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Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
Consumer-Led Transition: Australia’s World-Leading
Distributed Energy Resource Integration Efforts
It’s a sunny spring day in South Australia. A light breeze is cooling the coastal state capital of
Adelaide as approximately 260,000 distributed solar photovoltaic systems (D-PVs) on residential and
business rooftops generate electricity, setting a new State record for lowest minimum electrical
demand for the third time this spring.
All looks peaceful across the suburbs. D-PVs form an irregular yet persistent patchwork across one
third of houses in the state. Most consumers are going about their day without a glance at the D-PV
on these roofs. However, the mild temperature and bountiful sunshine see D-PV generation climb,
causing voltage to creep higher and power to flow in reverse across large swathes of the distribution
network. Some D-PVs are tripping off, unbeknownst to their owners or the local network operator.
The Australian Energy Market Operator (AEMO) is tracking falling demand and monitoring the
proportion of synchronous generation in the South Australian interconnected region. Engineering
teams are assessing the potential power system security implications of D-PV behaviour during
possible contingency events.
The state’s distribution network operator is monitoring and managing the changing voltages and
flows through the network. Other teams continue their work on developing innovative planning and
operational approaches – from new interconnection standards and flexible export limits to Virtual
Power Plants (VPPs) – for managing ever growing penetration of D-PV and, increasingly, home
Battery Energy Storage Systems (BESSs) and Electric Vehicles (EVs).
Meanwhile, consumers across the State are contemplating their most recent power bill, their
growing climate concerns, looking up at their empty roof space, and considering investing in D-PV
themselves.
1 State of play
The Australian National Electricity Market (NEM) serves approximately 90% of Australians through
one of the longest interconnected power systems in the world (Fig. 1). The electricity sector was
restructured in the late 1990s and features a regional wholesale spot market and retail competition.
Transmission and Distribution Network Service Providers (TNSPs and DNSPs) are regulated monopoly
businesses, separate from generators and retailers that purchase from the spot market and then sell
the electricity to consumers within deregulated retail market arrangements. AEMO is both the
independent system operator and market operator across the east and west coast of Australia.
1.1 D-PV uptake
Low PV system prices, excellent solar resource and a high proportion of stand-alone housing in
Australia, coupled with high retail electricity prices, have led to high D-PV uptake over the past
decade. Australia now has the highest proportion of houses with D-PV worldwide, with
approximately one in every four houses (all dwellings excluding apartments) having installed D-PV,
and over 2.2 million systems in total. The state of Queensland has the highest penetration of D-PV,
closely followed by South Australia (Fig. 1). However, the relative contribution of D-PV to demand is
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
much greater in South Australia compared with Queensland given South Australia’s smaller
industrial load and mild climate.
The South Australian DNSP is SA Power Networks (SAPN). In Queensland there are two DNSPs.
Energex serves the metropolitan south-east and Ergon Energy Network serves the more rural
northern and western consumers; both are part of the Energy Queensland Group.
While the majority of D-PV systems in Australia are small (less than 30kW AC capacity), there is an
emerging market in the 30kW - 200kW range for commercial and industrial sites.
Fig. 1. Australian National Electricity Market regions, penetration percentages are the proportion of
stand-alone household with D-PV. The graph indicates D-PV uptake and shows the volume installed
under the ‘legacy’ (pre-2015) and ‘current’ (post-2016) inverter interconnection standard across the
National Electricity Market. Note the inverter standard AS/NZS 4777 is currently under review.
Between 2018 and 2019 the number of new D-PV applications approved in South Australia alone
increased by 50%, and high D-PV uptake is widely expected to continue. Across the NEM, AEMO has
forecast D-PV generation to more than double by 2039-40 in all NEM market regions under a central
uptake scenario and to at least triple under a high uptake scenario. While D-PV is the most common
of the Distributed Energy Resources (DER) in Australia, other forms of DER including BESSs are also
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
increasingly prevalent. However there remains limited visibility of D-PV operation and minimal if any
remote interoperability.
1.2 Contributions to meeting NEM demand
D-PV is making increasing contributions to meeting demand, particularly during mild autumn and
spring conditions. At certain times of the day, D-PV in aggregate represents the largest single
generator in the NEM, reaching an estimated maximum of 6 gigawatts (GW) of instantaneous
generation in 2019 (or 23% of underlying demand).
In Spring 2019 D-PV contribution exceeded 50% of generation in South Australia for six hours on the
minimum ‘net’ system demand day (Fig. 2). Over the last decade, SAPN has observed a progressive
reduction in minimum demand each year across the distribution system (Fig. 3), and the rate of
reduction has accelerated in recent years, with minimum demand falling by ~200MW between
October 2018 and October 2019. As result, the entire distribution network is expected to be a net
source of power during minimum demand periods as early as spring 2020 (September-November),
while AEMO is projecting periods of zero net demand across all of South Australia by 2024-25 in
some scenarios. This has implications for distribution system operation as well as maintaining
system security, noting that South Australia often obtains inertia, frequency control ancillary
services, and system strength support through its AC interconnection with Victoria. System security
challenges are considered below and further details can be found in AEMO’s Renewable Integration
Study (RIS) (see “For further reading”).
Fig. 2. D-PV contribution on the 2019 minimum net load day in South Australia, Sunday 10 November
2019
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
Fig. 3. SAPN minimum loads (excludes major customers, includes major generation, D-PV netted off as
negative load), SAPN.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
2 The evolution of DER impacts
Significant volumes of DER present challenges and opportunities across the grid, requiring changes
to forecasting, planning, and operation. Fig. 4 illustrates the increased scope and depth of planning
for DNSPs. In addition to considering peak demand, network planners and operators now need to
estimate minimum demand and underlying demand (without D-PV generation). However, there
remains very limited visibility of DER, or indeed of the Low Voltage (LV) network. Trials provide much
needed insight into actual operational conditions and illustrate key challenges.
Fig. 4. SAPN: increasing depth and scope of network planning activities. For further details please refer
to SAPN Future Network Strategy 2017 in the “For Further Reading” section.
For instance, the SAPN’s Salisbury VPP trial connected 100 BESS coupled with D-PV at residential
premises in suburban Adelaide. Operational data from the trial demonstrates the evolution of DER
integration challenges in the distribution network. VPP implications for system operation are
considered in a later section.
Historically, the primary concern for planners and operators has been ensuring network thermal
limits are not breached during peak demand (Fig. 5a). High levels of D-PV make voltage management
a key challenge, as indicated in Fig. 5b. In this instance, VPP export is likely to be sufficiently large to
cause voltage rise outside the allowed range. The Salisbury trial highlighted that the orchestration of
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
DERs also poses new challenges. The trial showed that VPP operation can cause extreme peaks in
demand that significantly exceed the normal summer maximum load, e.g. when all batteries were
instructed to charge in anticipation of a storm front (Fig. 5c). Conversely, should a VPP be instructed
to discharge in the middle of the solar day during a high price event, or to provide frequency control
and ancillary services (FCAS), then voltage and thermal limits may be breached due to reverse power
flows (Fig. 5 d).
Fig. 5. South Australian Salisbury battery trial (a) existing thermal limit challenges during peak demand
(orange), (b) existing voltage challenges with high D-PV exports (green), (c) reduced peak demand with
batteries and observed peak during VPP charging event (purple), (d) modelled emerging VPP-driven
thermal limit challenges during VPP export events (dashed). For further details please refer to SAPN LV
Management Business Case 2019 in the “For Further Reading” section.
This article focuses on increased voltage ranges, reverse flows and D-PV implications for system
security, with each section below outlining challenges and solutions. However, further challenges
and opportunities are emerging, including implications for protection design in the distribution and
transmission system, reactive power management, under frequency load shedding and system black
start capabilities.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
3 Increasing voltage range
3.1 Challenges
Voltage management is growing more challenging in Australian distribution networks as extreme
summer temperatures drive air conditioning demand and D-PV uptake continues. The net effect is a
broader range of voltage conditions which can change rapidly over relatively short periods on a
single network feeder. Visibility in the LV system generally remains limited; however, some
monitoring exists and new techniques for data visualisation and analysis are emerging.
3.1.1 Existing voltage conditions
To comply with Australian Standard AS61000.3.100-2011, the V99% (99th voltage percentile) at a
customer point of connection must be no greater than 253V, and V1% must be no less than 216V.
Data from approximately 25,000 distribution transformer monitors across Queensland show that the
distribution of the 1st percentile voltage (V1%) measured at the distribution transformers appears
quite high compared with the lower limit of 216V. This margin is required to allow for voltage drop
to customers at the end of the LV network.
Voltage data from a significantly smaller quantity of about 4,000 LV monitors, typically installed near
the end of LV circuits (Fig. 6), demonstrate much lower V1% for customers distant from the
distribution transformer. The average customer’s voltage distribution in Queensland is likely to sit in
a narrower distribution than that shown in Fig. 6, which is illustrative of points at the end of the LV
network. Given limited LV network visibility, samples shown in Fig. 6 and Fig. 7 are not
representative of population-wide voltage conditions.
Fig. 6. Voltage Measurements for LV Monitoring on Energex Networks in November (Spring) 2019. Data
from ~4,000 LV monitors (of approximately 150,000 LV networks in Queensland). For further details
please refer to Energex and Ergon Energy Network Distribution Annual Planning Reports in the “For
Further Reading” section.
Customers at the ends of LV circuits are only exposed to the lowest voltages on a few days each year
when peak loads occur. DNSPs are responsible for maintaining voltage compliance in peak periods,
when maximum demand occurs, just as they must maintain compliance over the Spring and Autumn
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
months when loads are modest and reasonable solar irradiance results in minimum demand, events
that are likely to be observed significantly more frequently. Fig. 7 shows that during the weeks when
maximum demand occurs there is very limited room for further widescale reductions in voltage
levels.
Fig. 7. Voltage Measurements for LV Monitoring on Energex Networks in February (Summer) Peak
Week February 2020. Data from ~4,000 LV monitors (of approximately 150,000 LV networks in
Queensland). For further details please refer to Energex and Ergon Energy Network Distribution Annual
Planning Reports in the “For Further Reading” section.
3.1.2 Estimating PV curtailment
The curtailment of distributed PV generation due to high voltages in the distribution system has
received considerable interest due to the potential lost revenue for consumers with PV. In addition,
over voltage curtailment may limit opportunities for DER participation in the broader power system,
for instance through VPPs. Typically, curtailment occurs when local network voltages exceed inverter
over-voltage set points and the inverter ‘trips’ and curtails to zero power output, even when there is
behind the meter load (Fig. 8). In recent years, Australian DNSPs have moved to mandate that volt-
var and volt-watt response modes are enabled for new D-PVs, which allow for a more progressive
reduction in inverter output as voltage rises rather than relying on over-voltage trip settings.
Legacy D-PVs installed under the previous inverter interconnection standard tend to have higher
over voltage set points. Regions with high penetration of legacy D-PVs can therefore result in higher
voltages and greater levels of curtailment than amongst non-legacy D-PVs. The same standard also
applies to BESS and can prevent operation even when BESS are attempting to charge, which would
otherwise assist to alleviate over-voltage conditions.
An analysis of over 1,300 South Australian sites monitored by a solar monitoring company, Solar
Analytics, is presented here. This analysis examines 24 clear sky days and is therefore expected to
capture high curtailment conditions. Findings indicate that overall levels of PV curtailment due to
over voltage tripping are currently low, with an average of just 1% of generation being curtailed per
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
site overall. However, these impacts are not evenly distributed and some sites are badly affected,
losing up to 45% - 95% over a particular day (Fig. 9) with clear equity implications.
The most extreme curtailment is observed to occur in spring (September – November) where mild
temperature coupled with strong solar resource appears to result in local network voltage rise (Fig.
10). Customer inquiries in the SAPN area relating to PV and over voltage also display a seasonal
pattern and peak during spring (Fig. 11).
Fig. 8. Example of PV curtailment and loss of self-
consumption at a single site in South Australia on 5
March 2017
Fig. 9. Distribution of PV curtailment, where each
data point indicates an individual site that experienced
curtailment in South Australia over 24 clear sky days in 2018
(1851 distinct sites in the data set, 983 experienced curtailment)
Fig. 10. Spread of D-PV generation lost over the year
(impacted consumers only)
Notes: centre line indicates median, box edges
indicate 25th and 75th quartile, whiskers indicate 1.5x
interquartile range, black dot indicates average, grey
diamonds indicate outliers
Fig. 11. SAPN high voltage / D-PV-related customer enquiries,
spring (Sep-Nov) indicated in orange. For further details please
refer to the SAPN Low Voltage Management Business Case in
the “For Further Reading” section.
3.2 Solutions
3.2.1 Evolution of voltage management techniques
Australian DNSPs are pursuing a number of voltage management techniques as D-PV penetrations
increase. One traditional method of mitigating end-of-line-voltage spread on medium voltage (MV)
feeders with similar load profiles is with Line Drop Compensation (LDC). By boosting the voltage with
an On-Load Tap Changer (OLTC) as load increases, LDC mitigates peak load voltage drop at the end
of the feeder, and thus worst-case voltage spread.
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Number of Enquiries
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
LDC can also be applied under reverse flows to lower voltages. The result is increased voltage spread
at the start of the feeder, with higher voltages at maximum demand and lower voltages under
reverse flow, in exchange for a reduction in voltage spread at the end of the feeder.
The implication is that on voltage constrained parts of the network (typically towards the end of
longer MV feeders), falling minimum demand can cause increased voltage spread and breached
voltage constraints just as easily as rising maximum demand. Thus, voltage constraints associated
with reverse flows can be planned for using minimum demand forecasts in a proactive manner, just
as maximum demand forecasts have been used to plan for growth in peak load.
Most Australian distribution networks have a topology more like European networks than those of
the US, with a 400VP-P LV nominal, larger 3-phase distribution (MV/LV) transformers, supplying
roughly ten to several hundred customers and LV secondary circuits that can be hundreds of metres
long. In rural areas with much lower customer densities, single-phase feeders (including Single Wire
Earth Return or SWER) and smaller single customer distribution transformers are more common. In
addition, most Australian distribution transformers have off-load tap changers which require manual
adjustment by field personnel. As a result, while off-load tap chargers can permanently adjust
maximum and minimum voltage on the supplied LV network, they provide no reduction in voltage
spread.
Tap reductions and phase balancing of loads and PV systems are the first and least cost options for
managing voltage where feasible. Otherwise, excessive voltage spread (whether the result of
maximum demand growth or minimum demand reduction) can be reduced in four distinct ways:
• By reducing network impedance, either by using lower impedance (generally bigger)
conductors or higher rating transformers;
• By reducing the magnitude of real power flows, either traditionally by splitting feeders, with
demand response to shift demand, or with energy storage technologies like BESS
• By adjusting reactive power flows, either traditionally with capacitor banks and behind the
meter power factor correction or with modern devices like Statcoms or behind the meter
smart inverter reactive power compensation; or
• By using a regulating technology, such as an MV regulator, LV regulator or Voltage
Regulating Distribution Transformer (VRDT).
A summary of current and potential voltage management measures is provided in Fig. 12. As DER
uptake continues and visibility in the distribution network improves, it is possible that voltage
management challenges may be most economically addressed through MV solutions. That is,
solutions that impact large regions of the network, rather than localised and largely reactionary
measures in the LV network.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
Fig. 12. Current and potential voltage management options
Notes: (1) X/R is the ratio of source reactance to source resistance (2) see Thomas A. ‘Optimal
Incremental Pricing methodology for valuing demand management incentives’ AUPEC 2016 for details.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
4 Reverse flows
4.1 Challenges
When considered collectively, D-PV is by far the largest generator in the NEM. The next largest plant
is the Bayswater black coal plant at 2.6GW. Substantial reverse power flows are already being
observed in the distribution system across South Australia and metropolitan Queensland.
In the SAPN region, 42% of zone substations have already been observed in reverse flow with a
further 32% nearing reverse flow. In some cases, reverse flows are sufficiently large to exceed sub-
transmission substation reverse power limits (often constrained by legacy tap changer designs).
Whilst reverse flows are being felt most acutely in the LV network, their impacts are rapidly
extending to the sub-transmission and transmission systems, as well as raising system security
concerns for AEMO. Reduced efficacy of Under Frequency Load Shedding (UFLS) schemes is a major
concern, along with reactive power management, which are both exacerbated by the low levels of
visibility and control. It is therefore critical that adopted strategies consider impacts across the entire
power system.
4.2 Solutions
4.2.1 Incentivising load
Moving hot water demand to coincide with peak solar generation times presents one option, but
there are challenges to this approach; in South Australia this usually requires a site visit to manually
reprogram the time clock or meter in each customer’s meter box. In addition, the amount of
available load is likely to be sufficient only to defer, rather than resolve, the minimum demand issue.
Another approach being pursued in South Australia is the introduction of a new Time of Use ‘solar
soak’ network tariff from July 2020 that includes a low-cost off-peak rate in the middle of the day to
encourage customers to shift load into the solar trough. The effectiveness of this will depend in part
on the extent to which retailers choose to pass on this price signal in their retail tariffs.
4.2.2 Flexible Export Limits
Currently all embedded generating units with an export limit at or below 5kW are automatically
approved for connection in the SAPN network. SAPN and EA Technology analysis indicates that this
approach is unsustainable, even with volt-var- mode mandated for all new installations. Fig. 13
shows the approximate amount of D-PV in terms of kW per consumer that can be accommodated in
the SAPN network before voltage and thermal limits are exceeded across different network types,
and the present and forecast levels of D-PV penetration. The modelling shows that voltage limits are
typically breached ahead of thermal limits across all network types, and indeed voltages are already
exceeding allowable levels in some cases.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
Fig. 13. SAPN hosting capacity modelling outputs. The orange bars indicate the capacity of D-PV per
customer that networks of each type can accommodate before voltage limits are exceeded. The length of
the bar reflects the statistical variability between individual networks of a given type. The purple bars
indicate the amount of D-PV per customer before thermal limits are reached due to reverse current flow.
The green bars show (a) the average level of D-PV penetration in 2018, and (b) the forecast level of
penetration in 2025. For further details please refer to SAPN Low Voltage Management Business Case
2019 in the “For Further Reading” section.
Due to the increasing volume of large generator connections above 30kW and the subsequent effect
of breaching connecting substation reverse N-1 limits, SAPN generator interconnection standards
require a SCADA runback scheme carried out by generators at the constrained substation to prevent
any distribution and transmission asset overload and damage to equipment. Here, N-1 refers to the
total capacity of the connecting substation with one major item of plant out of service (a ‘single
contingent event’). In this case, it is the resultant capacity due to a single transformer outage from
either a zone substation or the transmission connection point substation.
Without remedial action, the projected 2025 uptake of D-PV is expected to result in widespread
voltage breaches and the distribution network may become a bottleneck, limiting the benefits that
can be captured from DER. Additionally, VPPs present a concern where simultaneous charging and
discharging, even at low battery penetrations, could exceed thermal limits.
In response, SAPN has considered three options:
1. Continue to apply a static connection limit of 5kW and increase the network hosting
capacity in order to accommodate all additional DER. This could be achieved through a
combination of network augmentation (such as investment in voltage regulators) and non-
network solutions such as demand management.
2. Start applying static connection limits to new DER which could result in ‘zero export limits’
for DER in parts of the network at technical capacity (i.e. no export is allowed).
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
3. Apply dynamic export limits (“flexible export connections”), meaning DER export limits can
vary depending on actual conditions with periods of export below the current 5kW limit and
potentially also periods of export greater than this limit.
A techno-economic analysis indicated that enabling dynamic export limits will provide the greatest
net economic benefit to all consumers, and hence this is SAPN’s proposed approach. The proposal is
currently under review by the Australian Energy Regulator as part of the revenue determination
process conducted every five years (also referred to as a General Rate Case in some regions). If
dynamic export limits are approved, SAPN plans to implement flexible export connections for all
small and medium DER by 2023.
A key component of this solution lies in the establishment of a standard web interface to
communicate dynamic export limits to smart inverters, aggregators, and VPPs. SAPN is already
undertaking preliminary trials in this area with VPP operators in South Australia and is planning a
larger trial to extend this capability to smart solar inverters in 2021. This will be undertaken in
collaboration with another DNSP, leading inverter manufacturers and a gateway vendor. SAPN is
planning to adopt the IEEE 2030.5 Standard for Smart Energy Profile Application Protocol, which is
also being applied in California as part of Rule 21. SAPN has leveraged the work undertaken by the
standard-setting organization SunSpec Alliance, and is identifying which aspects of IEEE 2030.5
should be applied in the South Australian context. A 24hr forecast series of export limits is expected
to be communicated to solar inverters, VPPs, and aggregators every 5 minutes on a rolling basis,
with the technical architecture shown in Fig. 14.
Fig. 14. Flexible export limit communications technical architecture, SAPN. Notes: communication
between the DNSP and the server use RESTful (Representational State Transfer) software architecture
whilst communication between the server and DER or DER controllers uses IEEE 2030.5.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
5 System security
5.1 Challenges
A growing body of evidence indicates that D-PV poses significant system security challenges in the
NEM, due to the response of inverters en masse during major power system disturbances, and due
to the continued ‘hollowing out’ of daytime system load.
This section focuses on D-PV disturbance response. However it is important to note that reduced
system load profiles have begun to impact operation of the South Australian region today due to its
high share of D-PV generation relative to local underlying demand, and weak transmission
interconnection with neighbouring regions – making it more susceptible to islanding from the NEM.
For further details please refer to the AEMO RIS.
5.1.1 Frequency disturbance case study
The current inverter interconnection standard requires an over-frequency droop response, or
frequency-Watt response (f-W). At the time the standard was published in 2015 this was a world
leading requirement, as f-W was generally not required for small scale systems. Analysis of real-
world operational data from over 3,000 D-PV system during a major system disturbance on 25
August 2018 has provided unique insight into inverter performance of this f-W function.
D-PVs installed under the current standard (‘Post-2016’ systems) appear to have performed the f-W
response adequately in aggregate (Fig. 15 and Fig. 16), providing evidence of D-PVs acting rapidly,
autonomously, and in concert to aid in maintaining power system security. This sort of useful DER
response is becoming more important in regions such as South Australia where there is limited
interconnection with neighbouring regions and demand is increasingly met by D-PVs during some
periods.
Fig. 15. Queensland Post-2016 inverter over
frequency droop response: average aggregate
power compared with specified profile. For
further details please refer to AEMO 2019 in the
“For Further Reading” section.
Fig. 16. South Australia Post-2016 inverter over
frequency droop response: average aggregate
power compared with specified profile. For
further details please refer to AEMO 2019 in the
“For Further Reading” section.
However, this separation event on 25 August 2018 also uncovered concerns regarding inverter
compliance. Analysis of individual D-PVs (rather than in aggregate) found that at least 15% of
systems in Queensland and 30% of systems in South Australia did not appear to perform f-W
response. High non-compliance rates raise concerns as to whether inverters can and will perform
key functions such as under-frequency ride-through when required.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
5.1.2 Voltage disturbance case study
D-PV response to major system voltage disturbances also poses substantial risks. A 30-40% reduction
in aggregate D-PV generation has been observed following major voltage disturbances in the NEM,
including an event in South Australia on 3 March 2017 following the loss of the Torrens Island gas
generator (steam sub-critical, nameplate capacity 1280MW). During this event, voltage fell to 0.1p.u.
on one phase in the Torrens Island area, in proximity to the main load centre of Adelaide. It is worth
noting that conditions during the disturbance were similar to those experienced prior to the 2016
South Australia system blackout event and that D-PV loss exacerbated the situation, with the most
extreme D-PV response close to the disturbance source (Fig. 17). Further analysis undertaken by
AEMO in its RIS supports a number of necessary actions. The RIS notes that in the absence of these
actions, AEMO may require a moratorium on D-PV installations or expensive retrofitting of existing
D-PV.
Fig. 17. South Australian voltage disturbance event map and D-PV response profile (where upscaled
generation indicates the estimated performance across the South Australian D-PV fleet based on
operational data) 3 March 2017. For further details please refer to Stringer et al. 2019 in the “For
Further Reading” section.
5.2 Solutions
5.2.1 Interconnection standards
In Australia DER are predominantly small systems connected to the LV grid using inverter energy
systems with requirements for their function and performance specified in the Standard for Grid
Connection of Energy Systems via Inverters: Part 2 Inverter requirements, Australian and New
Zealand Standard AS/NZS4777.2:2015.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
In June 2019, AEMO submitted a proposal to review AS/NZS4777.2 to address the key challenges of
increasing penetration of D-PV by aligning the aggregate behaviour requirements for these systems
with wider power system security objectives, as well as distribution-level protection, power quality,
and safety requirements. The changes proposed align with recent developments in international
standards, such as IEEE 1547-2018 and VDE 4105 (Germany), which have implemented ‘smart’
inverter functionality to support system security. As of July 2020, a revision of AS/NZS 4777.2 is out
for public consultation with expected publication in early 2021. This revision was developed through
close collaboration between AEMO, DNSPs, inverter manufacturers, and other key stakeholders. In
addition AEMO is seeking to mandate minimum device level curtailability requirements for new D-PV
installations in South Australia to aid in managing extreme abnormal system conditions during
periods of high D-PV contribution.
Disturbance withstand capabilities
As described above, analysis of recent system disturbances in the NEM has highlighted the
increasingly significant and unpredictable behaviour of D-PV during these events. The analysis shows
that some of the currently installed inverters behaved in unexpected ways. Potential non-
compliance with expected operation under the current standard could have caused unexpected
reduction or loss of generation, thus increasing the event severity.
With increasing DER levels, unpredictable and potentially damaging behaviour of D-PV creates a
growing risk and uncertainty that, in the absence of improved DER capabilities, will drive a need for
AEMO to take increasingly conservative actions in managing the power system. Under the most
extreme DER generation levels, AEMO might otherwise lose the ability to maintain line flows and
restore operational stability.
To continue to manage the power system securely as penetration of inverter-connected DER
continues to grow, disturbance withstand requirements are being clarified and defined
in AS/NZS4777.2. The proposed changes seek to define operational performance requirements for
disturbances to voltage (including multiple events) and frequency.
Power quality modes
Though AS/NZS4777.2:2015 already addresses power quality response, at the time of its adoption
many of the functionalities were novel and not widespread and thus were implemented only in an
optional capacity. With increasing DER penetration on distribution grids, DNSPs are now requiring
implementation of functions, such as volt-var and volt-watt response modes, for new D-PVs, which
allows for a more progressive reduction in inverter output as voltage rises. Otherwise, the system
relies on over-voltage trip settings to manage local system operation and increase feeder DER
hosting capacities.
Protection a nd control functionality
Unpredictable behaviour of D-PV following disturbances has been identified as potentially resulting
from the lack of clear guidelines for performance, measurement, and response during events
causing voltage waveform distortion. For the revised AS/NZS4777.2, the Standards Australia review
is considering the inclusion of clearer specifications around the expected accuracy; withstand to
associated voltage waveform disturbances; and performance for various system conditions, such as
capability to withstand rates of change of frequency and voltage phase angle jumps.
Next steps
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
The suggested changes in this revision of AS/NZS4777.2 are a first step towards a high DER future by
improving the autonomous behaviour of associated systems. Further requirements will be
considered by AEMO in a staged approach, such as active optimisation through interoperability,
resulting in a need for cybersecurity measures, and increased coverage beyond the low voltage
network.
5.2.2 Larger Systems
As per SAPN generator interconnection standards, it is a requirement for every generating system
net exporting above 200kW into the distribution network to implement a cost-effective SCADA
solution that has the ability to carry out a control signal issued by SAPN and at times under direction
by AEMO to manage system security. This may include curtailing the output of large asynchronous
generation during periods of low minimum demand combined with high PV output, and during a
non-credible contingency event. A recent example of such a contingency event is when the
interconnector between Victoria and South Australia separated on 31st January 2020.
5.2.3 Virtual Power Plant demonstrations
Given the potential scale of DER installations over the next decade, AEMO has established a
dedicated DER Program to integrate DER to the power system safely, securely, and in a way that
maximises the benefits of DER investments for all consumers, not just those who own DER. For
example, appropriate frameworks can incentivise DER to deliver value for all electricity consumers
by providing grid services that make the power system more efficient.
In 2019, AEMO launched the VPP Demonstrations to explore the capability of aggregated DER to
deliver FCAS and develop AEMO’s understanding of how VPPs respond to energy market price
signals. A VPP broadly refers to an aggregation of resources (such as decentralised generation,
storage, and controllable loads) coordinated to deliver services for power system operation and
electricity markets.
As of January 2020, there are two participants in the VPP Demonstration program and two further
VPPs are going through the enrolment process. Although there is a small pool of data to draw upon,
learnings to date indicate that VPPs can respond effectively to power system events and price
signals. This includes responding to frequency excursions beyond the normal operating range (49.85
– 50.15 Hz) and pre-charging (or dis-charging) to cater for future high (or low) price events,
respectively. Several SA VPP responses to contingency FCAS and energy events in South Australia
have been analysed below.
10 December 2019, response to under frequency event
On 10 December 2019 the NEM experienced both high (>50.15Hz) and low (<49.85Hz) frequency
events within 45 minutes of each other. The SA VPP responded immediately in both cases to first
charge the batteries to lower system frequency, and then dis-charge the batteries to raise system
frequency, shown in Fig. 18.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
Fig. 18. FCAS response for SA VPP - 10th December 2019, Victoria and South Australia regional
separation. For further details please refer to the AEMO Virtual Power plant Demonstration, Knowledge
Sharing Report #1 in the “For Further Reading” section.
9 - 15 January 2020, response to energy spot prices over the course of a week
Observing the VPPs’ response over the course of a week provides evidence that VPPs do respond to
energy market signals. This is shown in Fig. 19, where pre-charging in anticipation of elevated prices
and dis-charging during the elevated price event can be observed. As a result, the power system is
supported by the provision of additional power when needed.
Fig. 19. Energy response for SA VPP 9 – 15 January 2020, behaviour over a week. For further details
please refer to the AEMO Virtual Power plant Demonstration, Knowledge Sharing Report #1 in the “For
Further Reading” section.
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Power (MW) VPP behaviour over a week, price vs battery dispatch
Aggregate Battery Power (MW) Price (AUD/MWh)
Battery pre-charging in anticipation of elevated energy prices
Battery dis-charging during elevated energy prices
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
These events show that VPPs can benefit:
• Participating consumers by sharing the value earned through the VPP participating in FCAS
or responding to energy market prices; and
• All other consumers by creating more competition in these markets to reduce prices and, if
VPPs scale up enough, potentially deferring/displacing the need for large-scale generation
assets.
Next steps
Australia’s VPP demonstrations will continue to provide learnings regarding the effectiveness of
VPPs adding value to the power system. The addition of other participants will enrich the current
data set and allow for more analysis to be carried out and a deeper understanding to be gained.
Conclusions will then be drawn to inform other DER related trials and future market reform
recommendations.
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
6 Looking forward
Cast your mind forward to a bright spring day in the 2030s. D-PV is likely to be an even more familiar
sight across most major Australia cities, accompanied by BESSs and a fleet of EVs. Perhaps Adelaide,
the South Australian coastal capital, no longer has a monopoly on breaking minimum electricity
demand records. As solar noon approaches, distribution systems across the country become net
exporters and reverse flows are rife. However, the grid is humming along nicely and the system
remains stable and secure. Dynamic distribution network limits are being broadcast and voltage
managed as DER act to support the grid. Consumers are being rewarded for the role their DER
perform, VPPs are responding to power system needs, and the benefits are being shared across the
population. Very occasionally, a fault sends voltage or frequency wobbling; however, the system
quickly responds and predictably brings operations back into kilter. Consumers again go about their
business, rarely registering the new and evolving systems in place, as the grid of the future slides
seamlessly into the fabric of daily life.
Perhaps this world is even closer than expected, with Australia at the pointy end of DER integration
and impacts already being felt across the entire power system. As an eventful Australian summer
comes to a close, the challenges and opportunities afforded by DER are undiminished and
collaborations across the industry are as important as ever.
Acknowledgement
We would like to gratefully acknowledge contributions from the SA Power Networks team who
provided valuable input, guidance, and feedback during the development of this article.
For further reading
AEMO, "Technical Integration of Distributed Energy Resources," April 2019, available:
https://www.aemo.com.au/Media-Centre/Technical-Integration-of-Distributed-Energy-Resources-
Report
AEMO, “Virtual Power plant Demonstration, Knowledge Sharing Report #1”, March 2020, available:
https://aemo.com.au/-/media/files/electricity/nem/der/2019/vpp-demonstrations/aemo-
knowledge-sharing-stage-1-report.pdf
AEMO, "Renewable Integration Study Stage 1 Appendix A: High Penetrations of Distributed Solar
PV," April 2020, available: https://aemo.com.au/-/media/files/major-publications/ris/2020/ris-stage-
1-appendix-a.pdf
Energex “Distribution Annual Planning Report”, December 2019, available:
https://www.energex.com.au/about-us/company-information/company-policies-And-
reports/distribution-annual-planning-report
SA Power Networks, “Low Voltage Management Business Case”, January 2019, available:
https://www.aer.gov.au/networks-pipelines/determinations-access-arrangements/sa-power-
networks-determination-2020-25
Finalised version
1540-7977/20©2020IEEE
DOI: 10.1109/MPE.2020.3014720
Stringer, N., A. Bruce, I. MacGill, N. Haghdadi, P. Kilby, J. Mills, T. Veijalainen, M. Armitage and N. Wilmot (2020).
"Consumer-Led Transition: Australia's World-Leading Distributed Energy Resource Integration Efforts." IEEE Power and
Energy Magazine 18(6): 20-36.
SA Power Networks “Future Network Strategy”, November 2017, available:
https://www.aer.gov.au/networks-pipelines/determinations-access-arrangements/sa-power-
networks-determination-2020-25
N. Stringer, N. Haghdadi, A. Bruce, J. Riesz, and I. MacGill, “Observed behavior of distributed
photovoltaic systems during major voltage disturbances and implications for power system
security”, Applied Energy, vol. 260, p. 114283, 2020, available:
https://doi.org/10.1016/j.apenergy.2019.114283
Biographies
Naomi Stringer is with the University of New South Wales, Sydney, Australia.
Anna Bruce is with the University of New South Wales, Sydney, Australia.
Iain MacGill is with the University of New South Wales, Sydney, Australia.
Navid Haghdadi is with the University of New South Wales, Sydney, Australia.
Peter Kilby is with the Energy Queensland Group, Brisbane, Australia.
Jacqui Mills is with the Australian Energy Market Operator, Melbourne, Australia.
Taru Veijalainen is with the Australian Energy Market Operator, Brisbane, Australia.
Matt Armitage is with the Australian Energy Market Operator, Melbourne, Australia.
Nigel Wilmot is the Chair of the AS/NZS4777.2 Committee, Perth, Australia
