This article is the first of a four-part series that will explain what FPP-Reg-FCAS Recovery data reveals about dispatch errors, who is paying for them, who is being rewarded for correcting them, and what that says about the Regulation FCAS market.

Before getting too deep into the data in later articles, this first article will lead you through how a technical frequency-control problem led to the regulatory reform Mandatory Primary Frequency Response (MPFR) in 2020, and how this manifested as a settlements problem that led to Frequency Performance Payments (FPP) and changes to the recovery of Regulation FCAS costs in 2025. For reasons explained later, the changes to recovery of Regulation FCAS can be phrased as “Reg-FCAS Recovery”, and taken together, can be “FPP-Reg-FCAS Recovery”.

The objectives of the reforms were to restore fast local control inside the Normal Operating Frequency Band, pay for corrective response, and allocate costs to units, loads, and other participants whose dispatch errors created the need for that response. MPFR targeted the first objective and FPP-Reg-FCAS Recovery targeted the second. These articles investigate whether those objectives have been achieved.

The Frequency Operating Standard

Under the Frequency Operating Standard:

• AEMO must keep system frequency within the Normal Operating Frequency Band of ±0.15 Hz around 50 Hz for 99% of the time.
• Separately, contingencies such as generator or transmission circuit trips can cause an immediate loss of supply and are managed under wider contingency frequency bands; these events are not the focus of these articles.

Dispatch errors trigger corrective responses.

• In normal operation, these responses:
  • come from primary control, where units adjust output in proportion to changes in system frequency,
  • and secondary control, where units enabled for Regulation FCAS are adjusted by Automatic Generation Control (AGC) to correct the error.
• And, after a contingency e.g. trip of a large generator, via Contingency FCAS (not the subject of these articles).

A useful way to think about frequency control is as a set of interacting layers. Primary control is unilateral, immediate action based on local frequency. Secondary control is slower and centralised through AGC units enabled for Regulation FCAS. Dispatch then provides the five-minute market and operational framework within which units are expected to follow targets and remain within secure limits.

Frequency control layers
0. Inertia Physical / instantaneousSynchronous machines (and reduced by fast devices resisting the initial rate of change of frequency ROCOF).Purpose: slow the ROCOF after an imbalance.Nature: physical characteristic, not dispatched. Market Service: None, TNSPs may procure inertia services to limit ROCOF.	1. Primary control Technical / local / fastUnits measure local frequency and automatically move output in the correcting direction. Purpose: arrest frequency within the NOFB and Contingency bands.Reform: MPFR restored active control in this layer within NOFB.Market Service: Contingency FCAS – 1,6,60sec and 5min	2. Secondary control Technical + market / centralised / slowerAEMO’s AGC moves units enabled for Raise or Lower Regulation FCAS.Purpose: correct persisting dispatch errors and restore energy balance.Market service: Regulation FCAS	3. Tertiary / dispatch Market dispatch / five-minute targetsNEMDE issues dispatch targets within constraints to keep power system within secure operating limits.Purpose: schedule energy and FCAS for the dispatch interval, maximise the value of trade.Problem: deviations from target create dispatch errors.	Emergency / contingency Protection / wider frequency bandsProtection schemes, load shedding and other emergency schemes act after non-credible contingency events.Purpose: avoid cascading failure or major supply disruption.Focus here: not the subject of FPP-Reg-FCAS Recovery.
	FPP- Reg-FCAS Recovery settlement layer 4-sec data calculates bad and good errors. Good paid / Bad pays. Regulation FCAS costs recovered from Bad.

AEMO procures Raise and Lower Regulation FCAS:

• This might typically be 200-220 MW in each direction.
• But, as shown in this long-range trend, can be double that (or more) on some occasions.

AGC uses Raise-enabled (supply-side) units by signalling them above their dispatch trajectory and Lower-enabled units by moving them below it. In this way, Raise Regulation corrects negative errors and Lower Regulation corrects positive errors.

The Rules require scheduled units to comply with their five-minute dispatch targets. Although this is an absolute rule, it is only in egregious cases that the regulator has sought legal redress, issued infringement notices, or required enforceable undertakings. The obligations vary by technology, with Semi-Scheduled Generators (think solar and wind farms) having a lesser obligation because of variability in their energy source.

This is the operating context for MPFR. If there is too little primary control inside the NOFB, then even ordinary dispatch errors can move frequency quickly through the band before secondary control has time to act. Regulation FCAS can correct persistent errors, but it is not designed to be the first line of physical frequency control for every small imbalance.

Mandatory Primary Frequency Response (MPFR)

We can see, via Linton’s longer-range frequency analysis here, three distinct phases of frequency control:

• In Linton’s chart for 2011, we can see relatively tight control within the normal operating band of ±0.15 Hz.
• However in years 2017, 2018, 2019 and part-way through 2020:
  • we can see much looser control
  • which occurred because many power station operators had progressively widened their frequency control settings. As a result, some units only responded after frequency had moved outside the normal band and into the contingency band, and in some cases only when enabled by AEMO for Contingency FCAS.
• The Mandatory Primary Frequency Response Rule 2020 (MPFR) was introduced to rectify this degradation of frequency performance:
  • Which we can see in subsequent years
  • Albeit with ‘cats ears’ due to the MPFR deadband.
  • Linton’s article from September 2025 also shows the success in vastly reducing the number of instances outside of the NOFB.

MPFR required scheduled and semi-scheduled generators to operate with narrow-band frequency control. In practice, this means units automatically increase or decrease output in response to small frequency deviations, acting in the opposite direction to the frequency change. Put differently, MPFR put active control back inside the Normal Operating Frequency Band, rather than leaving small imbalances to move frequency until AGC or wider-band contingency settings responded.

 

Mainland frequency outcomes in Q1 2026 – AEMO’s frequency monitoring shows current frequency performance after MPFR had become embedded in normal operation.

 

Frequency performance relative to the Normal Operating Frequency Band in Q1 2026 – this provides AEMO’s current official reference point for the control environment in which FPP-RTCP now operates.

 

Interaction between MPFR and Dispatch Targets

The NEM dispatch engine uses to ensure dispatch instructions for generators, batteries, wind farms and other units remain within secure power system limits, including unit and transmission limits. An energy dispatch instruction is a cleared MW target that a unit must ramp toward from its initial MW output over a five-minute interval.

During normal operation dispatch errors can arise:

• from demand forecast errors, changes in demand within the interval,
• and units deviating from their expected straight-line ramp trajectory, including failures to start.

The following chart shows dispatch errors for a solar-farm:

For example, when operational demand is falling, units are expected to ramp down. If they are persistently slow to reduce output, a positive dispatch error can emerge, so AGC moves Lower Regulation units down to correct it. Conversely, when demand is rising, a negative dispatch error can occur, and AGC moves Raise Regulation units up.

The following chart presents a battery, this time providing Regulation FCAS – note LOWERREG is presented as negative.

MPFR did not remove the underlying dispatch errors. Instead, units providing primary control counteract those errors quickly enough to limit frequency deterioration. But primary control alone cannot fully rebalance the system. Because primary control responds in proportion to frequency deviation, a persisting dispatch error will still leave primary controllers doing work while frequency slides away from 50 Hz. AEMO’s Technical White Paper demonstrates this through simulations on pages 48–49 and a live SCADA loss event on pages 55–56. Both examples show why secondary control, being AGC Regulation FCAS, is needed to correct dispatch errors, relieve the work being done by primary controllers, and restore energy balance.

Secondary control relies on units providing SCADA, being enabled for Regulation FCAS, and being controlled through AGC. As a central control system, AGC has inherent delays because measurements must be received, processed, and converted into instructions for enabled units. It can also be tuned to target slow, more persistent errors detected by the system. By contrast, primary control is local, immediate, and based on the frequency measured at each plant.

This distinction explains why MPFR and AGC-Regulation FCAS are complementary. MPFR provides the fast, local response that stabilises frequency, while secondary control corrects the remaining dispatch error and brings the system back toward balance.

Together, MPFR and FPP- Reg-FCAS Recovery were intended to restore a coherent control and settlement philosophy. MPFR restored the physical control layer inside the NOFB. FPP- Reg-FCAS Recovery then put a settlement value on the corrective work being done by primary and secondary controllers, and sharpened cost recovery so units whose deviations create the need for corrective response bear more of that cost.

This is also where the AEMC and AEMO descriptions of the reform can sound slightly different. The AEMC framed the enduring arrangements as an incentive for primary frequency response and improved frequency control. AEMO’s technical and implementation material placed more emphasis on extending Causer Pays: identifying who caused the need for corrective response, who helped correct it, and how Regulation FCAS costs should be recovered. At the time, MPFR was already operating, and AEMO outlined in pages 17–19 of the AEMO PFR Incentive Arrangements Discussion Paper that under MPFR and the existing Regulation FCAS recovery approach there was a cross-subsidy between units that had implemented PFR and those causing dispatch errors without paying for them.

In short, MPFR was introduced because the system needed the technical layer of control reintroduced inside the Normal Operating Frequency Band. FPP- Reg-FCAS Recovery was introduced because the market also needed a way to price the dispatch errors being corrected, pay those helping, and charge those making the error worse. That is why this series treats MPFR and FPP-Reg-FCAS Recovery as linked reforms, but not as the same reform.

The next article will look at how FPP- Reg-FCAS Recovery turns 4-second performance data into payments, charges and technology-level outcomes.

 

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