In the first of a series of articles on the rapidly evolving domain of grid edge markets, we take a closer look at the increasing number of value streams available to distributed energy resources (DERs) particularly as they begin to become aggregated and orchestrated by virtual power plant technology. But with opportunity comes risk – we look at potential problems this may cause for grid operation and grid edge markets, and the emerging innovations that will work to solve these problems.
The future is distributed
Earlier this year the ENA and CSIRO reported[1] that “a future where up to 45% of all electricity is generated by the customers in 2050 – at the opposite end of the system from its original design – presents a very significant range of technical, economic and regulatory challenges”. Indeed, the implications across the system of that future are staggering.
And these forecasts are not far fetched. Bloomberg New Energy Finance predicts that by around 2035, 45% of all installed generation capacity will be from “non-grid-scale” decentralised energy sources, as highlighted in the chart below.
Figure 1: Decentralisation ratio (ratio of non-grid-scale capacity to total installed capacity)
Source: Bloomberg New Energy Finance
The value of distributed energy resources keeps growing
The rise in distributed energy resources (DERs) will continue – fuelled by historically high electricity prices and reducing technology costs. These technologies will get cheaper through scale, further technology innovation, deeper delivery capability and competitive pressures. Customer bundles of solar, storage and demand response technologies will become increasingly valuable as they gain access to additional markets and value streams via aggregation and orchestration technologies (DERMS – Distributed Energy Resource Management Systems) from businesses including Resposit Power, Redback technologies, GreenSync and Geli.
Examples of aggregated DERs gaining access to new sources of value in front of the meter include:
- AGL’s virtual power plant (VPP) project in South Australia, where 1,000 solar and battery storage systems will be aggregated to derive value from the wholesale market;
- GreenSync’s Mornington Peninsula project which will access network support payments to defer network augmentation on United Energy’s network via an aggregated portfolio of customer DERs;
- ARENA’s current Demand Response Competitive Round to enable aggregated flexible capacity to access AEMO’s reserve trader payments;
- Recent rule changes enabling aggregators to bid into the FCAS market; and
- Recommendations from the Finkel review requiring new large scale variable renewable energy generators to be coupled with adequate dispatchable capacity in each region.
Customers will continue to drive grid edge innovation as they search for greater control over their energy costs and more value from their investments in DERs. However, these new opportunities do not come without risk. Although orchestration of these distributed assets can enable a rapid response to a market signal, it can also cause some unintended issues for the network. As these fleets of DERs expand, the impact on the network of a sudden, orchestrated response increases which could ultimately lead to system failure. Even the threat of this situation could lead to networks taking broad based action to constrain DER behaviour, limiting customers’ access to these value streams.
Network issues and other complicating factors
Below are some practical examples of the complexities of a high density of DERs and the aggregation of those assets in response to market value signals.
Example 1: High penetration of distributed generation creates export constraints in some areas of the network
In South Australia, AEMO forecast that rooftop solar alone may be sufficient to supply the entire state’s demand at certain periods, as early as 2026[2]. As customers increase levels of distributed generation, there is a material risk of distribution transformers being overloaded in reverse flow, in addition to the voltage issues caused by rapid rises and falls in generation output as a result of weather events (e.g. a big cloud!)
Figure 2 below shows some of this impact unfolding across the network, with reverse flows at zone substations in many areas by 2020 – particularly in South Australia.
Figure 2: Timing of reverse flows
Source: Electricity Network Transformation Roadmap, Final Report
Traditional responses from a network might include a system upgrade or a broad based ban on solar PV exports. A smarter way would be to use a tool which enabled networks to specifically target the behaviour of DERs in constrained areas, and only at the times when the network is under stress. Orchestration of solar PV system output, via the lens of the network’s physical constraints, could in this case facilitate a greater penetration of solar PV on the grid.
Example 2: Aggregated DERs could act in a way that creates issues for network stability.
If all batteries in a virtual power plant acted in unison (which seems possible as they have similar technical characteristics and will be responding to the same market signals), and the virtual power plant is large enough, this can cause issues for the stability of the network.
An example of this was recently highlighted by SA Power Networks in relation to their Salisbury Trial involving a VPP of 100 solar and battery storage systems. The batteries were orchestrated to charge in preparation for a forecast storm, leading to a significant spike in network demand, as shown in the figure below.
Figure 3: An example of the unintended consequences of orchestrated DER behaviour
Source: SAPN, Presentation to the Australian Energy Storage Conference, June 2017
These unintended consequences for the physical network as a result of orchestrated DER behaviour could put the reliability and security of the system at risk.
Example 3: The characteristics of the network may constrain the ability of DERs to respond to market signals
If there is a large number of DERs in a given location on the network which are all aggregated within a VPP and acting in the same way in response to a market signal, the network on which they are connected may not have the capacity to transmit this generation back up the network. So, the network may constrain the extent to which those DERs can respond. But how does a distributed energy marketplace resolve this scenario? Which DER’s can respond (and hence get paid) and which one’s can’t? How does a DER know that it is constrained from responding?
Example 4: The ability to authenticate and settle transactions could be impacted by other activity on the network
The scheduled dispatch of large scale generators is relatively straightforward to authenticate and their impact on the network is measurable and predictable. However, when there are small scale DERs operating behind the meter at a customer’s premises, the impact of these operations is not necessarily distinguishable from fluctuations in customers’ demand and supply. These markets need to be able to validate that DER responses are distinguishable from the usual DER operations and settle the trade accordingly. But how is this done in practice? How does the approach vary across different types of DER?
All of these examples highlight a fundamental question raised by the future where almost half of all power supply is generated by customers:
How do we manage the system so that customers are able to optimise the value from their investments AND ensure that the security and reliability of the network is maintained?
Innovative technology will resolve these issues
The answer to this question lies in the concept of a platform – a DER management and market platform through which, all of this vibrant market activity is monitored and bounded so that DER behaviour does not attempt to contravene the laws of physics, or the physical limitations of the network: commercial market signals within physical constraints. This technology is beginning to emerge, and the details of this approach will be the topic of our next article in the Grid Edge series.
If you are a interested in emerging grid edge markets and want to understand how they will impact your organisation and what you can do to make the most of this opportunity and manage the risk – contact Paul Minnock at PaulM@marchmenthill.com
[1] CSIRO and Energy Networks Australia 2017, Electricity Network Transformation Roadmap, Final Report.
[2] AEMO, South Australian Renewable Energy Report, December 2016
