The CSIRO’s latest assessment of the cost of various generation technologies, GenCost 2021-22, shows renewables will remain the cheapest new build, even with integration costs for additional transmission and storage.
The latest report models the integration costs of large-scale solar and wind to 2030 in the National Electricity Market, Western Australia’s South West Interconnected System (SWIS) as well as other areas of the state outside the SWIS. While the assessment does expect a speed bump for cost reductions due to factors like the increased pressure on supply chains as a result of COVID-19 and other factors, it also anticipates cost reductions for technologies will resume from next year.
It projects that the levelized cost of electricity (LCoE) from large-scale solar will continue to fall from between $44 and $65/MWh currently to between $27 and $56/MWh by 2030, while the LCoE for onshore wind will go from between $49 and $61/MWh to between $40 and $59/MWh.
The integration costs for variable renewable energy (VRE) based on shares of generation ranging from 60 per cent to 90 per cent for combined large-scale solar and wind are also examined. GenCosts estimates those integration costs to support renewables will add between $16 to $28/MWh by 2030 depending on the final VRE share (as shown in figure 1).
Figure 1: Calculated LCOE by technology and category 2030
The integration costs are based on the need for storage, additional transmission and synchronous condensers, which can be used to replace lost inertia from traditional generation which is expected to retire. It also assumes the pumped hydro projects, Snowy 2.0 and Tasmania’s “Battery of the Nation”, are built before 2030, as well as transmission expansion projects flagged in the Australian Energy Market Operator’s Integrated System Plan as required before 2030. NSW gas peaking plants at Kurri Kurri and in the Illawarra are also assumed to have been built, while NSW’s target for an additional 2GW of at least 8 hours duration storage is also assumed to be met by 2030.
All estimates are based on a maximum of costs across nine weather years. When added to variable renewable generation costs and compared to other technology options, these estimates indicate that onshore wind and solar PV remain the lowest cost new-build technologies. See table 1.
Table 1: Technology LCOE projections, 2021-22/MWh
When considering wind and solar combined and the additional integration costs the LCoE increases to between $53 and $73/MWh (at a 60 per cent VRE share of the grid) and between $61 and $82/MWh (at a 90 per cent share) as shown in table 1.
In considering the integration costs GenCosts looked at transmission to connect Renewable Energy Zones (REZs), while other transmission includes interconnectors and expansion of existing lines.
It considers additional expenditure on synchronous condenser capacity is required in most states although it increases moderately with higher VRE share.
REZ transmission expansions is projected to add $6/MWh to $8/MWh, as VRE share increases from 60 per cent to 90 per cent and other transmission adds $3.8-$10.0/MWh and its costs are expected to accelerate as the VRE share grows. Synchronous condensers costs will add between $1.0/MWh to $1.2/MWh, while storage adds $6.4 to $8.4/MWh.
In 2030, GenCosts estimates the NEM will need 0.20kW to 0.34kW of storage capacity for each kW of variable renewable generation.
Capital Cost Expectations
Current capital costs for various technologies are shown in figure 3 compared to previous assessments.
Figure 3: Current Capital Costs by Technology versus earlier assessments
In the lastest GenCosts, the capital costs for large-scale solar have significantly reduced for 2021-22 compared to previous projections (see figure 4). Although the cost reductions are paused in 2022-23 to reflect tighter supply chains, cost reductions are expected to be accelerated based on the global net zero emissions by 2050 scenario, particularly later this decade.
Figure 4: Projected capital cost large-scale solar vs 2020-21
Like other technologies, the capital costs for onshore wind are expected to fall with greater global climate policy ambition, subsequent deployment as well as increased learning rates. It’s also assumed that wind can achieve further cost reductions by improving its capacity factor over time.
Figure 5: Projected capital cost onshore wind vs 2020-21
Offshore wind is expected to benefit from higher electricity demand globally. It’s considered well suited to countries with good wind resources, relatively shallow coastal waters and where this is limited onshore land or demand for other land uses. The report also notes offshore wind has the potential to increase its capacity factors due to greater scope to install larger turbines. Regardless the LCoE for offshore wind remains much higher than for onshore wind or solar (see table 1).
Figure 6: Projected capital cost offshore wind vs 2020-21
The roles and responsibilities of electricity distribution networks are being challenged by the changing mix of resources in the grid. The energy transition is not just about reducing emissions by changing technologies in large-scale generation, it is also about a trend towards more localised, or distributed energy resources (DER). The Australian Energy Council’s latest discussion paper looks at what the transition might mean for distribution networks and customers.
A recent report by the International Energy Agency has highlighted the dominant role of China in the world’s solar supply chain. The transition underway in the global energy market will not be immune from this dominance. The IEA estimates one out of every seven panels produced internationally now comes from a single manufacturing site in China. As we have seen recently with Russia’s gas supplies, a supply chain dependency can be extremely disruptive. So, are there options to avoid this?
The latest discussion paper in the Australian Energy Council’s “55 by 35” series on Australia’s Energy Future focuses on the implications of the target and the transition to net zero for regional economies in the light of the progressive closure of coal power plants. It recognises that there is a policy case for a focus on these regions, given that coal power plants (and in some cases associated mines) are major employers in those regions.
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