REPORT TO COAG ENERGY
COUNCIL ON SECURITY AND
RELIABILITY IN THE CONTEXT
OF CHANGING GENERATION
MIX
September 2015
REPORT TO COAG ENERGY COUNCIL ON SECURITY AND RELIABILITY IN THE CONTEXT OF CHANGING
GENERATION MIX
IMPORTANT NOTICE
Purpose
AEMO was requested by the Council of Australian Governments (COAG) Energy Council Senior
Committee of Officials (SCO) on 13 April 2015 to provide advice about security and reliability in the
context of changing generation mix. AEMO prepared this document in response to the SCO request.
This publication is based on information available to AEMO as at the end of September 2015.
Disclaimer
SCO requested that the above advice be provided by 30 September 2015.
This response has been prepared to meet the timelines specified by SCO. AEMO has made every effort
to discuss the technical issues raised by the request, however, a detailed program of work is required to
comprehensively understand all challenges.
AEMO makes every effort to ensure the quality of the information it provides, however it cannot
represent or warrant that the information, forecasts and assumptions are accurate or complete or
appropriate for particular circumstances. This document does not include all of the information that an
investor, participant or potential participant in the National Electricity Market might require, and does not
amount to a recommendation of any investment.
Anyone proposing to use the information in this document (including information and reports from third
parties) should independently verify and check its accuracy, completeness and suitability for purpose,
and obtain independent and specific advice from appropriate experts.
Accordingly, to the maximum extent permitted by law, AEMO and its officers, employees and
consultants involved in the preparation of this publication:
 make no representation or warranty, express or implied, as to the currency, accuracy, reliability or
completeness of the information in this document; and
 are not liable (whether by reason of negligence or otherwise) for any statements, opinions,
information or other matters contained in or derived from this publication, or any omissions from it,
or in respect of a person’s use of the information in this document.
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EXECUTIVE SUMMARY
In April 2015, the Standing Committee of Officials (SCO) requested that AEMO provide confidential
advice to the COAG Energy Council on power system security and reliability. The first report provided in
May, and later published1, focussed on power system security and reliability in the context of generation
exits. This second report focuses on power system security and reliability in the context of the changing
mix of generation.
Investment in low inertia, solid-state connected renewable generation is continuing at a substantial rate
in the National Electricity Market (NEM). This is currently in the form of embedded photovoltaic (PV)
generation and wind farms, but is expected to be supplemented by storage devices and growth in
commercial PV as projected in the 2015 National Electricity Forecasting Report.
The consequences of these investments are that:
 conventional synchronous generating plant2 is progressively losing market share, leading to
reduced financial viability and gradual withdrawal from the power system either for short or
extended periods, or in some cases permanently.
 Embedded generation is becoming a greater proportion of the total mix, with around 1.3 million
rooftop PV installations in the NEM in 2014-15. This represents a shift in market and power system
control from large scale generation which are transmission connected and centrally regulated in
terms of technical attributes, monitoring and dispatch, to a mix that includes an increasing
proportion of smaller scale, distribution connected plant which is not centrally regulated in relation
to its technical attributes, monitoring or dispatch, and potentially not even visible.
This progressive change in generation mix, through displacement of synchronous generation with
different technologies will gradually change the dynamic response of the power system to events such
as contingencies and changes in demand. These changes will raise questions as to the adequacy of
existing System Standards, which tend to assume a historical pattern of power system operation and
performance. Implications of the change in generation mix for the operating limits and characteristics of
the power system, including interconnector limits, oscillatory stability limits, frequency control and
system restart processes and emergency procedures to name a few, need to be understood and
adapted to the future generation mix well in advance.
Some of the services provided to the NEM by generation facilities such as “inertia”, voltage control,
frequency control, and even the ability to vary production levels in response to five-minute dispatch
targets, have been abundant to date, as they are normal attributes of a portfolio of synchronous
generating plant. However, if over time the Generators providing those services leave the power
system, or do not operate for periods of time, those services will become progressively scarce, with
implications for managing power system security.
In response to the questions posed by SCO, this report identifies some of the anticipated technical
challenges of managing a low inertia power system, considers how equipped AEMO and the industry
are to forecast and manage these impacts, how emerging technologies may be positioned to either
reduce or exacerbate the identified issues, and outlines a forward work program that AEMO suggests is
required as a means of identifying the full range of prospective technical risks to power system security
and reliability. This report builds upon the technical issues raised in AEMO’s May advice, but focuses
primarily on challenges related to the changing generation mix with a focus on inertia.
1
2
Available at https://scer.govspace.gov.au/files/2015/09/AEMO-Security-and-Reliability-in-the-NEM.pdf
A brief introductory description of the technical concepts of synchronous generation and power system inertia is provided at Appendix A.
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The level of inertia in the power system has broader challenges for system security which then can
ultimately impact supply reliability. AEMO’s day to day operation of the power system focuses on
maintaining the system within the secure operating limits, and AEMO has a range of mechanisms
available to it under the National Electricity Rules (NER) for achieving this. Examples include imposing
constraints on generation to keep network flows within safe limits, and procuring frequency control and
network control services. Ultimately, AEMO might need to shed customer load to maintain power
system security. Given the emphasis on inertia, this advice largely focuses on the challenges and
implications on system security that arise from low levels of inertia.
The report outlines the role inertia plays in power system operation, and the potential attributes of a lowinertia power system. The regions of the NEM where low inertia levels are likely to first arise are
identified, and the technical, regulatory and information challenges associated with forecasting and
modelling the dynamics of a low inertia power system are discussed. Some of these challenges have
been explored at a preliminary level in AEMO’s current program of work on the integration of
renewables in South Australia, but further detailed analysis is required. The importance of
understanding these challenges cannot be underestimated, as without the ability to accurately model
and forecast the power system, AEMO will not be able to operate the markets and power system.
Some challenges have already been discussed in the New Products and Services work led by the SCO
Energy Market Reform Working Group, but a large number of others remain to be identified or
acknowledged.
Regardless, there is little doubt that these challenges will have implications for current operational and
regulatory frameworks. Additional to the work AEMO is doing to progressively model and adapt its
processes to the evolving power system within current regulatory arrangements, it is important to
separately look further ahead to understand the need for regulatory changes and operational strategies
that can maintain a secure and efficient power system when there is little synchronous generating plant.
AEMO intends to continue its current modelling work with the initial focus on South Australia where
challenges are likely to arise first, and recommends that SCO establishes a means of monitoring and
co-ordinating the findings that might emerge from the work of various agencies including AEMO, in
relation to the integration of emerging technologies with a view to considering the need to advance any
necessary policy developments.
At present, and in the immediate future, AEMO, and the market as a whole, is able to respond to these
challenges and continue secure and reliable operation of the power system. However, with the potential
future exits of conventional generation, the market topology will continue to change and challenges will
become more frequent and significant. This creates an imperative to act now to develop the appropriate
models and frameworks to address issues before they arise.
The role of inertia in the power system
 Inertia is a function of the mass of the rotors of conventional generators, which are synchronous, or
all rotating in lock-step with each other across the interconnected power system. This inertia of
conventional generators acts to resist rapid changes in power system frequency, in a similar way
to a very fast frequency response service. It therefore acts to dampen the rate at which frequency
can change on the power system as a whole. Deviations in system frequency occur when there is
an instantaneous imbalance between demand and supply. The greater the amount of inertia
available on the power system, the slower the frequency of the power system will change in
response to a particular disturbance, such as that trip of a generating unit. Conversely, for a
system with low inertia, the faster the system frequency changes for a given disturbance.
 An increase in the rate of change of frequency (RoCoF) has implications for power system security
because traditional control systems such as contingency frequency control ancillary services
(FCAS) and under-frequency load shedding (UFLS) schemes might not respond quickly enough to
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GENERATION MIX
arrest and contain a frequency disturbance. Further technical analysis needs to be performed to
determine at what point RoCoF due to reduced power system inertia becomes unmanageable
under a range of normal and abnormal scenarios.
 Currently there is an inconsistency in the NER which require generating units to remain connected
through an event where RoCoF reaches 1 Hertz per second, but there is no System Standard
which requires the power system to be operated so the RoCoF during any contingency event is
always maintained at this level or better.
 The changing generation mix also has implications for the provision of other frequency control
services. FCAS are provided by conventional generators, so the availability of services is affected
by the operational availability of generators. Withdrawal of conventional generations can therefore
give rise to FCAS shortages in parts of the power system that can separate to form islands such as
South Australia and Tasmania, unless the services can be provided by emerging technologies or
through special operating arrangements.
Where will issues arise
 While the national grid remains intact and stable, electrical frequency is the same across the whole
grid. AEMO is able to recruit FCAS from any source regardless of its location. Similarly all
generators synchronised to the system contribute to the overall inertia available to the grid and
provide FCAS.
 At present, there is sufficient inertia and sufficient FCAS available from conventional generators,
and accessible across all the NEM regions connected synchronously, to maintain system security
and for AEMO to meet the frequency control standards set by the Reliability Panel except for
South Australia. The South Australian jurisdiction in 2001, due to concerns about limited FCAS
services being available in the region, formally requested AEMO (then NEMMCO) to operate to a
more relaxed standard for credible contingencies that result in separation of the South Australian
region from the remainder of the NEM.
 It is unlikely that the changing generation mix will give rise to material technical difficulties for the
NEM power system as a whole in the foreseeable future. However, there is potential for technical
issues to arise much earlier in parts of the network that are experiencing high concentrations of low
inertial renewables, AND which can readily island from the rest of the power system. For example,
South Australia, Tasmania and potentially also Northern Queensland.
 Low levels of inertia become more likely with reducing operation of synchronous generation. This
includes some regions or sub-regions during periods of low demand and high renewable
generation when conventional generation is offline.
 Tasmania is not synchronously connected to the NEM and so cannot access mainland inertia. In
Tasmania, periods of low inertia are more likely to occur when demand is low, and the hydro units
are offline. Unlike conventional coal and gas fired generation, hydro generation is less likely to be
withdrawn from the market on a permanent basis because of their renewable status and flexible
operating capability. Furthermore, some hydro generation can operate in a “synchronous
condenser”3 mode which allows them to provide inertia and voltage control services at a modest
cost, providing a means of managing low inertia that is unlikely to be available in other NEM
regions.
 South Australia is synchronously connected to the NEM via the Heywood interconnector. In the
(non-credible) event of the loss of this interconnector, South Australia will need to operate as an
islanded system, relying on local generation to provide the required services. As more
3
Operation in synchronous condenser or syncon mode involves synchronising the hydro generation to the power system, so it is rotating at normal
synchronous speed, but not generating energy and not using water resources. The generation therefore operates effectively as a large motor
with no mechanical load.
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REPORT TO COAG ENERGY COUNCIL ON SECURITY AND RELIABILITY IN THE CONTEXT OF CHANGING
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conventional generation withdraws, the South Australian system will be weak. AEMO is currently
progressing an exploratory study of the integration of renewables in South Australia in the context
of synchronous generation exits, and a report on that work is scheduled to be published in late
2015.
Challenges of forecasting a low inertia power system
 The changing dynamics of the power system will challenge traditional models used to carry out
technical analysis of the power system, and potentially some of the processes used to operate it.
Over recent years, the market has been shaped by a shift from centralised decision making to
investments based on economic and behavioural decisions at the consumer level, including
households.
 AEMO matches supply and demand at the transmission level through the five-minute central
dispatch process, complemented by FCAS. Generation dispatch is determined using a variety of
forecasts including operational demand, generation availability, wind generation, and shortly solar
generation. AEMO has extended the Australian Wind Energy Forecasting System (AWEFS) to
incorporate utility scale PV in the Australian Solar Energy Forecasting System (ASEFS). The
AWEFS and ASEFS forecasts are used in a number of market forecasting processes such as
Medium Term and Short Term PASA, and pre-dispatch processes.
 The existing processes for registration of participants in the NEM, central monitoring, control, and
security constrained dispatch provide the information required for AEMO to operate the power
system and forecast outcomes in all timeframes. This approach will be challenged by the emerging
generation mix which will present:
o a large number of small scale, embedded generation and potentially storage batteries
o limited avenues to obtain information on the location, size and performance of embedded
generation and storage
o limited controls on the technical standards applying to these generating units
o no ability to control the output of many of these generating units to maintain security.
This will make it increasingly difficult to forecast demand, supply and the behaviour of the power
system, and to manage the operation of the power system within its security limits.
 At present, AEMO is not fully equipped to analyse such a power system and forecast all the
potential technical issues that could arise, as current modelling tools are designed to represent the
dynamics of a power system centred on large synchronous generating units. This presents an
ongoing challenge, as the ability to accurately model and forecast the power system is essential to
its operation. More suitable modelling tools do exist, and AEMO started to explore their
applicability during the recent SRAS tender process.
 In building the tools to model a low inertia power system in both real-time and offline, there are key
modelling, regulatory, and information challenges:
 Modelling:
○ The increase of renewable generation introduces probabilistic elements into power system
modelling, which has traditionally been a discrete exercise. Unlike renewables, the
production level from conventional generating plant is not reliant on extraneous variables
such as sunshine or wind. Rather than a few central generating units providing a set value of
generation, AEMO needs to model the likely output of dispersed wind and PV generation
sources.
 Regulatory:
○ Currently, proponents of generation technologies less than 5 MW are exempt from
registration and so are not under the same regulatory obligations as their larger
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counterparts. Consequently, there is no visibility on the installation and operation of
embedded technologies. Information on the uptake of rooftop PV has been tracked only due
to the need to register for the Small-scale Renewable Energy Scheme (SRES). At present,
there is no obligation on consumers to register in respect of “behind-the-meter” technologies
such as battery storage. This creates a key operational challenge for AEMO as increasing
uptake of these technologies affects the ability to balance supply and demand. AEMO is
currently working through how the provisions in the NER will relate to batteries.
○ The increase in embedded generation means that AEMO has less control and visibility over
the power system. An example of this is the operational ownership of battery systems, with
various potential business models emerging. This means that systems may be controlled by
individual households, retailers, Network Service Providers (NSPs) or third-party
aggregators, each of which will have different impacts on the operation of the power system.
○ Emerging technologies having a shorter lifecycle than market planning and operational
frameworks. This means that regulatory frameworks and operational processes need to be
adapted to accommodate the emergence of known new technologies without being
prescriptive, so they can accommodate future technology developments with minimal
barriers.
 Information:
○ There is an emerging need for AEMO and potentially also NSPs to have access to more
sophisticated technical models of generating facilities than currently is the case.
○ The increasing incidence of small embedded generation facilities is progressively leading to
a reduction in the control and visibility of supply side options when compared to large
conventional generation that participates in the central dispatch process.
○ There is currently limited information available about the technical characteristics and usage
patterns of emerging technologies, including battery storage, to support analysis of their
impact on the power system.
○ Although it is still the subject of research, there is thought to be some potential for wind
farms and storage to provide a “synthetic inertia” in the form of a very fast energy injection to
the power system in response to frequency excursions. However, there has been little
analysis of the performance of such a service, particularly in the context of a low inertia
power system, and there has to date been no analysis in the context of the NEM. Further
work is required to determine whether a form of synthetic inertia from renewables can be
used to similar or equivalent effect to real inertia.
 There is some work internationally looking at low inertia power systems, particularly in Ireland and
Texas. These have been focussed on developing new ancillary service markets to support
operation within the required standards, and are still in development. The NEM is different from
these systems in that it is standalone, has large portions that can separate from the main grid
(island), and has regions with a high penetration of embedded generation. While the international
work can provide some insights, it is critical that we understand the specific technical issues that
are likely to arise in the Australian power system, or in parts of it.
AEMO’s current progressive analysis
 The South Australian power system has been the focus of a considerable amount of initial
exploratory analysis because it has a high and quickly growing concentration of low inertia
renewables, and can therefore serve as a test case for the rest of the NEM.
 The work has focussed primarily (though not exclusively) on analysing the implications of the
progressive withdrawal of conventional generation. This is consistent with AEMO’s normal
operational planning responsibilities which depend upon detailed analysis of expected future
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operating modes to ensure power system limits are well understood in advance. However, as a
consequence of this focus, the analysis has not looked further forward to explore the implications
of all, or nearly all, supply to South Australia being from low or no inertia plant on some occasions
in the future.
 The work suggests that in the near-term, AEMO can manage power system security and supply
reliability in South Australia using current modelling tools and within the current regulatory regime.
A report on the work done to date will be published in late 2015, and will set the scene for a more
structured approach to be taken in the next stages of crystallising future challenges.
 However, the analysis AEMO has done to date is limited in scope and so does not provide all the
necessary insights into a low inertia power system. There is potential for the displacement of
conventional generation in South Australia to continue to the point where only low-inertia plant
operates for significant periods of time. The timing of that process is not known at this stage,
however, it is imperative that we build an understanding of the dynamics of such a power system
sufficiently early for preparations to be made, be they changes to the NER, the System Standards,
Access Standards, market mechanisms or other areas.
Further Analysis to step ahead of current frameworks
 AEMO will continue to analyse the progressive changes to the power system, its characteristics
and its limit, as low inertia plant displaces synchronous plant. This work will use current modelling
tools and current generating plant models to gain insights into the next few years of operation. As
new operational conditions are progressively encountered, this approach enables AEMO to
calibrate its models to the observed new system dynamics, and continuously assess their validity.
However, it is anticipated that a point will be reached where current modelling tools become unable
to reflect the changed power system characteristics sufficiently accurately, or current regulatory
arrangements do not support the availability of sufficient information or services to have confidence
in further development of secure operating strategies.
 To provide a means of planning beyond that point where current modelling and regulatory
processes become challenged, it is important to separately look further ahead to understand and
prepare strategies for management of a power system with very little synchronous generating
plant. Such a process would aim to identify all the emerging and potential technical issues of a
power system with little synchronous generation in both the distribution and transmission space.
Once such a list of technical issues has been developed, it would inform the priorities for further
analysis and the need for regulatory reform.
 Both these processes will be beneficial to understanding and facilitating efficient operation of a low
inertia power system. The first will be driven by AEMO as part of its core responsibilities. The
second should seek to include input from industry sectors, potentially through a specialist
reference group, similar to the process driven by SCO in 2004 to identify the technical challenges
likely to arise in relation to the integration of emerging wind generation at that time. AEMO is
considering initiating and leading this process with a technical focus.
Potential policy implications
At this stage it is premature to specify what policy changes might be required. The technical analysis in
the two streams of work identified above are designed to identify the technical issues which could drive
policy and regulatory responses to accommodate the continued integration of renewable generation in
the NEM in a similar way to the process carried out in 2004 for wind generation. This could be
combined with other drivers that might emerge from commercial or market analysis being carried out by
AEMC, AER or SCO.
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Next Steps
AEMO has expanded and formalised its current modelling studies on the integration of renewables in
South Australia into a broader work programme that has a two-pronged approach to investigating the
operational issues of the changing generation mix:
1. Business as usual operations
AEMO will comprehensively model the operating characteristics and limits of the South
Australian power system as synchronous generating units are progressively displaced by solidstate connected low inertia plant. This will be undertaken within current regulatory and technical
frameworks to explore operational challenges that may emerge within a two to three year
outlook, and identify any changes to operational procedures or the regulatory framework that
may be required sufficiently in advance of the need. This work-stream will ensure ongoing
transparent operating strategies that can deliver a secure power system for the two to three
year timeframe.
2. Longer term operations
In parallel, AEMO will look further ahead to consider a potential zero or low inertia future power
system, and as a first step, aim to identify the range of technical challenges likely to arise in its
operation. AEMO intends to bring together a group of industry specialists to inform this workstream.
AEMO will report the progress on both work-streams to Ministers at the mid-year meeting of the COAG
Energy Council in 2016.
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CONTENTS
EXECUTIVE SUMMARY
3
1.
INTRODUCTION
11
2.
CONTEXT
12
3.
FORECASTING THE IMPLICATIONS OF A LOWER
INERTIA POWER SYSTEM
15
3.1
3.2
Attributes of a low inertia power system
Where will issues arise?
4.
FORECASTING AND MANAGING A LOW INERTIA
POWER SYSTEM
24
4.1
4.2
4.3
AEMO’s operational forecasts
Challenges of modelling performance of a low inertia power system
How equipped is AEMO to model the dynamics of a low inertia power system?
24
26
31
5.
CURRENT REGULATORY ARRANGEMENTS
5.1
System and Access Standards
6.
ADAPTING TO A LOW INERTIA POWER SYSTEM IN
THE FUTURE
6.1
Next Steps
APPENDIX A. GLOSSARY
15
20
35
35
36
38
39
TABLES
Table 1
Table 2
Table 3
Table 4
Proportion of rooftop PV relative to residential and commercial native consumption
Comparison of South Australian renewable penetration with some international grids
Summary of current operational forecasts and planning tools
Example of some required information for storage systems
12
22
25
27
FIGURES
Figure 1
Figure 2
Figure 3
Figure 4
© AEMO 2015
Installed capacity of renewable generation in the NEM
Example of frequency deviations following a contingency event
Forecast of operational minimum demand in South Australia
Duration curve for the level of online inertia in South Australia
12
17
20
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GENERATION MIX
1.
INTRODUCTION
On 13 April 2015, the COAG Energy Council Senior Committee of Officials (SCO) requested that
AEMO provide confidential advice to the COAG Energy Council that covers:
 AEMO’s current ability to forecast, measure and manage the impact of low or no inertia generation
technology on the power system.
 Whether AEMO is able to manage the resultant impacts under the existing regulatory
arrangements, and to what degree.
 Whether AEMO will continue to be able to forecast, measure and manage the impact of emerging
technologies, on the power system and to continue to effectively maintain the reliability and
security of the network under the current regulatory arrangements, and
 Advise on any direct mechanisms, technologies or other measures which are required to ensure
minimum levels of system reliability and security in the NEM regions are maintained without
creating barriers to new entrants and is technology neutral.
This advice draws on insights gained from AEMO’s range of annual forecasting and planning studies,
including the National Electricity Forecasting Report (NEFR 4), Electricity Statement of Opportunities
(ESOO5), and the National Transmission Network Development Plan (NTNDP 6). These studies have
started to identify the changing generation mix and explore the implications for the power system.
AEMO has also had the benefit of a limited amount of work that has been undertaken internally to
specifically examine the challenges likely to arise from these changes.
AEMO is able to manage any issues that may arise in the short-term, although the withdrawal of
synchronous generating plant in some parts of the network could give rise to increased operational
challenges. In the medium to long term, however, AEMO’s ability to forecast and manage the
operations of a low inertia power system with a significant proportion of intermittent and uncontrolled
generation may be challenged.
At this stage, the full extent of the technical challenges that may emerge have not been fully
understood. Nor has AEMO determined the effectiveness of the current arrangements to deal with
these challenges. It is therefore premature to consider potential long term mechanisms or measures
until all the issues have been identified and considered.
As a result, this report does not directly answer the questions asked. Rather it outlines the role of inertia
in the power system and, in particular, its impact on frequency management. It then considers how well
equipped AEMO is to forecast and manage these impacts and how emerging technologies may reduce
or exacerbate identified issues. Finally it outlines our proposed approach to identify and quantify the
range of technical risks to power system security and reliability.
Given the technical nature of this report, a glossary of some key terms is provided in Appendix A.
4
The 2015 NEFR can be found at: http://www.aemo.com.au/Electricity/Planning/Forecasting/National-Electricity-Forecasting-Report
The 2015 ESOO can be found at: http://www.aemo.com.au/Electricity/Planning/Electricity-Statement-of-Opportunities
6
The 2015 NTNDP is scheduled to be published in November 2015
5
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2.
CONTEXT
The generation mix in the National Electricity Market (NEM) has been changing over the last six years,
with renewable energy becoming an increasing component, driven by a combination of policy
incentives, consumer behaviour and advances in technology making alternative energy sources more
cost-effective.
Not only has the generation mix changed, but the ownership of generation is changing, with an
increasing proportion of embedded generation when compared to conventional transmission connected
generation. The 2015 National Electricity Forecasting Report (NEFR) projected that residential and
commercial photovoltaic (PV) in the NEM would increase from around 4 gigawatts (GW) in 2014-15 to
approximately 13 GW and 21 GW by 2024-25 and 2034-35 respectively. This growth offsets an
increasing proportion of consumption from the residential and commercial sector as shown in Table 1.
Table 1
Proportion of rooftop PV relative to residential and commercial native consumption7
Queensland
New South Wales
South Australia
Victoria
Tasmania
2014–15
5.7%
2017–18
9.1%
2.4%
8.4%
2.7%
3.0%
3.7%
11.9%
4.4%
4.9%
2024–25
2034–35
16.0%
6.3%
22.1%
8.6%
11.0%
20.2%
9.3%
28.5%
13.7%
17.4%
Figure 1 shows the amount of renewable generation installed in the NEM by region, as at August 2015.
South Australia has the highest wind and PV generation penetration of any NEM region, with about
1,475 MW of wind generation and 596 MW of PV generation installed. This represents about 41% and
16% of total installed wind and PV capacity in the NEM respectively.
Figure 1
Installed capacity of renewable generation in the NEM
QLD
QLD
Demand
Wind
PV
Hydro
3,940 - 8,900 MW
0 MW
1,336 MW
652 MW
SA
Demand
Wind
PV
Hydro
790 - 3,400 MW
1,475 MW
596 MW
0 MW
NSW
NSW
Demand
Wind
PV
Hydro
5,160 - 14,740 MW
649 MW
1,035 MW
2,650 MW
VIC
VIC – SA AC interconnection
(2 lines, 1 tower, 650 km)
VIC
7
3,600 - 10,580 MW
1,168 MW
759 MW
2,237 MW
NEM total
TAS
Demand
Wind
PV
Hydro
Demand
Wind
PV
Hydro
720 - 1,790 MW
308 MW
84 MW
2,261 MW
TAS
Demand
Wind
PV
Hydro
15 GW – 30 GW
3,600 MW
3,810 MW
7,800 MW
Native consumption refers to the total consumption of residential and commercial customers regardless of whether sourced from the grid or not.
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Having a high proportion of wind and PV generation can present operational challenges for some parts
of the network. This occurs as wind and PV generation, by themselves, are not able to provide the
required control and services to maintain the power system in a secure operating state. New and
emerging generation technologies, including wind, PV and storage, have a number of physical
attributes that differentiate them from conventional fossil-fuelled and hydro generation technologies, for
example lower inertia characteristics. New and emerging generation technologies are connected to the
grid through solid-state equipment (principally inverters), and so do not have any inertia.
Inertia is only one of a broad range of technical attributes that differentiate conventional synchronous
generation as currently installed on the power system, from new and emerging technologies as they are
currently being installed. Some of these attributes were touched upon in the earlier advice provided to
COAG by AEMO. By way of example, the following attributes are some of the better known:

Voltage control capabilities are inherent in synchronous generation, but not present in many
embedded technologies such as rooftop PV and distributed storage.

Contingency frequency control capabilities, where generating plant is configured to
automatically increase or decrease its generation level in response to local detection of a
predefined material deviation in power system frequency. This capability is inherent in many
synchronous generations, but requires additional configuration in most emerging technologies,
and in most cases the capability is not included.

Frequency regulation capability is where generation output is continuously adjusted by a central
process operated by AEMO to control power system frequency to a steady 50 Hertz (Hz) value.
This capability is also inherent in most synchronous generation, but is not included in most
emerging technologies.

Fault level contribution is a technical matter that supports the detection of faults on parts of the
transmission system. The fault level contribution of emerging solid-state connected
technologies is very low, which could ultimately challenge the effectiveness of conventional
protection systems which detect faults on the transmission and distribution networks.

Conventional under-frequency load-shedding (UFLS) facilities are installed in distribution
networks and are designed to detect very significant drops in power system frequency (as
might occur for example when there is a trip of generation or of an interconnector), and initiate
the controlled tripping of customer loads to quickly re-balance supply and demand. Due to the
rapid recent installation of rooftop PV within those distribution networks, there is potential for
some UFLS facilities to be less effective in re-balancing supply and demand than their design
objectives.

Power system stabilisers are installed with some synchronous generation to provide oscillatory
stability to the power system by dampening any deviations in the generation’s frequency.
The above is not an exhaustive list, but represents a sample of the technical challenges that AEMO is
considering. While it is important to tease out the challenges of each in turn, operational challenges of a
low inertia power system can only be addressed holistically, with issues potentially having different
levels of impact and urgency. However, the primary focus of this report is on the inertia of the power
system, consistent with the request from SCO. As system inertia has traditionally been a natural byproduct of conventional synchronous generation, and as such has never been “valued” as a market
ancillary service.
The level of inertia in the power system is expected to continue to decline with renewable energy
projected to grow. New generation capacity that is committed and expected to be commissioned
between July 2014 and February 2016 includes 219 MW of large-scale solar generation and 809 MW of
wind generation. With agreement reached on the LRET policy and proposed changes to Victorian
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Planning Provisions, the trend of renewable generation displacing conventional generation is expected
to continue.
Furthermore, changes in the market environment such as higher gas prices and declining grid-supplied
demand in some regions, will increase the likelihood of some synchronous generation being out of
service at any given time.
One result of this changing generation landscape will be a power system with a lower level of inertia.
Other considerations include a reduction in scheduled generating plant, and in generating plant that can
provide frequency control ancillary services or voltage control services.
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3.
FORECASTING THE IMPLICATIONS OF A
LOWER INERTIA POWER SYSTEM
Inertia is one of the several attributes of conventional generation that assists in managing the stability of
the power system. Although inertia is not an explicit requirement in the System Standards 8, it affects
AEMO’s ability to meet them. Its role is discussed below.
3.1
Attributes of a low inertia power system
In an electrical power system, inertia can be thought of as a measure of the mass of all the rotating
generating units connected to the power system. If a synchronous generating unit is online, it provides a
fixed amount of inertia to the power system; if it is not operating, it provides no inertia. As wind and PV
generation are connected via solid-state devices, they are electronically decoupled from the power
system and thus contribute no inertia9.
The magnitude of a synchronous generation’s inertia depends on its size and design, and is expressed
in megawatt seconds (MWs). A power system is made up of many generating units and motors
connected together electrically (magnetically coupled) by the transmission and distribution systems. All
generation connected together on the electrical system (synchronised) must spin at the same relative
speed, or frequency. The rotating parts of synchronous generating units or motors provide inertia to the
power system. That is, a tendency to resist a change in motion, or a change in frequency. This
maintains synchronisation.
This synchronicity enables conventional generation to provide an inertial response to deviations in
power system frequency that could occur due to faults on the transmission system, generation trips or
load trips which cause an imbalance between supply and demand:

If supply exceeds demand at an instant in time, system frequency will increase.

If demand exceeds supply at an instant in time, system frequency will decrease.
How quickly the frequency increases or decreases is referred to as the “rate of change of frequency”
(RoCoF)10, and it depends on the size of the generation or load loss (contingency) that caused it, and
the amount of inertia in the power system. The larger the contingency, the faster the frequency
changes, while RoCoF is inversely proportional to system inertia. High system inertia resists the change
in frequency and results in a slower, more manageable RoCoF.
If the power system has low inertia, it will slow down or speed up very quickly, making it difficult to
maintain frequency within acceptable limits, particularly after contingencies. Generation and load have
automatic controls that trip in response to frequency reaching certain thresholds. If the RoCoF is within
acceptable limits, this tripping of load or generation is utilised to arrest the frequency deviation, and
helps return the power system to secure operating levels. If, however, the RoCoF is outside those
limits, it can result in a cascading trip of load or generation.
The management of RoCoF is critical to maintaining system frequency within operational standards and
ensuring power system security, and is anticipated to be a challenge in operating a low inertia power
system.
8
See section 5.1.
Note, some newer generation wind turbines can provide some inertia. However, this is generally quite low and the performance has not been
verified.
10
This is often also referred to as df/dt.
9
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3.1.1
Frequency operating standards
The frequency operating standards are set by the Reliability Panel and prescribe the allowable
frequency deviations for different types of events: normal frequency operating band, credible events
(including loss of generation or load, forced network outage and separation), and multiple contingency
events. For credible events, the standard sets out the:
•
Maximum allowable deviation immediately following the event (containment).
•
Maximum allowable deviation one to five minutes after the event (stabilisation).
•
Time to restore frequency back to the normal frequency operating band.
There are a number of frequency operating standards, and the one that applies at a particular time is
dependent upon the region and the operational circumstances – for example, the standard that applies
when a region is interconnected will generally be different from the standard that applies when a region
is islanded. Tasmania has a unique set of standards, as does South Australia in the event that it
separates from the NEM.
In the NER, no standard is set for a maximum level of RoCoF on the power system. If a system
standard for RoCoF was in place, it would require the power system to be operated so the RoCoF
during any contingency event is always maintained within certain thresholds. Generation, on the other
hand, is required by their Access Standards 11 to remain connected through an event where RoCoF
reaches ±1 Hz/s.
3.1.2
Frequency control in the NEM
In the NEM, generation and demand are balanced through the central dispatch process, which includes
the dispatch of both energy and frequency control ancillary services (FCAS). The central dispatch
process operates on a five minute cycle, and AEMO forecasts the contribution from non-scheduled
generation to achieve the demand-generation balance.
The discussion below outlines the different means by which AEMO controls frequency depending on
the operating state of the power system. That is, during steady state operation and following
contingencies (credible or otherwise).
Regulation FCAS
Frequency regulation is a centrally managed frequency control process, where AEMO’s automatic
generation control (AGC) process detects minor deviations in power system frequency, and sends
“raise” or “lower” signals to generating units providing regulation FCAS to correct the frequency
deviation.
The minor deviations in power system frequency that are corrected by regulation FCAS can arise from
a range of circumstances that result in small mismatches between generation and demand. Examples
include demand variations within the five minute dispatch interval; variations in wind generation output
within the dispatch interval; the way generation moves from one target operating point to another;
scheduled generation not correctly following central dispatch targets; or a combination of these.
The definition of FCAS is designed to be technologically neutral, however, given the nature of the
services, these have traditionally been provided by conventional generations. Therefore, the availability
of FCAS may be affected by a change in the generation mix.
Low levels of inertia in the power system are likely to increase the frequency deviations in the fiveminute dispatch period that are controlled by regulation FCAS. In a power system with a greater
11
See section 5.1.
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proportion of variable, non-scheduled generation (such as wind and solar), operating the power system
over the five-minute cycle would require a greater reliance on regulation FCAS.
Contingency FCAS
Contingency FCAS is a decentralised process where providers of the contingency FCAS services
respond under their own local control to correct relatively material frequency deviations that might arise
from the larger demand–generation imbalances that occur following a sudden unplanned disconnection
of a load or generation from the power system (a contingency event).
Figure 2 shows the control of frequency in the NEM during normal operation, and following a
contingency event. In this figure, a contingency event (loss of generation) occurs at the time shown as
T1, resulting in a fall in power system frequency, which passes outside the normal frequency operating
range at T2. After T2, contingency FCAS would be used to arrest the fall in frequency, and to begin
restoring frequency to the normal range. The slope of the frequency as it drops is the RoCoF.
Figure 2
Example of frequency deviations following a contingency event
50.6
50.5
Contingency Frequency Range
Normal Frequency Range
Power System Frequency
50.4
50.3
Frequency (Hz)
50.2
50.1
50
49.9
49.8
49.7
49.6
49.5
T1
49.4
0
T2
10
20
30
Time (Seconds)
40
50
60
If frequency moves outside the contingency band, or the RoCoF becomes too high, emergency
protection equipment may disconnect generation (for a high-frequency event) or load (for a lowfrequency event).
RoCoF and the magnitude of the contingency event are key factors that determine the required
response from contingency services. AEMO uses separate calculations to determine the contingency
FCAS requirements for the NEM, and for the Tasmanian power system due to its different technical
characteristics and the characteristics of the Basslink Interconnector.
The current calculation of NEM global contingency FCAS requirements is determined within the
dispatch algorithm, and considers both the size of the largest contingency and the power system
demand. Contingency FCAS requirements are highest for large contingency sizes and low demand
conditions. For the NEM, at each dispatch run enablement instructions are sent out to FCAS providers,
and AEMO monitors the performance of enabled FCAS providers. Calculating contingency FCAS
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requirements for Tasmania also considers the inertia of the Tasmanian generating units, as contingency
FCAS requirements increase under low Tasmanian power system inertia conditions.
Given the time delay to activate contingency FCAS, the inertia provided by conventional generation
provides the first response to slow the RoCoF and, depending on the size of the contingency, can keep
the frequency within the specified band until FCAS services are deployed. This also means that the
power system may return to normal operating standards within a relatively short timeframe.
In a low inertia power system, the RoCoF will be greater in magnitude than that shown in Figure 2,
meaning that the frequency excursion will reach the threshold of the contingency frequency range more
quickly, reducing the required operational response time of stabilising control systems, and potentially
increasing the level of response services required in order to return to normal operating conditions. If
the RoCoF is too high, these services might not be sufficient or fast enough to arrest the frequency
excursion before it reaches unacceptable levels.
The consequences of this would be the automatic initiation of under-frequency load shedding and/or
generation tripping facilities.
This highlights the key considerations of frequency control in a low inertia power system:

Where do frequency control services come from?

How will the control systems of new and existing technologies behave with respect to larger
frequency deviations?

What is a manageable level of RoCoF?
Automatic frequency control schemes
If power system frequency deviations are large, then automatic frequency control schemes are
activated.
Under-frequency load shedding (UFLS) is instigated to manage frequency response following a noncredible event such as islanding of a region or loss of multiple generating units. UFLS is a distributed
system with relays in substations to trip local load blocks if frequency falls below a given level. The
settings and size of the load blocks is determined by AEMO to minimise the amount of load shed to
adhere to the frequency standards while also achieving an equitable share of load shedding between
regions.
If the RoCoF is very high for a particular contingency event, then there is a risk that UFLS schemes
might not operate quickly enough to be fully effective in arresting the frequency excursion.
Recent work by ElectraNet has shown the emergence of issues with UFLS due to the changing
generation mix. Many of the distribution feeders within the network that are connected to UFLS systems
have rooftop PV installed on premises supplied by the feeder, and can potentially represent a net
supply of generation rather than a load at some times of the day. In the event that these feeders are
automatically tripped following drop in frequency, their effectiveness will be reduced, or in the extreme,
the frequency drop would be exacerbated rather than being arrested. AEMO is currently reviewing
UFLS settings.
It is also possible to have events on the power system which raise frequency. To protect against such
events, generation has over-frequency tripping relays that effectively shed the generation. However, if
this tripping occurs in an uncoordinated fashion, then too much generation could be lost from the power
system, and the UFLS scheme might be initiated. This is avoided by coordination of the settings of
generation over-frequency relays.
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System restart ancillary services
System restart ancillary services (SRAS) are required to enable the system to be restarted following a
complete or partial system blackout. SRAS can be provided by two separate technologies:

General restart source: generation that can start and supply energy to the transmission grid
without any external source of supply.

Trip to house load: generation that can, on sensing a system failure, fold back onto its own
internal load and continue to generate until AEMO is able to use it to restart the system.
AEMO procures SRAS to meet the System Restart Standard for each region. The change in generation
mix may impact on the ability to provide sufficient SRAS in the future.
Network Support and Control Ancillary Services
AEMO can also procure Network Support and Control Ancillary Services (NSCAS) to maintain power
system security and reliability, and to maintain or increase the power transfer capabilities of the
network.
Transmission Network Service Providers (TNSPs) have primary responsibility for acquiring NSCAS
based on AEMO’s annual forecasts of NSCAS requirements over a five-year horizon.
AEMO can also request a TNSP to consider whether to make arrangements to meet an identified
“NSCAS gap”. If the relevant TNSP does not commit to meeting the gap and AEMO considers it
necessary to acquire NSCAS to prevent any adverse impact on power system security and reliability,
AEMO will acquire NSCAS to meet the gap.
AEMO can only forecast potential NSCAS requirements and procure these services for credible
contingencies.
3.1.3
Further challenges in balancing generation and demand
The role of the five-minute central dispatch process in balancing generation and demand was touched
upon above. The changing generation mix will have further implications on the ability to balance
generation and demand depending on the level of operational control AEMO has over the generation.
Demand is generally recognised as not being readily controllable, and although the central dispatch
process is capable of dispatching loads, it is optional in the NEM and rare for loads to participate. The
primary focus of the five-minute dispatch engine is therefore on the central control of generation over
various timeframes to follow demand.
To address the increased penetration of wind generation, AEMO developed the Australian Wind Energy
Forecasting Systems (AWEFS) to provide accurate forecasts of the wind generation to ensure that it
could be factored into the required dispatch of scheduled load calculations. AWEFS produces forecasts
for each of the outlook periods AEMO considers in operational planning, from the five-minute dispatch
to the medium term outlooks on power system adequacy of supply.
The increasing penetration of rooftop PV reduces AEMO’s ability to control the generation supplied to
the network, affecting the balance of generation and demand. This issue was investigated in the 2015
NEFR which developed prospective operational minimum demand forecasts for South Australia.
Traditionally, periods of minimum demand from the electricity grid have occurred in the evenings/early
mornings. The uptake of rooftop PV has seen this shift into the middle of the day, generally on
weekends or public holidays.
In 2015, minimum demand occurred on 26 December at 1.30 pm. At this time, the native demand of
1,235 MW was met by 445 MW of PV, and 790 MW of electricity from the grid. Figure 3 shows the
forecast impact of rooftop PV on operational minimum demand (note, this assumes no storage). This
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indicates that, under the current regulatory, technical and economic landscape with no technical
limitations in the distribution system, rooftop PV could supply 100% of South Australian demand at
certain times in the day by 2023-24.
Figure 3
Forecast of operational minimum demand in South Australia
This means that AEMO will progressively lose the ability to match generation and demand in South
Australia, and will be reliant on the interconnector to export this excess supply. Issues will arise both:
 If there is insufficient dispatchable plant within South Australia to follow the variations in
operational demand (contributed to by variations in demand, wind and PV).
 If the volume of uncontrollable PV exceeds local load and export capability.
3.2
Where will issues arise?
While the national grid remains intact and stable, electrical frequency is the same across the whole grid.
AEMO is able to recruit FCAS from any source regardless of its location. Similarly all generation
synchronised to the system contributes to the overall inertia available to the grid.
The power system can also be at low inertia during periods of low demand when the fewest generating
units are connected to the power system. This can be exacerbated by the increased share of renewable
generation which will further displace conventional generation in an economically efficient dispatch.
At present, there is sufficient inertia and sufficient FCAS available from conventional generation, and
accessible across all the NEM regions connected synchronously, to maintain system security, including
during credible contingency events except for South Australia. The South Australian jurisdiction in 2001,
due to concerns about limited FCAS services being available in the region, formally requested AEMO
(then NEMMCO) to operate to a more relaxed standard for credible contingencies that result in
separation of the South Australian region from the remainder of the NEM.
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It is unlikely that the changing generation mix will give rise to material technical difficulties for the NEM
power system as a whole in the foreseeable future. However, there is potential for technical issues to
arise much earlier in parts of the network that are experiencing high concentrations of low inertial
renewables, AND which can readily island from the rest of the power system. For example, South
Australia, Tasmania and potentially also Northern Queensland.
Tasmania is not synchronously connected to the NEM and so cannot access mainland inertia. The
Basslink Interconnector does however, have a frequency controller that can be used to control direct
current (DC) power to manage frequency deviations in either Tasmania or the mainland. In Tasmania,
periods of low inertia are more likely to occur when demand is low, and the hydro units are offline.
Unlike conventional coal and gas fired generating units, the hydro units are less likely to be withdrawn
from the market on a permanent basis because of their renewable status and flexible operating
capability. Furthermore, some hydro units can operate in a “synchronous condenser” 12 mode which
allows them to provide inertia and voltage control services at a modest cost, providing a means of
managing low inertia that is unlikely to be available in other NEM regions.
South Australia is synchronously connected to the NEM via the Heywood interconnector. In the (noncredible) event of the loss of this interconnector, South Australia will need to operate as an islanded
system, relying on local generation to provide the required services. At present, Northern, Torrens A
and B and Pelican Point Power Stations are classified for FCAS. As they progressively withdraw from
the NEM, or operate for less time, there is increasing risk of frequency control issues with the South
Australian system alone being weak.
3.2.1
The South Australian context
The installed capacity of renewable generation in South Australia at times exceeds regional demand,
and conventional synchronous generation have been displaced from the market, reducing the amount
of inertia available in the South Australian power system. Over the last year, the number of
synchronous generating units online in the region has at times reduced to four.
Figure 4 shows the duration curve for the level of online inertia in 2009-10 to 2014-15, and the impact
renewables and declining demand have had on displacing conventional generation. The displacement
of synchronous generating units is forecast to continue due to:
 The increase in the power transfer capability of the Heywood interconnector from 460 MW to 650
MW in 2016.
 Increased penetration of wind and rooftop PV generation.
 Forecast decline in operational consumption (see 2015 NEFR).
 Announced closures of Northern and Playford B in March 201713, and the announced mothballing
of Torrens A in 201714. While these closures have been announced, Playford B has not generated
since February 2012, and Northern has been operating at a capacity factor of 57.0% in 2014-15,
45.2% in 2012-13 and 48.2% in 2012-13.
12
Operation in synchronous condenser or syncon mode involves synchronising hydro generation to the power system, so it is rotting at normal
synchronous speed, but not generating energy and not using water resources. The generating units therefore operate effectively as a large motor
with no mechanical load.
13
https://alintaenergy.com.au/about-us/news/flinders-operations-closure-update
14
http://www.agl.com.au/about-agl/media-centre/article-list/2014/december/agl-to-mothball-south-australian-generating-units
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Figure 4
Duration curve for the level of online inertia in South Australia
In discussing the level of renewable penetration in South Australia, comparisons are often drawn to
countries such as Germany and Denmark. What is not often highlighted is that these countries are
synchronously connected to regions with large conventional generation, and these provide the
necessary operational balancing support.
The NEM is an islanded system and so the issues involved with the integration of renewables have
some unique characteristics. Regions that similarly represent single balancing areas are those with no
interconnectors (Hawaii), or only high voltage direct current (HVDC) ties to neighbouring regions
(Ireland, Texas). These are all known for their high penetration of renewables.
Table 2
Comparison of South Australian renewable penetration with some international grids
Balancing Area
Peak Demand
Annual Energy
Installed Wind
Installed PV
(% peak)
(% peak)
Texas15
68,000 MW
340 TWh
12,400 MW (18%)
300 MW (0.4%)
NEM
35,000 MW
194 TWh
3,600 MW (10%)
3,440 MW (10%)
Ireland (all island) 16
6,600 MW
35.4 TWh
2,325 MW (35%)
1 MW (0%)
South Australia
3,400 MW
13.2 TWh
1,475 MW (43%)
565 MW (17%)
Hawaii (Oahu)17
1,140 MW
7.0 TWh
99 MW (9%)
221 MW (19%)
Table 2 provides a comparison of these regions, and also provides a comparison of South Australia to
highlight the challenges that will emerge in the event of either the loss of the Heywood Interconnector or
the withdrawal of conventional generation. Some of the work currently underway in Texas and Ireland is
15
Electric Reliability Council of Texas
Eirgrid
17
Hawaiian Electric
16
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discussed briefly in Section 6. However, while the international work can provide some insights, it is
critical that we understand the specific technical issues that are likely to arise in the Australian power
system, or in parts of it. In particular, the South Australian region of the NEM is unique in its level of
penetration of both utility scale and embedded renewable generation.
AEMO has been continuing its work in the integration of renewable energy in South Australia and is
progressing an exploratory study in the context of synchronous generation exits. A report on that work
is scheduled to be published in late 2015. This study considered South Australia in the context of
normal operating conditions, credible and non-credible contingencies under conventional generation
exit scenarios, commencing with the current generation fleet.
The credible contingency considered was the trip of the remaining Heywood circuit when the other is
out of service, while the non-credible contingency considers the loss of both lines of the interconnector.
As this work was exploratory only, no new utility scale renewable generation was considered to enter
the market. The generation mix outlook is currently being modelled in the NTNDP which will be
published in late November 2015.
Overall, the work suggests that in the near-term, there are unlikely to be implications on power system
security and supply in South Australia except under the non-credible contingency event of losing the
Heywood Interconnector. The report to be published will set the scene for a more structured approach
to be taken in the next stages of crystallising future challenges.
However, as a consequence of this focus, the analysis has not looked further forward to explore the
implications of the withdrawal of multiple major power stations in South Australia, so that all, or the vast
majority of supply to South Australia is from low or no inertia plant.
There is potential for the displacement of conventional generation in the NEM, and initially in South
Australia, to continue to the point where only low inertia plant operates for significant periods of time.
The timing of that process is unknown at this stage, but a trend in this direction is evident in AEMO’s
2015 Electricity Statement of Opportunities.
Maintaining the security of the power system is core business for AEMO and a responsibility key
stakeholders expect us to rigorously perform. However, the changing generation mix presents risks for
the management of power system security that have not yet been defined to the level necessary.
In the short to medium term AEMO will need to adapt its processes within the current NER, policy
framework and technical paradigm. In the longer term however, it is expected that the NER and
regulatory framework, and most likely also the operational tools used to model and manage the power
system will need to change. Changes will need to be made sufficiently in advance of issues arising to
ensure AEMO can continue to meet its security obligations.
It is therefore imperative that AEMO builds an understanding of the dynamics of such a power system
sufficiently early for preparations to be made, be they changes to the NER, the System Standards,
Access Standards, market mechanisms or other areas.
In relation to the short to medium term, AEMO intends to comprehensively model the operating
characteristics and limits of the South Australian power system as synchronous generation is
progressively displaced by distributed, solid-state connected low inertia plant. The modelling would be
undertaken within current regulatory and technical frameworks, and aim to adapt operational
procedures, and calibrating modelling tools as the power system evolves.
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4.
FORECASTING AND MANAGING A LOW
INERTIA POWER SYSTEM
4.1
AEMO’s operational forecasts
The effective, efficient and economic planning and operation of the NEM power system relies on the
ability of both AEMO and Network Service Providers (NSPs) to:
 Model the most economic solutions to a power system flow limitations that result in congestion.
 Predict the behaviour of the power system when subjected to disturbances, with consequences on
system security and the potential for limitations to be placed on transfer capability.
Without accurate and reliable power system models and forecasts, particularly for the short-term
topology of the power system, the risk of inefficient planning and unsecure operation increases.
In the short-term, AEMO is able to manage and operate the NEM with its existing suite of models and
software. In the longer term, however, modelling the dynamics of a low inertia power system will
become challenging and test the limits of current models and modelling tools.
It is imperative to understand all these challenges and how best to model a low inertia power system.
Without the appropriate models, AEMO will not be able to manage and operate the market.
4.1.1
Demand forecasting
AEMO conducts forecasts of expected electricity demand in order to operate the NEM and plan the
network. A variety of forecasting processes are used to determine the level of demand for every
dispatch interval in the NEM. Then, using the submitted offers to generate electricity, AEMO produces a
schedule or timetable of generation to ensure that the forecast demand will be met based on the
requirements that the least expensive generation is dispatched and the power system remains in a
secure operating state.
As a prerequisite for maintaining generation and demand in balance, it is important for AEMO’s
planning processes to be informed in advance of any limits on the capacity of generating units to supply
electricity or networks to transport electricity. This enables the remainder of market participants to
respond to potential supply shortfalls by increasing their generation availability or network capacity.
Market participants are able to signal upcoming limitations on supply by means of a variety of planning
tools designed to improve the overall efficiency of the market.
AEMO produces pre-dispatch and Projected Assessments of System Adequacy (PASA) outlooks.
These provide market participants with information on supply availability and expected generating
capacity reserve levels to assist them make appropriate business decisions.
Pre-dispatch is a short-term forecast of supply and demand in the market. It is used to estimate the
price and demand for the upcoming trading day, and the volume of electricity expected to be supplied
through the interconnectors between regions. Generators and NSPs are required to notify AEMO of
their maximum supply capacity and availability, and this information is matched against regional
demand forecasts
The short-term and medium-term PASAs allow AEMO to monitor the future adequacy of generating
capacity based on the predicted availability of generating units at power plants. AEMO produces both
seven-day and two-year forecasts because of the variability of demand for electricity. They are used by
AEMO to ensure that adequate levels of reserve are in the system at all times, and by Generators and
NSPs to plan maintenance and standby outages.
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Table 3 provides a summary of the current forecasts and where inertia is considered.
Table 3
Summary of current operational forecasts and planning tools
Forecast
Outlook
Resolution
Description
Inertia considerations
Dispatch
5 minutes
Real time
Neural network model that forecasts
regional demand 5 minutes ahead in
order to determine more accurately the
dispatch price and reduce need for
frequency regulation
The dispatch is security constrained,
meaning that the optimisation takes
into account network constraints
and allows the power system to
remain secure for the occurrence of
any credible contingency event.
Within this process, the level of
inertia is considered, particularly for
transient stability limits.
5 min predispatch
1 hour
5 minutes
Similar to the dispatch forecast but uses the demand forecast for the first 5
minutes from the output of the dispatch algorithm, and for the remainder of the
outlook, uses demand changes based upon the historical average percentage
demand change relevant to the interval, derived from the previous two weeks’
of historical demand data.
Pre-dispatch
40 hours
30 minutes
Similar algorithms to above but instead
of relying on SCADA data for inputs,
they are measured off the power
system: available generation, network
configuration for each sequential half
hour. Objective is to maximise the
value of trade.
Incorporates a security constrained
dispatch with heuristic rules to
acknowledge uncertainties in
precise network limits where they
are dependent on actual network
switching status. Inertia is
determined using heuristic rules
where necessary, from the
generation dispatch, and is taken
into account in determining network
limits.
ST PASA
7 days
30 minutes
Assesses the expected supply and
demand of electricity for six days
starting from the end of the current predispatch period. No price inputs and
objective is to maximise reserves.
Incorporates a security constrained
optimisation that assesses reserve
levels and allocates contributions of
energy limited plant to maximise
reserves. Network constraints are
forecast in this process, and it
considers more heuristic rules than
above for considering inertia.
MT PASA
2 years
daily
Provides reserves forecasts for the two
year outlook.
Incorporates minimum reserve
constraints which optimise the
adequacy of generation capacity,
regional outage and lack of
reserves. Network constraints are
forecast as an input, and inertia is
considered as an outcome of the
capacity assessment.
4.1.2
Forecasting intermittent generation
The Australian Wind Energy Forecasting System (AEWFS) was established in response to the growth
in intermittent generation in the NEM and the increasing impact this growth was having on NEM
forecasting and dispatch processes, and planning tools. AWEFS forecasts are developed for each of
the range of timeframes of the various operational forecasts, from five minutes ahead to two years
ahead. They allow variable wind generation to be included in the central dispatch process in a manner
similar to conventional synchronous generation. Forecasts are produced for each wind farm, including
those not participating in the central dispatch process, to allow generation output outside the central
dispatch process to be considered in the demand–generation balance.
AEMO has extended this process to incorporate utility scale PV in the Australian Solar Energy
Forecasting System (ASEFS). Like AWEFS, forecasts for generation from solar farms are produced for
each of the timeframes in Table 3. These are treated in the dispatch, pre-dispatch and the short-term
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outlooks in the same manner as wind. AEMO intends to extend this capability to rooftop PV in the near
future.
4.2
Challenges of modelling performance of a low inertia
power system
In order to develop the ability to accurately model the performance of a low inertia power system, there
are many technical, regulatory, modelling and information challenges that need to be surmounted. At
present, all of these challenges are not yet known, and work must be undertaken to understand them. It
is anticipated that as AEMO progresses through modelling the integration of renewables in South
Australia, new challenges will be uncovered.
Some of the known challenges in the short and long terms are outlined below.
4.2.1
In the short term
In the short term, key challenges in modelling the performance of a low inertia power system are
concerned with technology uptake and performance.
Technology uptake and management
The ability to model any power system effectively requires visibility of all components. This becomes
increasingly more important and complex as the market shifts to greater embedded generation.
Monitoring and forecasting the installation of rooftop PV has been facilitated through the Small-scale
Renewable Energy Scheme (SRES) which requires all installations claiming the subsidy to be
registered with the Clean Energy Regulator (CER). Through this process, AEMO has been able to
access some of the key details relating to each residential rooftop PV system. However, as the subsidy
winds down or households upgrade or replace their panels, there will be no registration process to track
these installations, leaving AEMO and NSPs with less information on rooftop PVs.
Similarly, generation connecting to the transmission or distribution networks is visible through the
connection process, with generating systems greater than 5 MW required by AEMO to have
performance standards as specified in the NER.
However, proponents of small generation technologies on the distribution network are exempt from the
requirement for registration, and so are not under the same regulatory obligations. Subsequently, there
is no visibility of technologies behind the meter, nor control over their technical specifications.
The experience with rooftop PV has demonstrated that consumers are actively engaged in choosing to
install new technologies. In the short-term, it is anticipated that battery storage will become
economically viable for residential consumers, with the viability for commercial and large-scale storage
still being assessed. In June 2015, AEMO released the first step in its development of modelling the
uptake of residential battery storage18, and is undertaking studies to assess the system impacts of
storage uptake.
The underlying message from these analyses is the need to ensure appropriate mechanisms are in
place to allow AEMO to retain visibility of the amount of embedded generation and storage facilities in
the network, in particular their location, technical specifications and mode of operation.
As an example, Table 4 summarises some of the information required, and the consequences to the
system if it is not obtained.
18
http://www.aemo.com.au/Electricity/Planning/Forecasting/National-Electricity-Forecasting-Report/NEFR-Supplementary-Information
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Table 4
Example of some required information for storage systems
Location
Information required
Why it is required
Installations on the feeder level or by
postcode.


To retain visibility on the characteristics of each
feeder. This will be critical to services such as
UFLS.
To determine whether penetration levels
materially affect network operation.
Technical
Specifications
 Storage capacity
 Maximum charge/discharge
 Cycles
To understand performance, in particular how
quickly they can ramp up/down as this will affect the
required response to balance the grid.
Operation
 Is it coupled to a PV system? If so, what
size.
 Are they grid connected or can only
recharge from the PV system?
 How are the systems configured to operate
and who has controllability:
 The household, optimising for their
individual benefit based on tariff
structures and load profile.
 Retailers as part of a long-term leasing
agreement.
 NSPs who have accessibility to provide
value to the network.
 Part of an aggregation by a third party
which coordinates arbitrage and/or
participation in FCAS.
It is important to understand how storage devices
will respond in aggregate to market signals. If there
are discrete drivers such as tariff changes then
there could be step changes in operation that may
create inadvertent impacts on network.
The need to understand the operational performance and location of storage technologies extends to all
emerging technologies in the context of a low inertia power system. However, the potential uptake of
storage is highlighting the likelihood of a future paradigm shift in the dynamic performance of the power
system, and is beginning to expose some of the emerging challenges.
At present, it is unclear what the best mechanism is to track the uptake of storage, nor who the best
authority to do so is. Any framework will rely heavily on what, or who, ultimately drives the uptake.
Challenges also exist in the performance of larger scale battery storage, with the potential for
challenges to arise from the ability of these facilities to very quickly ramp up/down with implications for
local voltage and power quality, and for power system frequency. AEMO is currently working through
how the provisions in the NER will relate to large scale storage.
Understanding short-term performance: intermittency
To date, intermittency has been managed well in the NEM through the high quality of the AWEFS
forecasting system, the five minute central dispatch, and through the geographic diversity of the
intermittent rooftop PV and wind generation sources. The performance of these systems has not yet
been tested with utility scale PV or high concentrations of wind generation.
Battery systems could also potentially pose an intermittency risk depending on their operability and
penetration. If these systems were driven by market signals, electricity price for example, then there
could be a sizeable discharge from the batteries within milliseconds. This emphasises the importance of
understanding their technical specifications and management.
Understanding short-term performance: existing technologies
The ability to model the dynamics of a low inertia power system in the short term also relies on an
understanding of the performance of existing technologies with respect to frequency deviations.
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The minimum standard for new generation connections is that they can ride through a RoCoF of ± 1
Hz/s, however we do not have a clear understanding of the RoCoF protection settings for many existing
generating units. This means that there is limited visibility on the level of RoCoF that is manageable,
and will have an impact on the ability to model the dynamics of the power system under low inertia.
A consequence of this is that many of the modelling exercises assume a constraint that doesn’t allow
the system RoCoF to be outside ± 1 Hz/s. This then constrains a certain level of synchronous
generation to be online and makes it difficult to explore the low inertia environment, how control
systems respond to RoCoF or understand what level of RoCoF is manageable. These questions first
need to be explored in order to inform what performance requirements would be needed for new
technologies when they are displacing conventional generation.
Understanding the response to frequency deviations is particularly relevant for rooftop PV systems,
which do not have the same performance standards imposed. The inverters, however, have to comply
with Australian Standards which specify an over-frequency and under-frequency trip point. These
standards have been revised over the last decade as uptake increased, and there are various different
inverter products that do not perform exactly the same way. How inverters respond to frequency
deviations can impact the performance of control stability schemes. AEMO is currently looking at
inverter data to assess this issue.
Similarly, it has been suggested that some of the wind farms already in operation in the NEM can
provide inertia. This however, has not been either verified or quantified to date, and would need to be
investigated further in order to adequately model the dynamics of a low inertia power system.
It is also unclear how well the actual operational performance of the control systems for all existing
technologies have been tested to date.
4.2.2
In the long term
The modelling approach: forecasting supply
The increase of renewable generation introduces probabilistic elements into power system modelling,
which has traditionally been a discrete exercise. Unlike renewables, the production level from
conventional generating plant is not reliant on extraneous variables such as sunshine or wind. Rather
than a few central generating units providing a set quantity of generation, AEMO needs to forecast the
likely output of dispersed wind generation, rooftop PV generation, and in the future, storage devices and
potentially other new technologies. This introduces the need for greater management of variability and
forecast error into how AEMO operates and plans the market and the power system.
The modelling approach: representing demand
An issue experienced world-wide relates to how to appropriately represent the increasing levels of
embedded generation in power system simulations. Challenges include:
 Appropriate methods of aggregation.
 Appropriate representation of equipment (both generation and the devices interfaced with the
network, generally inverters).
 Forecasting the output of renewable generation facilities for various forward timeframes.
Embedded generation does not reduce the native demand consumed by customers, only the net
demand supplied by scheduled, semi-scheduled and significant non-scheduled generation through the
grid (operational demand). Modelling demand effectively requires the ability to simulate the native
demand as well as the expected output of any embedded generation.
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A reduction in operational demand and synchronous generation (as expected in South Australia), will
require more sophisticated demand modelling beyond the static load model that is currently used in
power system security assessments.
Furthermore, the forecast growth in embedded generation may necessitate the modelling of a greater
proportion of distribution networks to allow broader assessments of power system security to be
undertaken. This has not been performed to date, and AEMO is yet to determine the degree to which
the network models might need to be extended.
Technology life cycle and performance
Conventional generating technologies are well understood, have long lifespans, and investments were
made on economical principals. In general, if there was a projected long-term shortfall in supply, then
the building of new generation plant was considered.
The changing generation mix, in particular, the active participation of households, has added new
economic and behavioural dimensions into the market. Large scale renewable generation has been
incentivised through government policy settings, whereas small scale embedded generation is driven by
the individual business case, some cross subsidisation, and also behavioural factors such as a desire to
be more self-reliant from the grid. Investment timescales for embedded generation are much shorter,
with the cost of an average PV system in South Australia, for example, currently having a payback
period of around six years.
As well as investment timeframes becoming shorter, the lifecycle of embedded generation such as
rooftop PV is also much shorter than conventional generation. Questions are then raised about whether
these products are likely to be replaced at the end of their lifetime, and if so, are they replaced with
similar technology or something else?
The challenges these factors present to modelling include:

The need to include different investment drivers and time scales.

The shorter timeframes for emerging technologies means the technology mix might shift more
quickly, and will continuously evolve.

Understanding the dynamics and technology uptake in advance.
The shorter timeframes of new technology investments and life cycles also means that regulatory
frameworks and the technical envelope need to be able to accommodate a wide variety of potential
technologies. What make this challenging is that the development time for emerging technologies are
generally shorter than the lead times involved in decision making to implement appropriate frameworks.
As renewable and emerging technologies progressively constitute more and more of the generation
mix, AEMO needs confidence in the ability to procure ancillary services to enable it to maintain the
power system within operating standards.
There has been discussion about whether a form of “synthetic inertia” could potentially be provided by
solid-state connected facilities such as storage and windfarms, to provide a replacement for the inertia
that is lost from the power system as synchronous plant retires. Synthetic inertia refers to the
augmentation of the central control system of wind turbines that convert some of the kinetic energy of
the rotating blades into electrical energy that provides a resistance to material changes in power system
frequency.
Although feasible, AEMO has not been able to find any cases where this synthetic or emulated inertial
response has been adequately demonstrated in practice to date. Turbine manufacturers have been
working on the development of this capability but the technology has not as yet been tested in a low
inertia power system. Simulations have shown that the emulated response is not identical to the
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response of conventional generation, and may not be sufficient to arrest frequency excursions during
contingencies in all cases. Much of this appears to be due to the reduced energy output of the turbines
following the provision of inertia.
The uncertainties in synthetic inertia can be summarised as follows:
 The ability of various renewable technologies to provide synthetic inertia.
 The amount of inertial response that can be guaranteed.
 Whether the emulated inertial response can be sustained for the time period required to arrest and
recover frequency deviations.
 Investment cost of adding a synthetic inertia capability (either as part of a new build or retrofitted to
existing plant).
 Whether the provision of inertia has implications for the lifetime of the turbines and/or on the power
electronics.
 Whether synthetic inertia can provide additional power system support services.
Much work would need to be undertaken to understand the technical performance of synthetic inertia,
and whether any performance standards or such should be contemplated in relation to its provision.
As synthetic inertia is not a direct substitute for the actual inertia of synchronous generating plant, it will
also be important to develop an understanding of the amount of synthetic inertia required to have the
equivalent response of existing generation in the NEM.
Frequency control management may also be able to be provided by batteries. Batteries have the
advantage in that they are able to provide a rapid response (within a millisecond), and so are being
considered as a fast frequency response service in Texas and Ireland. Currently, the performance of
batteries is being assessed in various trials, including the University of Adelaide’s mobile energy
storage test facility which will provide data on battery performance.
An important criteria in the ability of batteries to counteract power system imbalances is their lifetime.
Batteries typically have a limit to the number of charge / discharge cycles they can sustain, so one
would need to consider whether the sole purpose of the battery was to provide frequency response
services, or whether system support services are intended to be a secondary function of the storage
system.
There is a potential for synthetic inertia to be provided in many ways and by many technologies both on
the supply and demand sides. Regardless of the technology, there needs to be confidence in the
deliverability of the required RoCoF management levels.
Investment uncertainties
One of the challenges of modelling the dynamics of a low inertia power system is that there is no clear
indication of what investments will take place, when it will occur, in what technologies and to what scale.
Historically, the long-term demand could be forecast and would indicate any projected supply shortfalls
that would drive new investment in conventional synchronous generating plant. In today’s market
however, other than policy drivers, investment signals are more complex and the investment responses
to them more complex, particularly with the broadening range of consumer engagement and choice that
is opening up.
Large scale generation that is required to classify as scheduled becomes visible to AEMO when
proponents apply for connection. While this provides some transparency in investment and some
regulation over technical performance, it only provides an approximate two year window, rather than a
long term approach. This may be complicated by the emergence of new technologies. For example, will
new renewable generation have synthetic inertia capability or a battery storage system? If they have
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storage, will the device be behind the meter and serve to smooth out generation, or will they be in front
of the meter and available for system support services? Storage is likely to be considered in the
business case of new renewable generation to optimise the value of trading and operations, and in the
case of South Australia, may reduce the time a wind farm is constrained off for the purposes of
managing network flows within secure operating limits.
Understanding what technologies will enter the market will be critical to assessing what will be the
operational requirements to maintain the power system within operating standards. With the changing
dynamics of the power system, new investments will likely need to be considered systemically rather
than as individual connections which is the current process. Rather than solely analysing a proposed
generating system’s ability to meet the Access Standards, AEMO may need to undertake more regional
modelling to understand how the connection will impact on the operation of the broader network.
Conventional generation exits
Understanding the progressive impact of synchronous generation exits will be a long-term objective of
modelling the dynamics of a low inertia power system. Some of the broad issues were highlighted in
AEMO’s earlier advice, but many of the issues may only become apparent as the generation exits.
Research and modelling beyond the initial work AEMO has conducted on the South Australian system
needs to be undertaken as a high priority to explore the challenges that will arise in greater depth. This
modelling needs to be undertaken within the context of the new technologies that may also emerge.
As part of its annual National Transmission Network Development Plan (NTNDP), AEMO models
potential scenarios for the commissioning and decommissioning of conventional generation. This
provides some indication of potential generation exits, however, is limited by the nature of the
modelling. The modelling adopts a least cost approach that considers the short run marginal cost of
generating. As such, it doesn’t consider (nor does AEMO have the information to) any portfolio
strategies or risk management practices in the market.
In the context of frequency control, unless new technologies can provide the required services that are
lost through synchronous generation withdrawals, then planning and investment challenges may arise
to provide sufficient capability to operate the power system to meet reliability and security standards.
Depending on how the dynamic response of the power system changes, and the detailed technical
characteristics of the emerging technologies that are replacing them, the market responses may not be
sufficient to maintain the power system within a secure operating state for credible contingency events,
or to provide AEMO with the necessary operational options to exercise effective interventions.
4.3
How equipped is AEMO to model the dynamics of a
low inertia power system?
Currently AEMO has the analytical tools to model the dynamic response of the power system, and
these are being utilised in the studies of South Australia discussed in Section 3.2. These studies will
progressively test the power system as more low inertia generation comes online and synchronous
generation withdraws. It is anticipated that as this work progresses, AEMO will gain further insight into
how it needs to further develop and augment its modelling capability.
The current models, however, are based on conventional synchronous generation in response to
passive load, and focus on simulating the system response to transmission and generation faults, and
managing voltages and loading of the network within a range of technical limits. The limits can relate to
a range of criteria including thermal loading limits of the network, transient stability limits following a
contingency, voltage control limits, and oscillatory stability limits for power transfer across large
distances. Furthermore, the dispatch process optimises the utilisation of generation resources within
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these limits, while allowing sufficient operational margin for any single contingency event to occur while
still remaining within the limits.
In order to advance our understanding of the operational characteristics of a low inertia power system,
AEMO has developed a two-pronged approach which is summarised below.
Business as usual operational models
As the inertia of power system reduces, some of the operational limits will potentially change,
particularly due to the fast response of power system frequency to imbalances between supply and
demand. As outlined in Section 3.2.1, South Australia will be the first NEM region to experience low
levels of inertia.
AEMO is currently implementing a programme of work that will comprehensively model the operating
characteristics and limits of the South Australian power system as synchronous generation is
progressively displaced by distributed, solid-state connected low inertia plant. The modelling will be
undertaken within current regulatory and technical frameworks, and aim to adapt operational
procedures to meet the needs of the next two to three years.
This modelling will have a three year outlook, and considers a range of scenarios that are designed to
stretch the operational parameters of the power system. This work will include, but not be limited to
addressing the following:
 Is there a minimum amount of inertia that is required to meet security standards, and how does this
change depending on the technology mix?
 What is a manageable level of RoCoF to avoid progressive plant trips occurring?
 How does the effectiveness of the central dispatch system change with increasing penetration of
embedded generation?
 What constraints on the dispatch of generation or on interconnector flows need to be imposed?
Are conventional generation governor response capabilities appropriate?
 Modelling the performance of existing wind generation under weak network and frequency
disturbances.
Can South Australia be operated for sustained periods as an island if required?
 Whether current regulatory arrangements support the availability of sufficient information or
services to maintain system security.
The focus of the analysis is on maintaining power system security under system normal, credible and
non-credible contingencies. It will explore the likely extremes of generation mix that would need to be
managed within the two to three year outlook timeframe, and determine the operational actions required
to maintain system security. Information from this ongoing analysis will feed into the two year supply
adequacy reports that AEMO prepares as a normal part of its business – Energy Adequacy
Assessment Projection (EAAP) and MT PASA.
The ongoing analysis will equip AEMO with a bank of knowledge on the potential challenges of the
power system in the short-term and associated operational strategies. As the power system evolves in
this direction, AEMO can continuously calibrate its modelling tools to the changing system dynamics. At
some point, there is potential for modelling results to begin to diverge from the actual system dynamics,
and be unable to reflect the changed power system characteristics with sufficient accuracy. This will
potentially drive the need for AEMO to adopt different modelling tools.
Longer term requirements of operational models
In parallel to the operational studies of South Australia, it is imperative that AEMO steps ahead and
develops the tools and capabilities to model a low inertia power system so that we can transition our
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operational processes to the changing dynamics without compromising security and reliability of the
power system.
A package of work needs to be developed to help inform this process, and the initial step would be to
catalogue as many as possible of the technical issues that have the potential to arise due to the
integration of renewables into the power system and strategies for assessing whether regulatory
change is required to address them. Inertia related issues will be a component of those catalogued but
the focus will be broader than inertia, covering the full range of operational parameters such as
frequency control, voltage control, management of transmission flows, scheduling of generating plant
and management of contingencies.
Internationally, there has been some research on simulating a low inertia power system, however, the
work is still in the early stages and does not consider the levels of renewable penetration that currently
exists in South Australia. Research to date also tends to utilise generic wind generation models only,
and does not have the same level of embedded generation as is projected to occur in the NEM. Similar
to AEMO, several jurisdictions have started to embark on a program to advance their modelling and
planning for the changing dynamics of the power system.
What is becoming more apparent is that the key characteristics required from any generating plant and
power system models will be different. The power system will be more dynamic in that frequency
deviations will happen more quickly, and have a greater number of generating plants in geographically
diverse locations. The modelling and operational tools AEMO uses will then need to be able to
accommodate the increased dynamics of the system, as well as the increased number of generating
plant.
The models used include generating plant models, software models and the power system model. Each
Generator provides AEMO with set data on its plant’s operational performance that feeds into AEMO’s
power system models. In a system that is more dynamic, the models provided by Generators may need
to be more detailed, providing greater information about the control systems so that generating system
performance under a greater range of network conditions can be assessed. This will be particularly the
case for wind farms with emulated inertia or storage systems designed to provide a response to
frequency deviations, as well as the performance of any other new technologies.
Conventional power system analysis software was designed around centralised systems and so has
limitations on the number of generating plant and detail of their performance that can be
accommodated. This has the potential to create issues in the capability of the software to model the
power system with sufficient accuracy, and in the timeframe that is required.
Simultaneous to developing the software capability, how AEMO currently models the power system
could also need to change. This will be informed both by the South Australian work discussed above,
and the potential technical issues that may arise in the long-term. Some of the considerations may
include:
 As discussed earlier, generating forecasts will become more probabilistic, and the model will need
to consider greater variability and forecasting error.
 How dispatch algorithms need to change, and how they should treat increasing penetrations of
embedded generation, some of which, like storage, may respond to price signals.
 Given the increased penetration of distributed generation, how granular does the power system
modelling need to be?
 With an increased reliance on solid-state connected generation, there is a need to fully understand
the performance of the electronic control system on a short time scale, possible down to the level
of milliseconds, and have those characteristics incorporated into the overall computer model of the
power system as a whole.
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 How FCAS requirements are to be calculated given the potential range of new technologies and
services.
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5.
CURRENT REGULATORY ARRANGEMENTS
5.1
System and Access Standards
AEMO and TNSPs are required to operate the power system within the System Standards (as set out in
Schedules 5.1 & 5.1a of the NER), while Generators are required to ensure that their plant performs in
accordance with agreed performance standards, which are negotiated as part of the connection
process.
The Access Standards for generation are set out in Schedule 5.2 of the NER. These help AEMO
ascertain the performance characteristics of the connecting plant, which ultimately assists AEMO in
operating the power system within the System Standards. There are three types of Access Standards
for connection onto the NEM: automatic, minimum and negotiated which set different technical
performance requirements. In terms of frequency, the Standards require:
 That a generating unit should ride through a frequency disturbance provided the magnitude of any
deviation and its duration remains within the limits set by the Frequency Operating Standard.
 That the generating unit is able to withstand a rapid rate of change in frequency provided it does
not exceed 1 Hz per second (or 4 Hz for automatic connection).
 Generating units to have facilities to automatically disconnect or rapidly reduce output if frequency
exceeds the limit specified by AEMO.
 Generating systems to maintain stable output in response to frequency changes.
 For automatic connection, to not increase output if frequency rises or decrease output if frequency
falls, and must be capable of increasing output if frequency falls below normal operating band such
that it would be capable of providing raise FCAS.
Wind farms also have a minimum standard that requires them to not increase output in response to a
rise in frequency, and to not decrease output by more than 2% per Hz when frequency falls.
AEMO is currently working through how the provisions in the NER will relate to storage.
Furthermore, Access Standards do not apply to generating systems smaller than 5 MW. This means
that there is no visibility on the installation and operation of embedded technologies, nor does AEMO
have the ability to set performance requirements for these small consumer devices. As already
discussed, this has the potential to create operational challenges for AEMO as penetration increases.
As we progress towards a low inertia power system, new connections will need to be considered
holistically, rather than on a stand-alone basis, to ensure they do not adversely affect the power system.
This could lead to a need for Access Standards to be recalibrated as the dynamic response of the
power system changes, raising issues of fairness between new connections and incumbents.
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6.
ADAPTING TO A LOW INERTIA POWER
SYSTEM IN THE FUTURE
There is a considerable body of work to be done to fully understand the dynamic performance of the
Australian power system as low inertia generating plant gradually displaces conventional synchronous
plant. It is likely that AEMO will need to change the way it plans, forecasts and operates the power
system.
In determining the appropriate technical, regulatory and/or commercial frameworks that may be
required in the long-term, it is important to first identify and understand the technical issues the power
system will encounter – this involves the power system as a whole including both at the distribution and
transmission levels. Without this understanding, it would be difficult to identify the future options that are
holistic, technology neutral, adaptive to changing dynamics, and economically efficient. The analysis
discussed in Section 4.3 will assist to inform this process as well as other changes that may need to
occur.
In 2004, SCO initiated a process to identify the technical challenges likely to arise in relation to the
integration of emerging wind generation at that time, with the formation of the Wind Energy Technical
Advisory Group (WETAG). That process provided the opportunity for technical representatives from a
range of industry sectors to be involved in both identifying the questions to be answered and in building
support to carry forward any changes to the framework identified through the process.
AEMO is considering initiating a similar process, also with a technical focus, and with technical
representation from relevant industry sectors. Such a process can build upon existing work such as the
Clean Energy Council’s Priorities for Inverter Energy System Connection Standards19, and the work
identified by the Australian Renewable Energy Agency (ARENA)20. The former provides an evaluation
of the technical issues of solid-state connected distributed generation both as stand-alone and when
combined with storage, and then has prioritised the short term and longer term issues that need to be
addressed in developing effective standards. ARENA has provided a comprehensive catalogue of all
projects investigating the integration of renewables from research to demonstration, and across multiple
stakeholders. This provides a basis by which to identify technical issues that are currently being
explored.
AEMO’s process would aim to quickly identify as many as possible of the emerging and potential
technical issues of integrating renewables into the power system in both the distribution and
transmission space, and would step beyond the next few years. Once the technical issues are identified
and the challenges of a low inertia power system are better understood, AEMO and the industry will be
better positioned to advise on how best to operate the power system. This will then inform how the
current systems, standards and markets may need to change.
Without this analysis, we are unable to make a judgement on whether for example we need a minimum
level of synchronous inertia in the power system, or whether new technologies appropriately
incentivised can maintain power system security in the most economically efficient manner.
The exploration and modelling process will also help assess the adaptability of current market
mechanisms, and whether they provide efficient or even sufficient incentives to drive appropriate
investments, and if not, where and when they fail.
19
http://www.cleanenergycouncil.org.au/dam/cec/policy-and-advocacy/ARENA/FPDI/Priorities-for-inverter-system-standards.pdf
20
http://www.ena.asn.au/sites/default/files/Integrating-Renewables-into-the-Grid-Stocktake-v1-1.pdf
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Identification of the technical issues and the shift to a greater proportion of embedded generation
should also provoke an assessment of what is the most efficient role of NSPs. With the increasing
penetration of embedded generation, it is becoming increasingly apparent from AEMO’s perspective
that it will need to have a greater relationship with distribution networks in order to operate efficiently.
This in itself, represents a shift in how the market has traditionally been operated.
Internationally, some new frameworks are being developed as outlined below.
Texas
The Electric Reliability Council of Texas (ERCOT) is a stand-alone interconnection and wholesale
electricity market. ERCOT has a high level of wind capacity, and in 2015 had its record instantaneous
wind penetration of 41%21. This compares to the 65% of instantaneous wind generation in South
Australia recorded in the same year. ERCOT has been undergoing a review of its frequency control
ancillary services in response to the lower system inertia, proposing two new services as well as
refining the existing ones. The two new services are a Synchronous Inertia Response (SIR) and Fast
Frequency Response (FFR), and are designed to manage RoCoF. ERCOT is currently working through
the requirements of each, including technical specifications for batteries to provide FFR and synthetic
inertia capability for SIR, and the best form of procurement. A report on the cost-benefit analysis is to be
published late 2015.
Ireland
In the Single Electricity Market (SEM) in Ireland and Northern Ireland, the grid code requires generation
to withstand a RoCoF of ± 0.5 Hz/s only, and so the implications of RoCoF management in the low
inertia context are more pronounced. (This compares with the minimum standard of ± 1 Hz/s in the
NEM). The market operator has imposed a system non-synchronous penetration ratio, whereby the
total generation by non-synchronous plant is constrained to 50% of instantaneous system load. This
50% includes any net imports through the interconnector. This was applied to address the lack of
knowledge in how conventional generation would perform to maintain system security. The constraint
allows the operator to start to identify system operational limits.
Ireland has a renewable energy target of 40% by 2020 and is party to the European Union’s mandate
on minimising the curtailment of renewables. To address the future challenges, it established the “DS3”
project which included a series of technical and regulatory studies. This proposed a competitivelyawarded contract procurement mechanism for a new set of ancillary services. The services include
synchronous inertia and a fast-frequency response service, both targeted at RoCoF management. The
proposal is for a combinatorial auction where each bidder may offer a set of mutually-exclusive bids
covering combinations of services it is willing to provide, which are then evaluated to find an overall
lowest-cost solution, with a market-clearing fixed price found for both the inertial and frequency
responses. The project has also explored strengthening RoCoF protection requirements and enabling
emulated inertia measures.
New Zealand
New Zealand has a high penetration of wind and the two islands can be separated from each other. The
system operator has been investigating the power system response to disturbances, and at present,
has found the current dynamics to be adequate. They have highlighted the future need to acquire new
products to provide frequency management and synthetic inertia. They have also proposed new form of
UFLS, changing a block to a RoCoF relay to allow acceleration of load shedding following a large event
if RoCoF > 1.2 Hz/s.22
21
22
http://www.elforsk.se/Global/Vindforsk/Konferenser/Inertia%20seminar/Julia.pdf
System Operator TASC Report, TASC 033 report, July 2014.
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Quebec – Hydro Quebec
Hydro Quebec in Canada is adding wind energy to its predominantly hydropower system and is
requiring wind farms to provide an emulated inertial response. All wind farms greater than 10 MW must
be able to reduce large, short-duration frequency deviations (such as those during a contingency event)
at least as much as does the inertial response of a conventional synchronous generation whose inertia
equals 3.5 s. 23 It has worked with wind-farm manufacturers since 2009 to define specific parameters
that suit the power system requirements, and the performance testing of these.
Studies of system integration are ongoing.
6.1
Next Steps
While learnings can be drawn from the international experience, many of these new frameworks seem
to be a reactive response to provide surety of power system security and reliability in the near term
while investigating the technical issues that may arise in the long term.
The NEM has some characteristics in common and others that differ from those jurisdictions, and at this
stage it is premature to specify what policy changes might be required in Australia. In particular, South
Australia is well ahead of the international experience in terms of the changing power system dynamics.
The technical analysis in the two streams of work identified above can provide technical drivers for
policy and technical developments to accommodate the continued integration of renewable generation
in the NEM, and this could be combined with other drivers that might emerge from regulatory,
commercial or market analysis being carried out by other agencies.
In order to address these challenges, AEMO has expanded and formalised its current modelling studies
on the integration of renewables in South Australia into a broader work programme that has a twopronged approach to investigating the operational issues of the changing generation mix:
1. Business as usual operations
AEMO will comprehensively model the operating characteristics and limits of the South
Australian power system as synchronous generation is progressively displaced by solid-state
connected low inertia plant. This will be undertaken within current regulatory and technical
frameworks to explore operational challenges that may emerge within a two to three year
outlook, and identify any changes to operational procedures or the regulatory framework that
may be required. This work-stream will ensure ongoing transparent operating strategies that
can deliver a secure power system for the two to three year timeframe.
2. Longer term operations
In parallel, AEMO will look further ahead to consider a potential zero or low inertia future power
system, and as a first step, aim to identify the range of technical challenges likely to arise in its
operation. AEMO intends to bring together a group of industry specialists to inform this workstream.
AEMO will report the progress on both work-streams to Ministers at the mid-year meeting of the COAG
Energy Council in 2016.
23
Technical requirements for the connection of power plants to the Hydro-Quebec transmission system
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APPENDIX A. GLOSSARY
Introduction to Inertia and Synchronous generation
‘Synchronous’ generation is generation whose operation is tightly ‘synchronised’ to the operating
frequency of the power system.
For example, in a power system operating at a normal frequency of exactly 50 Hz, or 50 cycles per
second24, the rotating parts of most synchronous generating units (such as the turbine and rotor)
connected to the power system will be spinning at a speed of exactly 50 revolutions per second.
Each synchronous generating unit connected to a power system will be rotating at a precise speed that
is dependent on its design and the power system frequency, and are in effect tightly synchronised to
each other through the power system.
An effect of this ‘synchronous’ operation of generating plant is that any change is the operating
frequency of the power system away from the normal level of 50 Hz requires that all generation
connected to the power system either ‘speed up’ or ‘slow down’ exactly in lock step with the change in
power system frequency.
Historically, all significant generation connected to the power system was ‘synchronous’, as a result of
the underlying similarity of the generating equipment used. However, newer generating technologies
such as wind and PV are not, due to fundamental differences in the nature of the equipment used in
these technologies.
The non-synchronous (or asynchronous) nature of these newer generating technologies has a range of
implications for power system performance and operation, particularly in relation to the control of power
system frequency. Importantly, as asynchronous generation is dispatched and displaces synchronous
generation, the inertia in the power system is reduced. This is discussed further below.
Power System Inertia
Maintaining the frequency of the power system very close to the normal level of 50 Hz is a key day-today operational responsibility for AEMO. The frequency of the power system will change away from the
normal level of 50 Hz following disturbances such as sudden loss of generation or load from the power
system. A sudden loss of generation will cause the frequency or speed of the power system to fall as
mechanical energy is drawn from the remaining generation to supply the load. Conversely, a sudden
loss of load will result in less electrical energy being drawn from the generation by loads than is being
supplied to the generation from it energy source (such as steam boilers), with the imbalance resulting in
generation speeding up, increasing power system frequency.
Ensuring that the frequency of the power system does not move too far from the normal level of 50 Hz
after a disturbance, and restoring frequency to 50 Hz within certain time frames are key issues for
AEMO to manage on a continuous basis. The exact requirements around AEMO’s frequency control
obligations are spelt out in the Frequency Operating Standards, and determined by the Reliability
Panel.
Inertia is a physical attribute of an object that is related to its mass, and can be thought of as a
resistance to change in the motion of the object. For example, a small mass that is travelling at a
particular speed in a straight line will be easier to slow down (or speed up) than a heavier object
travelling at the same speed. The heavier object is more resistant to the change in speed, and has
more inertia.
24
The NEM power system operates at 50 Hz, while some power systems operate at 60 Hz.
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In power systems, the inertia of the rotating parts of the generating systems provide resistance to
change in the frequency of the power system. The physical manifestation of inertia on the power system
is in the large mechanical masses of synchronous generation and their turbines and rotors, and the
energy stored in these masses when they are operating and rotating at high speeds.
The amount of inertia a particular generating unit provides to the power system is a function of the
mechanical design and mass of the generation. The amount of inertia provided to the power system by
generation is the same whenever it is operating, and does not vary with power output. The exact
amount of inertia provided to the power system is a characteristic of each individual generating unit,
with larger generating units typically providing more inertia to the power system than smaller ones.
This means the inertia of the power system at a point in time is determined solely by which synchronous
machines are connected to the power system at the point in time. As the number of generating units
committed to the power system at any time is not directly managed by AEMO, this means AEMO does
not directly control the level of power system inertia. Inertia is instead an indirect outcome of the
operation of the energy market.
When the inertia of the power system is high, the frequency of the power system will change slowly
following a given disturbance. When power system inertia is low, the frequency of the power system will
change more quickly following a disturbance, all other things being equal. This means that managing
frequency within required limits on the power system becomes more difficult when the inertia of the
power system is low.
Under conditions of very lower power system inertia, frequency can potentially move too fast for control
systems to respond, potentially leading to automatic load shedding, or even complete collapse of the
power system.
Characteristics of asynchronous generation
Asynchronous generation such as wind or PV typically provides little or no inertia to the power system.
This is an internationally recognised issue, and some new wind turbines are now capable of providing a
response to frequency disturbances. However, the degree to which this can substitute for inertia is a
matter of research at this stage. If a substitute for inertia (sometimes referred to as synthetic inertia) can
be provided in this way, it is likely to be low compared to synchronous generation of equivalent MW
rating.
The displacement of synchronous generation from the power system by non-synchronous generation, is
driving a long term trend of reducing power system inertia, particularly in South Australia, with its high
penetration of non-synchronous wind and PV generation.
As AEMO does not currently have direct or central control over the levels of inertia in the power system,
reducing levels of power system inertia create a risk around AEMO’s long term ability to adequately
control power system frequency under the necessary range of future operating conditions.
Solid-state connected generation
Conventional synchronous generation connects directly to the power system as it shares the same
electrical characteristics, i.e. it generates alternating current (AC) at the same frequency as the grid.
Generation that does not share the same electrical properties as the power system require a device that
will convert the electricity they generate so that they can supply this energy to the power system. These
connecting devices are solid-state electronics, which means that they have no rotational properties,
relying instead on chemical and electronic characteristics. The most common solid-state device that is
used in grid connection is an inverter.
Both wind and PV generation is connected to the NEM via inverters but for different reasons:
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 Electricity generated by the rotation of wind turbines can be AC with the same frequency as the
turbine’s rotation. Given that the frequency is dependent on the rotational speed of the turbine, the
frequency of the power generated will vary as the wind speed changes. An inverter is used to
regulate the power output of the wind turbines, and convert it to the same characteristics as the
power system.
 PV panels (residential and utility scale) are made of semi-conducting material, with no rotational
components. They therefore generate DC electricity. An inverter is used to convert the electricity to
AC for both use in residential premises and for export to the NEM.
As these generation technologies do not directly share the same frequency as the power system, they
can be referred to as asynchronous generation.
Secure operating state
The power system is in a secure operating state if it is in a satisfactory operating state, or such that
should a credible contingency occur, the power system will return to a satisfactory operating state.
AEMO is required to assess the technical envelope, or technical boundary limits, of the power system
for achieving and maintaining the secure operating state for any events considered to be credible
contingency events at that time. The technical envelope takes into account demand, capacity reserves,
operating plants, constraints and ancillary service requirements.
The NER sets out the properties of the power system used to determine whether it is in a satisfactory
operating state, which includes frequency, voltage and current all being within their applicable bands,
generation operating within its performance standards, and the power system has the capability to
disconnect any fault.
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