Grid Reliability in the Lower Mornington Peninsula Region (Victoria, Australia)
The Australian Energy Market Commission (AEMC) is an agency of the federal government tasked with governing the rules of the National Electricity Market (NEM), the electricity grid covering the Australian states of Queensland, New South Wales, ACT, Victoria, Tasmania and South Australia. This represents approximately 80% of the Australian energy consumption (AEMC 2017).
The wholesale price of electricity is struck at 30 second increments at the lowest price that will supply the necessary power, often referred to as a ‘merit order’ (see Figure 2). Supply is effectively guaranteed during peak demand (normally the hot days in Australia when air conditioners are all turned on) by allowing the wholesale price to spike, incentivising more expensive sources to come online. Some generation capacity can operate for as little as 10 hours a year and still be profitable (Parkinson 2017).
The primary actors in the electricity grid are (see Figure 3 for more details):
- Generators (Step 1): Owners and operators of generation capacity.
- Transmission Companies (Steps 2 & 3): Owners and operators of high voltage transmission lines from power plants to population centres.
- Utilities (Steps 4 & 5): Managers of sections of the distribution grid (a mixture of government and regulated monopolies).
- Retailers: Responsible for connecting and billing end consumers.
Over the past decade, two phenomena have undermined the efficiency of the NEM, increasing prices to consumers, and in some cases, affecting electricity supply:
- Gold plating of the grid: Over-investment by Utilities in network infrastructure (poles, wires, and substations).
- ‘Gaming’ of the wholesale energy market: Generators with monopoly power in certain jurisdictions have been able to exacerbate, and in some cases engineer, peaks in wholesale prices.
Public anger with these increased costs, as well as the precipitous drop in new energy technologies, has the potential to limit further cost increases and wrestle some control from the energy incumbents.
Combining distributed technologies (e.g. solar PV panels and battery storage) with digitalisation can counteract the forces that have driven up prices for consumers and transform of the energy system.
The specific region under analysis is the Lower Mornington Peninsula, in the state of Victoria, Australia. The area is roughly 100km from central Melbourne, and is a popular holiday spot, due to its proximity to the coast.
The electricity demand in this region is made up predominantly of the residential sector. (United Energy 2015). The number of permanent residents in the area stands at 150,000, but can increase by approximately 30% during the peak summer months (Mornington Peninsula Shire 2012).
There is also a high penetration of solar panels in the region, producing a classic ‘duck curve’ to the residual demand in the region. See Figure 5.
In 2014, the local utility, United Energy (UE), concluded that if they did nothing to address the issue over the next 5 years, reliability could be threatened. Under network rules, Utilities such as UE are obligated to put any work expected to pass a threshold of $A5 million to outside tender and consider non-network if it could be shown to reduce demand or utilize embedded generation(AER 2013).
Software company GreenSync proposed such a solution, named the ‘Community Grids Project’ (CGP). A small scale trial was run over the 2016/17 summer period, and will commence in earnest in late 2018.
The following strategies were employed as part of the solution:
- Subsidies to consumers with solar panels to purchase a battery;
- Two dedicated battery systems were installed;
- Demand Response strategies (where customers are incentivised to reduce their consumption at key moments) were employed;
- Demand Response Enabled Devices (DREDs) were piloted to directly control household appliances (e.g. air conditioners) to optimise their power; and
- As a last resort, backup diesel generation was installed to manage extreme cases.
The main problem of the case was to prove to policymakers that non-network solutions could be used at a large scale in a way that:
- Maintained network reliability: Electrical grids, like most infrastructure, are built for peaks in demand and long term reliability. The CDP trial would need to prove that the combination of strategies could meet the Utility’s need for ‘firm capacity’ – that power is guaranteed to be available when required.
- Was cost competitive: The CGP was expected to cost roughly 10-15% of the proposed network solution (United Energy 2015).
- Allowed investors in these technologies an economic return: The CDP would subsidize the consumer’s purchase of a battery in exchange for using that battery to help manage network constraints.
The emergence of the Smart Urban Energy System (SUES) is challenging the assumptions embedded in the traditional energy services layer in the following ways:
|Consumers (except very large ones) cannot generate, store or trade their own energy.||Distributed energy technologies (DETs) have experienced massive cost reductions, making them an option for more consumers.|
|Consumers cannot dynamically control their energy demand.||With DETs and smart management, prosumers can decouple their energy consumption from their actual grid demand.|
|Generation and distribution infrastructure requires large, long term investment.||DETs can be purchased and installed at a very small scale, requiring a shorter investment horizon and less regulatory certainty for the buyer.|
|Consumers want certainty on price.||New intermediaries, such as energy startups, are smartly mitigating energy market fluctuations on behalf of consumers.|
Table 1: SUES challenge to energy market orthodoxy
The first attempt at implementing a SUES in Australia was primarily a top-down initiative, using smart meters to incentivise consumers to reduce consumption at key times of expected stress on the grid, also known as ‘time of use’ pricing. This disregarded the dynamics shaping the energy market, however:
- Fixed Prices to Price Signals: Time-of-use pricing provided consumers a price signal, but nothing was done to automate reaction from devices.
- Centralised to Decentralised Generation: It was assumed centralised generation would continue to dominate. DETs were not seen as having a role.
- Planned Production to Intermittent Generation: It was assumed base load, fossil fuel (planned) production would continue to provide a constant ‘block’ of power to the grid. No attempt was made to enable intermittent generation (such as renewables) to make up a greater proportion of total capacity.
The CGP, by implementing a ‘microgrid’ model, harnessed these dynamics in a way that benefitted the grid and reduced network expenditure. The trial has been a success and will be the solution to provide grid reliability to the Mornington Peninsula region for the next 5 years.
This solution, however, still represents an ‘integrated’ vision of grid management. UE has simply outsourced network reliability for a section of their network to a third party for a period of time. There is minimal transparency of grid performance, and only a narrower group of actors can participate.
GreenSync developed deX, or Distributed Energy Exchange, represents a different vision, a ‘data platform’. It will allow solutions to be provided from a variety of actors, and for policymakers to turn learn what regulatory changes could be most effective.
Examples of the network services that could be provided by deX include:
- Network Constraint Management: Utilities will be able to offer incentives to consumers in specific locations where infrastructure investment can be offset. The effectiveness of this could encourage policymakers to demand that utilities publish real-time constraint data and open more to outside tender.
- Wholesale Energy Market Participation: Retailers will be able to leverage their existing relationship with consumers. Policymakers could also consider a reduction in the pricing interval (e.g. 30 minutes to 5 minutes has been mooted) to allow more DETs to participate in the market.
- Ancillary Services: Utilities will be able to access cheaper frequency and voltage management options provided by DETs. A better regulatory definition of possible support services would allow them to participate more effectively.
deX could catalyse a new class of actors in the energy market who will enable the benefits of digitalisation to emerge:
- Prosumers: End Customers will be able to produce, store and trade energy, stimulating unprecedented choice in their energy service.
- A new class of energy retailers: The prospect of aggregating the distributed assets of their customers (known as a ‘virtual power plant’) will enable them to better manage wholesale price risk and compete more effectively with the incumbants.
- Decentralized electricity producers and storage operators: The broader set of energy services available will open up markets for these players.
- Traders: Will be able to provide services on behalf of all of the above.
deX has only recently been announced, but has attracted a wide array of industry actors (including regulators and large incumbents) as foundational supporters.
The Australian experience has clearly demonstrated how not to ensure a cost-effective and innovative grid. Generators have used their powerful market position to manipulate wholesale prices, and Utilities have used the vague objective of reliability’ to overspend on capital expenditure..
The emergence of the SUES offers the opportunity for DETs to be absorbed into the grid to help address the needs of the grid more effectively. The CGP has shown that segmenting a monolithic grid and better defining the concept of grid reliability can lead to novel, more cost-effective solutions. deX takes that concept one step further by allowing more grid services to be provided by a new class of actors and business models.
We’re only at the beginning!
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Featured Image: Alex Proimos from Sydney, Australia
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