This Microgrid Feasibility and Screening Study was awarded $1.08 million from the Federal Government Regional and Remote Communities Reliability Fund in December 2021 to examine the potential for the electricity distribution network on the Eyre Peninsula to transition to renewable energy microgrids.
31 May 2023
The Eyre Peninsula is the westernmost part of the National Electricity Market (NEM) with distributed and small communities in remote townships and isolated properties. These communities play a significant role in Australia’s tourism, agriculture, manufacturing, and export sectors, but have been disproportionately impacted by issues of electricity affordability and reliability.
This Microgrid Feasibility and Screening Study was made possible with funding from Round Two of the Australian Government’s Regional and Remote Communities Reliability Fund (RRCRF). The RRCRF was established in October 2019. Its purpose is to support regional and remote communities in determining the cost-effectiveness of various options, including replacing, upgrading, or supplementing microgrids, as well as upgrading existing off-grid and fringe-of-grid supply using microgrids or other new energy technologies.
The intended outcomes of the RRCRF are:
ITP Renewables was commissioned to perform detailed microgrid feasibility studies at three locations in the Eyre Peninsula; Kimba, Koonibba, and Sceale Bay, and to develop a method to screen for the potential of microgrids and individual power systems to reduce costs across the entire Eyre Peninsula distribution network. Kimba and Koonibba were selected by RDAEP as locations of interest based on community motivation. The selection of Sceale Bay as the third location for feasibility study was informed by the distribution network operator, SA Power Networks (SAPN)’s visual assessment of customers at the end of long spur lines, and an assessment of maintenance costs, bushfire risk, and corrosion risk.
The current supply to Kimba, Koonibba, and Sceale Bay is via the interconnected grid, and the feasibility studies consider the option of adding microgrid capability to enable occasional islanding of these towns and fulfilment of local electricity demand with local supply. A microgrid would allow portions of the upstream network to be de‑energised on days of extreme or catastrophic bush fire risk, minimise outages caused by upstream faults, and reduce carbon emissions attributable to grid imports. Improved reliability of electricity supply would reduce loss of services, supplies, perishable stock, creating a positive impact on health services, education services, and local businesses.
The microgrid and individual power system (IPS) screening study assesses the cost implications of modifying the existing electricity distribution network with microgrids or individual power system options across the Eyre Peninsula. To achieve this, it is necessary to measure whether the distribution network, a microgrid, or IPS are lower cost for any combination of adjacent customers, at any location within the Eyre Peninsula distribution network. Battery energy storage system (BESS) cost sensitivity analysis also provides insight in to when certain network modifications become feasible if prices change.
These variables create a very large number of possible scenarios to consider, and the results of this study allow these scenarios to be ranked to inform infrastructure planning.
Microgrids, as defined by the Australian Energy Market Commission (AEMC), are always isolated from the interconnected grid. However, the focus of this report is on sections of the interconnected grid that may sometimes be islanded, and so operate as a microgrid intermittently. Intermittent microgrids have not been defined as a possible model of electricity supply for customers under the National Electricity Rules (NER). The Australian Energy Regulator (AER) has identified market settlement, customer retail tariffs, responsibility/liability for managing supply and demand, protection and power quality, and retailer-related mechanisms as some of the regulatory issues requiring further development to enable complete governance of intermittent microgrids.
If islanded operation is for short durations, the AER considers that the regulatory and financial issues arising are immaterial.
Possible configurations for electricity supply in Australia
Kimba and Sceale Bay
There are two options for ownership of assets that enable islanding. In both, SAPN retains ownership of the local network and customers retain their choice of retailer.
The first option is for SAPN to own and operate any in-front-of-meter generation/ storage. The assets can be used to provide network support but cannot participate in competitive markets such as wholesale spot and frequency control and ancillary services (FCAS), though it may be possible for SAPN to allow a 3rd party to lease and operate it within limits set by SAPN under an AER waiver. The assets could form part of SAPN’s Regulated Asset Base (RAB) if approved by the AER, allowing capital and operating costs to be recovered from all SA customers in the NEM.
The second option is for a 3rd party to own and operate any in-front-of-meter generation/storage assets. The capital and operating costs would be serviced by revenues from spot and FCAS markets and potentially a bilateral contract with SAPN to provide network support services (e.g. islanding).
There is anecdotal evidence that the community is interested in an alternative power supply arrangement. Community leaders have suggested that a communal model of procuring power may be preferable to individual retail contracts for each dwelling. This communal model would involve a community management corporation. Using grant funding, the community entity would own the central generation/ storage assets (e.g. by engaging a 3rd party developer who would develop and construct in-front-of-meter generation/storage assets on behalf of the community entity). Households would retain their existing retailer, and the community entity, using revenues from the generation/storage assets, would i) take on financial responsibility for household electricity bills (without becoming their retailer), or ii) pay each household a quarterly dividend that could be used to offset their electricity bill costs, or iii) establish/manage a community fund for other electricity cost reduction measures such as subsidising more efficient appliances.
This study found that a 4.55 MWp solar PV system coupled with a 4.5 MW/18 MWh BESS would provide sufficient generation to meet 93% of local demand in island mode in year 1 (2025), falling to 81% after 25 years (owing to load growth and PV/BESS degradation). Given that less than 100% of demand would be served, the community would be required to engage in a small amount of “demand response” during islanding events to conserve energy. Alternatively, 2 MW of diesel generation could be installed in parallel to increase demand coverage to 100%.
This study found that a 585 kWp solar PV system coupled with a 425 kW/1,700 kWh BESS would provide sufficient generation to meet 98% of local demand in island mode in year 1 (2025), falling to 92% after 25 years (owing to load growth and PV/BESS degradation). Given that less than 100% of demand would be served, the community would be required to engage in a small amount of “demand response” during islanding events to conserve energy. Alternatively, 300 kW of diesel generation could be installed in parallel to increase demand coverage to 100%.
This study found that a 260 kWp solar PV system coupled with a 300 kW/630 kWh BESS would provide sufficient generation to meet 92% of local demand in island mode in year 1 (2025), falling to 71% after 10 years (owing to load growth and PV/BESS degradation). Given that less than 100% of demand would be served, the community would be required to engage in a small amount of “demand response” during islanding events to conserve energy. Alternatively, 120 kW of diesel generation could be installed in parallel to increase demand coverage to 100%.
The results suggest that these projects will not pay back over a 25-year lifetime, without additional subsidy. There are several factors that contribute to this result, including:
The indirect financial benefits to SAPN associated with each project proceeding include the reduced bushfire risk and improved reliability for their customers. However, the magnitude of these benefits is not sufficient to offset the projected financial losses of each project, suggesting it is unlikely that SAPN could offer a sufficient incentive to attract a project developer.
Each project is expected to avoid a small volume of emissions over its lifetime. However, even at a high carbon price, this is insufficient to materially impact the economic case.
Section of the grid identified by the screening tool that could be decommissioned
This study found that 204 connection points (mostly homes and small businesses) on the Eyre Peninsula distribution network have the potential for implementation of IPS, allowing for the decommission of existing network assets. 162 connection points have the potential to be powered by a microgrid. Microgrids use existing network assets, so poles, wires, and other components would not be decommissioned when implementing microgrids at these locations.
A BESS Cost Sensitivity analysis shows that for both microgrid and IPS, substation zones SSD188 Port Lincoln Terminal and SSD269 Darke Peake are good candidates to re-screen in the future if BESS prices reduce below 70% of current prices. This study showed that there are no additional zones to consider for future disconnection.
A screening tool verification study shows that the largest contributing factors towards a positive financial return for IPS and microgrid implementation are the large VCR and bushfire risk associated with network assets such as high-voltage feeders, in combination with a low system cost for a given modification.
The total annual return to SAPN for all identified network modifications and all zones is $414,456. The total Net Present Value (NPV) over the lifetime of these systems would be approximately $7.3 million, with a discount rate of 2.9%.
Read the Public Report for the full analysis.