Energy calls in the Grattan Institute to unpack the diverse elements driving electricity prices.
“Political football.”
It’s a phrase often used to describe the electricity-price debate in Australia, particularly at a time when cost of living pressures continue to impact households.
But the pricing issue requires more investigation than the flippant treatment it can receive in the political arena, so we’ve enlisted Grattan Institute to help provide a clear view on the topic.
Firstly, Grattan Institute energy and climate change program director Alison Reeve shed light on the political landscape.
“For a long time, everyone had a mental shortcut, which was, ‘Renewables are more expensive’, because that was true,” Reeve told Energy. “The thing is, the more we deployed them (renewables), the more the cost came down, and so a lot of people are having to change their mental shortcuts.
“People who don’t spend all their time engaging with the energy system still have the old mental shortcut, which means politically, that message (renewables = higher prices) lands, because people go, ‘Yes, that politician is affirming the thing I know to be true’.”
Reeve believes this is why pushing the electricity-price debate has become attractive as a political strategy.
“We also often hear the argument of ‘coal is cheap’,” Reeve said. “The reason coal is cheap is because we paid off the capital decades ago.
“If you replace existing coal infrastructure with new coal plants, that new coal would not be cheap, because you would be footed with capital once again.”
CSIRO’s draft GenCost 2025–26 report released in December projected the capital costs of building various energy infrastructure in the years to come.
For Australia to achieve its 82 per cent renewable energy target by 2030 under current policies, building black coal and brown coal energy infrastructure would cost $6164/kW (down from $6946/kW today) and $9385/kW (down from $10,725/kW today), respectively.
In contrast, the capital costs of large-scale solar PV under current policies would cost $1239/kW in 2030 (a drop from $1621/kW today), and onshore wind would cost $2697/kW by the end of the decade (down from $3248/kW today).
The great connectors
In parallel with the renewable energy assets underpinning low-emissions power generation, Australia has been undergoing mammoth transmission projects to help interconnect such infrastructure, with several of these undertakings still in their infancy.
While EnergyConnect – an 900km-long electricity interconnector that extends from South Australia into Victoria and up to Wagga Wagga in NSW – is more than 90 per cent complete, HumeLink recently constructed the first of its 800 transmission towers.
Victoria to New South Wales Interconnector West (VNI West), on the other hand, which will transmit renewable energy between the two states, is still in its planning phase. Same goes for Marinus Link, a subsea power cable traversing Bass Strait to connect Heybridge, Tasmania with Waratah Bay, Victoria.
Project delays have led to cost overruns, adding further fuel to the cost debate.
“We’re having to build new transmission and new generation at the same time, which creates a coordination problem,” Reeve said.
“State governments have been trying to solve this by putting process around getting the transmission built, auctioning off access to that transmission and so on. This should be good for keeping costs down, but it also tends to slow everything down.
“And the longer you slow it down, the more costs go up.”
Reeve explained that when projects are initially costed with suppliers, they are held to that for a period of time.
“Your supplier of wind turbine blades, for example, might only be able to hold prices for 12 months,” she said. “If your project is delayed by 18 months, then your prices are going to be higher when you get underway.”
Cutting through green tape
Transmission and clean energy projects are also facing approval delays.
The Federal Government released its inaugural National Renewable Energy Priority List in March 2025, identifying 56 priority projects that will receive targeted support to streamline regulatory planning and approvals processes.
Long-sought reforms to the Environment Protection and Biodiversity Conservation (EPBC) Act came in November, with a new Streamlined Assessment Pathway reducing the timeframe for operators “who provide sufficient information upfront”.
New bilateral agreements between Federal and State Governments under the EPBC Act will remove duplication in the project assessment and approval process, while defined ‘go’ and ‘no go’ zones will provide greater clarity for project planning.
At the same time, 47 per cent of renewable energy companies surveyed by Infrastructure Australia viewed approval delays as being among the greatest risks to project delivery. This was shared in a November 2025 report.
VNI West, which is expected to be completed in 2030 instead of the previous goal of 2028, has faced community pushback.
In 2023, after six weeks of community and stakeholder consultation was undertaken by the Australian Electricity Market Operator (AEMO) and Transgrid regarding VNI West, 533 submissions were received, with 491 of these from concerned landowners and community members.
Transmission Company Victoria (TCV), which is now overseeing the project, said in July 2025 that the timeline for VNI West had been extended two years to reflect “updated planning, design, and construction assumptions that have evolved through the project’s early development stages”.
Reeve said approval delays had been compounded by labour shortages “which are still kicking through the system” after COVID.
“There’s been a number of headwinds for Australia’s renewable energy and transmission projects, which could have been manageable in isolation, but they’ve all manifested at once, creating a situation where things are slower and more expensive,” she said.
A low-emissions power system
In releasing its GenCost report in December, CSIRO introduced the system levelised cost of electricity (SLCOE) method to differ from the levelised cost of electricity (LCOE) metric used in the past, which simply compared costs of individual technologies.
SLCOE scrutinises capital costs against various electricity emission abatement scenarios to 2050, which CSIRO chief energy economist and GenCost project leader Paul Graham said provides “system modelling of the future generation mix and average cost of wholesale electricity”.
Using the new costing method, CSIRO found that the average cost of electricity in the National Electricity Market (NEM) consistent with meeting Australia’s 82 per cent renewables target by 2030 to be $91/MWh including transmission or $81/MWh for wholesale generation cost only.
For the electricity sector to support whole-of-economy net-zero abatement by 2050, CSIRO projected electricity costs to be between $135/MWh to $148/MWh in the NEM inclusive of new transmission costs or $115/MWh to $124/MWh from wholesale generation costs only.
For context, the historical average NEM volume-weighted generation price for 2024–25 is expected to be $129/MWh.
This suggests wholesale electricity prices will increase from 2030 to 2050, with GenCost demonstrating the true cost of running a highly reliable, near-zero-emissions power system, rather than just the cost of generating energy.
CSIRO sees a range of factors driving higher wholesale electricity prices as we reach 2050, with added costs for transmission, storage and firming to ensure reliable supply for a new-look grid.
The lowest-cost large-scale generation mix consistent with achieving 82 per cent renewables by 2030, according to CSIRO, comprises six per cent hydro, 41 per cent wind, 31 per cent solar PV, four per cent gas, and 18 per cent coal.
Could we already have the solution?
In releasing its report, Bills down, emissions down: A practical path to net-zero electricity, in October 2025, Grattan Institute explored what additional carbon constraint could mean for electricity prices.
“All of Australia’s policies are about pushing renewables in,” Reeve said. “What we thought about, instead, is what happens if you constrain how much people are allowed to emit, which is much more akin to taking coal and gas out.”
Grattan Institute analysed what impact emissions constraint would have on wholesale and retail electricity prices, along with overall household energy costs.
In doing so, the Melbourne-based think tank explored what adapting the Safeguard Mechanism to the electricity sector would look like.
Under the Safeguard Mechanism, which largely pertains to operators in industrial and transport sectors, companies that emit more than 100,000 tonnes of CO2-equivalent (CO2-e) per financial year are required to buy Australian carbon credit units (ACCUs) to offset their carbon footprint.
“Each (electricity) generator would receive an individual baseline, calculated from its output (MWh) and an emissions-intensity value,” the report stated.
“Generators that are above their baselines would need to obtain credits to offset these emissions. Generators that are below would be awarded credits.”
This model would see coal and gas generators pay renewable generators for credits, to essentially be a subsidy for renewable generators, “but one that is contained within the electricity market rather than coming from government”.
“The effect would be to make lower-emissions generation a more attractive investment, and higher-emissions generation less attractive,” the report stated. “Over time, this should achieve an efficient mix of generation to deliver the sector’s carbon budget.”
Grattan Institute found, with no policy change, the average annual household energy bill (including petrol, electricity, and gas) in 2050 would be about $2900 – down from about $5800 today.
By reducing emissions in line with the net-zero-by-2050 target, and by deploying the Safeguard Mechanism in the electricity sector, the average annual household energy bill would be about $3000.
“Emissions-reduction targets would be met, and households would still be about $2800 better off than they are today,” Grattan said.
Australia’s electricity cost landscape is complex, with a range of mechanisms and reports available to predict 2030 and 2050 trajectories.
While managing a highly reliable, 2050-era renewable energy system brings its added wholesale costs, many consumers will be self-determinant by that point – generating energy at home and storing excess power for peak demand.
And many electricity generators might be participating in a Safeguard Mechanism, built to deter emissions generation and support a healthy net-zero ecosystem.
This feature appeared in the March edition of Energy.
