)(1)(i): Check inductive Iq absorption ≥ 6%.

Unbalanced voltage disturbances - Iq curve

The purpose of this assessment is to produce a ΔIq(V) (positive sequence) curve for the generating system when subjected to unbalanced voltage disturbances. The following disturbances are applied:

• Residual voltage: 0.1, 0.2, 0.3, 0.4, 0.45, 0.5, 0.55, 0.6, 0.65, 0.67, 0.71, 0.73, 0.75, 0.77, 0.79, 0.81, 0.83, 0.85 p.u.
• Fault duration: 430 ms
• Fault types: PHG, 2PHG, PHPH

The rest of the assessment is predominantly the same as the balanced Iq curve assessment. Unbalanced overvoltage disturbances are not included, so there is no inductive (HVRT) K-factor check.

Pass criteria

• S5.2.5.5A(f)(1)(i): Check positive sequence capacitive Iq injection ≥ 4%.
• S5.2.5.5A(f)(1)(iii): Check negative sequence current opposes unbalanced voltage.

S5.2.5.6 Quality of electricity generated and continuous uninterrupted operation

The purpose of S5.2.5.6 is to confirm that your generating system does not disconnect as a result of specified voltage fluctuation, harmonic voltage distortion and voltage unbalance levels. We don't currently provide tests for S5.2.5.6. Additionally, compliance is often demonstrated via product information obtained via your OEM.

S5.2.5.7 Partial load rejection

The purpose of S5.2.5.7 is to confirm the ability of your generating system to maintain continuous uninterrupted operation during and following a particular power system load reduction event or a separation event with an equivalent impact.

• If your generating system is comprised of only grid-following asynchronous plant, then you could instead propose compliance with Section S5.2.5.7 via demonstrating compliance with Section S5.2.5.3 of the Rules. Specifically, you could assert that any system separation event, regardless of load reduction of pre-disturbance level cannot exceed the minimum frequency band and RoCoF as per S5.2.5.3.
• However - if you have a synchronous plant or grid-forming inverters in your generating system, the inertia of your generating system may need to be considered in your generating system's ability to maintain continuous uninterrupted operation during a partial load rejection event.

S5.2.5.7 is only relevant if your generating system has synchronous generating unit(s) and is either:

• Mainland: ≥ 30 MW/MVA; or
• Tasmania: ≥ 7.2 MW/MVA (i.e. 5% x 144 MW).

See S5.2.5.7(a).

note

The template includes the ability to playback the network load reduction event into a SMIB model. This is completed by recording the voltage, frequency and angle response at the proposed connection point in the network case where your generating system has not yet been integrated and playing this back to your PSS®E and PSCAD™ SMIB generating system models.

Pass criteria

• The generating system does not disconnect during the load reduction event.

S5.2.5.8 Protection from power system disturbances

The purpose of S5.2.5.8 is to confirm the generating system's protection response to a variety of power system disturbances.

S5.2.5.8 is only relevant if your generating system is either:

• Mainland: ≥ 30 MW/MVA; or
• Tasmania: ≥ 7.2 MW/MVA (i.e. 5% x 144 MW).

See S5.2.5.8(a00)(2).

Assumption

We've assumed that tests to assess compliance with S5.2.5.8(a2) - do not disconnect within 20 milliseconds - are sufficiently assessed by the tests in S5.2.5.4 of this template. Bespoke tests to check that the generating system does not trip for a 20 millisecond over-voltage event are therefore not provided in this template.

Over-frequency response

Assumption

• S5.2.5.3(b) states that the frequency ride-through requirements apply "unless the rate of change of frequency is outside the range of -4 Hz to 4 Hz per second for more than 0.25 seconds, -3 Hz to 3 Hz per second for more than one second". Hence, in this test we have applied the frequency disturbances such that a RoCoF of 4 Hz/s is applied for a maximum of 0.25 seconds and a RoCoF of 3 Hz/s is applied for a maximum of 1 second. For disturbances exceeding this duration, we have assumed a RoCoF of 2 Hz/s to reach the final value of the desired frequency disturbance.

S5.2.5.8 refers to the term, "extreme frequency excursion tolerance limits" whose value is provided in the AEMC | Frequency Operating Standard | Effective 9 October 2023. To determine that your generating system meets its requirement, you must choose a frequency ride-through SMIB playback test depending on your relevant frequency operating standard. Several common operating standards have been provided below. Copy and paste the chosen frequency operating standard into the PSS®E Dynamic and PSCAD™ Nodes SMIB frequency playback fields in all Nodes connected to Start Node 2812.

The "System restoration - Mainland" option is chosen by default in the template because it represents the most difficult frequency ride-through disturbances for the majority of projects (i.e. on the mainland).

Normal - Mainland

0,         50
5,         50
5.25,      51
5.416667,  51.5

Island - Tasmania

0,     50
5,     50
5.25,  51
6.25,  54
6.5,   54.5

System restoration - Mainland [Default]

0,         50
5,         50
5.25,      51
5.416667,  51.5

CWO REZ

0,         50
5,         50
5.25,      51
5.416667,  51.5

The plot below shows an example response to an over-frequency disturbance. Active power at the connection point reduces by at least 50% within 3 seconds of the frequency threshold being reached.

Pass criteria

• S5.2.5.8(a1): In response to the over-frequency disturbance, the generating system reduces its active power output at the connection point by at least 50% within 3 seconds.

Voltage phase angle shift

Assumption

It's unclear to us if S5.2.5.8(b6) - Voltage angle change ride-through tests - is applicable for all generating systems, or just those which are ≥ 30 MW/MVA as per S5.2.5.8(a00)(2). We've assumed that this test applies to all generating systems, as this requirement used to be part of S5.2.5.16 before it was deleted as part of AEMC ERC0393.

Choose a voltage phase angle shift depending on your relevant GPS requirements.

Normal

0,          0
5,          20
15,         0
25,         -20
35,         0
45,         0

CWO REZ

0,          0
5,          30
15,         0
25,         -30
35,         0
45,         0

note

ERC0393 deleted S5.2.5.16 and the requirement to not disconnect under phase angle changes was moved into S5.2.5.8(b6).

Pass criteria

• S5.2.5.8(b6): The generating system is able to ride through the voltage phase angle shift disturbance (i.e. does not trip).

S5.2.5.9 Protection systems that impact on power system security

The purpose of S5.2.5.9 is to confirm that your generating system has adequate protection systems. We don't currently provide tests for S5.2.5.9. Additionally, compliance is often demonstrated via design reports.

S5.2.5.10 Protection to trip plant for unstable operation

The purpose of S5.2.5.10 is to confirm that your generating system has adequate protection systems. We don't currently provide tests for S5.2.5.10. Additionally, compliance is often demonstrated via design reports.

S5.2.5.11 Frequency control

The purpose of S5.2.5.11 is to confirm the generating system's active power response to power system frequency changes. The control system response is tested to assess:

• the value to which the active power is changed as part of a frequency response mode; and
• that it is adequately damped.

Only SMIB studies have been completed. Network-wide studies may be added to further demonstrate that the response is adequately damped.

P(f) droop curve

The purpose of this assessment is to observe P(f) droop curve response of the generating system to frequency disturbances. The following disturbances are applied:

• Frequency disturbances: 50 Hz ± 0.015, 0.05, 0.1, 0.15, 0.25, 0.5, 0.75, 1, 1.5, 2, 2.5, 3 Hz
• RoCoF: Frequency disturbances used to create the P(f) droop curve are completed at a 2 Hz/s ramp rate. This RoCoF is lower than the most onerous requirement of "-4 Hz/s to 4 Hz/s for more than 0.25 seconds, and -3 Hz/s to 3 Hz/s for more than one second" and is chosen as the purpose of this test is not related to frequency ride-through, therefore lower RoCoF is appropriate.

Assumption

• It is assumed that for this test we are only interested in the settled value of the generating system and therefore tests are conducted at infinite SCR and X/R. To learn more, visit Choosing test SCR.

The plot below shows an example of the dedicated Fpoc and Ppoc plots produced for each frequency disturbance used to construct the P(f) droop curve. In this example, frequency is ramped to 50.75 Hz and the change in active power is calculated.

The settled change in active power at each frequency is used to construct the P(f) droop curve shown below.

Pass criteria

• S5.2.5.11(i)(2)(i): P(f) droop curve deadband must be within 0 to ± 1.0 Hz
• S5.2.5.11(i)(2)(i): P(f) droop curve droop ≤ 10%
• S5.2.5.11(i)(2)(i): P(f) droop curve droop ≥ 2%

The observed P(f) droop characteristic should also align with the model settings.

Frequency disturbances

The purpose of this assessment is to ensure the frequency control system is adequately damped for a range of frequency disturbances. The following disturbances are applied:

• Frequency disturbances:
  • 2 Hz/s ramp to 47 Hz
  • 1 Hz/s ramp to 47 Hz
  • 2 Hz/s ramp to 52 Hz
  • Ramp to 52 Hz over 3 seconds

The plot below shows an example of the dedicated Fpoc and Ppoc plots produced for each frequency disturbance. In this example, frequency is ramped at 2 Hz/s to 52 Hz with available power at 50% and active power at 0.5 × Pmax.

Pass criteria

• S5.2.5.11(g): Response is adequately damped

Frequency disturbance during active power ramp

The purpose of this assessment is to check that the generating system control logic works as expected when there is a frequency change during an active power ramp.

Sample desired logic	Sample undesirable logic
The active power reference changes to 0.5 p.u. Active power starts ramping towards the new reference at the configured ramp rate.	The active power reference changes to 0.5 p.u. Active power starts ramping towards the new reference at the configured ramp rate.
A frequency disturbance occurs during the ramp. The frequency response (PFR) is added on top of the ramping reference, so active power reflects both the ramp (AGC) and the P(f) droop.	A frequency disturbance occurs during the ramp. The frequency response is ignored until the ramp finishes, or the ramp is paused while the frequency is outside the deadband.

The control system logic can be assessed by applying a frequency disturbance during an active power ramp reference signal change. The following events were chosen:

• Active power reference set to 0.5 p.u. at t = 5 seconds.
• Frequency disturbances applied at a 2 Hz/s ramp rate.
• Frequency disturbances: 47 Hz and 52 Hz beginning at t = 10 seconds.

Pass criteria

• S5.2.5.11(b)(Note): Ppoc considers both active power dispatch command and frequency response requirements.

S5.2.5.12 Impact on network capability

The purpose of S5.2.5.12 is to confirm the extent to which your generating system impacts inter-regional and intra-regional network capability.

The assessment is divided into two parts:

• Static studies: Static studies may be used to assess thermal limits and voltage stability. Please refer to our template which addresses these requirements: Static studies.
• Dynamic studies: Dynamic studies are completed where faults are applied on a network case where the generating system is explicitly modelled and modelled as a negative load. The responses from both representations of the generating system are compared.

We don't currently provide specific tests in this template for S5.2.5.12, though this is typically completed using a combination of:

• Static studies template.
• The faults assessed in S5.2.5.5 above.

S5.2.5.13 Voltage and reactive power control

The purpose of S5.2.5.13 is to confirm the capability of your generating system's voltage and reactive power control systems.

Choosing your primary and secondary control modes

S5.2.5.13(b)(2A) states that your generating system must:

1. Operate in voltage control mode, unless your NSP says otherwise; and
2. Operate in one additional control mode - either power factor control mode or reactive power control mode.

Your NSP may specify which additional control mode applies. Power factor control has fewer performance requirements than reactive power control, however reactive power control may be required for compliance with AEMO's VAr dispatch system (if applicable).

This selection is most common for large plants because NSPs will want them to help regulate voltage during normal operation and may want to set the VAr dispatch during abnormal operating conditions in accordance with AEMO's VAr dispatch system. However, there are several instances where generating systems may have different control modes (e.g. NSPs will most likely want smaller generating systems in distribution networks to operate in power factor control during normal operation).

Q(V) droop curve

The purpose of this assessment is to observe Q(V) droop curve response of the generating system to voltage disturbances. The following disturbances are applied:

• Voltage disturbances applied as a step change.
• Voltage disturbances: Vnormal ± 0.005, 0.01, 0.015, 0.02, 0.025, 0.03, 0.035, 0.04, 0.05, 0.06, 0.07, 0.08, 0.09, 0.1 p.u.

Assumption

• It is assumed that for this test we are only interested in the settled value of the generating system and therefore tests are conducted at infinite SCR and X/R. To learn more, visit Choosing test SCR.

The settled reactive power at each voltage is used to construct the Q(V) droop curve shown below.

Pass criteria

• S5.2.5.13(b)(2B)(i): Q(V) droop meets the characteristics agreed with AEMO/NSP.

Primary control mode

The purpose of these tests is to confirm the capability of your generating system's voltage and reactive power control systems in the primary control mode. In accordance with S5.2.5.13(b)(2A), the primary control mode is voltage control unless your NSP instructs otherwise. The template includes tests for voltage, reactive power, and power factor control so you can enable the primary mode that applies to your generating system.

The following tests are completed:

	Within limiters	Into limiters
Reference steps	Voltage control mode Reactive power control mode Power factor control mode	Voltage control mode Reactive power control mode Power factor control mode
Grid voltage steps	Voltage control mode Reactive power control mode Power factor control mode	Voltage control mode

Assumption

• Table S5.2.1 - Row 1: The tests required as per the first row of Table S5.2.1 - a voltage setpoint change with the synchronous machine(s) not synchronised - are currently not included in this template.
• Table S5.2.1 - Maximum rise time: We have assumed that rise time requirements only apply to voltage disturbances, not setpoint changes. The Table column header is clear for settling time, but not rise time. We have made this assumption because the rise time content only refers to "2-5% voltage disturbance" and not "5% setpoint change".
• Table S5.2.1: When in reactive power and/or power factor control modes, 2-5% voltage disturbances (i.e. Vgrid steps) will not typically cause the limiting device to operate since the target value is independent of the grid voltage. Therefore, such tests are not included by default. Some generating systems may need to perform these tests (e.g. synchronous generators whose excitation system reactive power/power factor control mode is a slow control loop around a fast-acting voltage control inner loop - whereby for sudden voltage disturbances the control system will behave like it is in voltage control mode and therefore may hit UEL/OEL limiters). For such generating systems, please feel free to contact gridmo support to get help modifying the template accordingly.
• Several control modes have variable settling time requirements for setpoint changes based on whether the response "overshoots the sustained change or response is oscillatory" (i.e. "Power factor as primary" and "Reactive power as primary"). However, there are not the same variable settling time requirements for voltage disturbances. Given control systems typically have similar response times for equivalent setpoint changes and voltage disturbances, we assume that most generating systems will not be utilising the longer 30 second settling time allowance. Therefore, the template has been configured by default to assess the shorter settling time requirement, irrespective of whether the response overshoots or is oscillatory. Some generating systems may utilise these longer settling time allowances (e.g. generating systems which have different control gains or ramp rate limits on the reference setpoint input signals versus the overarching control system error summing junction). For such generating systems, please feel free to contact gridmo support to get help modifying the template accordingly.
• "Typical impedance" is assumed to mean "SCRmax" and "Highest impedance" is assumed to mean "SCRmin".

Two example tests from the template are shown below:

1. Primary control mode: Voltage | Vref steps | Within limiters: Vref steps of ±5% are applied. Settling time is calculated for Vpoc, Ppoc and Qpoc.
2. Primary control mode: Reactive power | Qref steps | Into limiters: Qpoc is initialised on or close to the limit. Qref is then stepped away from the limiter and then back through the limiter. Settling time is calculated for Qpoc.

Pass criteria

Applies to the enabled primary control mode.

• S5.2.5.13(b)(1)(i): Response is adequately damped
• S5.2.5.13(b)(1)(i): No hunting is observed

Voltage control (Table S5.2.1 Row 2)

• S5.2.5.13(b)(2A): Control system regulates voltage
• S5.2.5.13(b)(2B): Voltage regulation considers droop curve (within 0.5% of voltage setpoint)
• S5.2.5.13 - Table S5.2.1 Row 2: Vpoc, Ppoc and Qpoc settling time ≤ 5 s (within limiters)
• S5.2.5.13 - Table S5.2.1 Row 2: Qpoc rise time ≤ 3 s (Vgrid steps, within limiters)
• S5.2.5.13 - Table S5.2.1 Row 2: Vpoc, Ppoc and Qpoc settling time ≤ 7.5 s (into limiters)

Power factor control (Table S5.2.1 Row 4)

• S5.2.5.13(b)(2A): Control system regulates power factor
• S5.2.5.13(c1)(1)(ii): Power factor regulation within a power factor equivalent to 2% of Smax
• S5.2.5.13 - Table S5.2.1 Row 4: Ppoc and Qpoc settling time ≤ 5 s (within limiters)
• S5.2.5.13 - Table S5.2.1 Row 4: Ppoc and Qpoc settling time ≤ 7.5 s (into limiters)

Reactive power control (Table S5.2.1 Row 6)

• S5.2.5.13(b)(2A): Control system regulates reactive power
• S5.2.5.13(c1)(1)(i): Reactive power regulation within 2% of Smax
• S5.2.5.13 - Table S5.2.1 Row 6: Qpoc settling time ≤ 5 s (within limiters)
• S5.2.5.13 - Table S5.2.1 Row 6: Qpoc settling time ≤ 7.5 s (into limiters)

Secondary control mode

The purpose of these tests is to confirm the capability of your generating system's voltage and reactive power control systems in the secondary control mode. In accordance with S5.2.5.13(b)(2A), the secondary control mode is either power factor control or reactive power control. Voltage control tests are included for projects whose NSP has specified a primary mode other than voltage control.

The following tests are completed:

	Within limiters	Into limiters
Reference steps	Voltage control mode Reactive power control mode Power factor control mode	Voltage control mode Reactive power control mode Power factor control mode
Grid voltage steps	Voltage control mode Reactive power control mode Power factor control mode	Voltage control mode

Assumption

• Table S5.2.1: When in reactive power and/or power factor control modes, 2-5% voltage disturbances (i.e. Vgrid steps) will not typically cause the limiting device to operate since the target value is independent of the grid voltage. Therefore, such tests are not included by default. Some generating systems may need to perform these tests (e.g. synchronous generators whose excitation system reactive power/power factor control mode is a slow control loop around a fast-acting voltage control inner loop - whereby for sudden voltage disturbances the control system will behave like it is in voltage control mode and therefore may hit UEL/OEL limiters). For such generating systems, please feel free to contact gridmo support to get help modifying the template accordingly.
• Several control modes have variable settling time requirements for setpoint changes based on whether the response "overshoots the sustained change or response is oscillatory" (i.e. "Voltage as secondary" and "Reactive power as secondary"). However, there are not the same variable settling time requirements for voltage disturbances. Given control systems typically have similar response times for equivalent setpoint changes and voltage disturbances, we assume that most generating systems will not be utilising the longer 30 second settling time allowance. Therefore, the template has been configured by default to assess the shorter settling time requirement, irrespective of whether the response overshoots or is oscillatory. Some generating systems may utilise these longer settling time allowances (e.g. generating systems which have different control gains or ramp rate limits on the reference setpoint input signals versus the overarching control system error summing junction). For such generating systems, please feel free to contact gridmo support to get help modifying the template accordingly.
• Table S5.2.1 Row 5 (i.e. "Power factor as secondary") appears to have no rise or settling time performance requirements for power factor reference step changes. We note this is abnormal compared to other sections of the same table. However, we assume that this is not an error and therefore no RISE_TIME or SETTLING_TIME Commands have been included for PFref tests.
• "Typical impedance" is assumed to mean "SCRmax".

Pass criteria

Applies to the enabled secondary control mode.

• S5.2.5.13(b)(1)(i): Response is adequately damped
• S5.2.5.13(b)(1)(i): No hunting is observed

Voltage control (Table S5.2.1 Row 3)

• S5.2.5.13(b)(2A): Control system regulates voltage
• S5.2.5.13(b)(2B): Voltage regulation considers droop curve (within 0.5% of voltage setpoint)
• S5.2.5.13 - Table S5.2.1 Row 3: Vpoc, Ppoc and Qpoc settling time ≤ 5 s (within limiters)
• S5.2.5.13 - Table S5.2.1 Row 3: Vpoc, Ppoc and Qpoc settling time ≤ 7.5 s (into limiters)

Power factor control (Table S5.2.1 Row 5)

• S5.2.5.13(b)(2A): Control system regulates power factor
• S5.2.5.13(c1)(1)(ii): Power factor regulation within a power factor equivalent to 2% of Smax
• S5.2.5.13 - Table S5.2.1 Row 5: Ppoc and Qpoc settling time ≤ 5 s (Vgrid steps, within limiters)

Reactive power control (Table S5.2.1 Row 7)

• S5.2.5.13(b)(2A): Control system regulates reactive power
• S5.2.5.13(c1)(1)(i): Reactive power regulation within 2% of Smax
• S5.2.5.13 - Table S5.2.1 Row 7: Qpoc settling time ≤ 5 s (within limiters)
• S5.2.5.13 - Table S5.2.1 Row 7: Qpoc settling time ≤ 7.5 s (into limiters)

Network studies

The network studies for S5.2.5.13 are completed in the same way as the primary control mode tests. The difference is that your generating system is merged into the wide area network model.

The Vgrid disturbances are applied via switching of shunts (capacitor/reactor) in the wide area network model rather than with grid voltage playback (SMIB).

Assumption

• The reference step change tests have only been included for Voltage control mode by default. If your primary control mode is not voltage control mode, you will need to modify the step change tests.

Pass criteria

Applies to network studies for the primary voltage control mode.

• S5.2.5.13(b)(1)(i): Response is adequately damped
• S5.2.5.13(b)(1)(i): No hunting is observed

Voltage control (Table S5.2.1 Row 2)

• S5.2.5.13(b)(2A): Control system regulates voltage
• S5.2.5.13(b)(2B): Voltage regulation considers droop curve (within 0.5% of voltage setpoint)
• S5.2.5.13 - Table S5.2.1 Row 2: Vpoc, Ppoc and Qpoc settling time ≤ 5 s (within limiters)
• S5.2.5.13 - Table S5.2.1 Row 2: Qpoc rise time ≤ 3 s (Vgrid steps, within limiters)
• S5.2.5.13 - Table S5.2.1 Row 2: Vpoc, Ppoc and Qpoc settling time ≤ 7.5 s (into limiters)

Small signal amplification oscillation

To measure the impact of the generator's response to the voltage oscillation, the amplification factor is calculated at multiple test frequencies. The amplification factor at each frequency is defined as the ratio of:

• The magnitude of the voltage oscillation with the presence of the proposed generating system; to
• The magnitude of the voltage oscillation without the presence of the proposed generating system (i.e. the magnitude of the injected voltage oscillation).

An amplification factor greater than 1 means that the generating system is amplifying the injected voltage oscillation, whereas a value less than 1 means that the generating system is attenuating the injected voltage oscillation.

In this template, we have provided two methodologies to calculate the amplification factor - the 'engineering' methodology and the 'theoretical' methodology:

• Engineering methodology: The amplification factor considers the peak to peak values of Vpoc.
• Theoretical methodology [Powerlink default methodology]: The amplification factor only considers the oscillation magnitude at the frequency of the injected voltage oscillation signal. The impact of other induced frequencies are not considered.

For some plant responses, the two methodologies can have very different results. Consider the following example:

• A 10 Hz voltage oscillation is injected. The plant attenuates the 10 Hz oscillation very well.
• Unfortunately, the 10 Hz oscillation induces a 1 Hz voltage oscillation which has a large amplitude.

As shown in the image below, the 'engineering' methodology considers the peak to peak of the entire channel, irrespective of the injected oscillation frequency. Therefore, the amplification would be quite large. In contrast, the 'theoretical' methodology only considers the peak to peak of the injected oscillation frequency. Therefore, the amplification factor would be quite small.

We recommend using both methodologies in addition to reviewing the time series plots to gain a complete understanding of your generator's response to the voltage oscillation.

The plot below shows an example of the Vpoc and Qpoc overlay for the last 4 cycles of the injected voltage oscillation. In this example, a 0.4 Hz oscillation is applied. The relationship between Vpoc and Qpoc is visible.

S5.2.5.14 Active power control

The purpose of S5.2.5.14 is to confirm the capability of your generating system's active power control system.

Pass criteria

• The generating system follows the active power setpoints as they are applied.
• The generating system ramps linearly from one setpoint to the next.
• The generating system is capable of ramping from one setpoint to the next within 300 seconds.

S5.2.5.15 Short circuit ratio

The purpose of S5.2.5.15 is to confirm the ability of your generating system to operate stably and remain connected at a specified low short circuit ratio.

S5.2.5.15 states that this requirement should be "...assessed in accordance with the methodology prescribed in the system strength impact assessment guidelines". Please refer to our template which addresses these guidelines: AEMO System Strength Impact Assessment Guidelines (Appendix B).

Sources

• AEMC | National Electricity Rules | Version 234 | 21 August 2025
• AEMC | Final Determination ERC0393 | 22 May 2025
• AEMC | Frequency Operating Standard | Effective 9 October 2023
• AEMO | Primary Frequency Response Requirements | Effective 8 May 2023
• AEMO | Template for proposed Generator or Integrated Resource Provider Performance Standards | 15 March 2023
• AEMO | Access Standard Assessment Guide | 31 January 2019
• AEMO | Power System Model Guidelines | Version 3.0 | 2025
• EnergyCo | Template for Performance Standards for CWO REZ

Revision history

Version 8 | 5 October 2026

Improvements

• General:
  • Output file names reorganised into clause and test folders (for example GPS\S5.2.5.3\Ride-through\).
  • Conditional formatting applied to Table Nodes to highlight pass/fail status.
  • Requirement lines added to plots where a numerical limit applies (for example a line at the 5 second settling time) so compliance can be read from the plot.
  • uv_disturbance_threshold and ov_disturbance_threshold renamed to au_aemo_uv_disturbance_threshold and au_aemo_ov_disturbance_threshold.
• S5.2.4:
  • Summary table added for PSCAD™ initialisation times (Node 3510), with conditional formatting against the 3 second PSMG limit.
  • Settling time methodology in Node 2152 updated. FINAL_THRESHOLD_OVER and FINAL_THRESHOLD_UNDER set to 0%. FINAL_THRESHOLD_MIN=0.5 removed. Legend added to the settling time description, and a line drawn at the 3 second requirement.
  • Control mode label in the operating-condition loop updated from "Voltage droop" to "Voltage".
• S5.2.5.1:
  • Constrained PQ scatter plot removed.
  • Constrained VQ capability curve x-axis tightened from ±1.2 p.u. to ±0.6 p.u.
  • Start and end Vpoc, Ppoc and Qpoc values exported. End-of-run outputs moved onto a dedicated calculation plot.
• S5.2.5.3:
  • Ride-through and protection verification tests separated into different Start Nodes.
  • Table Nodes added with a summary of trip status.
  • Disabled loops on the protection verification tests removed. One operating condition is sufficient.
  • "No generator (applied test only)" nodes removed. They are not applicable for infinite SCR tests.
• S5.2.5.4:
  • Ride-through and protection verification tests separated into different Start Nodes.
  • Table Nodes added with a summary of trip status.
  • Disabled loops on the protection verification tests removed. One operating condition is sufficient.
  • Terminal voltage plots added for the UV and OV ride-through tests.
  • VQ curve and a V, P, Q points table added to the CUO test outputs.
  • "No generator (applied test only)" nodes removed. They are not applicable for infinite SCR tests.
• S5.2.5.5:
  • Balanced MFRT now runs sequences S2 and S3 at Pmin and Pmax, and at Qmin, Qnormal and Qmax. Sequence S1 is no longer run.
  • Unbalanced MFRT (sequences P1 and P2) now covers the same active and reactive power operating conditions.
  • Trip status tables added for balanced and unbalanced MFRT.
• S5.2.5.5A:
  • LVRT and HVRT transition band tests removed.
  • Dedicated plot and analysis added for the fault during frequency disturbance test. The test is now run at 0.5 × Pmax.
  • RoCoF in the fault during frequency disturbance test reduced to 2 Hz/s.
• S5.2.5.8:
  • Over-frequency response now reported as a percentage reduction in Ppoc over 3 seconds, with a dedicated Fpoc and Ppoc plot and an active power reduction table.
  • Trip status table added for the voltage phase angle shift test.
• S5.2.5.11:
  • P(f) droop curve table now reports Fpoc and Ppoc at the start and end of the ramp, and the change in each.
  • Dedicated Fpoc and Ppoc plots added.
  • P(f) droop curve simulation length is now the loop variable l_sim_time (default 15 s), so it can be extended when the plant ramp rate needs longer to settle.
• S5.2.5.13:
  • Settling time and rise time calculations moved onto dedicated plots, with a line at the 5 second (within limiters) or 7.5 second (into limiters) requirement.
  • Dedicated Vpoc and Qpoc plot added for the Q(V) droop curve.
• S5.2.5.14:
  • Dedicated plot for Ppoc and Pref.

Fixed

• S5.2.5.3:
  • Underfrequency and overfrequency playback points were 120 s and 600 s instead of 125 s and 605 s, because the disturbance begins at t = 5 s.
• S5.2.5.4:
  • CUO test is now forced into reactive power control mode.

New

• Global Variables added for the S5.2.5.5A timing criteria, so the limits can be edited without changing Analysis Nodes:
  • au_aemo_gps_iq_commencement_time (default 0.010 s)
  • au_aemo_gps_iq_rise_time (default 0.040 s)
  • au_aemo_gps_p_recovery_time (default 0.100 s)
  • S5.2.5.5 network fault studies and S5.2.5.5A response calculations, including conditional formatting on the results tables, now reference these variables.
• S5.2.5.11: New Start Node for a frequency disturbance applied during an active power ramp, to check that the output is the sum of the AGC setpoint and the primary frequency response (AEMO Primary Frequency Response Requirements, section 2.3.1).

Version 7 | 09 September 2026

Improvements

• PSCAD™ Nodes enabled by default for S5.2.5.3 with simulation length reduced.
• Global Variables added for uv_disturbance_threshold and ov_disturbance_threshold to allow for easier configuration of S5.2.5.5A.
  • Loop: Start Nodes 2536, 3187, 3034, 3394 updated to use these Global Variables.
• Added additional manual analysis to Analysis Node 3215 for S5.2.5.5A(f)(1)(iii).
• Major change to S5.2.5.5A Unbalanced voltage disturbances - Iq curve - Table Node 3208 to show more useful calculation quantities.

Fixed

• RoCoF requirements in the S5.2.5.3, S5.2.5.8 tests have been reduced to align with the most onerous requirement: "-4 Hz/s to 4 Hz/s for more than 0.25 seconds, and -3 Hz/s to 3 Hz/s for more than one second."
• RoCoF for S5.2.5.11 tests has been decreased from 4 Hz/s to 2 Hz/s as purpose of this test is not related to frequency ride-through, therefore lower RoCoF is appropriate.
• Analysis titles in section S5.2.5.5A updated to specify S5.2.5.5A rather than S5.2.5.5.
• S5.2.5.5A Unbalanced voltage disturbances - Iq curve: Updated Iq poc (pos seq) fault end calculation to be mean average of the final 5% of values during the fault rather than the absolute last value before fault end. Modification made in Plot Node 3224.

Version 6 | 31 July 2026

Improvements

• Enabled Excel (.xlsx) as the default output file type in all Table Nodes, instead of Comma-separated values (.csv).

Version 5 | 3 July 2026

Fixed

• S5.2.5.5A Balanced disturbances Iq curve - end values for Vpoc and Iqpoc set to the median of the final 5% of values during the fault rather than the absolute last value before fault end.
• Units for Ppoc fixed in Plot Node 3176 and 3183 to be MW rather than p.u.
• Plot Node 1336: Updated error bands which were missing, "TAT=120".

Version 4 | 24 June 2026

Improvements

• To support the growing complexity of projects and grid codes, we created a new version of the template which fully utilises the latest features in gridmo such as:
  • Global Variables in loops for easier setpoint configuration
  • Multiline partial Command Global Variables
  • Global subplots
  • Operating Conditions
  • PSCAD™ only initialisation

info

From this version onwards, the legacy template library version of this template is no longer maintained.

Fixed

• S5.2.5.1: Assessment begins from Pmin rather than P = 0 p.u.

New

• Custom label for commencement time added to plots. Plot Nodes 3382, 3149, 3180, 3200, 3173.
• S5.2.5.5 network studies - major update. New Global Variables for easier setpoint configuration.
• S5.2.5.7 network studies - major update. New Global Variables for easier setpoint configuration.
• S5.2.5.13 network studies - major update. New Global Variables for easier setpoint configuration.

Version 3 | 9 March 2026

Fixed

• S5.2.5.5: Network fault performance, commencement time methodology updated to begin at fault inception rather than at initiating condition. Commencement time requirement set to initiating condition + 10 ms. Rise time calculation also updated to begin at fault inception, not at initiating condition. Updated Nodes 3149, 3150, 3151, 3166, 3167, 3168.
• S5.2.5.5A: Balanced and Unbalanced voltage disturbances, commencement time methodology updated to begin at fault inception rather than at initiating condition. Commencement time requirement set to initiating condition + 10 ms. Rise time calculation also updated to begin at fault inception, not at initiating condition. Updated Nodes 3173, 3174, 3175, 3180, 3181, 3182, 3200, 3201, 3202, 2687, 3197. Additional plots added to show Iq commencement time margin to visualise compliance.
• S5.2.5.5A: FRT transition bands methodology updated to set the generating system to fixed reactive power control. Updated Nodes 2535, 2530, 2531.
• S5.2.5.5A: Unbalanced voltage disturbances, fixed typos in Analysis Node descriptions 3204, 3199.
• S5.2.5.5A: Balanced disturbances - Iq curve, Node 2688. Changed the assessment methodology for overvoltage events to be via voltage playback rather than via switched capacitor.
• S5.2.5.5A: Balanced disturbances - Iq curve, Node 2688. In PSS®E, the grid voltage playback occurs one timestep later than in PSCAD™, reflecting how PSS®E applies the playback signal.
• S5.2.5.5A: Rise time requirement and active power recovery requirement lines have been added to their respective Nodes. Updated Nodes 3175, 3176, 3182, 3183, 3202, 3203.
• S5.2.5.5A: Balanced voltage disturbance calculations and Iq rise and commencement calculations, are now completed using Iqpoc positive sequence rather than Iqpoc total. Updated Nodes 3173, 3175, 3180, 3182.
• S5.2.5.13 - In PSS®E, the grid voltage playback occurs one timestep later than in PSCAD™, reflecting how PSS®E applies the playback signal. Nodes 1516, 1520, 2020, 2022, 2243, 2245, 1733, 1735, 3252, 3255, 3269, 3270, 3289, 3291, 3216, 3318 updated.

Version 2 | 27 November 2025

Fixed

• S5.2.5.4: Updated Analysis Node 2637 to be a manual check for Qpoc response since the correct response depends on the default Q-loop control mode.
• S5.2.5.5A: Updated Iq curve scatter plots (Plot Nodes 2585 and 3216) such that the green AAS shading flattens out at 1 [p.u.] such that it doesn't imply that Iq > 1 [p.u.] is required to meet AAS. This plateau was removed in a later version. The current unsaturated curve continues the K-factor gradient past ΔIq = 1 [p.u.], because saturation is based on absolute Iqpoc.
• S5.2.5.5A: Updated unbalanced Iq curve scatter plot (Plot Node 3216) to remove HVRT gradient calculation since the template does not yet contain unbalanced overvoltage disturbances.
• S5.2.5.5A: Fixed typo in Analysis Node 3222 to correctly refer to phase c instead of b.

Version 1 | 30 June 2025

• First release

Related templates

• Dynamic Model Acceptance Tests (DMAT)
• System Strength Impact Assessment Guidelines (SSIAG)