GenCost FAQs

The GenCost report is one of several studies used by business leaders and decision-makers to plan and build reliable and affordable future energy solutions and help us achieve net zero emissions by 2050.   

Each year, CSIRO publishes GenCost in collaboration with the Australian Energy Market Operator (AEMO). It’s an unbiased, accurate and up-to-date economic report that provides cost estimates of building new electricity generation and storage projects, and hydrogen technologies, up to the year 2050.  

These technologies include coal, natural gas, solar photovoltaics, onshore and offshore wind, solar thermal, nuclear, bioenergy, pumped hydro, hydrogen electrolysers and batteries.  

The GenCost process is highly collaborative and draws on the deep expertise and knowledge of a large number of energy industry stakeholders. It includes engagement and consultation with members of the energy community to review the work and provide pre-publication feedback to improve its quality.   

For more detail watch this animation explaining the GenCost process. 

GenCost reports are developed over an annual cycle and actively provides opportunities for government, industry, the private sector, and economic specialists to ask questions and provide feedback.

Each year a large number of organisations provide input, ensuring a diverse range of perspectives and deep industry knowledge contribute to refining the report.

GenCost receives unprompted feedback throughout the year, but specifically targets the December and January period for invited consultation.

The project maintains a mailing list to share draft outputs which is open to all. To request inclusion, visit www.csiro.au/en/contact. On CSIRO’s behalf, AEMO also circulates the report to its Forecasting Reference Group mailing list and hosts a consultation web page which outlines the submissions period and procedures. 

The consultation is over a six-week period. The input and feedback gathered during consultation shapes the final report, which is released mid-year. Greater weight is given to input provided that is fact-based and includes verifiable data.

For more detail go to the GenCost Report section 1.1 Scope of the GenCost project and reporting on page 14.

GenCost projects the cost of electricity generation and storage for a wide range of technologies up to the year 2050.  

To do this, the report includes two types of data: capital costs and levelised costs.  

Capital costs provide the investment cost for each technology, but not the running costs. They are updated with input from an engineering firm.  

Levelised costs represent the per-unit cost of building and operating a generator over its lifetime. This provides a standardised measure for comparing the cost of electricity production across different technologies.  

For more detail go to the GenCost 2023-24 report section 5 Levelised cost of electricity analysis on page 6. You can also read the GenCost explainer or watch our animation explaining the GenCost process.

Levelised cost of electricity (LCOE) is a simple and widely used metric for comparing the cost of different technologies.   

Levelised costs combine capital costs with running costs such as operating, maintenance and fuel, in units that enable us to compare technologies side by side.  

The costs to maintain reliable renewable energy supply, known as ‘firming’ costs, are factored in from the current year forwards.  

For an investor, LCOE indicates the average price of electricity they would need to receive over the design life of their investment to recover all their costs and make a reasonable return on investment. The technology with the lowest LCOE is considered the most competitive.  

LCOE is only meaningful as a quick guide to competitiveness. Investors will need to carry out more in-depth modelling to support investment decisions and more complex questions such as policy analysis also require deeper modelling approaches.  

For more detail go to the GenCost 2023-24 report section 5 Levelised cost of electricity analysis on page 64. You can also read the GenCost explainer or watch our animation explaining the GenCost process.

‘Firming costs’ is a term often used to describe the investments needed to make variable renewables a reliable source of electricity for our power system. In the GenCost report our preferred term is ‘integration costs’.  

Integration costs include investments in storage, peaking generation, transmission and system security devices such as synchronous condensers. Modelling determines the most cost-effective combination of these investments.  

Pre-2030 integration costs were first incorporated in the 2023-24 consultation draft in response to stakeholder feedback. While this change led to higher cost estimates, renewables were still found to have the lowest cost range of any new build technology. 

For more detail go to the GenCost 2023-24 report section 5.2.1 Framework for calculating variable renewable integration costs on page 65.

Australia has never deployed nuclear power, so applying overseas costs to large-scale nuclear projects here is not a straightforward process. There are significant differences in labour costs, workforce expertise, governance, and standards, so the data source must be carefully selected.

GenCost used South Korea’s successful nuclear program as a basis for its large-scale nuclear cost estimates. It adjusted for differences between Australian and South Korean deployment costs by comparing the ratio of new coal generation costs in both countries.

GenCost's method offers a logical, transparent, and policy-neutral approach to estimating the costs of large-scale nuclear deployment in Australia. However, the reported costs can only be achieved if Australia commits to a continuous building program after constructing an initial higher-cost unit. The first unit of any new technology in Australia is expected to be impacted by higher costs, with a first-of-a-kind cost premium of up to 100 per cent, which GenCost estimates do not include.

For more detail go to the GenCost 2023-24 report section 2.5 Estimating large-scale nuclear costs on page 31.

It's standard practice that the financing period for an asset is less than its full operational life, similar to a car or house loan. 

For power stations, warranties expire and refurbishment costs increase around the 30-year mark. As a result, we use a 30-year lifespan for financial planning.

For more detail go to the GenCost Report Appendix D.4.1 on page 107.

The UAMPS Carbon Free Project in the USA provided the most reliable and transparent cost data available, making it the best source for GenCost’s nuclear SMR cost estimates. 

This decision was based on several key factors:

1. Reliable cost data
   The UAMPS Carbon Free Project provided open, verifiable cost data for a real nuclear SMR project. Other SMR cost estimates have been based on theoretical costs from vendors and are not considered reliable because they aretend to be too optimistic.
2. Project commitment
   The UAMPS project was a serious venture with real financial stakes. Developers had to provide accurate cost estimates upfront due to a subscription model for power production. Underestimating costs would have resulted in financial liabilities. 
3. Limited available data
   No other SMR project offers reliable, real-world cost data. Other suggested costs have been from vendors who have not committed to building or operating the projects themselves. 

For more detail go to the GenCost Report Appendix D.3.1 on page 104.

Baseload plants are power stations that provide a continuous and reliable electricity supply. In Australia, the average capacity factor for baseload black coal plants is 60%, with only a few reaching around 90%.

High performance is only possible if the plant is the lowest cost generator. In Australia’s electricity markets, the lowest cost plants get priority to generate electricity. Currently nuclear is unlikely to outbid cheaper options like existing coal or renewables. Despite this, GenCost allowed for a capacity factor range of 53% to 89%, based on historical data for baseload plants. 

For more detail go to the GenCost Report Appendix D.3.1 on page 104.

No. To keep calculations simple and transparent across all technologies, GenCost excludes costs that won’t significantly affect a technology’s competitive position. 

The common cost factors we include for each technology are: 

• generation capital
• capacity factor
• construction time
• operating and maintenance costs
• fuel efficiency
• fuel cost.

You can find out more about how radioactive waste is managed in Australia by visiting the ANSTO website.  

Nuclear power generates about 10 per cent of the world’s electricity, with 15 countries producing over 91 per cent of this energy.

But only 4 per cent of these countries rely on nuclear as their main energy source. Some, like Germany, are even phasing out nuclear in favour of renewables. 

As a country rich in renewable energy resources like solar and wind, Australia faces a range of challenges in adopting nuclear energy:

• Cost: Nuclear power is not the most cost-effective option for reducing emissions in our electricity sector.
• Time: Development times of more than 15 years and an empty project pipeline mean nuclear would not be able to play a major role in reducing emissions in our electricity sector.
• Expertise and skills: The absence of a local nuclear industry and workforce mean Australia would initially need to rely on offshore construction and operating experience.
• Community acceptance: Nuclear projects have not yet undergone local development approval processes, making community acceptance uncertain. 
• Regulation: Nuclear power generation is prohibited under federal and state laws in Australia. 

Public discussion on nuclear deployment in Australia often confuses total development time with construction time.'

Total development time includes not only construction, but pre-construction activities such as:

• site selection and acquisition
• technology design and engineering
• grid connection and impact studies
• environmental and technology permits
• sourcing fuel and water
• accessing project financing development and construction teams.

All developmental steps must be completed before construction can begin. Given Australia’s lack of a nuclear development pipeline and additional legal, safety, and security requirements, the first nuclear plant will face significant delays. Subsequent plants could be built more quickly once a pipeline is established. 

GenCost estimates that construction time for nuclear SMR to be 4.4 years and large-scale nuclear at 5.8 years.

For more information on nuclear development times, visit page 33 of the GenCost 2023-24 report. Construction times are detailed on page 35.

ANSTO was a reviewer of the GenCost report, however details of their involvement is not public information as it was part of standard consultation between government bureaus.

Written submissions made to GenCost during the AEMO-hosted consultation phase can be viewed on the AEMO website.

The levelised and capital costs for offshore wind are included in the GenCost report.  

GenCost only calculates the levelised cost of 60% to 90% variable renewable energy (VRE) shares for the years 2023 and 2030. Offshore wind was not included in these calculations as there was none in 2023, and AEMO has not projected offshore wind for 2030. 

These considerations are detailed in the GenCost report on page 67.  

The latest report highlights wind power’s slower recovery from global inflationary pressures, resulting in upward revisions for both onshore and offshore wind costs over the next decade. 

Despite this, updated analysis reaffirms that renewables, including associated storage and transmission costs, remain the lowest cost, new build technology. 

This competitive position reflects a decade of cost reductions in wind, solar photovoltaics (PV) and batteries before the pandemic. This is in contrast with costs of mature competitors which have remained flat. 

CSIRO does not recommend 100 per cent solar and wind for the electricity or energy sector. While technically feasible, it is not the most cost-effective solution for our energy transition.

For the electricity sector, CSIRO’s modelling shows the lowest cost path to net zero emissions by 2050 includes retaining a small amount of firming generation fuelled by natural gas, for times when storage and renewable generation is running low and offsetting those emissions from gas through land abatement or other measures.

It is possible, as the relevant technologies improve, we may be able to substitute natural gas for lower emission fuels such as green hydrogen or renewable gas to reduce electricity emissions closer to zero. However, on present knowledge, natural gas remains the lowest cost option.

GenCost calculates the breakeven costs needed for investors to recover their capital, fuel and operating costs, including a reasonable return on investment.   

This is an indicator of what electricity prices need to be to encourage new investment, but it does not control the electricity price. Electricity prices are controlled by the balance of supply and demand. If supply is tight relative to demand, then prices go up. If supply is significantly more than demand, then prices go down.   

In 2022, global natural gas supply constraints, triggered by sanctions on Russia due to the Ukraine war, together with unplanned coal plant outages, caused a price spike. This is still reverberating through the electricity system.   

Retailers, experiencing these conditions, secured electricity supply contracts for 2023-24 and factored these higher prices in.   

While additional renewable supply has, in some regions, lowered wholesale electricity prices, customers may not immediately feel the impact due to existing higher priced supply contracts, and any reductions might only become noticeable if they are sustained long enough to force forward contact prices down.  

Traditionally, our electricity system was thought to rely mainly on steady baseload power from coal, supplemented by gas and hydro to meet varying demand throughout the daily cycle. 

This view oversimplifies the historic reality; only a few of the very low-cost coal plants operated consistently at full capacity, most ramped up during the day and backed off at night.   

For many decades the average capacity factor of coal plant in Australia has been around 60 per cent, not the idealised 90 per cent.   

In moving to variable renewables, the capacity factor of our main energy source will be even lower at around 30 per cent.   

This will increase the need for storage and continue the need for natural gas or its lower emission substitutes such as biogas or hydrogen.   

Fortunately, the low cost of solar PV and wind and the declining costs of storage make this approach to operating a reliable electricity system economically viable whilst delivering lower emissions to address climate change.   

For more detail go to the GenCost 23-24 report section 5.3 Storage requirements underpinning variable renewable costs on page 75.