Carbon capture (CCS) lessons to learn for UK businesses

Bass Strait storage trials show underground CO2 capture at scale

Victoria’s CO2CRC has injected 100,000 tonnes of carbon dioxide underground at its Otway testing facility. This milestone, reached in late 2024, represents two decades of geological storage research aimed at proving whether emissions from the Latrobe Valley can be stored safely beneath Bass Strait.

The work feeds directly into CarbonNet, a project designed to capture emissions from Victoria’s Gippsland region and pump them 1.5 kilometres below the seabed. For UK businesses watching international carbon capture progress, the Australian experience offers concrete data on costs, timescales, and technical challenges.

CarbonNet received $100 million in combined federal and state funding. The plan involves a shared pipeline network running 80 kilometres to a hub at Golden Beach, then 20 kilometres offshore to injection sites in sandstone reservoirs. Shale and coal layers above these formations are expected to trap the gas permanently.

This article examines what the research has demonstrated, where costs and technical barriers remain, and why the findings matter for businesses evaluating carbon capture as part of their net zero planning.

Twenty years of testing underground CO2 injection

The Otway International Test Centre conducted Australia’s first geological CO2 storage demonstration in 2008. Since then, researchers have monitored how carbon dioxide behaves when injected into saline aquifers and depleted gas fields. The facility provides empirical evidence on containment, migration rates, and long-term stability.

Victoria’s government describes the storage approach as trapping emissions “safely there forever” beneath layers of impermeable rock. However, critics argue that commercial-scale deployment for coal power emissions remains unproven. The 100,000-tonne milestone at Otway represents significant volume for a research facility, yet it falls short of the millions of tonnes generated annually by industrial emitters.

Consequently, the gap between demonstration and deployment continues to drive debate. The technical feasibility has been established at test scale. What remains uncertain is whether the approach can be replicated economically at the volumes required by heavy industry.

CarbonNet targets Latrobe Valley emissions

The Latrobe Valley produces substantial CO2 from brown coal power stations and industrial processes. CarbonNet aims to create a shared infrastructure network that multiple capture projects can use. This model differs from site-specific approaches because it spreads pipeline and injection costs across several emitters.

Offshore geological formations in Bass Strait offer considerable storage capacity. The Pelican site, located 1.5 kilometres below the seabed, features sandstone reservoirs capped by shale and coal layers. These geological characteristics are designed to prevent upward migration of stored CO2.

Moreover, the proximity of storage sites to emission sources reduces transport distances compared to other Australian regions. The Hunter Valley, by contrast, lacks nearby large-scale storage prospects. This geographical advantage makes Bass Strait storage central to Victoria’s industrial transition strategy.

The CarbonNet model assumes commercial operation at scale. Therefore, it requires capture technology deployment at multiple industrial sites, coordinated transport infrastructure, and regulatory frameworks for long-term monitoring. Each element carries distinct cost and timing implications.

Hydrogen projects drive commercial interest

A Japanese consortium including J-POWER and Sumitomo Corporation is developing a coal-to-hydrogen project in the Latrobe Valley. The Hydrogen Energy Supply Chain project received over $2 billion in Japanese government commitment in 2023. Carbon capture is integral to the design because hydrogen production from coal generates significant CO2.

This project represents a potential anchor customer for CarbonNet infrastructure. Commercial hydrogen production would generate continuous emission volumes requiring permanent storage. Without viable carbon capture, the coal-to-hydrogen pathway cannot meet climate obligations.

Australia had 15 CO2 storage projects in development as of June 2024. The Moomba CCS project in South Australia began injecting CO2 in 2024, providing additional operational data. Meanwhile, Chevron’s Gorgon LNG project in Western Australia operates the world’s largest CCS facility, expected to store over 100 million tonnes across its lifetime.

These parallel developments create a growing evidence base. However, each project operates in different geological conditions with distinct emission sources. Lessons from one site do not automatically transfer to others.

Cost estimates reveal financial barriers

Historical analysis from 2005 estimated costs between $59 and $63 Australian dollars per tonne of CO2 avoided over a 25-year capture, transport, and injection cycle. Adjusted for inflation and technological progress, current costs remain substantial compared to alternative emissions reduction methods.

For UK manufacturers considering carbon capture, these figures provide a benchmark. The economic case depends on carbon pricing mechanisms, regulatory requirements, and whether shared infrastructure can distribute costs across multiple users. Single-site projects typically face higher per-tonne costs than networked approaches.

Furthermore, the CarbonNet business model assumes that storage costs will decline as injection volumes increase. This mirrors the experience in other infrastructure sectors where early projects bear higher unit costs. Nevertheless, the initial capital requirements remain a barrier for many industrial emitters.

Economic modelling suggests an east-coast CCS network could generate $66 billion in economic activity and support 15,250 jobs over coming decades. These projections assume successful deployment and ongoing operation. They also depend on policy settings that make carbon capture economically preferable to other decarbonisation options.

Commercial scale deployment faces technical questions

Critics highlight that CCS remains unproven at the scale required for coal power emissions. While the Otway facility demonstrates safe injection and containment, industrial applications require continuous operation at far higher volumes. This introduces additional technical and operational risks.

Safety concerns focus on long-term containment. Geological surveys indicate that shale and coal layers will trap CO2 indefinitely. However, monitoring must continue for decades to verify this assumption. The regulatory framework for long-term liability remains under development in many jurisdictions.

In addition, capture technology at coal power stations is energy-intensive. The parasitic load reduces overall plant efficiency, which means more fuel is required to generate the same net output. This creates a secondary cost impact beyond the direct expenses of capture equipment and operation.

The Australian experience shows that different geological formations behave differently. What works in Bass Strait may not apply elsewhere. Therefore, businesses evaluating carbon capture must assess local geology, transport distances, and regulatory conditions specific to their location.

What the Australian research demonstrates

The following points summarise the key findings from CO2CRC’s work and the broader CarbonNet initiative:

• Geological storage at 1.5 kilometres depth has been demonstrated through injection of 100,000 tonnes at the Otway facility over two decades of operation.
• Shared pipeline infrastructure can reduce per-tonne costs by distributing capital expenses across multiple emission sources in the same region.
• Commercial deployment requires anchor customers generating continuous emission volumes, such as the coal-to-hydrogen project receiving over $2 billion in Japanese investment.
• Historical cost estimates suggest $59 to $63 Australian dollars per tonne for capture, transport, and injection over a 25-year period.
• Proximity between emission sources and storage sites significantly affects project economics, with Bass Strait offering advantages not available in other Australian regions.
• Long-term monitoring and regulatory frameworks for liability remain under development despite proven technical feasibility at demonstration scale.
• Energy penalties from capture processes reduce overall plant efficiency, creating secondary cost impacts for industrial operations.

Carbon capture fits specific industrial contexts

The Latrobe Valley presents particular characteristics that make carbon capture relevant. Brown coal power generation and potential hydrogen production create concentrated emission sources near suitable geological storage. This combination may not exist in other regions.

For UK businesses, the question is whether similar conditions apply to your operations. Industries with unavoidable process emissions, such as cement or steel production, may find carbon capture necessary regardless of cost. Power generation and heating applications often have lower-cost alternatives through renewable energy.

Supply chain implications also matter. Public sector procurement increasingly requires net zero commitments from suppliers. Our sustainable procurement support helps businesses understand how these requirements affect tender eligibility. Carbon capture may become part of the evidence base demonstrating emissions reduction in specific sectors.

Geographical factors are equally important. UK industrial clusters near potential offshore storage sites face different economics than inland operations requiring long-distance CO2 transport. The North Sea has been identified as having significant storage capacity, but infrastructure development timelines remain uncertain.

Financial planning must account for both capital costs and ongoing operational expenses. Carbon capture requires substantial upfront investment with returns dependent on carbon pricing and regulatory stability. Therefore, businesses should model different policy scenarios when evaluating feasibility.

Policy settings determine commercial viability

The Australian government’s $70 million federal contribution and $30 million state funding for CarbonNet illustrate that public investment underpins early deployment. Similarly, the UK government supports carbon capture through various funding mechanisms, but commercial viability depends on long-term policy certainty.

Carbon pricing mechanisms directly affect the economic case. When the cost of emitting exceeds the cost of capture and storage, businesses have clear financial incentives. However, price volatility creates uncertainty for long-term investment decisions.

Regulatory frameworks for long-term liability remain in development. Questions about who bears responsibility for stored CO2 over decades or centuries affect insurance costs and risk assessment. These issues must be resolved before large-scale deployment can proceed with confidence.

Moreover, planning processes for CO2 pipelines and injection facilities involve multiple regulatory bodies. Timescales for approvals can extend project schedules significantly. Businesses considering carbon capture must factor these delays into their transition planning.

Comparing carbon capture with alternative approaches

The £59 to £63 per tonne cost estimate provides a benchmark for comparison. Many emissions reduction measures cost less, particularly energy efficiency improvements and renewable energy procurement. Carbon capture makes most sense where alternatives are limited or unavailable.

Process emissions from cement kilns or blast furnaces cannot easily be eliminated through fuel switching. In these cases, carbon capture may represent the only viable path to significant emissions reduction. However, operational changes and material substitution should be evaluated first.

Our net zero program helps businesses assess which combination of measures delivers the most cost-effective emissions reduction. Carbon capture typically appears later in the marginal abatement cost curve, after efficiency gains and renewable energy have been maximised.

Scope 3 emissions present additional complexity. If your supply chain includes high-emission processes, carbon capture by upstream suppliers may affect your reported footprint. Understanding these relationships requires detailed supply chain mapping and engagement with key suppliers.

What UK businesses should consider now

The Australian experience provides data points rather than definitive answers. Geological storage works at demonstration scale. Commercial deployment faces cost, technical, and regulatory hurdles. Whether carbon capture makes sense for your business depends on your specific circumstances.

Start by understanding your emissions profile. Identify which emissions can be reduced through efficiency, renewable energy, or process changes. What remains may be candidates for carbon capture, but only if suitable storage exists within economic transport distance.

Next, monitor policy developments. UK government funding programs and regulatory frameworks are evolving. Early engagement with industrial cluster initiatives may provide access to shared infrastructure that improves project economics.

Additionally, evaluate your sector’s trajectory. If competitors or customers are moving towards carbon capture, waiting may create competitive disadvantage. Conversely, rushing into deployment before costs decline could waste resources on technology that becomes obsolete.

Finally, consider how carbon capture fits into broader net zero strategy. Compliance with carbon reporting requirements and tender criteria requires documented progress toward emissions reduction. Carbon capture may form one component of a portfolio approach rather than a single solution.

Australian storage research informs UK decisions

The 100,000-tonne injection at Otway demonstrates technical feasibility. The CarbonNet project tests commercial-scale infrastructure design. The coal-to-hydrogen initiative shows how carbon capture enables specific industrial pathways. Together, these elements provide evidence for businesses evaluating similar options.

However, each jurisdiction presents unique geological, economic, and regulatory conditions. What works in Bass Strait may not transfer directly to the North Sea. Cost estimates from Australia provide benchmarks but require adjustment for UK conditions.

The fundamental lesson is that carbon capture requires patient capital, stable policy settings, and suitable geology. It is not a universal solution but rather a tool applicable in specific industrial contexts where emissions are concentrated and alternatives are limited.

UK businesses should engage with these developments as part of broader net zero planning. Understanding the technology, costs, and limitations helps inform investment decisions and risk assessment. The Australian experience shows both the potential and the challenges ahead.

Sources and further information

The Australian Department of Climate Change, Energy, the Environment and Water provides updates on national carbon capture policy and funding programs.

The Global CCS Institute tracks worldwide projects and publishes annual status reports on deployment progress and cost trends.

The UK Department for Energy Security and Net Zero outlines government strategy for carbon capture, including industrial cluster development and funding mechanisms.

The UK government guidance on carbon capture, usage and storage explains regulatory requirements and support available for businesses exploring these technologies.