This report sets out a high-level assessment of the policy action required to decarbonise Australia’s infrastructure sector, across its asset classes. It covers energy, transport, and asset management during construction, operation and waste.
Energy is the first frontier of Australia’s decarbonisation journey
The path to decarbonising Australia’s energy system has been clear for many years: a renewables-dominated electricity system, backed by a diverse mix of storage technologies, and declining reliance on fossil fuels for energy in other parts of the economy. A low-carbon energy system is vital for a low-carbon Australia, and the sooner energy decarbonises, the easier Australia’s transition to net zero will be – but this must happen in an orderly fashion.
The good news is that we have the tools for the job and we know how to do it. Industry has been driving the transition at pace over recent years, and Australia has been installing wind and solar resources at a per capita rate ten times quicker than the world average. This has been driven by rapidly changing economics, with wind and solar having clearly surpassed fossil fuel-fired generators as the least cost sources of new supply. Energy projects have been added to the Australia New Zealand Infrastructure Pipeline (ANZIP) at record pace over recent years, with 100 renewable energy projects with an estimated total cost of $254 billion now under development or construction across Australia. The recent announcements of early coal plant closures for Liddell in 2023, Eraring in 2025, and Yallourn in 2028, are real-time examples of new low-cost renewables forcing out higher cost legacy fossil fuel generation.
The major challenge is completing this transition at least cost and with no disruption for energy consumers. This is where governments can do more. While state and territory governments are pushing forward with their own energy transition priorities and projects, and institutions, including the Energy Security Board and the Australian Energy Market Operator, are providing guidance, the absence of Federal coordination and leadership is the equivalent of boxing with one arm tied behind our back.
A national transition strategy that is focused on the future end state of the nation’s energy networks at a whole-of system level, not broken by jurisdictional boundaries, is the missing piece of the puzzle.
This approach is twofold – covering what Australia can do with existing renewable energy technology today, and how emerging renewable energy technology can support the transition in the near-term. To build a low-carbon, low-cost energy system fit for the twenty-first century, Australia must do more than tinker with historical market settings. Australia needs a whole new approach to delivering energy, backed by governments with a clear and unified vision.
But instead of a national transition plan that unites state priorities and gives space for the market to run its course, a broader trend of government intervention in large energy projects is emerging, as seen in projects Snowy 2.0, the Kurri Kurri gas plant, and the recent Waratah Big Battery announcement. Some degree of government intervention may be justifiable, where a genuine market failure exists. But when a broader pattern of intervention in the project pipeline is established, particularly with a preference for certain generation or storage technologies, this risks distorting the market and undermining the confidence of investors who have no shortage of capital to finance an efficient energy transition.
The Energy Security Board’s Post-2025 Market Design agenda and goal of ensuring the electricity grid is affordable, reliable and secure has gone a long way to bringing the sector on a whole-of-system journey. Building on this as the sector’s transition starting point, we need to think longer term to decarbonise in a proactive manner. Energy’s transition to renewably generated electricity is happening one way or another, but it would be smoother, less expensive, and much quicker, if there was a national plan in place to coordinate an orderly transition. Pursuit of a net zero emissions by 2050 target will be enhanced by interim targets along the way – including, in the first instance, a reduced emissions by 2030 target. There are three key components that need to be considered in this plan: where energy comes from, how energy will be firmed, and how will that energy be moved to where it is needed.
Sun and wind will overwhelmingly power Australia’s future
Australia has world-class solar and wind energy resources. With continued investment over the coming decades, these resources can easily meet Australia’s energy needs, while providing almost limitless potential for energy exports. Investor appetite for renewable energy asset projects has never been stronger and opportunities for solar, offshore wind and onshore wind emerge on an almost weekly basis.
Wind and solar energy generation technology have become growing forces of supply in Australia’s energy mix. In the last three months of 2021, renewable energy made up 27.8 per cent of the National Electricity Market’s (NEM) energy supply and nearly 40 per cent of Western Australia’s Wholesale Electricity Market’s energy supply. By 2030, this figure could reach 61 per cent of the nation’s total energy supply.
Much has been made of the cost, pain and disruption of the transition to a renewables-dominated energy system, but less has been made of the incredible opportunities this could bring for Australians. While change will be hard, particularly for communities that have been heavily reliant on coal extraction or coal-fired generation, a low-carbon energy system provides far greater opportunities than one stubbornly hanging on to the past. And there are far greater opportunities for productivity growth and job creation across an economy powered by low-cost, low-carbon energy.
Case studies 1 and 2: Design and implementation considerations for Contracts for Difference
Contracts for Difference (CfDs) are often proposed as a tool to accelerate investment in emerging renewable energy technologies where policy or markets do not provide sufficient incentives. Project developers pursuing energy generation projects with emerging technologies often face additional risks on top of energy generation’s usual high capital costs, long payback periods, and volatile wholesale electricity markets.
This additional risk makes it more difficult for the private sector to invest in emerging technologies, but CfDs can reduce this risk, by providing a mechanism for a public sector entity to guarantee the offtake price for a new generation investment. To guarantee the offtake price, the public sector entity signs a contract with an energy generator, whereby the public sector entity will pay a subsidy equal to the difference between the market price and the agreed strike price (which is the price required by the generator to make the project investable).
CfDs differ from typical subsidy schemes in several ways:
- The subsidy amount paid is not fixed, if the market price is high then the subsidy will be small, but if the market price is low, then the public sector entity must subsidise a large amount.
- If the market price is higher than the strike price, the generator will pay back the subsidy to the public entity.
- The strike price can be determined administratively or through reverse auctions where bidders submit the price needed to make their project investable, with the lowest bids awarded contracts.
- CfDs have fixed time limits (the contract) which avoids the common problem of removing subsidies once they have served their purpose.
These two case studies illustrate potential positive and negative outcomes of CfD programs. These experiences highlight that CfD programs must be fit for purpose and designed appropriately for the specific market and technologies that are targeted.
Case Study 1: Driving down offshore wind costs in the United Kingdom using CfDs
The United Kingdom (UK) was experiencing an increase in electricity demand at the same time many older emissions intensive power plants were closing. In response, the UK Government announced a CfD program as part of its 2013 Electricity Market Reforms to incentivise investment in emerging renewable energy technologies including offshore wind.
At the time, offshore wind was still an emerging technology in the UK, so the Government sought to kickstart private investment by using 15-year CfDs to guarantee the offtake price needed to make these projects investable. The CfD program operated as a series of competitive reverse auctions. The UK Government would then establish a threshold strike price and all bidders below this price would be offered a contract.
Over the course of three rounds of CfDs, the strike price for offshore wind was lowered from almost £120/MWh to £39/MWh (see Figure 1 below). Alongside offshore wind technology improvements in the global industry, the UK’s CfD program helped to incentivise investment, which accelerated learning rates and technology improvements – in turn driving down project costs.
The three rounds of CfDs for emerging technologies cost the UK Government £260 million (Round One), £296 million (Round Two), and £65 million (Round Three). In December 2021, the UK launched a fourth round of the CfD program. Significantly, the last quarter of 2021 also saw generators across the UK’s CfD portfolio for renewable energy, including offshore wind generators, pay back £39,222,407 since the strike prices are now below the market reference price.
Figure 1: Reductions in UK Offshore Wind Strike Prices
Source: University of Oxford Smith School for Enterprise and the Environment, 2021, Zero-Emissions Shipping: Contracts-for-difference as incentives for the decarbonisation of international shipping
Case Study 2: Bill shock for Australian Capital Territory energy customers due to CfDs
To support an ambitious target of sourcing 100 per cent of electricity from renewable energy by 2020, the ACT Government implemented a CfD program to incentivise the development of new renewable energy generation. The program was administered by Evoenergy, the ACT’s distribution network service provider, with any subsidy costs incurred due to CfDs to flow through to customer network charges.
Five reverse auctions were run between 2012 and 2020, with contracts awarded for 840 MW of renewable energy generation over durations of between 10 and 20 years. The ACT used its large-scale feed-in tariff scheme to guarantee offtake prices, with many contracts locking in strike prices of $90/MWh.
The ACT Government’s CfD program had been performing as expected for several years, with some generators even paying back subsidies because wholesale prices were higher than the strike price. However, in 2021 the wholesale electricity price decreased significantly to an average of $35-40/MWh, which left a significant gap to be covered under the CfD program. Evoenergy’s payments to generators rose from $42 million in FY2020-21 to $127 million in FY2021-22, with these additional funds flowing through to customer bills, which saw average network charges increase by 41 per cent.
The UK’s experience with CfDs shows that they can be a useful tool to incentivise investment in emerging technologies, whereas the ACT’s CfD program has recently led to unintended consequences for customers. Although many factors contributed to these divergent outcomes, the design and context of each CfD program played an important role.
For example, Australia has an energy-only electricity market, whereas the UK has an energy capacity market, which typically has lower wholesale price volatility and therefore provides a more predictable environment for CfDs. Moreover, the UK’s CfD program was implemented at the national level, rather than the sub-national level as with the ACT, which made it easier to consider and control for interactions with other policy measures.
In the context of Australia’s complex and changing policy environment for electricity markets, CfDs may have a more appropriate role in incentivising zero-emission fuels for harder-to-abate sectors such as heavy transport.
Firming will be an essential component of a low-carbon electricity system
For all the advantages of renewables, the reality is the sun does not always shine and the wind does not always blow. But this is not a critical flaw in a renewables-dominated grid – it is an eminently solvable challenge.
Firming of intermittent renewable supply is possible by storing energy when renewable supply is abundant, and then providing power to the grid during times when demand outstrips supply. These services can be provided by a growing array of storage and backup technologies, including large-scale battery storage, pumped hydro and peaking gas plants.
The NEM relies on price signals to ensure reliable supply. Firming providers look for moments where demand outstrips supply when wholesale prices peak to provide energy, while taking energy to recharge their assets when supply is abundant and prices are low. This is backed by measures such as the Retailer Reliability Obligation, which was introduced in 2019, and the Reliability and Emergency Reserve Trader mechanism, which each provide additional safeguards to ensure supply is available when required. The economics of energy storage can also be bolstered by acting as an insurance product even while not in use.
An alternative model could see a capacity market established within the NEM. Capacity markets are quantity rather than price-driven, and can provide greater certainty over long-term supply, and also bring lower price volatility, though also bring challenges in ensuring price efficiency over a much longer horizon than the wholesale spot market. This approach is used in the UK, European Union (EU), some parts of the United States of America (US) and in Western Australia via its Reserve Capacity Mechanism.
Firming should form an important part of a national plan for decarbonisation, as should a clear determination on the optimal market mechanisms to ensure reliable supply over the long-term. The present ad hoc system of project development and approvals is likely to grow increasingly problematic over the coming years as demand for storage and backup services increases in line with renewable penetration.
Case study 3: QIC and Pacific Energy Hydrogen Demonstration Plant
QIC Global Infrastructure Fund’s portfolio company, Pacific Energy, provides power to its client, Horizon Power, who provides power to the remote town of Denham, in Western Australia. Horizon Power has a goal of no new installations of diesel generation from 2025 and is exploring offsetting diesel generation requirements with viable renewable alternatives. Pacific Energy is delivering a demonstration plant as a pilot project to investigate the feasibility of hydrogen filling this gap.
The Plant will test the:
- integration and deployment of the technology into remote diesel microgrids, and
- reliability of hydrogen to produce dispatchable power for towns dependent on diesel fuel power systems.
The Plant will use solar renewable energy to power an electrolyser that produces hydrogen, which is stored for later use in a fuel cell to deliver electricity. It will also provide base load green hydrogen power into a microgrid.
The total project cost is $8.9 million, with the Federal Government’s Australian Renewable Energy Agency providing $2.6 million in funding, and the Government of Western Australia providing $5.7 million in funding as part of its Recovery Plan, including $1 million from the Western Australian Renewable Hydrogen Fund.
Horizon Power Denham Hydrogen Demonstration
Sources of firming to support a low-carbon electricity system
Batteries contribute to firming both as grid support services during unexpected disruptions to the supply network, and as energy storage to supplement supply when demand becomes higher than usual. Batteries lose little energy in their round-trip efficiency and can operate independent of transmission grid infrastructure. However, with current technology the best rechargeable batteries can store up to four hours’ capacity and most big battery proposals in Australia are below this capacity, while the manufacturing of grid-scale batteries requires large volumes of rare earth minerals and other resources. As of April 2022, there are 13 big battery projects equating to a total 7.45-gigawatt capacity on ANZIP, along with another 22 energy projects that include battery storage. While this technology has taken substantive steps forward in recent years and will likely continue to do so, it is insufficient to rely on alone – particularly where firming may be required for more than a few hours.
Gas-powered generators are a proven firming option to bridge the energy output gap when required. While these plants are exposed to price volatility and supply constraints in global gas markets, and are the most carbon-intensive form of firming, peaking plants are likely to provide a key interim technology to ensure reliability while more sustainable sources of firming capacity are developed. A number of gas plants developed in recent years have the capacity to switch to hydrogen as a fuel source. While the economics of this switch remain unclear, the creation of an efficient green hydrogen market could help to prolong the useful lives of these assets while supporting broader decarbonisation of the energy system.
Given its renewable nature, pumped hydro will play a foundational role in Australia’s long-term firming mix. Despite pumped hydro assets losing more energy with a lower round-trip efficiency than batteries, they last longer than batteries. Special Adviser to the Australian Government on Low Emissions Technology, Dr Alan Finkel, supports growth in the technology, acknowledging that while for most of the year pumped hydro facilities may not be used, their multi-day storage capability will be a lifeline for consecutive calm days and overcast skies. A research team at the Australian National University led by Professor Andrew Blakers has identified up to 22,000 potential sites for projects across the country, which could be developed to support a fully renewable grid. In planning new pumped hydro assets, where they are located must be weighed against the cost of production, the environmental impact of their development, the capacity they can generate, and their proximity to sections of the grid with latent or expandable transmission capacity.
When feasible and commercialised, the ability to create green hydrogen using only renewable electricity and water will be game changing, and the opportunities are immense for Australia with its abundant solar and wind resources. Hydrogen is volatile in liquid form, but converting hydrogen to ammonia – a technology pioneered by the CSIRO – could enable the transport of energy in a relatively stable form to global markets.
Despite a number of studies and research projects pushing towards this outcome, the development pathway of hydrogen to a commercially-viable form of energy storage in Australia’s domestic system or export markets remains uncertain. The most feasible form of hydrogen long-term will be fully renewable, but this will only be viable with an abundant supply of cheap renewable energy powering its production. The economics of hydrogen are advancing rapidly, with a range of hydrogen production facilities underway across Australia – including some backed by institutional investors as highlighted in Case Study 3.
Transmission and distribution network upgrades will be required to support a transformed energy system
Just as Australia’s electricity supply and storage require an overhaul to deliver a low-carbon system, so too do the poles and wires moving electricity where it is required. Australia’s electricity grids were built and developed to support a system with relatively few centralised sources of power – mostly coal generators. The dramatic shift in where and how energy enters the grid and changing patterns of demand means much of Australia’s grid must be upgraded or expanded to meet consumers’ needs in the twenty-first century.
Recent decades have seen rapid growth in intermittent renewable generation, rising from 0.6 per cent of supply in the NEM in 2006 to 19.4 per cent in 2020. The proliferation of rooftop solar – backed by government subsidies and generous feed-in tariffs – has created a two-way electricity relationship, increasingly feeding energy back into the grid through low voltage electricity lines. Rooftop solar accounts for 8.3 per cent of total annual supply across the country.
These distributed energy resources have exposed the limitations of existing grid infrastructure, and technical challenges have been compounded by a lack of coordination. Energy market operators have struggled to understand how and when distributed sources of supply will come online, while many solar and wind projects have been developed in rural corners of the grid with limited capacity. This has caused bottlenecks and frustration for energy providers, while rule changes to protect system stability and encourage supply in more efficient parts of the grid have undermined the commercial outcomes of recent renewable projects. Policies to encourage generators in efficient parts of the grid can help to coordinate distributed supply more efficiently, but these types of reforms have proven difficult to land.
Many of these issues have been ironed out over time, with work by AEMO through its Integrated Systems Plan (ISP) and the introduction of future Renewable Energy Zones (REZs) by a number of state governments having helped to better coordinate supply, prioritise grid upgrades and provide greater certainty for energy providers, customers and investors. However, limitations persist across whole regions such as the West Murray Zone. Greater coordination between energy market bodies, federal and state governments could utilise REZs as a more effective tool for managing demand and supply across the whole of the NEM. Similarly, reforms to simplify and accelerate planning and approvals of new transmission capacity could provide greater ability to address grid constraints before they emerge. Regulatory reform is also required to ensure investment made by regulated networks in the required transmission infrastructure is commercially-viable and can proceed with certainty.
For now at least, the top priority for Australia’s energy bodies and market participants must be getting on with the energy transition. The focus of energy bodies and governments must be on the creation of an efficient, low-emission, affordable and reliable energy system, connected by a grid fit for our twenty-first century needs. Beyond efforts to support efficient investment in this system, introducing further major reforms now – when the market has already adapted to the vision laid out in the previous ISP and numerous other major plans and strategies by the energy market bodies – risks further delays and disruption at a time when Australia can least afford it. National leadership needs to empower energy market bodies to take accountability for the delivery of a decentralised, low-emission grid, ensuring market participants are able to attract the necessary capital and resources to make the transition.
Case study 4: Developing transmission infrastructure through renewable energy zones
Renewable energy development, such as wind and solar, often face the impediment of a lack of transmission capacity. Wind and solar resources are often strongest in regional and remote locations, where there has not been a historically large demand for electricity and therefore there is not a great deal of transmission capacity.In July 2020, the Australian Energy Market Operator identified potential renewable energy zones across the NEM as part of the Integrated System Plan. Since then, several state governments have already committed to develop renewable energy zones, with six zones in Victoria, five zones in NSW and three zones in Queensland.
In Texas in 2005, the State Government began developing a strategy to address the mismatch between traditional transmission planning and the project development requirements of renewable energy. This led to legislation to designate Competitive Renewable Energy Zones (CREZs). The Texas public utilities commission identified demand for circa 20 gigawatts (GW) of wind energy across five renewable energy zones.
By 2013, US$7 billion was invested to construct new transmission lines, enabling wind generation capacity to grow from one GW to 20 GW while maintaining low electricity prices.
Renewable energy as a future export economy
There has been a lot of hype about Australia’s potential role as a renewable energy export powerhouse. This hype is not unjustified. Australia’s geographic comparative advantage puts us in good stead to create an ultra-cheap renewable energy market to sell to the rest of the world. The potential rewards of a future export economy are significant – increased jobs, higher wages, and a higher standard of living to name a few – but the nation’s leaders need to get on with laying the foundations of this economy. Balanced against this is the need to retain sufficient domestic energy supplies for our domestic market, and ensure Australians are not short-changed of affordable and reliable electricity.
Our country is uniquely positioned with access to sun and wind resources that many of our energy-intensive trading partners, including Japan, Korea, Singapore and others, do not have. That presents an opportunity for Australia to be the literal powerhouse of the Asia-Pacific. But realising this opportunity requires development, planning and negotiation in the short-term to unlock benefits in the long-term. A clear and strategic national policy framework and energy transition plan will pave the way for the next steps required to shape this future economy.
It is not just renewable energy that Australia has the future opportunity to export either. Potential future production of green hydrogen also presents us with opportunities to create and export zero-emission steel and aluminium overseas – and concurrently decarbonise the domestic construction industry.
Recommendations to decarbonise Australia’s energy
What needs to change
What needs to change
A consistent lack of national leadership and coordination on the energy transition has resulted in a patchwork of overlapping and competing strategies and policies across the country, causing substantial policy and investor uncertainty.
The Federal Government should coordinate with state and territory governments to create a clear, national energy transition plan with solar and wind as the backbone of energy supply, an appropriate mix of firming technologies, and adequate transmission network capability. This plan should empower industry to act within a clear framework and an ambitious timeline for action.
Pursuit of a net zero emissions by 2050 target will be enhanced by interim targets along the way – including, in the first instance, a reduced emissions by 2030 target.
Industry and government stakeholders should improve coordination and engagement to augment the role of existing mechanisms, like REZs, in the energy transition.
What needs to change
The transmission grid was built for a different type of energy production in another era, and has become constrained with what low- to zero-emission sources can contribute to its electricity supply.
National leadership needs to empower Australia’s energy market bodies to take accountability for the delivery of a grid that supports a decentralised, low-emission electricity system, and ensure market participants are able to attract the necessary capital and resources to make the transition.
Regulators and policy makers should seek to accelerate and simplify planning and regulatory approvals for transmission upgrades required to support the energy transition. They should also undertake reform to ensure that regulated transmission network projects needed for the transition are commercially-viable so they can proceed with certainty.
What needs to change
The precise mix of generation sources, firming and storage technologies in a low-emission energy system is unclear.
A national transition plan should capitalise on commercially-viable solutions in the near term, while supporting studies and pilots to accelerate development of currently sub-commercial solutions, including green hydrogen, over the medium- to long-term. Planning should not wait for these technologies to emerge, but plan for their integration within an already rapidly decarbonising energy system.
What needs to change
The absence of a plan for existing fossil fuel assets that may be stranded in the wake of the energy transition.
Governments should adopt a hold-and-transition-fossil-fuel-assets approach for responsible owners to follow, requiring the orderly withdrawal of coal and fossil fuel-based energy production, followed by the transition of sites to renewable generation or storage facilities. Clear retirement timeframes within a national agenda will allow industry to plan for the future of their assets.
2. Emissions from the movement of people and goods have been rising, but transformation is around the corner
Despite improvements in vehicle efficiency over recent decades, Australia’s transport emissions have risen by 48.8 per cent against 1990 levels. But change is on the horizon, with the commercialisation of technologies that will underpin decarbonisation of public transport and light vehicles – of which the latter is consumer-led. Freight decarbonisation is on a slower trajectory, but there are clear steps governments and industry can take now to accelerate the change required.
In contrast to the gains made in energy, pre-pandemic transport emissions rose steadily from 9.7 per cent in 1990 to 19 per cent of Australia’s national total in 2019. There was a brief dip during 2020, but transport emissions have bounced back to make up 18.1 per cent of the national total last year. Actual emissions are likely much higher as well, given emissions from international aviation and shipping are excluded from these totals.
This upward trend reflects some of the challenges we face as a nation – vast distances between cities, production regions and markets, as well as a growing population with changing needs. But emerging technologies will turn this trend on its head. This is particularly true for light vehicles, which are on the cusp of a major transformation. Uptake of hybrid- and battery-electric vehicles is growing rapidly as their prices fall relative to internal combustion engine vehicles. The trajectory towards a low- to zero-emission light vehicle fleet is now all but certain.
3. Decarbonising assets through construction, operation and waste will require sustained innovation and reform
The final frontier of decarbonising the infrastructure sector requires a reduction in the emissions across asset stages – emissions embedded through construction, generated by asset operations, and left behind through waste. Compared to energy and transport, the technologies and methods required to overcome this challenge are the least developed. But with sustained commitment to innovation and reform, and by aligning incentives and investment opportunities with industry appetite for change, decarbonisation of the full infrastructure sector is possible.
The scope of emissions-related challenges in infrastructure has expanded rapidly over recent years, to a moment now where the carbon embedded within assets is in stark focus as an area for action. There has been some progress – largely industry-driven – through developments such as green concrete, recycled waste in construction materials, and pre-fabricated construction. But, up until now, embedded emissions across construction, operation, and waste have generally been a second order issue in dialogue on decarbonising the sector.
While Australia’s official carbon emission reporting does not account for construction emissions in its own standalone category, it is estimated that Australia’s construction industry generates 30 to 50 million tonnes of carbon every year.
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Director, Policy and Research
Infrastructure Partnerships Australia
Director, Policy and Research
Infrastructure Partnerships Australia
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Infrastructure Partnerships Australia